[Title 49 CFR ]
[Code of Federal Regulations (annual edition) - October 1, 2023 Edition]
[From the U.S. Government Publishing Office]



[[Page i]]

          

          Title 49

Transportation


________________________

Parts 178 to 199

                         Revised as of October 1, 2023

          Containing a codification of documents of general 
          applicability and future effect

          As of October 1, 2023
                    Published by the Office of the Federal Register 
                    National Archives and Records Administration as a 
                    Special Edition of the Federal Register

[[Page ii]]

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[[Page iii]]




                            Table of Contents



                                                                    Page
  Explanation.................................................       v

  Title 49:
    SUBTITLE B--Other Regulations Relating to Transportation 
      (Continued)
          Chapter I--Pipeline and Hazardous Materials Safety 
          Administration, Department of Transportation 
          (Continued)                                                5
  Finding Aids:
      Table of CFR Titles and Chapters........................     741
      Alphabetical List of Agencies Appearing in the CFR......     761
      List of CFR Sections Affected...........................     771

[[Page iv]]





                     ----------------------------

                     Cite this Code: CFR
                     To cite the regulations in 
                       this volume use title, 
                       part and section number. 
                       Thus, 49 CFR 178.1 refers 
                       to title 49, part 178, 
                       section 1.

                     ----------------------------

[[Page v]]



                               EXPLANATION

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Title 1 through Title 16.................................as of January 1
Title 17 through Title 27..................................as of April 1
Title 28 through Title 41...................................as of July 1
Title 42 through Title 50................................as of October 1

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[[Page vi]]

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[[Page vii]]

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    Office of the Federal Register
    October 1, 2023







[[Page ix]]



                               THIS TITLE

    Title 49--Transportation is composed of nine volumes. The parts in 
these volumes are arranged in the following order: Parts 1-99, parts 
100-177, parts 178-199, parts 200-299, parts 300-399, parts 400-571, 
parts 572-999, parts 1000-1199, and part 1200 to end. The first volume 
(parts 1-99) contains current regulations issued under subtitle A--
Office of the Secretary of Transportation; the second volume (parts 100-
177) and the third volume (parts 178-199) contain the current 
regulations issued under chapter I--Pipeline and Hazardous Materials 
Safety Administration (DOT); the fourth volume (parts 200-299) contains 
the current regulations issued under chapter II--Federal Railroad 
Administration (DOT); the fifth volume (parts 300-399) contains the 
current regulations issued under chapter III--Federal Motor Carrier 
Safety Administration (DOT); the sixth volume (parts 400-571) contains 
the current regulations issued under chapter IV--Coast Guard (DHS), and 
some of chapter V--National Highway Traffic Safety Administration (DOT); 
the seventh volume (parts 572-999) contains the rest of the regulations 
issued under chapter V--National Highway Traffic Safety Administration 
(DOT), and the current regulations issued under chapter VI--Federal 
Transit Administration (DOT), chapter VII--National Railroad Passenger 
Corporation (AMTRAK), and chapter VIII--National Transportation Safety 
Board; the eighth volume (parts 1000-1199) contains some of the current 
regulations issued under chapter X--Surface Transportation Board and the 
ninth volume (part 1200 to end) contains the rest of the current 
regulations issued under chapter X--Surface Transportation Board, 
chapter XI--Research and Innovative Technology Administration (DOT), and 
chapter XII--Transportation Security Administration (DHS). The contents 
of these volumes represent all current regulations codified under this 
title of the CFR as of October 1, 2023.

    In the volume containing parts 100-177, see Sec.  172.101 for the 
Hazardous Materials Table. The Federal Motor Vehicle Safety Standards 
appear in part 571.

    For this volume, Cheryl E. Sirofchuck was Chief Editor. The Code of 
Federal Regulations publication program is under the direction of John 
Hyrum Martinez, assisted by Stephen J. Frattini.

[[Page 1]]



                        TITLE 49--TRANSPORTATION




                  (This book contains parts 178 to 199)

  --------------------------------------------------------------------

  Editorial Note: Other regulations issued by the Department of 
Transportation appear in 14 CFR chapters I and II, 23 CFR, 33 CFR 
chapters I and IV, 44 CFR chapter IV, 46 CFR chapters I through III, 48 
CFR chapter 12, and 49 CFR chapters I through VI.

  SUBTITLE B--Other Regulations Relating to Transportation (Continued)

                                                                    Part

chapter I--Pipeline and Hazardous Materials Safety 
  Administration, Department of Transportation, DOT.........         178

[[Page 3]]

  Subtitle B--Other Regulations Relating to Transportation (Continued)

[[Page 5]]



   CHAPTER I--PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION, 
                DEPARTMENT OF TRANSPORTATION (CONTINUED)




  --------------------------------------------------------------------

        SUBCHAPTER C--HAZARDOUS MATERIALS REGULATIONS (CONTINUED)
Part                                                                Page
178             Specifications for packagings...............           7
179             Specifications for tank cars................         264
180             Continuing qualification and maintenance of 
                    packagings..............................         326
181-185

[Reserved]

                      SUBCHAPTER D--PIPELINE SAFETY
186-189

[Reserved]

190             Pipeline safety enforcement and regulatory 
                    procedures..............................         391
191             Transportation of natural and other gas by 
                    pipeline; annual, incident, and other 
                    reporting...............................         421
192             Transportation of natural and other gas by 
                    pipeline: Minimum Federal safety 
                    standards...............................         429
193             Liquefied natural gas facilities: Federal 
                    safety standards........................         600
194             Response plans for onshore oil pipelines....         620
195             Transportation of hazardous liquids by 
                    pipeline................................         630
196             Protection of underground pipelines from 
                    excavation activity.....................         715
197

[Reserved]

198             Regulations for grants to aid State pipeline 
                    safety programs.........................         718
199             Drug and alcohol testing....................         722

[[Page 7]]



        SUBCHAPTER C_HAZARDOUS MATERIALS REGULATIONS (CONTINUED)





PART 178_SPECIFICATIONS FOR PACKAGINGS--Table of Contents



Sec.
178.1 Purpose and scope.
178.2 Applicability and responsibility.
178.3 Marking of packagings.

Subpart A [Reserved]

       Subpart B_Specifications for Inside Containers, and Linings

178.33 Specification 2P; inner nonrefillable metal receptacles.
178.33-1 Compliance.
178.33-2 Type and size.
178.33-3 Inspection.
178.33-4 Duties of inspector.
178.33-5 Material.
178.33-6 Manufacture.
178.33-7 Wall thickness.
178.33-8 Tests.
178.33-9 Marking.
178.33a Specification 2Q; inner nonrefillable metal receptacles.
178.33a-1 Compliance.
178.33a-2 Type and size.
178.33a-3 Inspection.
178.33a-4 Duties of inspector.
178.33a-5 Material.
178.33a-6 Manufacture.
178.33a-7 Wall thickness.
178.33a-8 Tests.
178.33a-9 Marking.
178.33b Specification 2S; inner nonrefillable plastic receptacles
178.33b-1 Compliance.
178.33b-2 Type and size.
178.33b-3 Inspection.
178.33b-4 Duties of inspector.
178.33b-5 Material.
178.33b-6 Manufacture.
178.33b-7 Design qualification test.
178.33b-8 Production tests.
178.33b-9 Marking.
178.33c Specification 2P; inner nonrefillable metal receptacle 
          variation.
178.33c-1 Compliance.
178.33c-2 Variation.
178.33d Specification 2Q; inner nonrefillable metal receptacle 
          variations.
178.33d-1 Compliance.
178.33d-2 Variation 1.
178.33d-3 Variation 2.

                 Subpart C_Specifications for Cylinders

178.35 General requirements for specification cylinders.
178.36 Specification 3A and 3AX seamless steel cylinders.
178.37 Specification 3AA and 3AAX seamless steel cylinders.
178.38 Specification 3B seamless steel cylinders.
178.39 Specification 3BN seamless nickel cylinders.
178.42 Specification 3E seamless steel cylinders.
178.44 Specification 3HT seamless steel cylinders for aircraft use.
178.45 Specification 3T seamless steel cylinders.
178.46 Specification 3AL seamless aluminum cylinders.
178.47 Specification 4DS welded stainless steel cylinders for aircraft 
          use.
178.50 Specification 4B welded or brazed steel cylinders.
178.51 Specification 4BA welded or brazed steel cylinders.
178.53 Specification 4D welded steel cylinders for aircraft use.
178.55 Specification 4B240ET welded or brazed cylinders.
178.56 Specification 4AA480 welded steel cylinders.
178.57 Specification 4L welded insulated cylinders.
178.58 Specification 4DA welded steel cylinders for aircraft use.
178.59 Specification 8 steel cylinders with porous fillings for 
          acetylene.
178.60 Specification 8AL steel cylinders with porous fillings for 
          acetylene.
178.61 Specification 4BW welded steel cylinders with electric-arc welded 
          longitudinal seam.
178.65 Specification 39 non-reusable (non-refillable) cylinders.
178.68 Specification 4E welded aluminum cylinders.
178.69 Responsibilities and requirements for manufacturers of UN 
          pressure receptacles.
178.70 Approval of UN pressure receptacles.
178.71 Specifications for UN pressure receptacles.
178.74 Approval of MEGCs.
178.75 Specifications for MEGCs.

Appendix A to Subpart C of Part 178--Illustrations: Cylinder Tensile 
          Sample

Subparts D-G [Reserved]

               Subpart H_Specifications for Portable Tanks

178.251--178.253-5 [Reserved]
178.255 Specification 60; steel portable tanks.

[[Page 8]]

178.255-1 General requirements.
178.255-2 Material.
178.255-3 Expansion domes.
178.255-4 Closures for manholes and domes.
178.255-5 Bottom discharge outlets.
178.255-6 Loading and unloading accessories.
178.255-7 Protection of valves and accessories.
178.255-8 Safety devices.
178.255-9 Compartments.
178.255-10 Lining.
178.255-11 Tank mountings.
178.255-12 Pressure test.
178.255-13 Repair of tanks.
178.255-14 Marking.
178.255-15 Report.
178.273 Approval of Specification UN portable tanks.
178.274 Specification for UN portable tanks.
178.275 Specification for UN Portable Tanks intended for the 
          transportation of liquid and solid hazardous materials.
178.276 Requirements for the design, construction, inspection and 
          testing of portable tanks intended for the transportation of 
          non-refrigerated liquefied compressed gases.
178.277 Requirements for the design, construction, inspection and 
          testing of portable tanks intended for the transportation of 
          refrigerated liquefied gases.

Subpart I [Reserved]

Subpart J_Specifications for Containers for Motor Vehicle Transportation

178.318 Specification MC 201; container for detonators and percussion 
          caps.
178.318-1 Scope.
178.318-2 Container.
178.318-3 Marking.
178.320 General requirements applicable to all DOT specification cargo 
          tank motor vehicles.
178.337 Specification MC 331; cargo tank motor vehicle primarily for 
          transportation of compressed gases as defined in subpart G of 
          part 173 of this subchapter.
178.337-1 General requirements.
178.337-2 Material.
178.337-3 Structural integrity.
178.337-4 Joints.
178.337-5 Bulkheads, baffles and ring stiffeners.
178.337-6 Closure for manhole.
178.337-7 Overturn protection.
178.337-8 Openings, inlets and outlets.
178.337-9 Pressure relief devices, piping, valves, hoses, and fittings.
178.337-10 Accident damage protection.
178.337-11 Emergency discharge control.
178.337-12 [Reserved]
178.337-13 Supporting and anchoring.
178.337-14 Gauging devices.
178.337-15 Pumps and compressors.
178.337-16 Testing.
178.337-17 Marking.
178.337-18 Certification.
178.338 Specification MC-338; insulated cargo tank motor vehicle.
178.338-1 General requirements.
178.338-2 Material.
178.338-3 Structural integrity.
178.338-4 Joints.
178.338-5 Stiffening rings.
178.338-6 Manholes.
178.338-7 Openings.
178.338-8 Pressure relief devices, piping, valves, and fittings.
178.338-9 Holding time.
178.338-10 Accident damage protection.
178.338-11 Discharge control devices.
178.338-12 Shear section.
178.338-13 Supporting and anchoring.
178.338-14 Gauging devices.
178.338-15 Cleanliness.
178.338-16 Inspection and testing.
178.338-17 Pumps and compressors.
178.338-18 Marking.
178.338-19 Certification.
178.340-178.343 [Reserved]
178.345 General design and construction requirements applicable to 
          Specification DOT 406 (Sec.  178.346), DOT 407 (Sec.  
          178.347), and DOT 412 (Sec.  178.348) cargo tank motor 
          vehicles.
178.345-1 General requirements.
178.345-2 Material and material thickness.
178.345-3 Structural integrity.
178.345-4 Joints.
178.345-5 Manhole assemblies.
178.345-6 Supports and anchoring.
178.345-7 Circumferential reinforcements.
178.345-8 Accident damage protection.
178.345-9 Pumps, piping, hoses and connections.
178.345-10 Pressure relief.
178.345-11 Tank outlets.
178.345-12 Gauging devices.
178.345-13 Pressure and leakage tests.
178.345-14 Marking.
178.345-15 Certification.
178.346 Specification DOT 406; cargo tank motor vehicle.
178.346-1 General requirements.
178.346-2 Material and thickness of material.
178.346-3 Pressure relief.
178.346-4 Outlets.
178.346-5 Pressure and leakage tests.
178.347 Specification DOT 407; cargo tank motor vehicle.
178.347-1 General requirements.
178.347-2 Material and thickness of material.
178.347-3 Manhole assemblies.
178.347-4 Pressure relief.
178.347-5 Pressure and leakage test.
178.348 Specification DOT 412; cargo tank motor vehicle.
178.348-1 General requirements.
178.348-2 Material and thickness of material.

[[Page 9]]

178.348-3 Pumps, piping, hoses and connections.
178.348-4 Pressure relief.
178.348-5 Pressure and leakage test.

   Subpart K_Specifications for Packagings for Class 7 (Radioactive) 
                                Materials

178.350 Specification 7A; general packaging, Type A.

       Subpart L_Non-bulk Performance-Oriented Packaging Standards

178.500 Purpose, scope and definitions.
178.502 Identification codes for packagings.
178.503 Marking of packagings.
178.504 Standards for steel drums.
178.505 Standards for aluminum drums.
178.506 Standards for metal drums other than steel or aluminum.
178.507 Standards for plywood drums.
178.508 Standards for fiber drums.
178.509 Standards for plastic drums and jerricans.
178.510 Standards for wooden barrels.
178.511 Standards for aluminum and steel jerricans.
178.512 Standards for steel, aluminum or other metal boxes.
178.513 Standards for boxes of natural wood.
178.514 Standards for plywood boxes.
178.515 Standards for reconstituted wood boxes.
178.516 Standards for fiberboard boxes.
178.517 Standards for plastic boxes.
178.518 Standards for woven plastic bags.
178.519 Standards for plastic film bags.
178.520 Standards for textile bags.
178.521 Standards for paper bags.
178.522 Standards for composite packagings with inner plastic 
          receptacles.
178.523 Standards for composite packagings with inner glass, porcelain, 
          or stoneware receptacles.

          Subpart M_Testing of Non-bulk Packagings and Packages

178.600 Purpose and scope.
178.601 General requirements.
178.602 Preparation of packagings and packages for testing.
178.603 Drop test.
178.604 Leakproofness test.
178.605 Hydrostatic pressure test.
178.606 Stacking test.
178.607 Cooperage test for bung-type wooden barrels.
178.608 Vibration standard.
178.609 Test requirements for packagings for infectious substances.

              Subpart N_IBC Performance-Oriented Standards

178.700 Purpose, scope and definitions.
178.702 IBC codes.
178.703 Marking of IBCs.
178.704 General IBC standards.
178.705 Standards for metal IBCs.
178.706 Standards for rigid plastic IBCs.
178.707 Standards for composite IBCs.
178.708 Standards for fiberboard IBCs.
178.709 Standards for wooden IBCs.
178.710 Standards for flexible intermediate bulk containers.

                        Subpart O_Testing of IBCs

178.800 Purpose and scope.
178.801 General requirements.
178.802 Preparation of fiberboard IBCs for testing.
178.803 Testing and certification of IBCs.
178.810 Drop test.
178.811 Bottom lift test.
178.812 Top lift test.
178.813 Leakproofness test.
178.814 Hydrostatic pressure test.
178.815 Stacking test.
178.816 Topple test.
178.817 Righting test.
178.818 Tear test.
178.819 Vibration test.

                  Subpart P_Large Packagings Standards

178.900 Purpose and scope.
178.905 Large Packaging identification codes.
178.910 Marking of Large Packagings.
178.915 General Large Packaging standards.
178.920 Standards for metal Large Packagings.
178.925 Standards for rigid plastic Large Packagings.
178.930 Standards for fiberboard Large Packagings.
178.935 Standards for wooden Large Packagings.
178.940 Standards for flexible Large Packagings.

                  Subpart Q_Testing of Large Packagings

178.950 Purpose and scope.
178.955 General requirements.
178.960 Preparation of Large Packagings for testing.
178.965 Drop test.
178.970 Bottom lift test.
178.975 Top lift test.
178.980 Stacking test.
178.985 Vibration test.

               Subpart R_Flexible Bulk Container Standards

178.1000 Purpose and scope.
178.1005 Flexible Bulk Container identification code.
178.1010 Marking of Flexible Bulk Containers.

[[Page 10]]

178.1015 General Flexible Bulk Container standards.
178.1020 Period of use for transportation of hazardous materials in 
          Flexible Bulk Containers.

              Subpart S_Testing of Flexible Bulk Containers

178.1030 Purpose and scope.
178.1035 General requirements.
178.1040 Preparation of Flexible Bulk Containers for testing.
178.1045 Drop test.
178.1050 Top lift test.
178.1055 Stacking test.
178.1060 Topple test.
178.1065 Righting test.
178.1070 Tear test.

Appendix A to Part 178--Specifications for Steel
Appendix B to Part 178--Alternative Leakproofness Test Methods
Appendix C to Part 178--Nominal and Minimum Thicknesses of Steel Drums 
          and Jerricans
Appendix D to Part 178--Thermal Resistance Test
Appendix E to Part 178--Flame Penetration Resistance Test

    Authority: 49 U.S.C. 5101-5128; 49 CFR 1.81 and 1.97.



Sec.  178.1  Purpose and scope.

    This part prescribes the manufacturing and testing specifications 
for packaging and containers used for the transportation of hazardous 
materials in commerce.

[Amdt. 178-40, 42 FR 2689, Jan. 13, 1977. Redesignated by Amdt. 178-97, 
55 FR 52715, Dec. 21, 1990]



Sec.  178.2  Applicability and responsibility.

    (a) Applicability. (1) The requirements of this part apply to 
packagings manufactured--
    (i) To a DOT specification, regardless of country of manufacture; or
    (ii) To a UN standard, for packagings manufactured within the United 
States. For UN standard packagings manufactured outside the United 
States, see Sec.  173.24(d)(2) of this subchapter. For UN standard 
packagings for which standards are not prescribed in this part, see 
Sec.  178.3(b).
    (2) A manufacturer of a packaging subject to the requirements of 
this part is primarily responsible for compliance with the requirements 
of this part. However, any person who performs a function prescribed in 
this part shall perform that function in accordance with this part.
    (b) Specification markings. When this part requires that a packaging 
be marked with a DOT specification or UN standard marking, marking of 
the packaging with the appropriate DOT or UN markings is the 
certification that--
    (1) Except as otherwise provided in this section, all requirements 
of the DOT specification or UN standard, including performance tests, 
are met; and
    (2) All functions performed by, or on behalf of, the person whose 
name or symbol appears as part of the marking conform to requirements 
specified in this part.
    (c) Notification. (1) Except as specifically provided in Sec. Sec.  
178.337-18, 178.338-19, and 178.345-15 of this part, the manufacturer or 
other person certifying compliance with the requirements of this part, 
and each subsequent distributor of that packaging must:
    (i) Notify each person to whom that packaging is transferred--
    (A) Of all requirements in this part not met at the time of 
transfer, and
    (B) With information specifying the type(s) and dimensions of the 
closures, including gaskets and any other components needed to ensure 
that the packaging is capable of successfully passing the applicable 
performance tests. This information must include any procedures to be 
followed, including closure instructions for inner packagings and 
receptacles, to effectively assemble and close the packaging for the 
purpose of preventing leakage in transportation. Closure instructions 
must provide for a consistent and repeatable means of closure that is 
sufficient to ensure the packaging is closed in the same manner as it 
was tested. For packagings sold or represented as being in conformance 
with the requirements of this subchapter applicable to transportation by 
aircraft, this information must include relevant guidance to ensure that 
the packaging, as prepared for transportation, will withstand the 
pressure differential requirements in Sec.  173.27 of this subchapter.

[[Page 11]]

    (ii) Retain copies of each written notification for at least one 
year from date of issuance; and
    (iii) Make copies of all written notifications available for 
inspection by a representative of the Department.
    (2) The notification required in accordance with this paragraph (c) 
may be in writing or by electronic means, including e-mailed 
transmission or transmission on a CD or similar device. If a 
manufacturer or subsequent distributor of the packaging utilizes 
electronic means to make the required notifications, the notification 
must be specific to the packaging in question and must be in a form that 
can be printed in hard copy by the person receiving the notification.
    (d) Except as provided in paragraph (c) of this section, a packaging 
not conforming to the applicable specifications or standards in this 
part may not be marked to indicate such conformance.
    (e) Definitions. For the purpose of this part--
    Manufacturer means the person whose name and address or symbol 
appears as part of the specification markings required by this part or, 
for a packaging marked with the symbol of an approval agency, the person 
on whose behalf the approval agency certifies the packaging.
    Specification markings mean the packaging identification markings 
required by this part including, where applicable, the name and address 
or symbol of the packaging manufacturer or approval agency.
    (f) No packaging may be manufactured or marked to a packaging 
specification that was in effect on September 30, 1991, and that was 
removed from this part 178 by a rule published in the Federal Register 
on December 21, 1990 and effective October 1, 1991.

[Amdt. 178-97, 55 FR 52715, Dec. 21, 1990; 56 FR 66284, Dec. 20, 1991, 
as amended by Amdt. 178-106, 59 FR 67519, Dec. 29, 1994; Amdt. 178-117, 
62 FR 14338, Mar. 26, 1997; 68 FR 45041, July 31, 2003; 69 FR 34612, 
June 22, 2004; 75 FR 5395, Feb. 2, 2010; 75 FR 60339, Sept. 30, 2010; 78 
FR 1118, Jan. 7, 2013; 78 FR 15328, Mar. 11, 2013]



Sec.  178.3  Marking of packagings.

    (a) Each packaging represented as manufactured to a DOT 
specification or a UN standard must be marked on a non-removable 
component of the packaging with specification markings conforming to the 
applicable specification, and with the following:
    (1) In an unobstructed area, with letters, and numerals identifying 
the standards or specification (e.g. UN 1A1, DOT 4B240ET, etc.).
    (2) Unless otherwise specified in this part, the name and address or 
symbol of the packaging manufacturer or the person certifying compliance 
with a UN standard. Symbols, if used, must be registered with the 
Associate Administrator. Unless authorized in writing by the holder of 
the symbol, symbols must represent either the packaging manufacturer or 
the approval agency responsible for providing the most recent 
certification for the packaging through design certification testing or 
periodic retesting, as applicable. Duplicative symbols are not 
authorized.
    (3) The markings must be stamped, embossed, burned, printed or 
otherwise marked on the packaging to provide adequate accessibility, 
permanency, contrast, and legibility so as to be readily apparent and 
understood.
    (4) Unless otherwise specified, letters and numerals must be at 
least 12.0 mm (0.47 inches) in height except for packagings of less than 
or equal to 30 L (7.9 gallons) capacity for liquids or 30 kg (66 pounds) 
maximum net mass for solids the height must be at least 6.0 mm (0.2 
inches). For packagings having a capacity of 5 L (1.3 gallons) or less 
or of 5 kg (11 pounds) maximum net mass, letters and numerals must be of 
an appropriate size.
    (5) For packages with a gross mass of more than 30 kg (66 pounds), 
the markings or a duplicate thereof must appear on the top or on a side 
of the packaging.
    (b) A UN standard packaging for which the UN standard is set forth 
in this part may be marked with the United Nations symbol and other 
specification markings only if it fully conforms to the requirements of 
this part. A UN standard packaging for which the UN standard is not set 
forth in this part may be marked with the United Nations symbol and 
other specification markings for that standard as provided in the ICAO 
Technical Instructions or

[[Page 12]]

the IMDG Code subject to the following conditions:
    (1) The U.S. manufacturer must establish that the packaging conforms 
to the applicable provisions of the ICAO Technical Instructions (IBR, 
see Sec.  171.7 of this subchapter) or the IMDG Code (IBR, see Sec.  
171.7 of this subchapter), respectively.
    (2) If an indication of the name of the manufacturer or other 
identification of the packaging as specified by the competent authority 
is required, the name and address or symbol of the manufacturer or the 
approval agency certifying compliance with the UN standard must be 
entered. Symbols, if used, must be registered with the Associate 
Administrator.
    (3) The letters ``USA'' must be used to indicate the State 
authorizing the allocation of the specification marks if the packaging 
is manufactured in the United States.
    (c) Where a packaging conforms to more than one UN standard or DOT 
specification, the packaging may bear more than one marking, provided 
the packaging meets all the requirements of each standard or 
specification. Where more than one marking appears on a packaging, each 
marking must appear in its entirety.
    (d) No person may mark or otherwise certify a packaging or container 
as meeting the requirements of a manufacturing special permit unless 
that person is the holder of or a party to that special permit, an agent 
of the holder or party for the purpose of marking or certification, or a 
third party tester.

[Amdt. 178-97, 55 FR 52716, Dec. 21, 1990; 56 FR 66284, Dec. 20, 1991, 
as amended by Amdt. 178-106, 59 FR 67519, Dec. 29, 1994; Amdt. 178-113, 
61 FR 21102, May 9, 1996; 65 FR 50462, Aug. 18, 2000; 66 FR 45386, Aug. 
28, 2001; 67 FR 61015, Sept. 27, 2002; 68 FR 75748, Dec. 31, 2003; 70 FR 
73166, Dec. 9, 2005; 78 FR 14714, Mar. 7, 2013; 87 FR 44999, July 26, 
2022]

Subpart A [Reserved]



       Subpart B_Specifications for Inside Containers, and Linings

    Source: 29 FR 18823, Dec. 29, 1964, unless otherwise noted. 
Redesignated at 32 FR 5606, Apr. 5, 1967.



Sec.  178.33  Specification 2P; inner nonrefillable metal receptacles.



Sec.  178.33-1  Compliance.

    (a) Required in all details.
    (b) [Reserved]



Sec.  178.33-2  Type and size.

    (a) Single-trip inside containers. Must be seamless, or with seams, 
welded, soldered, brazed, double seamed, or swedged.
    (b) The maximum capacity of containers in this class shall not 
exceed one liter (61.0 cubic inches). The maximum inside diameter shall 
not exceed 3 inches.

[29 FR 18813, Dec. 29, 1964, as amended by Order 71, 31 FR 9074, July 1, 
1966. Redesignated at 32 FR 5606, Apr. 5, 1967, and amended by Amdt. 
178-101, 58 FR 50237, Sept. 24, 1993; 66 FR 45386, Aug. 28, 2001]



Sec.  178.33-3  Inspection.

    (a) By competent inspector.
    (b) [Reserved]



Sec.  178.33-4  Duties of inspector.

    (a) To inspect material and completed containers and witness tests, 
and to reject defective materials or containers.
    (b) [Reserved]



Sec.  178.33-5  Material.

    (a) Uniform quality steel plate such as black plate, electro-tin 
plate, hot dipped tin plate, tern plate or other commercially accepted 
can making plate; or nonferrous metal of uniform drawing quality.
    (b) Material with seams, cracks, laminations or other injurious 
defects not authorized.



Sec.  178.33-6  Manufacture.

    (a) By appliances and methods that will assure uniformity of 
completed containers; dirt and scale to be removed as necessary; no 
defect acceptable that is likely to weaken the finished container 
appreciably; reasonably smooth and uniform surface finish required.
    (b) Seams when used must be as follows:
    (1) Circumferential seams: By welding, swedging, brazing, soldering, 
or double seaming.

[[Page 13]]

    (2) Side seams: By welding, brazing, or soldering.
    (c) Ends: The ends shall be of pressure design.

[29 FR 18823, Dec. 29, 1964, as amended by Order 71, 31 FR 9074, July 1, 
1966. Redesignated at 32 FR 5606, Apr. 5, 1967]



Sec.  178.33-7  Wall thickness.

    (a) The minimum wall thickness for any container shall be 0.007 
inch.
    (b) [Reserved]

[Order 71, 31 FR 9074, July 1, 1966. Redesignated at 32 FR 5606, Apr. 5, 
1967]



Sec.  178.33-8  Tests.

    (a) One out of each lot of 25,000 containers or less, successively 
produced per day shall be pressure tested to destruction and must not 
burst below 240 psig gauge pressure. The container tested shall be 
complete with end assembled.
    (b) Each such 25,000 containers or less, successively produced per 
day, shall constitute a lot and if the test container shall fail, the 
lot shall be rejected or ten additional containers may be selected at 
random and subjected to the test under which failure occurred. These 
containers shall be complete with ends assembled. Should any of the ten 
containers thus tested fail, the entire lot must be rejected. All 
containers constituting a lot shall be of like material, size, design 
construction, finish, and quality.

[Order 71, 31 FR 9074, July 1, 1966. Redesignated at 32 FR 5606, Apr. 5, 
1967, as amended by 66 FR 45387, Aug. 28, 2001]



Sec.  178.33-9  Marking.

    (a) By means of printing, lithographing, embossing, or stamping, 
each container must be marked to show:
    (1) DOT-2P.
    (2) Name or symbol of person making the mark specified in paragraph 
(a)(1) of this section. Symbol, if used, must be registered with the 
Associate Administrator.
    (b) [Reserved]

[Amdt. 178-40, 41 FR 38181, Sept. 9, 1976, as amended by Amdt. 178-97, 
56 FR 66287, Dec. 20, 1991; 66 FR 45386, Aug. 28, 2001]



Sec.  178.33a  Specification 2Q; inner nonrefillable metal receptacles.



Sec.  178.33a-1  Compliance.

    (a) Required in all details.
    (b) [Reserved]

[Order 71, 31 FR 9074, July 1, 1966. Redesignated at 32 FR 5606, Apr. 5, 
1967]



Sec.  178.33a-2  Type and size.

    (a) Single-trip inside containers. Must be seamless, or with seams 
welded, soldered, brazed, double seamed, or swedged.
    (b) The maximum capacity of containers in this class shall not 
exceed 1 L (61.0 cubic inches). The maximum inside diameter shall not 
exceed 3 inches.

[Order 71, 31 FR 9074, July 1, 1966. Redesignated at 32 FR 5606, Apr. 5, 
1967, and amended by Amdt. 178-43, 42 FR 42208, Aug. 22, 1977; Amdt. 
178-101, 58 FR 50237, Sept. 24, 1993; 66 FR 45387, Aug. 28, 2001]



Sec.  178.33a-3  Inspection.

    (a) By competent inspector.
    (b) [Reserved]

[Order 71, 31 FR 9074, July 1, 1966. Redesignated at 32 FR 5606, Apr. 5, 
1967]



Sec.  178.33a-4  Duties of inspector.

    (a) To inspect material and completed containers and witness tests, 
and to reject defective materials or containers.
    (b) [Reserved]

[Order 71, 31 FR 9074, July 1, 1966. Redesignated at 32 FR 5606, Apr. 5, 
1967]



Sec.  178.33a-5  Material.

    (a) Uniform quality steel plate such as black plate, electrotin 
plate, hot dipped tinplate, ternplate or other commercially accepted can 
making plate; or nonferrous metal of uniform drawing quality.
    (b) Material with seams, cracks, laminations or other injurious 
defects not authorized.

[Order 71, 31 FR 9074, July 1, 1966. Redesignated at 32 FR 5606, Apr. 5, 
1967]



Sec.  178.33a-6  Manufacture.

    (a) By appliances and methods that will assure uniformity of 
completed

[[Page 14]]

containers; dirt and scale to be removed as necessary; no defect 
acceptable that is likely to weaken the finished container appreciably; 
reasonably smooth and uniform surface finish required.
    (b) Seams when used must be as follows:
    (1) Circumferential seams. By welding, swedging, brazing, soldering, 
or double seaming.
    (2) Side seams. By welding, brazing or soldering.
    (c) Ends. The ends shall be of pressure design.

[Order 71, 31 FR 9074, July 1, 1966. Redesignated at 32 FR 5606, Apr. 5, 
1967]



Sec.  178.33a-7  Wall thickness.

    (a) The minimum wall thickness for any container shall be 0.008 
inch.
    (b) [Reserved]

[Order 71, 31 FR 9074, July 1, 1966. Redesignated at 32 FR 5606, Apr. 5, 
1967]



Sec.  178.33a-8  Tests.

    (a) One out of each lot of 25,000 containers or less, successively 
produced per day, shall be pressure tested to destruction and must not 
burst below 270 psig gauge pressure. The container tested shall be 
complete with end assembled.
    (b) Each such 25,000 containers or less, successively produced per 
day, shall constitute a lot and if the test container shall fail, the 
lot shall be rejected or ten additional containers may be selected at 
random and subjected to the test under which failure occurred. These 
containers shall be complete with ends assembled. Should any of the ten 
containers thus tested fail, the entire lot must be rejected. All 
containers constituting a lot shall be of like material, size, design, 
construction, finish and quality.

[Order 71, 31 FR 9074, July 1, 1966. Redesignated at 32 FR 5606, Apr. 5, 
1967, as amended by 66 FR 45387, Aug. 28, 2001]



Sec.  178.33a-9  Marking.

    (a) By means of printing, lithographing, embossing, or stamping, 
each container must be marked to show:
    (1) DOT-2Q.
    (2) Name or symbol of person making the mark specified in paragraph 
(a)(1) of this section. Symbol, if used, must be registered with the 
Associate Administrator.
    (b) [Reserved]

[Amdt. 178-40, 41 FR 38181, Sept. 9, 1976, as amended by Amdt. 178-97, 
56 FR 66287, Dec. 20, 1991; 66 FR 45386, Aug. 28, 2001]



Sec.  178.33b  Specification 2S; inner nonrefillable plastic receptacles.



Sec.  178.33b-1  Compliance.

    (a) Required in all details.
    (b) [Reserved]

[74 FR 2268, Jan. 14, 2009]



Sec.  178.33b-2  Type and size.

    (a) Single-trip inside containers.
    (b) The maximum capacity of containers in this class shall not 
exceed one liter (61.0 cubic inches). The maximum inside diameter shall 
not exceed 3 inches.

[74 FR 2268, Jan. 14, 2009]



Sec.  178.33b-3  Inspection.

    (a) By competent inspector.
    (b) [Reserved]

[74 FR 2268, Jan. 14, 2009]



Sec.  178.33b-4  Duties of inspector.

    (a) To inspect material and completed containers and witness tests, 
and to reject defective materials or containers.
    (b) [Reserved]

[74 FR 2268, Jan. 14, 2009]



Sec.  178.33b-5  Material.

    (a) The receptacles must be constructed of polyethylene 
terephthalate (PET), polyethylene napthalate (PEN), polyamide (Nylon) or 
a blend of PET, PEN, ethyl vinyl alcohol (EVOH) and/or Nylon.
    (b) Material with seams, cracks, laminations or other injurious 
defects are forbidden.

[74 FR 2268, Jan. 14, 2009]



Sec.  178.33b-6  Manufacture.

    (a) Each container must be manufactured by thermoplastic processes 
that will assure uniformity of the completed container. No used material

[[Page 15]]

other than production residues or regrind from the same manufacturing 
process may be used. The packaging must be adequately resistant to aging 
and to degradation caused either by the substance contained or by 
ultraviolet radiation.
    (b) [Reserved]

[74 FR 2268, Jan. 14, 2009]



Sec.  178.33b-7  Design qualification test.

    (a) Drop testing. (1) To ensure that creep does not affect the 
ability of the container to retain the contents, each new design must be 
drop tested as follows: Three groups of twenty-five filled containers 
must be dropped from 1.8 m (5.9 ft) on to a rigid, non-resilient, flat 
and horizontal surface. One group must be conditioned at 38 [deg]C (100 
[deg]F) for 26 weeks, the second group for 100 hours at 50 [deg]C (122 
[deg]F) and the third group for 18 hours at 55 [deg]C (131 [deg]F), 
prior to performing the drop test. The closure, or sealing component of 
the container, must not be protected during the test. The orientation of 
the test container at drop must be statistically random, but direct 
impact on the valve or valve closure must be avoided.
    (2) Criteria for passing the drop test: The containers must not 
break or leak.
    (b) Design qualification testing must be completed if the design is 
manufactured with a new mold or if there is any change in the properties 
of the material of construction.

[75 FR 73, Jan. 4, 2010]



Sec.  178.33b-8  Production tests.

    (a) Burst Testing. (1) One out of each lot of 5,000 containers or 
less, successively produced per day must be pressure tested to 
destruction and must not burst below 240 psig. The container tested must 
be complete as intended for transportation.
    (2) Each such 5,000 containers or less, successively produced per 
day, shall constitute a lot and if the test container shall fail, the 
lot shall be rejected or ten additional containers may be selected at 
random and subjected to the test under which failure occurred. These 
containers shall be complete as intended for transportation. Should any 
of the ten containers thus tested fail, the entire lot must be rejected. 
All containers constituting a lot shall be of like material, size, 
design construction, finish, and quality.
    (b) [Reserved]

[74 FR 2268, Jan. 14, 2009, as amended at 75 FR 74, Jan. 4, 2010]



Sec.  178.33b-9  Marking.

    (a) Each container must be clearly and permanently marked to show:
    (1) DOT-2S.
    (2) Name or symbol of person making the mark specified in paragraph 
(a)(1) of this section. Symbol, if used, must be registered with the 
Associate Administrator.
    (b) [Reserved]

[74 FR 2268, Jan. 14, 2009]



Sec.  178.33c  Specification 2P; inner nonrefillable metal receptacle   
variation.



Sec.  178.33c-1  Compliance.

    Required in all details.

[81 FR 3685, Jan. 21, 2016]



Sec.  178.33c-2  Variation.

    Notwithstanding the variation provided in this section, each 
container must otherwise conform to a DOT 2P container in accordance 
with Sec.  178.33. The following conditions also apply under Variation 
1--
    (a) Manufacture. Side seams: not permitted. Ends: The ends shall be 
designed to withstand pressure and be equipped with a pressure relief 
system (e.g., rim-venting release or a dome expansion device) designed 
to function prior to bursting of the container.
    (b) Tests. (1) One out of each lot of 25,000 containers or less, 
successively produced per day complete with ends assembled (and without 
a pressure relief system assembled) shall be pressure tested to 
destruction at gauge pressure and must not burst below 240 psig. For 
containers with a pressure relief system as described in paragraph (a) 
of this section and assembled, failure at a location other than the 
pressure relief system will reject the lot. For containers with an end 
expansion device, the lot must be rejected if the container bursts prior 
to buckling of the device.

[[Page 16]]

    (2) Each such 25,000 containers or less, successively produced per 
day, shall constitute a lot and if the test container(s) shall fail, the 
lot shall be rejected. Otherwise, ten (10) additional containers of each 
container design produced may be selected at random and subjected to the 
test. These containers shall be complete with ends assembled. Should any 
of the containers thus tested fail, the entire lot must be rejected. All 
containers constituting a lot shall be of like material, size, design 
construction, finish, and quality.
    (c) Marking. By means of printing, lithographing, embossing, or 
stamping, each container must be marked:
    (1) DOT-2P1.
    (2) With the name or symbol of the person making the mark. A symbol, 
if used, must be registered with the Associate Administrator.

[81 FR 3685, Jan. 21, 2016]



Sec.  178.33d  Specification 2Q; inner nonrefillable metal receptacle    
variations.



Sec.  178.33d-1  Compliance.

    Required in all details.

[81 FR 3685, Jan. 21, 2016]



Sec.  178.33d-2  Variation 1.

    Notwithstanding the variation provided in this paragraph, each 
container must otherwise conform to a DOT 2Q container in accordance 
with Sec.  178.33a. The following conditions also apply under Variation 
1--
    (a) Type and size. The maximum capacity of containers in this class 
may not exceed 0.40 L (24.4 cubic inches). The maximum inside diameter 
shall not exceed 2.1 inches.
    (b) Manufacture. Ends: The top of the container must be designed 
with a pressure relief system consisting of radial scores on the top 
seam(s). The bottom of the container must be designed to buckle at a 
pressure greater than the pressure at which the top buckles and vents.
    (c) Wall thickness. The minimum wall thickness for any container 
shall be 0.0085 inches.
    (d) Tests. (1) Two containers (one without a pressure relief system 
and one with) out of each lot of 25,000 or less, successively produced 
per day shall be pressure tested to destruction at gauge pressure. The 
container without a pressure relief system must not burst below 320 
psig. The container assembled with a pressure relief system as described 
in paragraph (b) of this section must be tested to destruction. The 
bottom of the container must buckle at a pressure greater than the 
pressure at which the top buckles and vents.
    (2) Each such 25,000 containers or less, successively produced per 
day, shall constitute a lot and if the test container(s) shall fail, the 
lot shall be rejected. Otherwise, ten (10) additional pairs of 
containers may be selected at random and subjected to the test under 
which failure occurred. Should any of the containers thus tested fail, 
the entire lot must be rejected. All containers constituting a lot shall 
be of like material, size, design construction, finish, and quality.
    (e) Marking. By means of printing, lithographing, embossing, or 
stamping, each container must be marked:
    (1) DOT-2Q1.
    (2) With the name or symbol of the person making the mark. A symbol, 
if used, must be registered with the Associate Administrator.

[81 FR 3685, Jan. 21, 2016]



Sec.  178.33d-3  Variation 2.

    Notwithstanding the variation provided in this paragraph, each 
container must otherwise conform to a DOT 2Q container in accordance 
with Sec.  178.33a. The following conditions also apply under Variation 
2--
    (a) Manufacture. Ends: The ends shall be designed to withstand 
pressure and the container equipped with a pressure relief system (e.g., 
rim-venting release or a dome expansion device) designed to buckle prior 
to the burst of the container.
    (b) Tests. (1) One out of each lot of 25,000 containers or less, 
successively produced per day shall be pressure tested to destruction at 
gauge pressure and must not burst below 270 psig. For containers with a 
pressure relief system as described in paragraph (a) of this section and 
assembled, failure at a location other than the pressure relief system 
will reject the lot.

[[Page 17]]

    (2) Each such 25,000 containers or less, successively produced per 
day, shall constitute a lot and if the test container(s) shall fail, the 
lot shall be rejected. Otherwise, ten (10) additional containers of each 
container design produced may be selected at random and subjected to the 
test. These containers shall be complete with ends assembled. Should any 
of the containers thus tested fail, the entire lot must be rejected. All 
containers constituting a lot shall be of like material, size, design 
construction, finish, and quality.
    (c) Marking. By means of printing, lithographing, embossing, or 
stamping, each container must be marked:
    (1) DOT-2Q2.
    (2) With the name or symbol of the person making the mark. A symbol, 
if used, must be registered with the Associate Administrator.

[81 FR 3685, Jan. 21, 2016]



                 Subpart C_Specifications for Cylinders



Sec.  178.35  General requirements for specification cylinders.

    (a) Compliance. Compliance with the requirements of this subpart is 
required in all details.
    (b) Inspections and analyses. Chemical analyses and tests required 
by this subchapter must be made within the United States, unless 
otherwise approved in writing by the Associate Administrator, in 
accordance with subpart I of part 107 of this chapter. Inspections and 
verification must be performed by--
    (1) An independent inspection agency approved in writing by the 
Associate Administrator, in accordance with subpart I of part 107 of 
this chapter; or
    (2) For DOT Specifications 3B, 3BN, 3E, 4B, 4BA, 4B240ET, 4AA480, 
4L, 8, 8AL, 4BW, 4E, 4D (with a water capacity less than 1,100 cubic 
inches) and Specification 39 (with a marked service pressure 900 psig or 
lower), and manufactured within the United States, a competent inspector 
of the manufacturer.
    (c) Duties of inspector. The inspector shall determine that each 
cylinder made is in conformance with the applicable specification. 
Inspections shall conform to CGA C-11 (IBR, see Sec.  171.7 of this 
subchapter) except as otherwise specified in the applicable 
specification.
    (1) Seamless cylinders. Seamless cylinders shall be inspected in 
accordance with Section 5 of CGA C-11. For cylinders made by the billet-
piercing process, billets must be inspected and shown to be free from 
piping (laminations), cracks, excessive segregation and other injurious 
defects after parting or, when applicable, after nick and cold break.
    (2) Welded cylinders. Welded cylinders shall be inspected in 
accordance with Section 6 of CGA C-11. Note: The recommended locations 
for test specimens are depicted in Figures 1 through 5 in appendix A to 
subpart C of part 178.
    (3) Non-refillable cylinders. Non-refillable cylinders shall be 
inspected in accordance with Section 7 of CGA C-11
    (4) Inspector's report. The inspector shall prepare a report 
containing, at a minimum, the applicable information listed in CGA C-11. 
Any additional information or markings that are required by the 
applicable specification must be shown on the test report. The signature 
of the inspector on the reports certifies that the processes of 
manufacture and heat treatment of cylinders were observed and found 
satisfactory. The inspector must furnish the completed test reports 
required by this subpart to the maker of the cylinder and, upon request, 
to the purchaser. The test report must be retained by the inspector for 
15 years from the original test date of the cylinder.
    (d) Defects and attachments. Cylinders must conform to the 
following:
    (1) A cylinder may not be constructed of material with seams, cracks 
or laminations, or other injurious defects.
    (2) Metal attachments to cylinders must have rounded or chamfered 
corners or must be protected in such a manner as to prevent the 
likelihood of causing puncture or damage to other hazardous materials 
packages. This requirement applies to anything temporarily or 
permanently attached to the cylinder, such as metal skids.
    (e) Safety devices. Pressure relief devices and protection for 
valves, safety

[[Page 18]]

devices, and other connections, if applied, must be as required or 
authorized by the appropriate specification, and as required in Sec.  
173.301 of this subchapter.
    (f) Markings. Markings on a DOT Specification cylinder must conform 
to applicable requirements.
    (1) Each cylinder must be marked with the following information:
    (i) The DOT specification marking must appear first, followed 
immediately by the service pressure. For example, DOT-3A1800.
    (ii) The serial number must be placed just below or immediately 
following the DOT specification marking.
    (iii) A symbol (letters) must be placed just below, immediately 
before or following the serial number. Other variations in sequence of 
markings are authorized only when necessitated by a lack of space. The 
symbol and numbers must be those of the manufacturer. The symbol must be 
registered with the Associate Administrator; duplications are not 
authorized.
    (iv) The inspector's official mark and date of test (such as 5-95 
for May 1995) must be placed near the serial number. This information 
must be placed so that dates of subsequent tests can be easily added. An 
example of the markings prescribed in this paragraph (f)(1) is as 
follows:

DOT-3A1800
1234
XY
AB 5-95

    Or;

DOT-3A1800-1234-XY
AB 5-95

Where:

DOT-3A = specification number
1800 = service pressure
1234 = serial number
XY = symbol of manufacturer
AB = inspector's mark
5-95 = date of test

    (2) Additional required marking must be applied to the cylinder as 
follows:
    (i) The word ``spun'' or ``plug'' must be placed near the DOT 
specification marking when an end closure in the finished cylinder has 
been welded by the spinning process, or effected by plugging.
    (ii) As prescribed in specification 3HT (Sec.  178.44) or 3T (Sec.  
178.45), if applicable.
    (3) Marking exceptions. A DOT 3E cylinder is not required to be 
marked with an inspector's mark or a serial number.
    (4) Unless otherwise specified in the applicable specification, the 
markings on each cylinder must be stamped plainly and permanently on the 
shoulder, top head, or neck.
    (5) The size of each marking must be at least 0.25 inch or as space 
permits.
    (6) Other markings are authorized provided they are made in low 
stress areas other than the side wall and are not of a size and depth 
that will create harmful stress concentrations. Such marks may not 
conflict with any DOT required markings.
    (7) Marking exceptions. A DOT 8 or 8AL cylinder is not required to 
be marked with the service pressure.
    (8) Tare weight or mass weight, and water capacity marking. DOT-
specification 4B, 4BA, 4BW, and 4E cylinders used in liquefied 
compressed gas service manufactured after December 28, 2022, must be 
marked with the tare weight or mass weight. Additionally, the cylinder 
must be permanently marked with the water capacity. The owner of the 
cylinder must ensure it is marked with the following information, as 
applicable:
    (i) Tare weight. The tare weight for a cylinder 25 pounds or less at 
the time of manufacture, with a lower tolerance of 3 percent and an 
upper tolerance of 1 percent; or for a cylinder exceeding 25 pounds at 
the time of manufacture, with a lower tolerance of 2 percent and an 
upper tolerance of 1 percent. The tare weight marking must be the actual 
weight of the fully assembled cylinder, including the valve(s) and other 
permanently affixed appurtenances. Removable protective cap(s) or 
cover(s) must not be included in the cylinder tare weight. Tare weight 
shall be abbreviated ``TW''; or
    (ii) Mass weight. The mass weight for a cylinder 25 pounds or less 
at the time of manufacture, with a lower tolerance of 3 percent and an 
upper tolerance of 1 percent; or the mass weight marking for a cylinder 
exceeding 25 pounds at the time of manufacture, with a lower tolerance 
of 2 percent and an upper tolerance of 1 percent. The mass weight 
marking must be the actual weight of the fully assembled cylinder, 
excluding

[[Page 19]]

valve(s) and removable protective cap(s) or cover(s). Mass weight shall 
be abbreviated ``MW''; and
    (iii) Water capacity. The water capacity for a cylinder 25 pounds 
water capacity or less, with a tolerance of minus 1 percent and no upper 
tolerance; or for a cylinder exceeding 25 pounds water capacity, with a 
tolerance of minus 0.5 percent and no upper tolerance. The marked water 
capacity of the cylinder must be the capacity of the cylinder at the 
time of manufacture. Water capacity shall be abbreviated ``WC''.
    (g) Manufacturer's reports. At or before the time of delivery to the 
purchaser, the cylinder manufacturer must have all completed 
certification documents listed in CGA C-11. The manufacturer of the 
cylinders must retain the reports required by this subpart for 15 years 
from the original test date of the cylinder.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended at 66 FR 45185, 
Aug. 28, 2001; 67 FR 51652, Aug. 8, 2002; 68 FR 75748, Dec. 31, 2003; 76 
FR 43531, July 20, 2011; 83 FR 55810, Nov. 7, 2018; 85 FR 75716, Nov. 
25, 2020; 85 FR 85419, Dec. 28, 2020]



Sec.  178.36  Specification 3A and 3AX seamless steel cylinders.

    (a) Type size and service pressure. In addition to the requirements 
of Sec.  178.35, cylinders must conform to the following:
    (1) A DOT-3A cylinder is a seamless steel cylinder with a water 
capacity (nominal) not over 1,000 pounds and a service pressure of at 
least 150 psig.
    (2) A DOT-3AX is a seamless steel cylinder with a water capacity not 
less than 1,000 pounds and a service pressure of at least 500 psig, 
conforming to the following requirements:
    (i) Assuming the cylinder is to be supported horizontally at its two 
ends only and to be uniformly loaded over its entire length consisting 
of the weight per unit of length of the straight cylindrical portion 
filled with water and compressed to the specified test pressure; the sum 
of two times the maximum tensile stress in the bottom fibers due to 
bending, plus that in the same fibers (longitudinal stress), due to 
hydrostatic test may not exceed 80 percent of the minimum yield strength 
of the steel at such maximum stress. Wall thickness must be increased 
when necessary to meet the requirement.
    (ii) To calculate the maximum longitudinal tensile stress due to 
bending, the following formula must be used:

S = Mc/I

    (iii) To calculate the maximum longitudinal tensile stress due to 
hydrostatic test pressure, the following formula must be used:

S = A1 P/A2

where:

S = tensile stress--p.s.i.;
M = bending moment-inch pounds--(wl\2\)/8;
w = weight per inch of cylinder filled with water;
l = length of cylinder-inches;
c = radius (D)/(2) of cylinder-inches;
I = moment of inertia--0.04909 (D\4\-d\4\) inches fourth;
D = outside diameter-inches;
d = inside diameter-inches;
A1 = internal area in cross section of cylinder-square 
          inches;
A2 = area of metal in cross section of cylinder-square 
          inches;
P = hydrostatic test pressure-psig.

    (b) Steel. Open-hearth or electric steel of uniform quality must be 
used. Content percent may not exceed the following: Carbon, 0.55; 
phosphorous, 0.045; sulphur, 0.050.
    (c) Identification of material. Material must be identified by any 
suitable method, except that plates and billets for hot-drawn cylinders 
must be marked with the heat number.
    (d) Manufacture. Cylinders must be manufactured using equipment and 
processes adequate to ensure that each cylinder produced conforms to the 
requirements of this subpart. No fissure or other defect is permitted 
that is likely to weaken the finished cylinder appreciably. A reasonably 
smooth and uniform surface finish is required. If not originally free 
from such defects, the surface may be machined or otherwise treated to 
eliminate these defects. The thickness of the bottoms of cylinders 
welded or formed by spinning is, under no condition, to be less than two 
times the minimum wall thickness of the cylindrical shell; such bottom 
thicknesses must be measured within an area bounded by a line 
representing

[[Page 20]]

the points of contact between the cylinder and floor when the cylinder 
is in a vertical position.
    (e) Welding or brazing. Welding or brazing for any purpose 
whatsoever is prohibited except as follows:
    (1) Welding or brazing is authorized for the attachment of neckrings 
and footrings which are non-pressure parts and only to the tops and 
bottoms of cylinders having a service pressure of 500 psig or less. 
Cylinders, neckrings, and footrings must be made of weldable steel, the 
carbon content of which may not exceed 0.25 percent except in the case 
of 4130X steel which may be used with proper welding procedures.
    (2) As permitted in paragraph (d) of this section.
    (3) Cylinders used solely in anhydrous ammonia service may have a 
\1/2\ inch diameter bar welded within their concave bottoms.
    (f) Wall thickness. For cylinders with service pressure less than 
900 psig, the wall stress may not exceed 24,000 psig. A minimum wall 
thickness of 0.100 inch is required for any cylinder over 5 inches 
outside diameter. Wall stress calculation must be made by using the 
following formula:

S = [P(1.3D\2\ + 0.4d\2\)]/(D\2\-d\2\)

Where:

S = wall stress in psi;
P = minimum test pressure prescribed for water jacket test or 450 psig 
          whichever is the greater;
D = outside diameter in inches;
d = inside diameter in inches.

    (g) Heat treatment. The completed cylinder must be uniformly and 
properly heat-treated prior to tests.
    (h) Openings in cylinders and connections (valves, fuse plugs, etc.) 
for those openings. Threads are required on openings.
    (1) Threads must be clean cut, even, without checks, and to gauge.
    (2) Taper threads, when used, must be of length not less than as 
specified for American Standard taper pipe threads.
    (3) Straight threads having at least 6 engaged threads are 
authorized. Straight threads must have a tight fit and calculated shear 
strength of at least 10 times the test pressure of the cylinder. 
Gaskets, adequate to prevent leakage, are required.
    (i) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:
    (1) The test must be by water-jacket or direct expansion method as 
prescribed in CGA C-1 (IBR; see Sec.  171.7 of this subchapter). The 
testing equipment must be calibrated as prescribed in CGA C-1. All 
testing equipment and pressure indicating devices must be accurate 
within the parameters defined in CGA C-1.
    (2) Each cylinder must be tested to a minimum of \5/3\ times service 
pressure.
    (3) The minimum test pressure must be maintained for at least 30 
seconds and sufficiently longer to ensure complete expansion. Any 
internal pressure applied after heat-treatment and previous to the 
official test may not exceed 90 percent of the test pressure. If, due to 
failure of the test apparatus or operator error, the test pressure 
cannot be maintained, the test may be repeated in accordance with CGA C-
1, section 5.7.2.
    (4) Permanent, volumetric expansion may not exceed 10 percent of the 
total volumetric expansion at test pressure.
    (j) Flattening test. A flattening test must be performed on one 
cylinder taken at random out of each lot of 200 or less, by placing the 
cylinder between wedge shaped knife edges having a 60[deg] included 
angle, rounded to \1/2\-inch radius. The longitudinal axis of the 
cylinder must be at a 90-degree angle to knife edges during the test. 
For lots of 30 or less, flattening tests are authorized to be made on a 
ring at least 8 inches long cut from each cylinder and subjected to same 
heat treatment as the finished cylinder.
    (k) Physical test. A physical test must be conducted to determine 
yield strength, tensile strength, elongation, and reduction of area of 
material as follows:
    (1) The test is required on 2 specimens cut from 1 cylinder taken at 
random out of each lot of 200 or less. For lots of 30 or less, physical 
tests are authorized to be made on a ring at least 8 inches long cut 
from each cylinder and subjected to same heat treatment as the finished 
cylinder.
    (2) Specimens must conform to the following:

[[Page 21]]

    (i) Gauge length of 8 inches with a width of not over 1\1/2\ inches, 
a gauge length of 2 inches with a width of not over 1\1/2\ inches, or a 
gauge length of at least 24 times thickness with width not over 6 times 
thickness is authorized when cylinder wall is not over \3/16\ inch 
thick.
    (ii) The specimen, exclusive of grip ends, may not be flattened. 
Grip ends may be flattened to within 1 inch of each end of the reduced 
section.
    (iii) When size of cylinder does not permit securing straight 
specimens, the specimens may be taken in any location or direction and 
may be straightened or flattened cold, by pressure only, not by blows. 
When specimens are so taken and prepared, the inspector's report must 
show in connection with record of physical tests detailed information in 
regard to such specimens.
    (iv) Heating of a specimen for any purpose is not authorized.
    (3) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gauge length. The following 
conditions apply:
    (i) The yield strength must be determined by either the ``offset'' 
method or the ``extension under load'' method as prescribed in ASTM E 8 
(IBR, see Sec.  171.7 of this subchapter).
    (ii) In using the ``extension under load'' method, the total strain 
(or ``extension under load'') corresponding to the stress at which the 
0.2-percent permanent strain occurs may be determined with sufficient 
accuracy by calculating the elastic extension of the gauge length under 
appropriate load and adding thereto 0.2 percent of the gauge length. 
Elastic extension calculations must be based on an elastic modulus of 
30,000,000. In the event of controversy the entire stress-strain diagram 
must be plotted and the yield strength determined from the 0.2 percent 
offset.
    (iii) For the purpose of strain measurement, the initial strain must 
be set while the specimen is under a stress of 12,000 psig and the 
strain indicator reading must be set at the calculated corresponding 
strain.
    (iv) Cross-head speed of the testing machine may not exceed \1/8\ 
inch per minute during yield strength determination.
    (l) Acceptable results for physical and flattening tests. Either of 
the following is an acceptable result:
    (1) An elongation at least 40 percent for a 2-inch gauge length or 
at least 20 percent in other cases and yield strength not over 73 
percent of tensile strength. In this instance, the flattening test is 
not required.
    (2) An elongation at least 20 percent for a 2-inch gauge length or 
10 percent in other cases and a yield strength not over 73 percent of 
tensile strength. In this instance, the flattening test is required, 
without cracking, to 6 times the wall thickness.
    (m) Leakage test. All spun cylinders and plugged cylinders must be 
tested for leakage by gas or air pressure after the bottom has been 
cleaned and is free from all moisture subject to the following 
conditions and limitations:
    (1) Pressure, approximately the same as but no less than service 
pressure, must be applied to one side of the finished bottom over an 
area of at least \1/16\ of the total area of the bottom but not less 
than \3/4\ inch in diameter, including the closure, for at least 1 
minute, during which time the other side of the bottom exposed to 
pressure must be covered with water and closely examined for indications 
of leakage. Except as provided in paragraph (n) of this section, a 
cylinder that is leaking must be rejected.
    (2) A spun cylinder is one in which an end closure in the finished 
cylinder has been welded by the spinning process.
    (3) A plugged cylinder is one in which a permanent closure in the 
bottom of a finished cylinder has been effected by a plug.
    (4) As a safety precaution, if the manufacturer elects to make this 
test before the hydrostatic test, the manufacturer should design the 
test apparatus so that the pressure is applied to the smallest area 
practicable, around the point of closure, and so as to use the smallest 
possible volume of air or gas.
    (n) Rejected cylinders. Reheat treatment is authorized for rejected 
cylinders. Subsequent thereto, cylinders must pass all prescribed tests 
to be acceptable. Repair by welding or spinning

[[Page 22]]

is not authorized. Spun cylinders rejected under the provisions of 
paragraph (m) of this section may be removed from the spun cylinder 
category by drilling to remove defective material, tapping and plugging.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended at 62 FR 51561, 
Oct. 1, 1997; 66 FR 45185, 45386, Aug. 28, 2001; 67 FR 51652, Aug. 8, 
2002; 68 FR 75748, Dec. 31, 2003; 73 FR 57006, Oct. 1, 2008; 85 FR 
85420, Dec. 28, 2020]



Sec.  178.37  Specification 3AA and 3AAX seamless steel cylinders.

    (a) Type, size and service pressure. In addition to the requirements 
of Sec.  178.35, cylinders must conform to the following:
    (1) A DOT-3AA cylinder is a seamless steel cylinder with a water 
capacity (nominal) of not over 1,000 pounds and a service pressure of at 
least 150 psig.
    (2) A DOT-3AAX cylinder is a seamless steel cylinder with a water 
capacity of not less than 1,000 pounds and a service pressure of at 
least 500 psig, conforming to the following requirements:
    (i) Assuming the cylinder is to be supported horizontally at its two 
ends only and to be uniformly loaded over its entire length consisting 
of the weight per unit of length of the straight cylindrical portion 
filled with water and compressed to the specified test pressure; the sum 
of two times the maximum tensile stress in the bottom fibers due to 
bending, plus that in the same fibers (longitudinal stress), due to 
hydrostatic test pressure may not exceed 80 percent of the minimum yield 
strength of the steel at such maximum stress. Wall thickness must be 
increased when necessary to meet the requirement.
    (ii) To calculate the maximum tensile stress due to bending, the 
following formula must be used:

S = Mc/I

    (iii) To calculate the maximum longitudinal tensile stress due to 
hydrostatic test pressure, the following formula must be used:

S = A\1\P/A\2\

Where:

S = tensile stress-p.s.i.;
M = bending moment-inch pounds (wl\2\)/8;
w = weight per inch of cylinder filled with water;
l = length of cylinder-inches;
c = radius (D)/(2) of cylinder-inches;
I = moment of inertia-0.04909 (D\4\-d\4\) inches fourth;
D = outside diameter-inches;
d = inside diameter-inches;
A\1\ = internal area in cross section of cylinder-square inches;
A\2\ = area of metal in cross section of cylinder-square inches;
P = hydrostatic test pressure-psig.

    (b) Authorized steel. Open-hearth, basic oxygen, or electric steel 
of uniform quality must be used. A heat of steel made under the 
specifications in table 1 of this paragraph (b), check chemical analysis 
of which is slightly out of the specified range, is acceptable, if 
satisfactory in all other respects, provided the tolerances shown in 
table 2 of this paragraph (b) are not exceeded. When a carbon-boron 
steel is used, a hardenability test must be performed on the first and 
last ingot of each heat of steel. The results of this test must be 
recorded on the Record of Chemical Analysis of Material for Cylinders 
required by Sec.  178.35. This hardness test must be made \5/16\-inch 
from the quenched end of the Jominy quench bar and the hardness must be 
at least Rc 33 and no more than Rc 53. The following chemical analyses 
are authorized:

                                                              Table 1--Authorized Materials
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                        Inter- mediate
           Designation              4130X (percent)    NE-8630 (percent)    9115 (percent)      9125 (percent)       Carbon-boron          manganese
                                     (see Note 1)        (see Note 1)        (see Note 1)        (see Note 1)          (percent)           (percent)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Carbon..........................  0.25/0.35.........  0.28/0.33.........  0.10/0.20.........  0.20/0.30.........  0.27-0.37.........  0.40 max.
Manganese.......................  0.40/0.90.........  0.70/0.90.........  0.50/0.75.........  0.50/0.75.........  0.80-1.40.........  1.35/1.65.
Phosphorus......................  0.04 max..........  0.04 max..........  0.04 max..........  0.04 max..........  0.035 max.........  0.04 max.
Sulfur..........................  0.05 max..........  0.04 max..........  0.04 max..........  0.04 max..........  0.045 max.........  0.05 max.
Silicon.........................  0.15/0.35.........  0.20/0.35.........  0.60/0.90.........  0.60/0.90.........  0.3 max...........  0.10/0.30.
Chromium........................  0.80/1.10.........  0.40/0.60.........  0.50/0.65.........  0.50/0.65.
Molybdenum......................  0.15/0.25.........  0.15/0.25
Zirconium.......................  ..................  ..................  0.05/0.15.........  0.05/0.15

[[Page 23]]

 
Nickel..........................  ..................  0.40/0.70.........
Boron...........................  ..................  ..................  ..................  ..................  0.0005/0.003.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note 1: This designation may not be restrictive and the commercial steel is limited in analysis as shown in this table.


                                       Table 2--Check Analysis Tolerances
----------------------------------------------------------------------------------------------------------------
                                                                                        Tolerance (percent) over
                                                                                          the maximum limit or
                                                                                         under the minimum limit
                    Element                      Limit or maximum specified (percent)  -------------------------
                                                                                           Under         Over
                                                                                          minimum      maximum
                                                                                           limit        limit
----------------------------------------------------------------------------------------------------------------
Carbon........................................  To 0.15 incl..........................         0.02         0.03
                                                Over 0.15 to 0.40 incl................          .03          .04
Manganese.....................................  To 0.60 incl..........................          .03          .03
                                                Over 0.60 to 1.15 incl................         0.04         0.04
                                                Over 1.15 to 2.50 incl................         0.05         0.05
Phosphorus\1\.................................  All ranges............................  ...........          .01
Sulphur.......................................  All ranges............................  ...........          .01
Silicon.......................................  To 0.30 incl..........................          .02          .03
                                                Over 0.30 to 1.00 incl................          .05          .05
Nickel........................................  To 1.00 incl..........................          .03          .03
Chromium......................................  To 0.90 incl..........................          .03          .03
                                                0.90 to 2.90 incl.....................          .05          .05
Molybdenum....................................  To 0.20 incl..........................          .01          .01
                                                Over 0.20 to 0.40.....................          .02          .02
Zirconium.....................................  All ranges............................          .01          .05
----------------------------------------------------------------------------------------------------------------
\1\ Rephosphorized steels not subject to check analysis for phosphorus.

    (c) Identification of material. Material must be identified by any 
suitable method except that plates and billets for hot-drawn cylinders 
must be marked with the heat number.
    (d) Manufacture. Cylinders must be manufactured using equipment and 
processes adequate to ensure that each cylinder produced conforms to the 
requirements of this subpart. No fissure or other defects is permitted 
that is likely to weaken the finished cylinder appreciably. A reasonably 
smooth and uniform surface finish is required. If not originally free 
from such defects, the surface may be machined or otherwise treated to 
eliminate these defects. The thickness of the bottoms of cylinders 
welded or formed by spinning is, under no condition, to be less than two 
times the minimum wall thickness of the cylindrical shell; such bottom 
thicknesses must be measured within an area bounded by a line 
representing the points of contact between the cylinder and floor when 
the cylinder is in a vertical position.
    (e) Welding or brazing. Welding or brazing for any purpose 
whatsoever is prohibited except as follows:
    (1) Welding or brazing is authorized for the attachment of neckrings 
and footrings which are non-pressure parts, and only to the tops and 
bottoms of cylinders having a service pressure of 500 psig or less. 
Cylinders, neckrings, and footrings must be made of weldable steel, the 
carbon content of which may not exceed 0.25 percent except in the case 
of 4130X steel which may be used with proper welding procedure.
    (2) As permitted in paragraph (d) of this section.
    (f) Wall thickness. The thickness of each cylinder must conform to 
the following:
    (1) For cylinders with a service pressure of less than 900 psig, the 
wall stress may not exceed 24,000 psi. A minimum wall thickness of 0.100 
inch is required for any cylinder with an outside diameter of over 5 
inches.
    (2) For cylinders with service pressure of 900 psig or more the 
minimum wall must be such that the wall stress at the minimum specified 
test pressure

[[Page 24]]

may not exceed 67 percent of the minimum tensile strength of the steel 
as determined from the physical tests required in paragraphs (k) and (l) 
of this section and must be not over 70,000 psi.
    (3) Calculation must be made by the formula:

S = [P(1.3D\2\ + 0.4d\2\)]/(D\2\-d\2\)

Where:

S = wall stress in psi;
P = minimum test pressure prescribed for water jacket test or 450 psig 
          whichever is the greater;
D = outside diameter in inches;
d = inside diameter in inches.

    (g) Heat treatment. The completed cylinders must be uniformly and 
properly heat treated prior to tests. Heat treatment of cylinders of the 
authorized analyses must be as follows:
    (1) All cylinders must be quenched by oil, or other suitable medium 
except as provided in paragraph (g)(5) of this section.
    (2) The steel temperature on quenching must be that recommended for 
the steel analysis, but may not exceed 1750 [deg]F.
    (3) All steels must be tempered at a temperature most suitable for 
that steel.
    (4) The minimum tempering temperature may not be less than 1000 
[deg]F except as noted in paragraph (g)(6) of this section.
    (5) Steel 4130X may be normalized at a temperature of 1650 [deg]F 
instead of being quenched and cylinders so normalized need not be 
tempered.
    (6) Intermediate manganese steels may be tempered at temperatures 
not less than 1150 [deg]F., and after heat treating each cylinder must 
be submitted to a magnetic test to detect the presence of quenching 
cracks. Cracked cylinders must be rejected and destroyed.
    (7) Except as otherwise provided in paragraph (g)(6) of this 
section, all cylinders, if water quenched or quenched with a liquid 
producing a cooling rate in excess of 80 percent of the cooling rate of 
water, must be inspected by the magnetic particle, dye penetrant or 
ultrasonic method to detect the presence of quenching cracks. Any 
cylinder designed to the requirements for specification 3AA and found to 
have a quenching crack must be rejected and may not be requalified. 
Cylinders designed to the requirements for specification 3AAX and found 
to have cracks must have cracks removed to sound metal by mechanical 
means. Such specification 3AAX cylinders will be acceptable if the 
repaired area is subsequently examined to assure no defect, and it is 
determined that design thickness requirements are met.
    (h) Openings in cylinders and connections (valves, fuse plugs, etc.) 
for those openings. Threads are required on openings.
    (1) Threads must be clean cut, even, without checks, and to gauge.
    (2) Taper threads, when used, must be of a length not less than as 
specified for American Standard taper pipe threads.
    (3) Straight threads having at least 6 engaged threads are 
authorized. Straight threads must have a tight fit and a calculated 
shear strength of at least 10 times the test pressure of the cylinder. 
Gaskets, adequate to prevent leakage, are required.
    (i) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:
    (1) The test must be by water-jacket or direct expansion method as 
prescribed in CGA C-1 (IBR; see Sec.  171.7 of this subchapter). The 
testing equipment must be calibrated as prescribed in CGA C-1. All 
testing equipment and pressure indicating devices must be accurate 
within the parameters defined in CGA C-1.
    (2) Each cylinder must be tested to a minimum of \5/3\ times service 
pressure.
    (3) The minimum test pressure must be maintained for at least 30 
seconds and sufficiently longer to ensure complete expansion. Any 
internal pressure applied after heat-treatment and previous to the 
official test may not exceed 90 percent of the test pressure. If, due to 
failure of the test apparatus or operator error, the test pressure 
cannot be maintained, the test may be repeated in accordance with CGA C-
1, section 5.7.2.
    (4) Permanent, volumetric expansion may not exceed 10 percent of the 
total volumetric expansion at test pressure.
    (j) Flattening test. A flattening test must be performed on one 
cylinder taken at random out of each lot of 200

[[Page 25]]

or less, by placing the cylinder between wedge shaped knife edges having 
a 60[deg] included angle, rounded to \1/2\-inch radius. The longitudinal 
axis of the cylinder must be at a 90-degree angle to knife edges during 
the test. For lots of 30 or less, flattening tests are authorized to be 
made on a ring at least 8 inches long cut from each cylinder and 
subjected to the same heat treatment as the finished cylinder. Cylinders 
may be subjected to a bend test in lieu of the flattening test. Two bend 
test specimens must be taken in accordance with ISO 9809-1 or ASTM E 290 
(IBR, see Sec.  171.7 of this subchapter), and must be subjected to the 
bend test specified therein.
    (k) Physical test. A physical test must be conducted to determine 
yield strength, tensile strength, elongation, and reduction of area of 
material as follows:
    (1) The test is required on 2 specimens cut from 1 cylinder taken at 
random out of each lot of 200 or less. For lots of 30 or less, physical 
tests are authorized to be made on a ring at least 8 inches long cut 
from each cylinder and subjected to the same heat treatment as the 
finished cylinder.
    (2) Specimens must conform to the following:
    (i) Gauge length of 8 inches with a width of not over 1\1/2\ inches, 
a gauge length of 2 inches with a width of not over 1\1/2\ inches, or a 
gauge length of at least 24 times the thickness with width not over 6 
times thickness when the thickness of the cylinder wall is not over \3/
16\ inch.
    (ii) The specimen, exclusive of grip ends, may not be flattened. 
Grip ends may be flattened to within 1 inch of each end of the reduced 
section.
    (iii) When size of cylinder does not permit securing straight 
specimens, the specimens may be taken in any location or direction and 
may be straightened or flattened cold, by pressure only, not by blows. 
When specimens are so taken and prepared, the inspector's report must 
show in connection with record of physical tests detailed information in 
regard to such specimens.
    (iv) Heating of a specimen for any purpose is not authorized.
    (3) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gauge length. The following 
conditions apply:
    (i) The yield strength must be determined by either the ``offset'' 
method or the ``extension under load'' method as prescribed in ASTM E 8 
(IBR, see Sec.  171.7 of this subchapter).
    (ii) In using the ``extension under load'' method, the total strain 
(or ``extension under load'') corresponding to the stress at which the 
0.2 percent permanent strain occurs may be determined with sufficient 
accuracy by calculating the elastic extension of the gauge length under 
appropriate load and adding thereto 0.2 percent of the gauge length. 
Elastic extension calculations must be based on an elastic modulus of 
30,000,000. In the event of controversy, the entire stress-strain 
diagram must be plotted and the yield strength determined from the 0.2 
percent offset.
    (iii) For the purpose of strain measurement, the initial strain must 
be set while the specimen is under a stress of 12,000 psi, the strain 
indicator reading being set at the calculated corresponding strain.
    (iv) Cross-head speed of the testing machine may not exceed \1/8\ 
inch per minute during yield strength determination.
    (l) Acceptable results for physical, flattening and bend tests. An 
acceptable result for physical and flattening tests is elongation of at 
least 20 percent for 2 inches of gauge length or at least 10 percent in 
other cases. Flattening is required, without cracking, to 6 times the 
wall thickness of the cylinder. An acceptable result for the alternative 
bend test is no crack when the cylinder is bent inward around the 
mandrel until the interior edges are not further apart than the diameter 
of the mandrel.
    (m) Leakage test. All spun cylinders and plugged cylinders must be 
tested for leakage by gas or air pressure after the bottom has been 
cleaned and is free from all moisture. Pressure, approximately the same 
as but no less than the service pressure, must be applied to one side of 
the finished bottom over an area of at least \1/16\ of the total area of

[[Page 26]]

the bottom but not less than \3/4\ inch in diameter, including the 
closure, for at least one minute, during which time the other side of 
the bottom exposed to pressure must be covered with water and closely 
examined for indications of leakage. Except as provided in paragraph (n) 
of this section, a cylinder must be rejected if there is any leaking.
    (1) A spun cylinder is one in which an end closure in the finished 
cylinder has been welded by the spinning process.
    (2) A plugged cylinder is one in which a permanent closure in the 
bottom of a finished cylinder has been effected by a plug.
    (3) As a safety precaution, if the manufacturer elects to make this 
test before the hydrostatic test, the manufacturer should design the 
test apparatus so that the pressure is applied to the smallest area 
practicable, around the point of closure, and so as to use the smallest 
possible volume of air or gas.
    (n) Rejected cylinders. Reheat treatment is authorized for rejected 
cylinders. Subsequent thereto, cylinders must pass all prescribed tests 
to be acceptable. Repair by welding or spinning is not authorized. Spun 
cylinders rejected under the provision of paragraph (m) of this section 
may be removed from the spun cylinder category by drilling to remove 
defective material, tapping and plugging.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended at 65 FR 58631, 
Sept. 29, 2000; 66 FR 45386, Aug. 28, 2001; 67 FR 51652, Aug. 8, 2002; 
68 FR 75748, Dec. 31, 2003; 76 FR 43531, July 20, 2011; 85 FR 85420, 
Dec. 28, 2020]



Sec.  178.38  Specification 3B seamless steel cylinders.

    (a) Type, size, and service pressure. A DOT 3B cylinder is seamless 
steel cylinder with a water capacity (nominal) of not over 1,000 pounds 
and a service pressure of at least 150 to not over 500 psig.
    (b) Steel. Open-hearth or electric steel of uniform quality must be 
used. Content percent may not exceed the following: carbon, 0.55; 
phosphorus, 0.045; sulphur, 0.050.
    (c) Identification of material. Material must be identified by any 
suitable method except that plates and billets for hot-drawn cylinders 
must be marked with the heat number.
    (d) Manufacture. Cylinders must be manufactured using equipment and 
processes adequate to ensure that each cylinder produced conforms to the 
requirements of this subpart. No fissure or other defect is permitted 
that is likely to weaken the finished cylinder appreciably. A reasonably 
smooth and uniform surface finish is required. If not originally free 
from such defects, the surface may be machined or otherwise treated to 
eliminate these defects. The thickness of the bottoms of cylinders 
welded or formed by spinning is, under no condition, to be less than two 
times the minimum wall thickness of the cylindrical shell; such bottom 
thicknesses to be measured within an area bounded by a line representing 
the points of contact between the cylinder and floor when the cylinder 
is in a vertical position.
    (e) Welding or brazing. Welding or brazing for any purpose 
whatsoever is prohibited except as follows:
    (1) Welding or brazing is authorized for the attachment of neckrings 
and footrings which are non-pressure parts, and only to the tops and 
bottoms of cylinders having a service pressure of 500 psig or less. 
Cylinders, neckrings, and footrings must be made of weldable steel, 
carbon content of which may not exceed 0.25 percent except in the case 
of 4130X steel which may be used with proper welding procedure.
    (2) As permitted in paragraph (d) of this section.
    (f) Wall thickness. The wall stress may not exceed 24,000 psi. The 
minimum wall thickness is 0.090 inch for any cylinder with an outside 
diameter of 6 inches. Calculation must be made by the following formula:

S = [P(1.3D\2\ + 0.4d\2\)]/(D\2\-d\2\)

Where:

S = wall stress in psi;
P = at least two times service pressure or 450 psig, whichever is the 
          greater;
D = outside diameter in inches;
d = inside diameter in inches.

    (g) Heat treatment. The completed cylinders must be uniformly and 
properly heat-treated prior to tests.
    (h) Openings in cylinders and connections (valves, fuse plugs, etc.) 
for those

[[Page 27]]

openings. Threads, conforming to the following, are required on all 
openings:
    (1) Threads must be clean cut, even, without checks, and to gauge.
    (2) Taper threads when used, must be of a length not less than as 
specified for American Standard taper pipe threads.
    (3) Straight threads having at least 4 engaged threads are 
authorized. Straight threads must have a tight fit, and calculated shear 
strength at least 10 times the test pressure of the cylinder. Gaskets, 
adequate to prevent leakage, are required.
    (i) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:
    (1) The test must be by water-jacket or direct expansion method as 
defined in CGA C-1 (IBR; see Sec.  171.7 of this subchapter). The 
testing equipment must be calibrated as prescribed in CGA C-1. All 
testing equipment and pressure indicating devices must be accurate 
within the parameters defined in CGA C-1.
    (2) Cylinders must be tested as follows:
    (i) Each cylinder to at least two (2) times its service pressure; or
    (ii) One (1) cylinder out of each lot of 200 or fewer to at least 
three (3) times its service pressure. When one (1) cylinder out of each 
lot of 200 or less is tested to at least 3 times service pressure, the 
balance of the lot must be pressure tested by the proof pressure, water-
jacket or direct expansion test method as prescribed in CGA C-1. The 
cylinders must be subjected to at least 2 times service pressure and 
show no defect. If, due to failure of the test apparatus or operator 
error, the test pressure cannot be maintained, the test may be repeated 
in accordance with CGA C-1 5.7.2 or 7.1.2, as appropriate. Determination 
of expansion properties is not required.
    (3) When each cylinder is tested to the minimum test pressure, the 
minimum test pressure must be maintained at least 30 seconds and 
sufficiently longer to ensure complete expansion. Any internal pressure 
applied after heat-treatment and previous to the official test may not 
exceed 90 percent of the test pressure. If, due to failure of the test 
apparatus or operator error, the test pressure cannot be maintained, the 
test may be repeated in accordance with CGA C-1, section 5.7.2.
    (4) Permanent volumetric expansion may not exceed 10 percent of 
total volumetric expansion at test pressure.
    (j) Flattening test. A flattening test must be performed on one 
cylinder taken at random out of each lot of 200 or less, by placing the 
cylinder between wedge shaped knife edges having a 60[deg] included 
angle, rounded to \1/2\-inch radius. The longitudinal axis of the 
cylinder must be at a 90-degree angle to knife edges during the test. 
For lots of 30 or less, flattening tests are authorized to be made on a 
ring at least 8 inches long cut from each cylinder and subjected to same 
heat treatment as the finished cylinder.
    (k) Physical test. A physical test must be conducted to determine 
yield strength, tensile strength, elongation, and reduction of area of 
material, as follows:
    (1) The test is required on 2 specimens cut from 1 cylinder taken at 
random out of each lot of 200 or less. For lots of 30 or less, physical 
tests are authorized to be made on a ring at least 8 inches long cut 
from each cylinder and subjected to same heat treatment as the finished 
cylinder.
    (2) Specimens must conform to the following:
    (i) Gauge length of 8 inches with a width of not over 1\1/2\ inches; 
or a gauge length of 2 inches with a width of not over 1\1/2\ inches; or 
a gauge length at least 24 times the thickness with a width not over 6 
times thickness is authorized when a cylinder wall is not over \3/16\ 
inch thick.
    (ii) The specimen, exclusive of grip ends, may not be flattened. 
Grip ends may be flattened to within one inch of each end of the reduced 
section.
    (iii) When size of cylinder does not permit securing straight 
specimens, the specimens may be taken in any location or direction and 
may be straightened or flattened cold, by pressure only, not by blows. 
When specimens are so taken and prepared, the inspector's report must 
show in connection with record of physical tests detailed information in 
regard to such specimens.

[[Page 28]]

    (iv) Heating of a specimen for any purpose is not authorized.
    (3) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gauge length. The following 
conditions apply:
    (i) The yield strength must be determined by either the ``offset'' 
method or the ``extension under load'' method as prescribed in ASTM E 8 
(IBR, see Sec.  171.7 of this subchapter).
    (ii) In using the ``extension under load'' method, the total strain 
(or ``extension under load'') corresponding to the stress at which the 
0.2 percent permanent strain occurs may be determined with sufficient 
accuracy by calculating the elastic extension of the gauge length under 
appropriate load and adding thereto 0.2 percent of the gauge length. 
Elastic extension calculations must be based on an elastic modulus of 
30,000,000. In the event of controversy, the entire stress-strain 
diagram must be plotted and the yield strength determined from the 0.2 
percent offset.
    (iii) For the purpose of strain measurement, the initial strain must 
be set while the specimen is under a stress of 12,000 psi, and the 
strain indicator reading being set at the calculated corresponding 
strain.
    (iv) Cross-head speed of the testing machine may not exceed \1/8\ 
inch per minute during yield strength determination.
    (l) Acceptable results for physical and flattening tests. Either of 
the following is an acceptable result:
    (1) An elongation of at least 40 percent for a 2-inch gauge length 
or at least 20 percent in other cases and yield strength not over 73 
percent of tensile strength. In this instance, the flattening test is 
not required.
    (2) An elongation of at least 20 percent for a 2-inch gauge length 
or 10 percent in other cases and yield strength not over 73 percent of 
tensile strength. Flattening is required, without cracking, to 6 times 
the wall thickness.
    (m) Leakage test. All spun cylinders and plugged cylinders must be 
tested for leakage by gas or air pressure after the bottom has been 
cleaned and is free from all moisture, subject to the following 
conditions and limitations:
    (1) Pressure, approximately the same as but no less than service 
pressure, must be applied to one side of the finished bottom over an 
area of at least \1/16\ of the total area of the bottom but not less 
than \3/4\ inch in diameter, including the closure, for at least one 
minute, during which time the other side of the bottom exposed to 
pressure must be covered with water and closely examined for indications 
of leakage. Except as provided in paragraph (n) of this section, a 
cylinder must be rejected if there is any leaking.
    (2) A spun cylinder is one in which an end closure in the finished 
cylinder has been welded by the spinning process.
    (3) A plugged cylinder is one in which a permanent closure in the 
bottom of a finished cylinder has been effected by a plug.
    (4) As a safety precaution, if the manufacturer elects to make this 
test before the hydrostatic test, he should design his apparatus so that 
the pressure is applied to the smallest area practicable, around the 
point of closure, and so as to use the smallest possible volume of air 
or gas.
    (n) Rejected cylinders. Reheat treatment of rejected cylinders is 
authorized. Subsequent thereto, cylinders must pass all prescribed tests 
to be acceptable. Repair by welding or spinning is not authorized. Spun 
cylinders rejected under the provisions of paragraph (m) of this section 
may be removed from the spun cylinder category by drilling to remove 
defective material, tapping and plugging.
    (o) Marking. Markings may be stamped into the sidewalls of cylinders 
having a service pressure of 150 psig if all of the following conditions 
are met:
    (1) Wall stress at test pressure may not exceed 24,000 psi.
    (2) Minimum wall thickness must be not less than 0.090 inch.
    (3) Depth of stamping must be no greater than 15 percent of the 
minimum wall thickness, but may not exceed 0.015 inch.
    (4) Maximum outside diameter of cylinder may not exceed 5 inches.
    (5) Carbon content of cylinder may not exceed 0.25 percent. If the 
carbon content exceeds 0.25 percent, the complete cylinder must be 
normalized after stamping.

[[Page 29]]

    (6) Stamping must be adjacent to the top head.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended by 66 FR 45185, 
45386, Aug. 28, 2001; 67 FR 51652, Aug. 8, 2002; 68 FR 75748, Dec. 31, 
2003; 85 FR 85420, Dec. 28, 2020]



Sec.  178.39  Specification 3BN seamless nickel cylinders.

    (a) Type, size and service pressure. A DOT 3BN cylinder is a 
seamless nickel cylinder with a water capacity (nominal) not over 125 
pounds water capacity (nominal) and a service pressure at least 150 to 
not over 500 psig.
    (b) Nickel. The percentage of nickel plus cobalt must be at least 
99.0 percent.
    (c) Identification of material. The material must be identified by 
any suitable method except that plates and billets for hot-drawn 
cylinders must be marked with the heat number.
    (d) Manufacture. Cylinders must be manufactured using equipment and 
processes adequate to ensure that each cylinder produced conforms to the 
requirements of this subpart. No defect is permitted that is likely to 
weaken the finished cylinder appreciably. A reasonably smooth and 
uniform surface finish is required. Cylinders closed in by spinning 
process are not authorized.
    (e) Welding or brazing. Welding or brazing for any purpose 
whatsoever is prohibited except that welding is authorized for the 
attachment of neckrings and footrings which are nonpressure parts, and 
only to the tops and bottoms of cylinders. Neckrings and footrings must 
be of weldable material, the carbon content of which may not exceed 0.25 
percent. Nickel welding rod must be used.
    (f) Wall thickness. The wall stress may not exceed 15,000 psi. A 
minimum wall thickness of 0.100 inch is required for any cylinder over 5 
inches in outside diameter. Wall stress calculation must be made by 
using the following formula:

S = [P(1.3D\2\ + 0.4d\2\)] / (D\2\ - d\2\)

Where:

S = wall stress in psi;
P = minimum test pressure prescribed for water jacket test or 450 psig 
          whichever is the greater;
D = outside diameter in inches;
d = inside diameter in inches.

    (g) Heat treatment. The completed cylinders must be uniformly and 
properly heat-treated prior to tests.
    (h) Openings in cylinders and connections (valves, fuse plugs, etc.) 
for those openings. Threads conforming to the following are required on 
openings:
    (1) Threads must be clean cut, even, without checks, and to gauge.
    (2) Taper threads, when used, to be of length not less than as 
specified for American Standard taper pipe threads.
    (3) Straight threads having at least 6 engaged threads are 
authorized. Straight threads must have a tight fit and a calculated 
shear strength of at least 10 times the test pressure of the cylinder. 
Gaskets, adequate to prevent leakage, are required.
    (i) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:
    (1) The test must be by water-jacket or direct expansion method as 
prescribed in CGA C-1 (IBR; see Sec.  171.7 of this subchapter). The 
testing equipment must be calibrated as prescribed in CGA C-1. All 
testing equipment and pressure indicating devices must be accurate 
within the parameters defined in CGA C-1.
    (2) Each cylinder must be tested to a minimum of at least two (2) 
times its service pressure.
    (3) The minimum test pressure must be maintained at least 30 seconds 
and sufficiently longer to ensure complete expansion. Any internal 
pressure applied after heat-treatment and previous to the official test 
may not exceed 90 percent of the test pressure. If, due to failure of 
the test apparatus or operator error, the test pressure cannot be 
maintained, the test may be repeated in accordance with CGA C-1, section 
5.7.2.
    (4) Permanent volumetric expansion may not exceed 10 percent of 
total volumetric expansion at test pressure.
    (j) Flattening test. A flattening test must be performed on one 
cylinder taken at random out of each lot of 200 or less, by placing the 
cylinder between wedge shaped knife edges having a 60[deg] included 
angle, rounded to \1/2\-inch radius. The longitudinal axis of the 
cylinder must be at a 90-degree angle to knife edges during the test. 
For lots of

[[Page 30]]

30 or less, flattening tests are authorized to be made on a ring at 
least 8 inches long cut from each cylinder and subjected to same heat 
treatment as the finished cylinder.
    (k) Physical test. A physical test must be conducted to determine 
yield strength, tensile strength, elongation, and reduction of area of 
material, as follows:
    (1) The test is required on 2 specimens cut from 1 cylinder taken at 
random out of each lot of 200 or less. For lots of 30 or less, physical 
tests are authorized to be made on a ring at least 8 inches long cut 
from each cylinder and subjected to same heat treatment as the finished 
cylinder.
    (2) Specimens must conform to the following:
    (i) A gauge length of 8 inches with a width of not over 1\1/2\ 
inches, a gauge length of 2 inches with a width of not over 1\1/2\ 
inches, or a gauge length of at least 24 times the thickness with a 
width not over 6 times thickness is authorized when a cylinder wall is 
not over \3/16\ inch thick.
    (ii) The specimen, exclusive of grip ends, may not be flattened. 
Grip ends may be flattened to within one inch of each end of the reduced 
section.
    (iii) When size of cylinder does not permit securing straight 
specimens, the specimens may be taken in any location or direction and 
may be straightened or flattened cold, by pressure only, not by blows. 
When specimens are so taken and prepared, the inspector's report must 
show in connection with record of physical tests detailed information in 
regard to such specimens.
    (iv) Heating of a specimen for any purpose is not authorized.
    (3) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gauge length. The following 
conditions apply:
    (i) The yield strength must be determined by either the ``offset'' 
method or the ``extension under load'' method as prescribed in ASTM E 8 
(IBR, see Sec.  171.7 of this subchapter).
    (ii) In using the ``extension under load'' method, the total strain 
(or ``extension under load'') corresponding to the stress at which the 
0.2 percent permanent strain occurs may be determined with sufficient 
accuracy by calculating the elastic extension of the gauge length under 
appropriate load and adding thereto 0.2 percent of the gauge length. 
Elastic extension calculations must be based on an elastic modulus of 
30,000,000. In the event of controversy, the entire stress-strain 
diagram must be plotted and the yield strength determined from the 0.2 
percent offset.
    (iii) For the purpose of strain measurement, the initial strain must 
be set while the specimen is under a stress of 12,000 psi, and the 
strain indicator reading must be set at the calculated corresponding 
strain.
    (iv) Cross-head speed of the testing machine may not exceed \1/8\ 
inch per minute during yield strength determination.
    (l) Acceptable results for physical and flattening tests. Either of 
the following is an acceptable result:
    (1) An elongation of at least 40 percent for a 2 inch gauge length 
or at least 20 percent in other cases and yield point not over 50 
percent of tensile strength. In this instance, the flattening test is 
not required.
    (2) An elongation of at least 20 percent for a 2 inch gauge length 
or 10 percent in other cases and a yield point not over 50 percent of 
tensile strength. Flattening is required, without cracking, to 6 times 
the wall thickness.
    (m) Rejected cylinders. Reheat treatment is authorized for rejected 
cylinders. Subsequent thereto, cylinders must pass all prescribed tests 
to be acceptable. Repair by welding is not authorized.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended by 66 FR 45185, 
45386, 45388, Aug. 28, 2001; 67 FR 51652, Aug. 8, 2002; 68 FR 75748, 
Dec. 31, 2003; 85 FR 85420, Dec. 28, 2020]



Sec.  178.42  Specification 3E seamless steel cylinders.

    (a) Type, size, and service pressure. A DOT 3E cylinder is a 
seamless steel cylinder with an outside diameter not greater than 2 
inches nominal, a length less than 2 feet and a service pressure of 
1,800 psig.

[[Page 31]]

    (b) Steel. Open-hearth or electric steel of uniform quality must be 
used. Content percent may not exceed the following: Carbon, 0.55; 
phosphorus, 0.045; sulphur, 0.050.
    (c) Identification of steel. Materials must be identified by any 
suitable method.
    (d) Manufacture. Cylinders must be manufactured by best appliances 
and methods. No defect is permitted that is likely to weaken the 
finished cylinder appreciably. A reasonably smooth and uniform surface 
finish is required. The thickness of the spun bottom is, under no 
condition, to be less than two times the minimum wall thickness of the 
cylindrical shell; such bottom thickness must be measured within an area 
bounded by a line representing the points of contact between the 
cylinder and floor when the cylinder is in a vertical position.
    (e) Openings in cylinders and connections (valves, fuse plugs, etc.) 
for those openings. Threads conforming to the following are required on 
openings.
    (1) Threads must be clean cut, even, without checks, and to gauge.
    (2) Taper threads, when used, must be of length not less than as 
specified for American Standard taper pipe threads.
    (3) Straight threads having at least 4 engaged threads are 
authorized. Straight threads must have a tight fit and a calculated 
shear strength of at least 10 times the test pressure of the cylinder. 
Gaskets, adequate to prevent leakage, are required.
    (f) Pressure testing. Cylinders must be tested as follows:
    (1) One cylinder out of each lot of 500 or fewer must be subjected 
to a hydrostatic test pressure of 6,000 psig or higher.
    (2) The cylinder referred to in paragraph (f)(1) of this section 
must burst at a pressure higher than 6,000 psig without fragmenting or 
otherwise showing lack of ductility, or must hold a pressure of 12,000 
psig for 30 seconds without bursting. In which case, it must be 
subjected to a flattening test without cracking to six times wall 
thickness between knife edges, wedge shaped 60 degree angle, rounded out 
to a \1/2\ inch radius. The inspector's report must be suitably changed 
to show results of latter alternate and flattening test. The testing 
equipment must be calibrated as prescribed in CGA C-1 (IBR, see Sec.  
171.7 of this subchapter). All testing equipment and pressure indicating 
devices must be accurate within the parameters defined in CGA C-1.
    (3) The remaining cylinders of the lot must be pressure tested by 
the proof pressure water-jacket or direct expansion test method as 
prescribed in CGA C-1. Cylinders must be examined under pressure of at 
least 3,000 psig and not to exceed 4,500 psig and show no defect. 
Cylinders tested at a pressure in excess of 3,600 psig must burst at a 
pressure higher than 7,500 psig when tested as specified in paragraph 
(f)(2) of this section. The pressure must be maintained for at least 30 
seconds and sufficiently longer to ensure complete examination. The 
testing equipment must be calibrated as prescribed in CGA C-1. All 
testing equipment and pressure indicating devices must be accurate 
within the parameters defined in CGA C-1. If, due to failure of the test 
apparatus or operator error, the test pressure cannot be maintained, the 
test may be repeated in accordance with CGA C-1 5.7.2 or 7.1.2, as 
appropriate. Determination of expansion properties is not required.
    (g) Leakage test. All spun cylinders and plugged cylinders must be 
tested for leakage by gas or air pressure after the bottom has been 
cleaned and is free from all moisture subject to the following 
conditions and limitations:
    (1) A pressure, approximately the same as but not less than the 
service pressure, must be applied to one side of the finished bottom 
over an area of at least \1/16\ of the total area of the bottom but not 
less than \3/4\ inch in diameter, including the closure, for at least 
one minute, during which time the other side of the bottom exposed to 
pressure must be covered with water and closely examined for indications 
of leakage. Accept as provided in paragraph (h) of this section, a 
cylinder must be rejected if there is any leakage.
    (2) A spun cylinder is one in which an end closure in the finished 
cylinder has been welded by the spinning process.
    (3) A plugged cylinder is one in which a permanent closure in the 
bottom of a finished cylinder has been effected by a plug.

[[Page 32]]

    (4) As a safety precaution, if the manufacturer elects to make this 
test before the hydrostatic test, the manufacturer shall design the test 
apparatus so that the pressure is applied to the smallest area 
practicable, around the point of closure, and so as to use the smallest 
possible volume of air or gas.
    (h) Rejected cylinders. Reheat treatment is authorized for rejected 
cylinders. Subsequent thereto, cylinders must pass all prescribed tests 
to be acceptable. Repair by welding or spinning is not authorized. Spun 
cylinders rejected under the provisions of paragraph (g) of this section 
may be removed from the spun cylinder category by drilling to remove 
defective material, tapping and plugging.
    (i) Marking. Markings required by Sec.  178.35 must be stamped 
plainly and permanently on the shoulder, top head, neck or sidewall of 
each cylinder.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended by 66 FR 45386, 
Aug. 28, 2001; 85 FR 85421, Dec. 28, 2020]



Sec.  178.44  Specification 3HT seamless steel cylinders for aircraft use.

    (a) Type, size and service pressure. A DOT 3HT cylinder is a 
seamless steel cylinder with a water capacity (nominal) of not over 150 
pounds and a service pressure of at least 900 psig.
    (b) Authorized steel. Open hearth or electric furnace steel of 
uniform quality must be used. A heat of steel made under the 
specifications listed in Table 1 in this paragraph (b), a check chemical 
analysis that is slightly out of the specified range is acceptable, if 
satisfactory in all other respects, provided the tolerances shown in 
Table 2 in this paragraph (b) are not exceeded. The maximum grain size 
shall be 6 or finer. The grain size must be determined in accordance 
with ASTM E 112-88 (IBR, see Sec.  171.7 of this subchapter). Steel of 
the following chemical analysis is authorized:

                      Table 1--Authorized Materials
------------------------------------------------------------------------
              Designation                      AISI 4130 (percent)
------------------------------------------------------------------------
Carbon.................................  0.28/0.33
Manganese..............................  0.40/0.60
Phosphorus.............................  0.040 maximum
Sulfur.................................  0.040 maximum
Silicon................................  0.15/0.35
Chromium...............................  0.80/1.10
Molybdenum.............................  0.15/0.25
------------------------------------------------------------------------


                   Table 2--Check Analysis Tolerances
------------------------------------------------------------------------
                                                           Tolerance
                                                      (percent) over the
                                                       maximum limit or
                                                       under the minimum
           Element                Limit or maximum           limit
                                specified (percent)  -------------------
                                                        Under     Over
                                                       minimum   maximum
                                                        limit     limit
------------------------------------------------------------------------
Carbon.......................  Over 0.15 to 0.40           .03       .04
                                incl.
Manganese....................  To 0.60 incl.........       .03       .03
Phosphorus\1\................  All ranges...........  ........       .01
Sulphur......................  All ranges...........  ........       .01
Silicon......................  To 0.30 incl.........       .02       .03
                               Over 0.30 to 1.00           .05       .05
                                incl.
Chromium.....................  To 0.90 incl.........       .03       .03
                               Over 0.90 to 2.10           .05       .05
                                incl.
Molybdenum...................  To 0.20 incl.........       .01       .01
                               Over 0.20 to 0.40           .02       .02
                                incl.
------------------------------------------------------------------------
\1\ Rephosphorized steels not subject to check analysis for phosphorus.

    (c) Identification of material. Material must be identified by any 
suitable method. Steel stamping of heat identifications may not be made 
in any area which will eventually become the side wall of the cylinder. 
Depth of stamping may not encroach upon the minimum prescribed wall 
thickness of the cylinder.
    (d) Manufacture. Cylinders must be manufactured using equipment and 
processes adequate to ensure that each cylinder produced conforms to the 
requirements of this subpart. No fissure or other defect is permitted 
that is likely to weaken the finished container appreciably. The general 
surface finish may not exceed a roughness of 250 RMS. Individual 
irregularities such as draw marks, scratches, pits, etc., should be held 
to a minimum consistent with good high stress pressure vessel 
manufacturing practices. If the cylinder is not originally free of such 
defects or does not meet the finish requirements, the surface may be 
machined or otherwise treated to eliminate these defects. The point of 
closure of cylinders closed by spinning may not be less than two times 
the prescribed wall thickness of the cylindrical shell. The cylinder end 
contour must be hemispherical or ellipsoidal with a ratio of major-to-
minor axis not exceeding two

[[Page 33]]

to one and with the concave side to pressure.
    (e) Welding or brazing. Welding or brazing for any purpose 
whatsoever is prohibited, except that welding by spinning is permitted 
to close the bottom of spun cylinders. Machining or grinding to produce 
proper surface finish at point of closure is required.
    (f) Wall thickness. (1) Minimum wall thickness for any cylinder must 
be 0.050 inch. The minimum wall thickness must be such that the wall 
stress at the minimum specified test pressure may not exceed 75 percent 
of the minimum tensile strength of the steel as determined from the 
physical tests required in paragraph (m) of this section and may not be 
over 105,000 psi.
    (2) Calculations must be made by the formula:

S = [P(1.3D\2\ + 0.4d\2\)] / (D\2\ - d\2\)

Where:

S = Wall stress in psi;
P = Minimum test pressure prescribed for water jacket test;
D = Outside diameter in inches;
d = Inside diameter in inches.

    (3) Wall thickness of hemispherical bottoms only permitted to 90 
percent of minimum wall thickness of cylinder sidewall but may not be 
less than 0.050 inch. In all other cases, thickness to be no less than 
prescribed minimum wall.
    (g) Heat treatment. The completed cylinders must be uniformly and 
properly heated prior to tests. Heat treatment of the cylinders of the 
authorized analysis must be as follows:
    (1) All cylinders must be quenched by oil, or other suitable medium.
    (2) The steel temperature on quenching must be that recommended for 
the steel analysis, but may not exceed 1750 [deg]F.
    (3) The steel must be tempered at a temperature most suitable for 
the particular steel analysis but not less than 850 [deg]F.
    (4) All cylinders must be inspected by the magnetic particle or dye 
penetrant method to detect the presence of quenching cracks. Any 
cylinder found to have a quenching crack must be rejected and may not be 
requalified.
    (h) Openings in cylinders and connections (valves, fuse plugs, etc.) 
for those openings. Threads conforming to the following are required on 
openings:
    (1) Threads must be clean cut, even, without cracks, and to gauge.
    (2) Taper threads, when used, must be of length not less than as 
specified for National Gas Tapered Thread (NGT) as required by American 
Standard Compressed Gas Cylinder Valve Outlet and Inlet Connections.
    (3) Straight threads having at least 6 engaged threads are 
authorized. Straight threads must have a tight fit and a calculated 
shear stress of at least 10 times the test pressure of the cylinder. 
Gaskets, adequate to prevent leakage, are required.
    (i) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:
    (1) The test must be by water-jacket or direct expansion method as 
prescribed in CGA C-1 (IBR; see Sec.  171.7 of this subchapter). The 
testing equipment must be calibrated as prescribed in CGA C-1. All 
testing equipment and pressure indicating devices must be accurate 
within the parameters defined in CGA C-1.
    (2) Each cylinder must be tested to minimum of \5/3\ times service 
pressure.
    (3) The minimum test pressure must be maintained at least 30 seconds 
and sufficiently longer to ensure complete expansion. Any internal 
pressure applied after heat-treatment and previous to the official test 
may not exceed 90 percent of the test pressure. If, due to failure of 
the test apparatus or operator error, the test pressure cannot be 
maintained, the test may be repeated in accordance with CGA C-1, section 
5.7.2.
    (4) Permanent volumetric expansion may not exceed 10 percent of 
total volumetric expansion at test pressure.
    (j) Cycling tests. Prior to the initial shipment of any specific 
cylinder design, cyclic pressurization tests must have been performed on 
at least three representative samples without failure as follows:
    (1) Pressurization must be performed hydrostatically between 
approximately zero psig and the service pressure at a rate not in excess 
of 10 cycles per minute. Adequate recording instrumentation must be 
provided if equipment is

[[Page 34]]

to be left unattended for periods of time.
    (2) Tests prescribed in paragraph (j)(1) of this section must be 
repeated on one random sample out of each lot of cylinders. The cylinder 
may then be subjected to a burst test.
    (3) A lot is defined as a group of cylinders fabricated from the 
same heat of steel, manufactured by the same process and heat treated in 
the same equipment under the same conditions of time, temperature, and 
atmosphere, and may not exceed a quantity of 200 cylinders.
    (4) All cylinders used in cycling tests must be destroyed.
    (k) Burst test. One cylinder taken at random out of each lot of 
cylinders must be hydrostatically tested to destruction.
    (l) Flattening test. A flattening test must be performed on one 
cylinder taken at random out of each lot of 200 or less, by placing the 
cylinder between wedge shaped knife edges having a 60[deg] included 
angle, rounded to \1/2\-inch radius. The longitudinal axis of the 
cylinder must be at a 90-degree angle to knife edges during the test. 
For lots of 30 or less, flattening tests are authorized to be made on a 
ring at least 8 inches long cut from each cylinder and subjected to same 
heat treatment as the finished cylinder.
    (m) Physical tests. A physical test must be conducted to determine 
yield strength, tensile strength, elongation, and reduction of area of 
material, as follows:
    (1) Test is required on 2 specimens cut from 1 cylinder taken at 
random out of each lot of cylinders.
    (2) Specimens must conform to the following:
    (i) A gauge length of at least 24 times the thickness with a width 
not over six times the thickness. The specimen, exclusive of grip ends, 
may not be flattened. Grip ends may be flattened to within one inch of 
each end of the reduced section. When size of cylinder does not permit 
securing straight specimens, the specimens may be taken in any location 
or direction and may be straightened or flattened cold by pressure only, 
not by blows. When specimens are so taken and prepared, the inspector's 
report must show in connection with the record of physical tests 
detailed information in regard to such specimens.
    (ii) Heating of a specimen for any purpose is not authorized.
    (3) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gauge length.
    (i) The yield strength must be determined by either the ``offset'' 
method or the ``extension under load'' method as prescribed in ASTM E 8 
(IBR, see Sec.  171.7 of this subchapter).
    (ii) In using the ``extension under load'' method, the total strain 
(or ``extension under load'') corresponding to the stress at which the 
0.2 percent permanent strain occurs may be determined with sufficient 
accuracy by calculating the elastic extension of the gauge length under 
appropriate load and adding thereto 0.2 percent of the gauge length. 
Elastic extension calculations must be based on an elastic modulus of 
30,000,000. In the event of controversy, the entire stress-strain 
diagram must be plotted and the yield strength determined from the 0.2 
percent offset.
    (iii) For the purpose of strain measurement, the initial strain must 
be set while the specimen is under a stress of 12,000 psi, the strain 
indicator reading being set at the calculated corresponding strain.
    (iv) Cross-head speed of the testing machine may not exceed \1/8\ 
inch per minute during yield strength determination.
    (n) Magnetic particle inspection. Inspection must be performed on 
the inside of each container before closing and externally on each 
finished container after heat treatment. Evidence of discontinuities, 
which in the opinion of a qualified inspector may appreciably weaken or 
decrease the durability of the cylinder, must be cause for rejection.
    (o) Leakage test. All spun cylinders and plugged cylinders must be 
tested for leakage by dry gas or dry air pressure after the bottom has 
been cleaned and is free from all moisture, subject to the following 
conditions and limitations:
    (1) Pressure, approximately the same as but not less than service 
pressure,

[[Page 35]]

must be applied to one side of the finished bottom over an area of at 
least \1/16\ of the total area of the bottom but not less than \3/4\ 
inch in diameter, including the closure, for at least one minute, during 
which time the other side of the bottom exposed to pressure must be 
covered with water and closely examined for indications of leakage. 
Except as provided in paragraph (q) of this section, a cylinder must be 
rejected if there is leakage.
    (2) A spun cylinder is one in which an end closure in the finished 
cylinder has been welded by the spinning process.
    (3) A plugged cylinder is one in which a permanent closure in the 
bottom of a finished cylinder has been effected by a plug.
    (4) As a safety precaution, if the manufacturer elects to make this 
test before the hydrostatic test, the manufacturer should design the 
test apparatus so that the pressure is applied to the smallest area 
practicable, around the point of closure, and so as to use the smallest 
possible volume of air or gas.
    (p) Acceptable results of tests. Results of the flattening test, 
physical tests, burst test, and cycling test must conform to the 
following:
    (1) Flattening required without cracking to ten times the wall 
thickness of the cylinder.
    (2) Physical tests:
    (i) An elongation of at least 6 percent for a gauge length of 24 
times the wall thickness.
    (ii) The tensile strength may not exceed 165,000 p.s.i.
    (3) The burst pressure must be at least \4/3\ times the test 
pressure.
    (4) Cycling-at least 10,000 pressurizations.
    (q) Rejected cylinders. Reheat treatment is authorized for rejected 
cylinders. Subsequent thereto, cylinders must pass all prescribed tests 
to be acceptable. Repair by welding or spinning is not authorized. For 
each cylinder subjected to reheat treatment during original manufacture, 
sidewall measurements must be made to verify that the minimum sidewall 
thickness meets specification requirements after the final heat 
treatment.
    (r) Marking. (1) Cylinders must be marked by low stress type steel 
stamping in an area and to a depth which will insure that the wall 
thickness measured from the root of the stamping to the interior surface 
is equal to or greater than the minimum prescribed wall thickness. 
Stamping must be permanent and legible. Stamping on side wall not 
authorized.
    (2) The rejection elastic expansion (REE), in cubic cm (cc), must be 
marked on the cylinder near the date of test. The REE for a cylinder is 
1.05 times its original elastic expansion.
    (3) Name plates are authorized, provided that they can be 
permanently and securely attached to the cylinder. Attachment by either 
brazing or welding is not permitted. Attachment by soldering is 
permitted provided steel temperature does not exceed 500 [deg]F.
    (s) Inspector's report. In addition to the requirements of Sec.  
178.35, the inspector's report must indicate the rejection elastic 
expansion (REE), in cubic cm (cc).

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended at 62 FR 51561, 
Oct. 1, 1997; 65 FR 58631, Sept. 29, 2000; 66 FR 45385, Aug. 28, 2001; 
67 FR 51652, Aug. 8, 2002; 68 FR 75748, 75749, Dec. 31, 2003; 85 FR 
85421, Dec. 28, 2020]



Sec.  178.45  Specification 3T seamless steel cylinder.

    (a) Type, size, and service pressure. A DOT 3T cylinder is a 
seamless steel cylinder with a minimum water capacity of 1,000 pounds 
and a minimum service pressure of 1,800 psig. Each cylinder must have 
integrally formed heads concave to pressure at both ends. The inside 
head shape must be hemispherical, ellipsoidal in which the major axis is 
two times the minor axis, or a dished shape falling within these two 
limits. Permanent closures formed by spinning are prohibited.
    (b) Material, steel. Only open hearth, basic oxygen, or electric 
furnace process steel of uniform quality is authorized. The steel 
analysis must conform to the following:

                           Analysis Tolerances
------------------------------------------------------------------------
                                                         Check Analysis
             Element                  Ladle analysis   -----------------
                                                         Under     Over
------------------------------------------------------------------------
Carbon...........................  0.35 to 0.50.......     0.03     0.04
Manganese........................  0.75 to 1.05.......     0.04     0.04
Phosphorus (max).................  0.035..............  .......     0.01
Sulphur (max)....................  0.04...............  .......     0.01

[[Page 36]]

 
Silicon..........................  0.15 to 0.35.......     0.02     0.03
Chromium.........................  0.80 to 1.15.......     0.05     0.05
Molybdenum.......................  0.15 to 0.25.......     0.02     0.02
------------------------------------------------------------------------

    (1) A heat of steel made under the specifications in the table in 
this paragraph (b), the ladle analysis of which is slightly out of the 
specified range, is acceptable if satisfactory in all other aspects. 
However, the check analysis tolerances shown in the table in this 
paragraph (b) may not be exceeded except as approved by the Department.
    (2) Material with seams, cracks, laminations, or other injurious 
defects is not permitted.
    (3) Material used must be identified by any suitable method.
    (c) Manufacture. General manufacturing requirements are as follows:
    (1) Surface finish must be uniform and reasonably smooth.
    (2) Inside surfaces must be clean, dry, and free of loose particles.
    (3) No defect of any kind is permitted if it is likely to weaken a 
finished cylinder.
    (4) If the cylinder surface is not originally free from the defects, 
the surface may be machined or otherwise treated to eliminate these 
defects provided the minimum wall thickness is maintained.
    (5) Welding or brazing on a cylinder is not permitted.
    (d) Wall thickness. The minimum wall thickness must be such that the 
wall stress at the minimum specified test pressure does not exceed 67 
percent of the minimum tensile strength of the steel as determined by 
the physical tests required in paragraphs (j) and (k) of this section. A 
wall stress of more than 90,500 p.s.i. is not permitted. The minimum 
wall thickness for any cylinder may not be less than 0.225 inch.
    (1) Calculation of the stress for cylinders must be made by the 
following formula:

S = [P(1.3D\2\ + 0.4d\2\)] / (D\2\ - d\2\)

Where:

S = Wall stress in psi;
P = Minimum test pressure, at least \5/3\ service pressure;
D = Outside diameter in inches;
d = Inside diameter in inches.

    (2) Each cylinder must meet the following additional requirement 
which assumes a cylinder horizontally supported at its two ends and 
uniformly loaded over its entire length. This load consists of the 
weight per inch of length of the straight cylindrical portion filled 
with water compressed to the specified test pressure. The wall thickness 
must be increased when necessary to meet this additional requirement:
    (i) The sum of two times the maximum tensile stress in the bottom 
fibers due to bending (see paragraph (d)(2)(ii) of this section), plus 
the maximum tensile stress in the same fibers due to hydrostatic testing 
(see paragraph (d)(2)(iii) of this section) may not exceed 80 percent of 
the minimum yield strength of the steel at this maximum stress.
    (ii) The following formula must be used to calculate the maximum 
tensile stress due to bending:

S = Mc / I

Where:

S = Tensile stress in psi;
M = Bending moment in inch-pounds (wl\2\/8);
I = Moment of inertia--0.04909 (D\4\-d\4\) in inches fourth;
c = Radius (D/2) of cylinder in inches;
w = Weight per inch of cylinder filled with water;
l = Length of cylinder in inches;
D = Outside diameter in inches;
d = Inside diameter in inches.

    (iii) The following formula must be used to calculate the maximum 
longitudinal tensile stress due to hydrostatic test pressure:

S = A1 P / A2

Where:

S = Tensile stress in psi;
A1 = Internal area in cross section of cylinder in square 
          inches;
P = Hydrostatic test pressure-psig;
A2 = Area of metal in cross section of cylinder in square 
          inches.

    (e) Heat treatment. Each completed cylinder must be uniformly and 
properly heat treated prior to testing, as follows:
    (1) Each cylinder must be heated and held at the proper temperature 
for at least one hour per inch of thickness

[[Page 37]]

based on the maximum thickness of the cylinder and then quenched in a 
suitable liquid medium having a cooling rate not in excess of 80 percent 
of water. The steel temperature on quenching must be that recommended 
for the steel analysis, but it must never exceed 1750 [deg]F.
    (2) After quenching, each cylinder must be reheated to a temperature 
below the transformation range but not less than 1050 [deg]F., and must 
be held at this temperature for at least one hour per inch of thickness 
based on the maximum thickness of the cylinder. Each cylinder must then 
be cooled under conditions recommended for the steel.
    (f) Openings. Openings in cylinders must comply with the following:
    (1) Openings are permitted on heads only.
    (2) The size of any centered opening in a head may not exceed one 
half the outside diameter of the cylinder.
    (3) Openings in a head must have ligaments between openings of at 
least three times the average of their hole diameter. No off-center 
opening may exceed 2.625 inches in diameter.
    (4) All openings must be circular.
    (5) All openings must be threaded. Threads must be in compliance 
with the following:
    (i) Each thread must be clean cut, even, without any checks, and to 
gauge.
    (ii) Taper threads, when used, must be the American Standard Pipe 
thread (NPT) type and must be in compliance with the requirements of NBS 
Handbook H-28 (IBR, see Sec.  171.7 of this subchapter).
    (iii) Taper threads conforming to National Gas Taper thread (NGT) 
standards must be in compliance with the requirements of NBS Handbook H-
28.
    (iv) Straight threads conforming with National Gas Straight thread 
(NGS) standards are authorized. These threads must be in compliance with 
the requirements of NBS Handbook H-28.
    (g) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:
    (1) The test must be by water-jacket or direct expansion method as 
prescribed in CGA C-1 (IBR; see Sec.  171.7 of this subchapter). The 
testing equipment must be calibrated as prescribed in CGA C-1. All 
testing equipment and pressure indicating devices must be accurate 
within the parameters defined in CGA C-1.
    (2) Each cylinder must be tested to minimum of \5/3\ times service 
pressure.
    (3) The minimum test pressure must be maintained at least 30 seconds 
and sufficiently longer to ensure complete expansion. Any internal 
pressure applied after heat-treatment and prior to the official test may 
not exceed 90 percent of the test pressure. If, due to failure of the 
test apparatus or operator error, the test pressure cannot be 
maintained, the test may be repeated in accordance with CGA C-1, section 
5.7.2.
    (4) Permanent volumetric expansion may not exceed 10 percent of 
total volumetric expansion at test pressure.
    (h) Ultrasonic examination. After the hydrostatic test, the 
cylindrical section of each vessel must be examined in accordance with 
ASTM E 213 for shear wave and E 114 for straight beam (IBR, Standard see 
Sec.  171.7 of this subchapter). The equipment used must be calibrated 
to detect a notch equal to five percent of the design minimum wall 
thickness. Any discontinuity indication greater than that produced by 
the five percent notch must be cause for rejection of the cylinder, 
unless the discontinuity is repaired within the requirements of this 
specification.
    (i) Basic requirements for tension and Charpy impact tests. 
Cylinders must be subjected to a tension and Charpy impact as follows:
    (1) When the cylinders are heat treated in a batch furnace, two 
tension specimens and three Charpy impact specimens must be tested from 
one of the cylinders or a test ring from each batch. The lot size 
represented by these tests may not exceed 200 cylinders.
    (2) When the cylinders are heat treated in a continuous furnace, two 
tension specimens and three Charpy impact specimens must be tested from 
one of the cylinders or a test ring from each four hours or less of 
production. However, in no case may a test lot based on this production 
period exceed 200 cylinders.
    (3) Each specimen for the tension and Charpy impact tests must be 
taken

[[Page 38]]

from the side wall of a cylinder or from a ring which has been heat 
treated with the finished cylinders of which the specimens must be 
representative. The axis of the specimens must be parallel to the axis 
of the cylinder. Each cylinder or ring specimen for test must be of the 
same diameter, thickness, and metal as the finished cylinders they 
represent. A test ring must be at least 24 inches long with ends covered 
during the heat treatment process so as to simulate the heat treatment 
process of the finished cylinders it represents.
    (4) A test cylinder or test ring need represent only one of the 
heats in a furnace batch provided the other heats in the batch have 
previously been tested and have passed the tests and that such tests do 
not represent more than 200 cylinders from any one heat.
    (5) The test results must conform to the requirements specified in 
paragraphs (j) and (k) of this section.
    (6) When the test results do not conform to the requirements 
specified, the cylinders represented by the tests may be reheat treated 
and the tests repeated. Paragraph (i)(5) of this section applies to any 
retesting.
    (j) Basic conditions for acceptable physical testing. The following 
criteria must be followed to obtain acceptable physical test results:
    (1) Each tension specimen must have a gauge length of two inches 
with a width not exceeding one and one-half inches. Except for the grip 
ends, the specimen may not be flattened. The grip ends may be flattened 
to within one inch of each end of the reduced section.
    (2) A specimen may not be heated after heat treatment specified in 
paragraph (d) of this section.
    (3) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gage length.
    (i) This yield strength must be determined by the ``offset'' method 
or the ``extension under load'' method described in ASTM E 8 (IBR, see 
Sec.  171.7 of this subchapter).
    (ii) For the ``extension under load'' method, the total strain (or 
extension under load) corresponding to the stress at which the 0.2 
percent permanent strain occurs may be determined with sufficient 
accuracy by calculating the elastic extension of the gage length under 
appropriate load and adding thereto 0.2 percent of the gage length. 
Elastic extension calculations must be based on an elastic modulus of 
30,000,000. However, when the degree of accuracy of this method is 
questionable the entire stress-strain diagram must be plotted and the 
yield strength determined from the 0.2 percent offset.
    (iii) For the purpose of strain measurement, the initial strain must 
be set with the specimen under a stress of 12,000 p.s.i. and the strain 
indicator reading set at the calculated corresponding strain.
    (iv) The cross-head speed of the testing machine may not exceed \1/
8\ inch per minute during the determination of yield strength.
    (4) Each impact specimen must be Charpy V-notch type size 10 mm x 10 
mm taken in accordance with paragraph 11 of ASTM A 333 (IBR, see Sec.  
171.7 of this subchapter). When a reduced size specimen is used, it must 
be the largest size obtainable.
    (k) Acceptable physical test results. Results of physical tests must 
conform to the following:
    (1) The tensile strength may not exceed 155,000 p.s.i.
    (2) The elongation must be at least 16 percent for a two-inch gage 
length.
    (3) The Charpy V-notch impact properties for the three impact 
specimens which must be tested at 0 [deg]F may not be less than the 
values shown as follows:

------------------------------------------------------------------------
                                  Average value for    Minimum value (1
     Size of specimen (mm)          acceptance (3      specimen only of
                                     specimens)             the 3)
------------------------------------------------------------------------
10.0 x 10.0....................  25.0 ft. lbs......  20.0 ft. lbs.
10.0 x 7.5.....................  21.0 ft. lbs......  17.0 ft. lbs.
10.0 x 5.0.....................  17.0 ft. lbs......  14.0 ft. lbs.
------------------------------------------------------------------------

    (4) After the final heat treatment, each vessel must be hardness 
tested on the cylindrical section. The tensile strength equivalent of 
the hardness number obtained may not be more than 165,000 p.s.i. (Rc 
36). When the result of a hardness test exceeds the maximum permitted, 
two or more retests may be made; however, the hardness number obtained 
in each retest may not exceed the maximum permitted.

[[Page 39]]

    (l) Rejected cylinders. Reheat treatment is authorized for rejected 
cylinders. However, each reheat treated cylinder must subsequently pass 
all the prescribed tests. Repair by welding is not authorized.
    (m) Markings. Marking must be done by stamping into the metal of the 
cylinder. All markings must be legible and located on a shoulder.
    (n) Inspector's report. In addition to the requirements of Sec.  
178.35, the inspector's report for the physical test report, must 
indicate the average value for three specimens and the minimum value for 
one specimen for each lot number.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended at 66 FR 45385, 
43588, Aug. 28, 2001; 67 FR 51652, Aug. 8, 2002; 68 FR 48571, Aug. 14, 
2003; 68 FR 75748, 75749, Dec. 31, 2003; 85 FR 85421, Dec. 28, 2020]



Sec.  178.46  Specification 3AL seamless aluminum cylinders.

    (a) Size and service pressure. A DOT 3AL cylinder is a seamless 
aluminum cylinder with a maximum water capacity of 1000 pounds and 
minimum service pressure of 150 psig.
    (b) Authorized material and identification of material. The material 
of construction must meet the following conditions:
    (1) Starting stock must be cast stock or traceable to cast stock.
    (2) Material with seams, cracks, laminations, or other defects 
likely to weaken the finished cylinder may not be used.
    (3) Material must be identified by a suitable method that will 
identify the alloy, the aluminum producer's cast number, the solution 
heat treat batch number and the lot number.
    (4) The material must be of uniform quality. Only the following heat 
treatable aluminum alloys in table 1 and 2 are permitted as follows:

         Table 1--Heat or Cast Analysis for Aluminum; Similar to ``Aluminum Association''\1\ Alloy 6061
                                    [CHEMICAL ANALYSIS IN WEIGHT PERCENT\2\]
----------------------------------------------------------------------------------------------------------------
                                                                                        Other
Si min/         Cu min/          Mg min/  Cr min/                                 ----------------
  max   Fe max    max    Mn max    max      max    Zn max  Ti max  Pb max  Bi max   each    total        A1
                                                                                     max     max
----------------------------------------------------------------------------------------------------------------
  0.4/     0.7    0.15/    0.15    0.8/     0.04/    0.25    0.15   0.005   0.005    0.05    0.15  Bal.
    0.8             0.4             1.2      0.35
----------------------------------------------------------------------------------------------------------------
\1\ The ``Aluminum Association'' refers to ``Aluminum Standards and Data 1993'', published by the Aluminum
  Association Inc.
\2\ Except for ``Pb'' and ``Bi'', the chemical composition corresponds with that of Table 1 of ASTM B 221 (IBR,
  see Sec.   171.7 of this subchapter) for Aluminum Association alloy 6061.


                                       Table 2--Mechanical Property Limits
----------------------------------------------------------------------------------------------------------------
                                                              Tensile strength--PSI          Elongation--percent
                                                    ----------------------------------------  minimum for 2 or 4D \1\
                                                      Ultimate--minimum    Yield--minimum       size specimen
----------------------------------------------------------------------------------------------------------------
6061-T6............................................              38,000              35,000                \2\14
----------------------------------------------------------------------------------------------------------------
\1\ ``D'' represents specimen diameters. When the cylinder wall is greater than \3/16\ inch thick, a retest
  without reheat treatment using the 4D size specimen is authorized if the test using the 2 inch size specimen
  fails to meet elongation requirements.
\2\ When cylinder wall is not over \3/16\-inch thick, 10 percent elongation is authorized when using a 24t x 6t
  size test specimen.

    (5) All starting stock must be 100 percent ultrasonically inspected, 
along the length at right angles to the central axis from two positions 
at 90[deg] to one another. The equipment and continuous scanning 
procedure must be capable of detecting and rejecting internal defects 
such as cracks which have an ultrasonic response greater than that of a 
calibration block with a \5/64\-inch diameter flat bottomed hole.
    (6) Cast stock must have uniform equiaxed grain structure not to 
exceed 500 microns maximum.
    (7) Any starting stock not complying with the provisions of 
paragraphs (b)(1) through (b)(6) of this section must be rejected.

[[Page 40]]

    (c) Manufacture. Cylinders must be manufactured in accordance with 
the following requirements:
    (1) Cylinder shells must be manufactured by the backward extrusion 
method and have a cleanliness level adequate to ensure proper 
inspection. No fissure or other defect is acceptable that is likely to 
weaken the finished cylinder below the design strength requirements. A 
reasonably smooth and uniform surface finish is required. If not 
originally free from such defects, the surface may be machined or 
otherwise conditioned to eliminate these defects.
    (2) Thickness of the cylinder base may not be less than the 
prescribed minimum wall thickness of the cylindrical shell. The cylinder 
base must have a basic torispherical, hemispherical, or ellipsoidal 
interior base configuration where the dish radius is no greater than 1.2 
times the inside diameter of the shell. The knuckle radius may not be 
less than 12 percent of the inside diameter of the shell. The interior 
base contour may deviate from the true torispherical, hemispherical or 
ellipsoidal configuration provided that--
    (i) Any areas of deviation are accompanied by an increase in base 
thickness;
    (ii) All radii of merging surfaces are equal to or greater than the 
knuckle radius;
    (iii) Each design has been qualified by successfully passing the 
cycling tests in this paragraph (c); and
    (iv) Detailed specifications of the base design are available to the 
inspector.
    (3) For free standing cylinders, the base thickness must be at least 
two times the minimum wall thickness along the line of contact between 
the cylinder base and the floor when the cylinders are in the vertical 
position.
    (4) Welding or brazing is prohibited.
    (5) Each new design and any significant change to any acceptable 
design must be qualified for production by testing prototype samples as 
follows:
    (i) Three samples must be subjected to 100,000 pressure reversal 
cycles between zero and service pressure or 10,000 pressure reversal 
cycles between zero and test pressure, at a rate not in excess of 10 
cycles per minute without failure.
    (ii) Three samples must be pressurized to destruction and failure 
may not occur at less than 2.5 times the marked cylinder service 
pressure. Each cylinder must remain in one piece. Failure must initiate 
in the cylinder sidewall in a longitudinal direction. Rate of 
pressurization may not exceed 200 psig per second.
    (6) In this specification ``significant change'' means a 10 percent 
or greater change in cylinder wall thickness, service pressure, or 
diameter; a 30 percent or greater change in water capacity or base 
thickness; any change in material; over 100 percent increase in size of 
openings; or any change in the number of openings.
    (d) Wall thickness. The minimum wall thickness must be such that the 
wall stress at the minimum specified test pressure will not exceed 80 
percent of the minimum yield strength nor exceed 67 percent of the 
minimum ultimate tensile strength as verified by physical tests in 
paragraph (i) of this section. The minimum wall thickness for any 
cylinder with an outside diameter greater than 5 inches must be 0.125 
inch. Calculations must be made by the following formula:

S = [P(1.3D\2\ + 0.4d\2\)] / (D\2\ - d\2\)

Where:

S = Wall stress in psi;
P = Prescribed minimum test pressure in psig (see paragraph (g) of this 
          section);
D = Outside diameter in inches; and
d = Inside diameter in inches.

    (e) Openings. Openings must comply with the following requirements:
    (1) Openings are permitted in heads only.
    (2) The size of any centered opening in a head may not exceed one-
half the outside diameter of the cylinder.
    (3) Other openings are permitted in the head of a cylinder if:
    (i) Each opening does not exceed 2.625 inches in diameter, or one-
half the outside diameter of the cylinder; whichever is less;
    (ii) Each opening is separated from each other by a ligament; and
    (iii) Each ligament which separates two openings must be at least 
three

[[Page 41]]

times the average of the diameters of the two openings.
    (4) All openings must be circular.
    (5) All openings must be threaded. Threads must comply with the 
following:
    (i) Each thread must be clean cut, even, without checks, and to 
gauge.
    (ii) Taper threads, when used, must conform to one of the following:
    (A) American Standard Pipe Thread (NPT) type, conforming to the 
requirements of NBS Handbook H-28 (IBR, see Sec.  171.7 of this 
subchapter);
    (B) National Gas Taper Thread (NGT) type, conforming to the 
requirements of NBS Handbook H-28; or
    (C) Other taper threads conforming to other standards may be used 
provided the length is not less than that specified for NPT threads.
    (iii) Straight threads, when used, must conform to one of the 
following:
    (A) National Gas Straight Thread (NGS) type, conforming to the 
requirements of NBS Handbook H-28;
    (B) Unified Thread (UN) type, conforming to the requirements of NBS 
Handbook H-28;
    (C) Controlled Radius Root Thread (UN) type, conforming to the 
requirements of NBS Handbook H-28; or
    (D) Other straight threads conforming to other recognized standards 
may be used provided that the requirements in paragraph (e)(5)(iv) of 
this section are met.
    (iv) All straight threads must have at least 6 engaged threads, a 
tight fit, and a factor of safety in shear of at least 10 at the test 
pressure of the cylinder. Shear stress must be calculated by using the 
appropriate thread shear area in accordance with NBS Handbook H-28.
    (f) Heat treatment. Prior to any test, all cylinders must be 
subjected to a solution heat treatment and aging treatment appropriate 
for the aluminum alloy used.
    (g) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:
    (1) The test must be by water-jacket or direct expansion method as 
prescribed in CGA C-1 (IBR; see Sec.  171.7 of this subchapter). The 
testing equipment must be calibrated as prescribed in CGA C-1. All 
testing equipment and pressure indicating devices must be accurate 
within the parameters defined in CGA C-1.
    (2) The minimum test pressure must be the greater of the following:
    (i) 450 psig regardless of service pressure;
    (ii) Two (2) times the service pressure for cylinders having service 
pressure less than 500 psig; or
    (iii) \5/3\ times the service pressure for cylinders having a 
service pressure of 500 psig or greater.
    (3) The minimum test pressure must be maintained at least 30 seconds 
and sufficiently longer to ensure complete expansion. Any internal 
pressure applied after heat treatment and prior to the official test may 
not exceed 90 percent of the test pressure. If, due to failure of the 
test apparatus or operator error, the test pressure cannot be 
maintained, the test may be repeated in accordance with CGA C-1, section 
5.7.2, however, if a second failure to maintain the test pressure occurs 
the cylinder being tested must be rejected.
    (4) Permanent volumetric expansion may not exceed 10 percent of 
total volumetric expansion at test pressure.
    (h) Flattening test. One cylinder taken at random out of each lot 
must be subjected to a flattening test as follows:
    (1) The test must be between knife edges, wedge shaped, having a 
60[deg] included angle, and rounded in accordance with the following 
table. The longitudinal axis of the cylinder must be at an angle 90[deg] 
to the knife edges during the test. The flattening test table is as 
follows:

                     Table 3--Flattening Test Table
------------------------------------------------------------------------
                                                                 Radius
               Cylinder wall thickness in inches                   in
                                                                 inches
------------------------------------------------------------------------
Under .150....................................................      .500
.150 to .249..................................................      .875
.250 to .349..................................................     1.500
.350 to .449..................................................     2.125
.450 to .549..................................................     2.750
.550 to .649..................................................     3.500
.650 to .749..................................................     4.125
------------------------------------------------------------------------

    (2) An alternate bend test in accordance with ASTM E 290 using a 
mandrel diameter not more than 6 times the wall thickness is authorized 
to qualify lots that fail the flattening test of this section without 
reheat treatment. If used, this test must be performed on

[[Page 42]]

two samples from one cylinder taken at random out of each lot of 200 
cylinders or less.
    (3) Each test cylinder must withstand flattening to nine times the 
wall thickness without cracking. When the alternate bend test is used, 
the test specimens must remain uncracked when bent inward around a 
mandrel in the direction of curvature of the cylinder wall until the 
interior edges are at a distance apart not greater than the diameter of 
the mandrel.
    (i) Mechanical properties test. Two test specimens cut from one 
cylinder representing each lot of 200 cylinders or less must be 
subjected to the mechanical properties test, as follows:
    (1) The results of the test must conform to at least the minimum 
acceptable mechanical property limits for aluminum alloys as specified 
in paragraph (b) of this section.
    (2) Specimens must be 4D bar or gauge length 2 inches with width not 
over 1\1/2\ inch taken in the direction of extrusion approximately 
180[deg] from each other; provided that gauge length at least 24 times 
thickness with width not over 6 times thickness is authorized, when 
cylinder wall is not over \3/16\ inch thick. The specimen, exclusive of 
grip ends, may not be flattened. Grip ends may be flattened to within 
one inch of each end of the reduced section. When the size of the 
cylinder does not permit securing straight specimens, the specimens may 
be taken in any location or direction and may be straightened or 
flattened cold by pressure only, not by blows. When such specimens are 
used, the inspector's report must show that the specimens were so taken 
and prepared. Heating of specimens for any purpose is forbidden.
    (3) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gauge length.
    (i) The yield strength must be determined by either the ``offset'' 
method or the ``extension under load'' method as prescribed in ASTM B 
557 (IBR, see Sec.  171.7 of this subchapter).
    (ii) In using the ``extension under load'' method, the total strain 
(or ``extension under load'') corresponding to the stress at which the 
0.2 percent permanent strain occurs may be determined with sufficient 
accuracy by calculating the elastic extension of the gauge length under 
appropriate load and adding thereto 0.2 percent of the gauge length. 
Elastic extension calculations must be based on an elastic modulus of 
10,000,000 psi. In the event of controversy, the entire stress-strain 
diagram must be plotted and the yield strength determined from the 0.2 
percent offset.
    (iii) For the purpose of strain measurement, the initial strain must 
be set while the specimen is under a stress of 6,000 psi, the strain 
indicator reading being set at the calculated corresponding strain.
    (iv) Cross-head speed of the testing machine may not exceed \1/8\ 
inch per minute during yield strength determination.
    (j) Rejected cylinder. Reheat treatment of rejected cylinders is 
authorized one time. Subsequent thereto, cylinders must pass all 
prescribed tests to be acceptable.
    (k) Duties of inspector. In addition to the requirements of Sec.  
178.35, the inspector shall:
    (1) Verify compliance with the provisions of paragraph (b) of this 
section by:
    (i) Performing or witnessing the performance of the chemical 
analyses on each melt or cast lot or other unit of starting material; or
    (ii) Obtaining a certified chemical analysis from the material or 
cylinder manufacturer for each melt, or cast of material; or
    (iii) Obtaining a certified check analysis on one cylinder out of 
each lot of 200 cylinders or less, if a certificate containing data to 
indicate compliance with the material specification is obtained.
    (2) The inspector must verify ultrasonic inspection of all material 
by inspection or by obtaining the material producer's certificate of 
ultrasonic inspection. Ultrasonic inspection must be performed or 
verified as having been performed in accordance with paragraph (b)(5) of 
this section.
    (3) The inspector must also determine that each cylinder complies 
with this specification by:

[[Page 43]]

    (i) Selecting the samples for check analyses performed by other than 
the material producer;
    (ii) Verifying that the prescribed minimum thickness was met by 
measuring or witnessing the measurement of the wall thickness; and
    (iii) Verifying that the identification of material is proper.
    (4) Prior to initial production of any design or design change, 
verify that the design qualification tests prescribed in paragraph 
(c)(6) of this section have been performed with acceptable results.
    (l) Definitions. (1) In this specification, a ``lot'' means a group 
of cylinders successively produced having the same:
    (i) Size and configuration;
    (ii) Specified material of construction;
    (iii) Process of manufacture and heat treatment;
    (iv) Equipment of manufacture and heat treatment; and
    (v) Conditions of time, temperature and atmosphere during heat 
treatment.
    (2) In no case may the lot size exceed 200 cylinders, but any 
cylinder processed for use in the required destructive physical testing 
need not be counted as being one of the 200.
    (m) Inspector's report. In addition to the information required by 
Sec.  178.35, the record of chemical analyses must also include the 
alloy designation, and applicable information on iron, titanium, zinc, 
magnesium and any other applicable element used in the construction of 
the cylinder.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended at 66 FR 45386, 
Aug. 28, 2001; 67 FR 51652, Aug. 8, 2002; 68 FR 75749, Dec. 31, 2003; 77 
FR 60943, Oct. 5, 2012; 85 FR 85421, Dec. 28, 2020]



Sec.  178.47  Specification 4DS welded stainless steel cylinders for 
                            aircraft use.

    (a) Type, size, and service pressure. A DOT 4DS cylinder is either a 
welded stainless steel sphere (two seamless hemispheres) or 
circumferentially welded cylinder both with a water capacity of not over 
100 pounds and a service pressure of at least 500 but not over 900 psig.
    (b) Steel. Types 304, 321 and 347 stainless steel are authorized 
with proper welding procedure. A heat of steel made under the 
specifications in table 1 in this paragraph (b), check chemical analysis 
of which is slightly out of the specified range, is acceptable, if 
satisfactory in all other respects, provided the tolerances shown in 
table 2 in this paragraph (b) are not exceeded, except as approved by 
Associate Administrator. The following chemical analyses are authorized:

                                          Table 1--Authorized Materials
----------------------------------------------------------------------------------------------------------------
                                                                   Stainless steels
                                    ----------------------------------------------------------------------------
                                            304 (percent)               321 (percent)           347 (percent)
----------------------------------------------------------------------------------------------------------------
Carbon (max).......................  0.08                        0.08                        0.08
Manganese (max)....................  2.00                        2.00                        2.00
Phosphorus (max)...................  .030                        .030                        .030
Sulphur (max)......................  .030                        .030                        .030
Silicon (max)......................  .75                         .75                         .75
Nickel.............................  8.0/11.0                    9.0/13.0                    9.0/13.0
Chromium...........................  18.0/20.0                   17.0/20.0                   17.0/20.0
Molybdenum
Titanium...........................  ..........................  (\1\)
Columbium..........................  ..........................  ..........................  (\2\)
----------------------------------------------------------------------------------------------------------------
\1\ Titanium may not be more than 5C and not more than 0.60%.
\2\ Columbium may not be less than 10C and not more than 1.0%.


                                       Table 2--Check Analysis Tolerances
----------------------------------------------------------------------------------------------------------------
                                                                                        Tolerance (percent) over
                                                                                          the maximum limit or
                                                                                         under the minimum limit
            Element                       Limit or maximum specified (percent)         -------------------------
                                                                                           Under         Over
                                                                                          minimum      maximum
                                                                                           limit        limit
----------------------------------------------------------------------------------------------------------------
Carbon.........................  To 0.15 incl.........................................         0.01         0.01

[[Page 44]]

 
Manganese......................  Over 1.15 to 2.50 incl...............................         0.05         0.05
Phosphorus\1\..................  All ranges...........................................  ...........          .01
Sulphur........................  All ranges...........................................  ...........          .01
Silicon........................  Over 0.30 to 1.00 incl...............................          .05          .05
Nickel.........................  Over 5.30 to 10.00 incl..............................          .10          .10
                                 Over 10.00 to 14.00 incl.............................          .15          .15
Chromium.......................  Over 15.00 to 20.00 incl.............................          .20          .20
Titanium.......................  All ranges...........................................          .05          .05
Columbium......................  All ranges...........................................          .05          .05
----------------------------------------------------------------------------------------------------------------
\1\Rephosphorized steels not subject to check analysis for phosphorus.

    (c) Identification of material. Materials must be identified by any 
suitable method.
    (d) Manufacture. Cylinders must be manufactured using equipment and 
processes adequate to ensure that each cylinder produced conforms to the 
requirements of this subpart. No defect is permitted that is likely to 
weaken the finished cylinder appreciably, a reasonably smooth and 
uniform surface finish is required. No abrupt change in wall thickness 
is permitted. Welding procedures and operators must be qualified in 
accordance with CGA Pamphlet C-3 (IBR, see Sec.  171.7 of this 
subchapter). All seams of the sphere or cylinder must be fusion welded. 
Seams must be of the butt type and means must be provided for 
accomplishing complete penetration of the joint.
    (e) Attachments. Attachments to the container are authorized by 
fusion welding provided that such attachments are made of weldable 
stainless steel in accordance with paragraph (b) of this section.
    (f) Wall thickness. The minimum wall thickness must be such that the 
wall stress at the minimum specified test pressure may not be over 
60,000 psig. A minimum wall thickness of 0.040 inch is required for any 
diameter container. Calculations must be made by the following formulas:
    (1) Calculation for sphere must be made by the formula:


S = PD / 4tE

Where:

S = Wall stress in psi;
P = Test pressure prescribed for water jacket test, i.e., at least two 
          times service pressure, in psig;
D = Outside diameter in inches;
t = Minimum wall thickness in inches;
E = 0.85 (provides 85 percent weld efficiency factor which must be 
          applied in the girth weld area and heat zones which zone must 
          extend a distance of 6 times wall thickness from center of 
          weld);
E = 1.0 (for all other areas).

    (2) Calculation for a cylinder must be made by the formula:

S = [P(1.3D\2\ + 0.4d\2\)] / (D\2\ - d\2\)

Where:

S = Wall stress in psi;
P = Test pressure prescribed for water jacket test, i.e., at least two 
          times service pressure, in psig;
D = Outside diameter in inches;
d = Inside diameter in inches.

    (g) Heat treatment. The seamless hemispheres and cylinders may be 
stress relieved or annealed for forming. Welded container must be stress 
relieved at a temperature of 775 [deg]F 25[deg] 
after process treatment and before hydrostatic test.
    (h) Openings in container. Openings must comply with the following:
    (1) Each opening in the container must be provided with a fitting, 
boss or pad of weldable stainless steel securely attached to the 
container by fusion welding.
    (2) Attachments to a fitting, boss, or pad must be adequate to 
prevent leakage. Threads must comply with the following:
    (i) Threads must be clean cut, even, without checks, and tapped to 
gauge.

[[Page 45]]

    (ii) Taper threads to be of length not less than as specified for 
American Standard taper pipe threads.
    (iii) Straight threads having at least 4 engaged threads, to have 
tight fit and calculated shear strength at least 10 times the test 
pressure of the container; gaskets required, adequate to prevent 
leakage.
    (i) Process treatment. Each container must be hydraulically 
pressurized in a water jacket to at least 100 percent, but not more than 
110 percent, of the test pressure and maintained at this pressure for a 
minimum of 3 minutes. Total and permanent expansion must be recorded and 
included in the inspector's report.
    (j) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:
    (1) The test must be by water-jacket or direct expansion method as 
prescribed in CGA C-1 (IBR; see Sec.  171.7 of this subchapter). The 
testing equipment must be calibrated as prescribed in CGA C-1. All 
testing equipment and pressure indicating devices must be accurate 
within the parameters defined in CGA C-1.
    (2) Each cylinder must be tested to a minimum of at least two (2) 
times its service pressure.
    (3) The minimum test pressure must be maintained at least 30 seconds 
and sufficiently longer to ensure complete expansion. Any internal 
pressure applied after heat-treatment and prior to the official test may 
not exceed 90 percent of the test pressure. If, due to failure of the 
test apparatus or operator error, the test pressure cannot be 
maintained, the test may be repeated in accordance with CGA C-1, section 
5.7.2.
    (4) Permanent volumetric expansion may not exceed 10 percent of the 
total volumetric expansion at test pressure.
    (5) The cylinder must then be inspected. Any wall thickness lower 
than that required by paragraph (f) of this section must be cause for 
rejection. Bulges and cracks must be cause for rejection. Welded joint 
defects exceeding requirements of paragraph (k) of this section are 
cause for rejection.
    (k) Radiographic inspection. Radiographic inspection is required on 
all welded joints which are subjected to internal pressure, except that 
at the discretion of the disinterested inspector, openings less than 25 
percent of the container diameter need not be subjected to radiographic 
inspection. Evidence of any defects likely to seriously weaken the 
container is cause for rejection. Radiographic inspection must be 
performed subsequent to the hydrostatic test.
    (l) Burst test. One container taken at random out of 200 or less 
must be hydrostatically tested to destruction. Rupture pressure must be 
included as part of the inspector's report.
    (m) Flattening test. A flattening test must be performed as follows:
    (1) For spheres the test must be at the weld between parallel steel 
plates on a press with welded seam at right angles to the plates. Test 
one sphere taken at random out of each lot of 200 or less after the 
hydrostatic test. Any projecting appurtenances may be cut off (by 
mechanical means only) prior to crushing.
    (2) For cylinders the test must be between knife edges, wedge 
shaped, 60[deg] angle, rounded to \1/2\-inch radius. Test one cylinder 
taken at random out of each lot of 200 or less, after the hydrostatic 
test.
    (n) Acceptable results for flattening and burst tests. Acceptable 
results for flattening and burst tests are as follows:
    (1) Flattening required to 50 percent of the original outside 
diameter without cracking.
    (2) Burst pressure must be at least 3 times the service pressure.
    (o) Rejected containers. Repair of welded seams by welding prior to 
process treatment is authorized. Subsequent thereto, containers must be 
heat treated and pass all prescribed tests.
    (p) Duties of inspector. In addition to the requirements of Sec.  
178.35, the inspector must verify that all tests are conducted at 
temperatures between 60 [deg]F and 90 [deg]F.
    (q) Marking. Markings must be stamped plainly and permanently on a 
permanent attachment or on a metal nameplate permanently secured to the

[[Page 46]]

container by means other than soft solder.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended at 66 FR 45386, 
45388, Aug. 28, 2001; 67 FR 51653, Aug. 8, 2002; 68 FR 75748, Dec. 31, 
2003; 85 FR 85421, Dec. 28, 2020]



Sec.  178.50  Specification 4B welded or brazed steel cylinders.

    (a) Type, size, pressure, and application. A DOT 4B is a welded or 
brazed steel cylinder with water capacity (nominal) not over 1,000 
pounds and a service pressure of at least 150 but not over 500 psig. 
Longitudinal seams must be forged lap-welded or brazed. Cylinders closed 
in by spinning process are not authorized.
    (b) Steel. Open-hearth, electric or basic oxygen process steel of 
uniform quality must be used. Content percent may not exceed the 
following: Carbon, 0.25; phosphorus, 0.045; sulphur, 0.050. The cylinder 
manufacturer must maintain a record of intentionally added alloying 
elements.
    (c) Identification of material. Pressure-retaining materials must be 
identified by any suitable method that does not compromise the integrity 
of the cylinder. Plates and billets for hotdrawn cylinders must be 
marked with the heat number.
    (d) Manufacture. Cylinders must be manufactured using equipment and 
processes adequate to ensure that each cylinder produced conforms to the 
requirements of this subpart. No defect is permitted that is likely to 
weaken the finished cylinder appreciably. A reasonably smooth and 
uniform surface finish is required. Exposed bottom welds on cylinders 
over 18 inches long must be protected by footrings. Welding procedures 
and operators must be qualified in conformance with CGA C-3 (IBR, see 
Sec.  171.7 of this subchapter). Seams must be made as follows:
    (1) Brazing materials. Brazing materials must be by copper brazing, 
by copper alloy brazing, or by silver alloy brazing. Copper alloy 
composition must be: Copper, 95 percent minimum; Silicon, 1.5 percent to 
3.85 percent; Manganese, 0.25 percent to 1.10 percent.
    (2) Brazed circumferential seams. Heads attached by brazing must 
have a driving fit with the shell, unless the shell is crimped, swedged, 
or curled over the skirt or flange of the head, and be thoroughly brazed 
until complete penetration by the brazing material of the brazed joint 
is secured. Depth of brazing of the joint must be at least four (4) 
times the minimum thickness of shell metal.
    (3) Welded circumferential seams. Circumferential seams are 
permitted by the welding process.
    (4) Longitudinal seams in shells. Longitudinal seams must be a 
forged lap joint design. When brazed, the plate edge must be lapped at 
least eight (8) times the thickness of the plate, laps being held in 
position, substantially metal to metal, by riveting or electric spot-
welding; brazing must be done by using a suitable flux and by placing 
brazing material on one side of seam and applying heat until this 
material shows uniformly along the seam of the other side.
    (e) Welding or brazing. Only the attachment of neckrings, footrings, 
handles, bosses, pads, and valve protection rings to the tops and 
bottoms of cylinders by welding or brazing is authorized. Attachments 
and the portion of the cylinder to which they are attached must be made 
of weldable steel, the carbon content of which may not exceed 0.25 
percent except in the case of 4130X steel, which may be used with proper 
welding procedure.
    (f) Wall thickness. The wall thickness of the cylinder must comply 
with the following requirements:
    (1) For cylinders with outside diameters over 6 inches, the minimum 
wall thickness must be 0.090 inch. In any case, the minimum wall 
thickness must be such that calculated wall stress at minimum test 
pressure (paragraph (i)(4) of this section) may not exceed the following 
values:
    (i) 24,000 psig for cylinders without longitudinal seam.
    (ii) 22,800 psig for cylinders having copper brazed or silver alloy 
brazed longitudinal seam.
    (iii) 18,000 psig for cylinders having forged lapped welded 
longitudinal seam.
    (2) Calculation must be made by the formula:

S = [P(1.3D\2\ + 0.4d\2\)]/(D\2\ - d\2\)

Where:
S = wall stress in psig;

[[Page 47]]

P = minimum test pressure prescribed for water jacket test or 450 psig 
          whichever is the greater;
D = outside diameter in inches; and
d = inside diameter in inches.

    (g) Heat treatment. Cylinder heads, bodies or the completed 
cylinder, formed by drawing or pressing, must be uniformly and properly 
heat treated by an applicable method shown in table 1 of appendix A of 
this part before tests.
    (h) Opening in cylinders. Openings in cylinders must comply with the 
following:
    (1) Any opening must be placed on other than a cylindrical surface.
    (2) Each opening in a spherical type of cylinder must be provided 
with a fitting, boss, or pad of weldable steel securely attached to the 
cylinder by fusion welding.
    (3) Each opening in a cylindrical type cylinder, except those for 
pressure relief devices, must be provided with a fitting, boss, or pad, 
securely attached to container by brazing or by welding.
    (4) If threads are used, they must comply with the following:
    (i) Threads must be clean cut, even without checks, and tapped to 
gauge.
    (ii) Taper threads must be of a length not less than as specified 
for American Standard taper pipe threads.
    (iii) Straight threads, must have at least four (4) engaged threads, 
must have tight fit and a calculated shear strength at least ten (10) 
times the test pressure of the cylinder; gaskets are required for 
straight threads and must be of sufficient quality to prevent leakage.
    (iv) A brass fitting may be brazed to the steel boss or flange on 
cylinders used as component parts of handheld fire extinguishers.
    (5) The closure of a fitting, boss, or pad must be adequate to 
prevent leakage.
    (i) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows: (1) Lot testing. (i) At least one (1) cylinder 
randomly selected out of each lot of 200 or fewer must be tested by the 
water jacket or direct expansion method as prescribed in CGA C-1 (IBR; 
see Sec.  171.7 of this subchapter). The testing equipment must be 
calibrated as prescribed in CGA C-1. All testing equipment and pressure 
indicating devices must be accurate within the parameters defined in CGA 
C-1.
    (ii) Each cylinder must be tested to a minimum of 2 times service 
pressure.
    (iii) The minimum test pressure must be maintained at least 30 
seconds and sufficiently longer to ensure complete expansion. Any 
internal pressure applied after heat-treatment and prior to the official 
test may not exceed 90 percent of the test pressure. If, due to failure 
of the test apparatus or operator error, the test pressure cannot be 
maintained, the test may be repeated in accordance with CGA C-1, section 
5.7.2.
    (iv) Permanent volumetric expansion may not exceed 10 percent of the 
total volumetric expansion at test pressure.
    (2) Pressure testing. (i) The remaining cylinders in the lot must be 
tested by the proof pressure, water-jacket, or direct expansion test 
method as prescribed in CGA C-1. The minimum test pressure must be 
maintained for the specific timeframe and the testing equipment must be 
calibrated as prescribed in CGA C-1. Further, all testing equipment and 
pressure indicating devices must be accurate within the parameters 
defined in CGA C-1. If, due to failure of the test apparatus or operator 
error, the test pressure cannot be maintained, the test may be repeated 
in accordance with CGA C-1, sections 5.7.2 or 7.1.2, as appropriate. 
Determination of expansion properties is not required.
    (ii) Each cylinder must be tested to a minimum of at least two (2) 
times service pressure and show no defect.
    (j) Mechanical test. A mechanical test must be conducted to 
determine yield strength, tensile strength, elongation as a percentage, 
and reduction of area of material as a percentage as follows:
    (1) Testing is required on two (2) specimens removed from one (1) 
cylinder, or part thereof, heat-treated as required, as illustrated in 
appendix A to this subpart. For lots of 30 or fewer, mechanical tests 
are authorized to be made on a ring at least 8 inches long removed from 
each cylinder and subjected to the same heat treatment as the finished 
cylinder.
    (2) Specimens must comply with the following:

[[Page 48]]

    (i) When a cylinder wall is \3/16\ inch thick or less, one the 
following gauge lengths is authorized: A gauge length of 8 inches with a 
width not over 1\1/2\ inches, a gauge length of 2 inches with a width 
not over 1\1/2\ inches, or a gauge length at least twenty-four (24) 
times the thickness with a width not over six (6) times the thickness.
    (ii) The specimen, exclusive of grip ends, may not be flattened. 
Grip ends may be flattened to within one inch of each end of the reduced 
section.
    (iii) When the size of a cylinder does not permit securing straight 
specimens, the specimens may be taken in any location or direction and 
may be straightened or flattened cold, by pressure only, not by blows. 
When specimens are taken and prepared using this method, the inspector's 
report must show detailed information regarding such specimens in 
connection with the record of mechanical tests.
    (iv) Heating of a specimen for any purpose is not authorized.
    (3) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gauge length. The following 
conditions apply:
    (i) The yield strength must be determined by either the ``offset'' 
method or the ``extension under load'' method as prescribed in ASTM E 8 
(IBR, see Sec.  171.7 of this subchapter).
    (ii) In using the ``extension under load'' method, the total strain 
(or ``extension under load'') corresponding to the stress at which the 
0.2 percent permanent strain occurs may be determined with sufficient 
accuracy by calculating the elastic extension of the gauge length under 
appropriate load and adding thereto 0.2 percent of the gauge length. 
Elastic extension calculations must be based on an elastic modulus of 
30,000,000. In the event of controversy, the entire stress-strain 
diagram must be plotted and the yield strength determined from the 0.2 
percent offset.
    (iii) For strain measurement, the initial strain reference must be 
set while the specimen is under a stress of 12,000 psig, and strain 
indicator reading must be set at the calculated corresponding strain.
    (iv) Cross-head speed of the testing machine may not exceed \1/8\ 
inch per minute during yield strength determination.
    (v) The yield strength must not exceed 73 percent of the tensile 
strength.
    (k) Elongation. Mechanical test specimens must show at least a 40 
percent elongation for a 2-inch gauge length or at least 20 percent in 
other cases. However, elongation percentages may be reduced numerically 
by 2 percent for 2-inch specimens, and by 1 percent in other cases, for 
each 7,500 psig increase of tensile strength above 50,000 psig. The 
tensile strength may be incrementally increased by four increments of 
7,500 psig for a maximum total of 30,000 psig.
    (l) Flattening test--(1) Cylinders. After pressure testing, a 
flattening test must be performed on one cylinder taken at random out of 
each lot of 200 or fewer by placing the cylinder between wedge-shaped 
knife edges having a 60 degree included angle, rounded to a half-inch 
radius. The longitudinal axis of the cylinder must be at a 90-degree 
angle to knife edges during the test. For lots of 30 or fewer, 
flattening tests are authorized to be performed on a ring of at least 8 
inches long removed from each cylinder and subjected to the same heat 
treatment as the finished cylinder.
    (2) Pipes. When cylinders are constructed of lap welded pipe, an 
additional flattening test is required, without evidence of cracking, up 
to six (6) times the wall thickness. In such case, the rings (crop ends) 
removed from each end of the pipe, must be tested with the weld 45 
[deg]F or less from the point of greatest stress.
    (m) Acceptable results for flattening tests. There must be no 
evidence of cracking of the sample when it is flattened between flat 
plates to no more than six (6) times the wall thickness. If this test 
fails, one additional sample from the same lot may be taken. If this 
second sample fails, the entire lot must be rejected.
    (n) Rejected cylinders. Reheat treatment is authorized for a 
rejected cylinder in accordance with this paragraph (n). After reheat 
treatment, a cylinder must pass all prescribed tests

[[Page 49]]

in this section to be considered acceptable. Repair of brazed seams by 
brazing and welded seams by welding is authorized. For cylinders with an 
outside diameter of less than or equal to six (6) inches, welded seam 
repairs greater than one (1) inch in length shall require reheat 
treatment of the cylinder. For cylinders greater than an outside 
diameter of 6 inches, welded seam repairs greater than three (3) inches 
in length shall require reheat treatment.
    (o) Markings. (1) Markings must be as required as in Sec.  178.35 
and in addition must be stamped plainly and permanently in any of the 
following locations on the cylinder:
    (i) On shoulders and top heads whose wall thickness is not less than 
0.087-inch thick;
    (ii) On side wall adjacent to top head for side walls which are not 
less than 0.090 inch thick;
    (iii) On a cylindrical portion of the shell that extends beyond the 
recessed bottom of the cylinder, constituting an integral and non-
pressure part of the cylinder;
    (iv) On a metal plate attached to the top of the cylinder or 
permanent part thereof; sufficient space must be left on the plate to 
provide for stamping at least six retest dates; the plate must be at 
least \1/16\-inch thick and must be attached by welding, or by brazing. 
The brazing rod must melt at a temperature of 1100 [deg]F. Welding or 
brazing must be along all the edges of the plate;
    (v) On the neck, neckring, valve boss, valve protection sleeve, or 
similar part permanently attached to the top of the cylinder; or
    (vi) On the footring permanently attached to the cylinder, provided 
the water capacity of the cylinder does not exceed 30 pounds.
    (2) Embossing the cylinder head or sidewall is not permitted.

[85 FR 85422, Dec. 28, 2020, as amended at 87 FR 79784, Dec. 27, 2022]



Sec.  178.51  Specification 4BA welded or brazed steel cylinders.

    (a) Type, size, pressure, and application. A DOT 4BA cylinder is a 
cylinder, either spherical or cylindrical design, with a water capacity 
of 1,000 pounds or less and a service pressure range of 225 to 500 psig. 
Closures made by the spinning process are not authorized.
    (1) Spherical type cylinder designs are permitted to have only one 
circumferentially welded seam.
    (2) Cylindrical type cylinder designs must be of circumferentially 
welded or brazed construction; longitudinally brazed or silver-soldered 
seams are also permitted.
    (b) Steel. The steel used in the construction of the cylinder must 
be as specified in table 1 of appendix A to this part. The cylinder 
manufacturer must maintain a record of intentionally added alloying 
elements.
    (c) Identification of material. Pressure-retaining material must be 
identified by any suitable method that does not compromise the integrity 
of the cylinder. Plates and billets for hotdrawn cylinders must be 
marked with the heat number.
    (d) Manufacture. Cylinders must be manufactured using equipment and 
processes adequate to ensure that each cylinder produced conforms to the 
requirements of this subpart. No defect is permitted that is likely to 
weaken the finished cylinder appreciably. A reasonably smooth and 
uniform surface finish is required. Exposed bottom welds on cylinders 
over 18 inches long must be protected by footrings.
    (1) Seams must be made as follows:
    (i) Minimum thickness of heads and bottoms must be not less than 90 
percent of the required thickness of the side wall.
    (ii) Circumferential seams must be made by welding or by brazing. 
Heads attached by brazing must have a driving fit with the shell unless 
the shell is crimped, swedged, or curled over the skirt or flange of the 
head and must be thoroughly brazed until complete penetration by the 
brazing material of the brazed joint is secured. Depth of brazing from 
end of the shell must be at least four (4) times the thickness of shell 
metal.
    (iii) Longitudinal seams in shells must be made by copper brazing, 
copper alloy brazing, or by silver alloy brazing. Copper alloy 
composition must be: Copper 95 percent minimum, Silicon 1.5 percent to 
3.85 percent, Manganese 0.25 percent to 1.10 percent. The

[[Page 50]]

melting point of the silver alloy brazing material must be in excess of 
1,000 [deg]F. The plate edge must be lapped at least eight times the 
thickness of plate, laps being held in position, substantially metal to 
metal, by riveting or by electric spot-welding. Brazing must be done by 
using a suitable flux and by placing brazing material on one side of 
seam and applying heat until this material shows uniformly along the 
seam of the other side. Strength of longitudinal seam: Copper brazed 
longitudinal seam must have strength at least \3/2\ times the strength 
of the steel wall.
    (2) Welding procedures and operators must be qualified in 
conformance with CGA C-3 (IBR, see Sec.  171.7 of this subchapter).
    (e) Welding or brazing. Welding or brazing of any attachment or 
opening to the heads of cylinders is permitted provided the carbon 
content of the steel does not exceed 0.25 percent except in the case of 
4130 x steel, which may be used with proper welding procedure.
    (f) Wall thickness. The minimum wall thickness of the cylinder must 
meet the following conditions:
    (1) For any cylinder with an outside diameter of greater than 6 
inches, the minimum wall thickness is 0.078 inch. In any case, the 
minimum wall thickness must be such that the calculated wall stress at 
the minimum test pressure may not exceed the lesser value of any of the 
following:
    (i) The value shown in table 1 of appendix A to this part, for the 
material under consideration;
    (ii) One-half of the minimum tensile strength of the material 
determined as required in paragraph (j) of this section;
    (iii) 35,000 psig; or
    (iv) Further provided that wall stress for cylinders having copper 
brazed longitudinal seams may not exceed 95 percent of any of the above 
values. Measured wall thickness may not include galvanizing or other 
protective coating.
    (2) Cylinders that are cylindrical in shape must have the wall 
stress calculated by the formula:

S = [P(1.3D\2\ + 0.4d\2\)]/(D\2\ - d\2\)

Where:
S = wall stress in psig;
P = minimum test pressure prescribed for water jacket test;
D = outside diameter in inches; and
d = inside diameter in inches.

    (3) Cylinders that are spherical in shape must have the wall stress 
calculated by the formula:

S = PD/4tE
Where:
S = wall stress in psig;
P = minimum test pressure prescribed for water jacket test;
D = outside diameter in inches;
t = minimum wall thickness in inches;
E = 0.85 (provides 85 percent weld efficiency factor which must be 
          applied in the circumferential weld area and heat affected 
          zones which zone must extend a distance of 6 times wall 
          thickness from center line of weld); and
E = 1.0 (for all other areas).

    (4) For a cylinder with a wall thickness less than 0.100 inch, the 
ratio of tangential length to outside diameter may not exceed 4.1.
    (g) Heat treatment. Cylinders must be heat treated in accordance 
with the following requirements:
    (1) Each cylinder must be uniformly and properly heat treated prior 
to test by the applicable method shown in table 1 of appendix A to this 
part. Heat treatment must be accomplished after all forming and welding 
operations, except that when brazed joints are used, heat treatment must 
follow any forming and welding operations, but may be done before, 
during or after the brazing operations (see paragraph (m) of this 
section for weld repairs).
    (2) Heat treatment is not required after the welding or brazing of 
weldable low carbon parts to attachments of similar material which have 
been previously welded or brazed to the top or bottom of cylinders and 
properly heat treated, provided such subsequent welding or brazing does 
not produce a temperature in excess of 400 [deg]F in any part of the top 
or bottom material.
    (h) Openings in cylinders. Openings in cylinders must comply with 
the following requirements:
    (1) Any opening must be placed on other than a cylindrical surface.

[[Page 51]]

    (2) Each opening in a spherical type cylinder must be provided with 
a fitting, boss, or pad of weldable steel securely attached to the 
container by fusion welding.
    (3) Each opening in a cylindrical type cylinder must be provided 
with a fitting, boss, or pad, securely attached to container by brazing 
or by welding.
    (4) If threads are used, they must comply with the following:
    (i) Threads must be clean-cut, even, without checks and tapped to 
gauge.
    (ii) Taper threads must be of a length not less than that specified 
for American Standard taper pipe threads.
    (iii) Straight threads, having at least 4 engaged threads, must have 
a tight fit and a calculated shear strength of at least 10 times the 
test pressure of the cylinder. Gaskets, adequate to prevent leakage, are 
required.
    (i) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:
    (1) Lot testing. (i) At least one (1) cylinder randomly selected out 
of each lot of 200 or fewer must be tested by water jacket or direct 
expansion method as prescribed in CGA C-1 (IBR, see Sec.  171.7 of this 
subchapter). The testing equipment must be calibrated as prescribed in 
CGA C-1. All testing equipment and pressure indicating devices must be 
accurate within the parameters defined in CGA C-1.
    (ii) The selected cylinder must be tested to a minimum of two (2) 
times service pressure.
    (iii) The minimum test pressure must be maintained at least 30 
seconds and sufficiently longer to ensure complete expansion. Any 
internal pressure applied after heat-treatment and prior to the official 
test may not exceed 90 percent of the test pressure. If, due to failure 
of the test apparatus or operator error, the test pressure cannot be 
maintained, the test may be repeated in accordance with CGA C-1, section 
5.7.2.
    (iv) Permanent volumetric expansion may not exceed 10 percent of the 
total volumetric expansion at test pressure.
    (2) Pressure testing. (i) The remaining cylinders in the lot must be 
tested by the proof pressure, water-jacket, or direct expansion test 
method as prescribed in CGA C-1. The minimum test pressure must be 
maintained for the specific timeframe and the testing equipment must be 
calibrated as prescribed in CGA C-1. Further, all testing equipment and 
pressure indicating devices must be accurate within the parameters 
defined in CGA C-1.
    (ii) Each cylinder must be tested to a minimum of two (2) times 
service pressure and show no defect. If, due to failure of the test 
apparatus or operator error, the test pressure cannot be maintained, the 
test may be repeated in accordance with CGA C-1 5.7.2 or 7.1.2, as 
appropriate. Determination of expansion properties is not required.
    (j) Mechanical test. (1) A mechanical test must be conducted to 
determine yield strength, tensile strength, elongation as a percentage, 
and reduction of area of material as a percentage, as follows:
    (i) Cylinders. Testing is required on two (2) specimens removed from 
one cylinder or part thereof taken at random out of each lot of 200 or 
fewer. Samples must be removed after heat treatment as illustrated in 
appendix A to this subpart.
    (ii) Spheres. Testing is required on two (2) specimens removed from 
the sphere or flat representative sample plates of the same heat of 
material taken at random from the steel used to produce the spheres. 
Samples (including plates) must be taken from each lot of 200 or fewer. 
The flat steel from which two specimens are to be removed must receive 
the same heat treatment as the spheres themselves. Samples must be 
removed after heat treatment as illustrated in appendix A to this 
subpart.
    (2) Specimens must comply with the following:
    (i) When a cylinder wall is \3/16\ inch thick or less, one the 
following gauge lengths is authorized: A gauge length of 8 inches with a 
width not over 1\1/2\ inches, a gauge length of 2 inches with a width 
not over 1\1/2\ inches, or a gauge length at least twenty-four (24) 
times the thickness with a width not over six (6) times the thickness.
    (ii) The specimen, exclusive of grip ends, may not be flattened. 
Grip ends may be flattened to within one inch of each end of the reduced 
section.

[[Page 52]]

    (iii) When size of the cylinder does not permit securing straight 
specimens, the specimens may be taken in any location or direction and 
may be straightened or flattened cold, by pressure only, not by blows. 
When specimens are so taken and prepared, the inspector's report must 
show with the record of physical tests detailed information in regard to 
such specimens.
    (iv) Heating of a specimen for any purpose is not authorized.
    (3) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gauge length. The following 
conditions apply:
    (i) The yield strength must be determined by either the ``offset'' 
method or the ``extension under load'' method as prescribed in ASTM E 8 
(IBR, see Sec.  171.7 of this subchapter).
    (ii) In using the ``extension under load'' method, the total strain 
(or ``extension under load''), corresponding to the stress at which the 
0.2 percent permanent strain occurs may be determined with sufficient 
accuracy by calculating the elastic extension of the gauge length under 
appropriate load and adding thereto 0.2 percent of the gauge length. 
Elastic extension calculations must be based on an elastic modulus of 
30,000,000. In the event of controversy, the entire stress-strain 
diagram must be plotted and the yield strength determined from the 0.2 
percent offset.
    (iii) For strain measurement, the initial strain reference must be 
set while the specimen is under a stress of 12,000 psig, and the strain 
indicator reading must be set at the calculated corresponding strain.
    (k) Elongation. Mechanical test specimens must show at least a 40 
percent elongation for a 2-inch gauge length or at least 20 percent in 
other cases. However, elongation percentages may be reduced numerically 
by 2 percent for 2-inch specimens, and by 1 percent in other cases, for 
each 7,500 psig increase of tensile strength above 50,000 psig. The 
tensile strength may be incrementally increased by four increments of 
7,500 psig for a maximum total of 30,000 psig.
    (l) Tests of welds. Except for brazed seams, welds must be tested as 
follows:
    (1) Tensile test. A specimen must be removed from one cylinder of 
each lot of 200 or fewer, or welded test plate. The welded test plate 
must be of one of the heats in the lot of 200 or fewer which it 
represents, in the same condition and approximately the same thickness 
as the cylinder wall except that in no case must it be of a lesser 
thickness than that required for a quarter size Charpy impact specimen. 
The weld must be made by the same procedures and subjected to the same 
heat treatment as the major weld on the cylinder. The specimen must be 
taken from across the major seam and must be prepared and tested in 
conformance with and must meet the requirements of CGA C-3. Should this 
specimen fail to meet the requirements, one additional specimen must be 
taken from two additional cylinders or welded test plates from the same 
lot and tested. If either of these latter two specimens fail to meet the 
requirements, the entire lot represented must be rejected.
    (2) Guided bend test. A root bend test specimen must be removed from 
the cylinder or welded test plate that was used for the tensile test 
specified in paragraph (l)(1) of this section. The specimen must be 
taken from across the circumferential seam and must be prepared and 
tested in conformance with and must meet the requirements of CGA C-3. 
Should this specimen fail to meet the requirements, one additional 
specimen must be taken from two additional cylinders or welded test 
plates from the same lot and tested. If either of these latter two 
specimens fail to meet the requirements, the entire lot represented must 
be rejected.
    (3) Alternate guided-bend test. This test may be used and must be as 
required by CGA C-3. The specimen must be bent until the elongation at 
the outer surface, adjacent to the root of the weld, between the lightly 
scribed gage lines a to b, must be at least 20 percent, except that this 
percentage may be reduced for steels having a tensile strength in excess 
of 50,000 psig, as provided in paragraph (k) of this section. Should the 
specimen fail to meet the requirements, one additional specimen must be 
taken from two additional cylinders or welded test plates

[[Page 53]]

from the same lot and tested. If any of these latter two specimens fail 
to meet the requirements, the entire lot represented must be rejected.
    (m) Rejected cylinders. Reheat treatment is authorized for a 
rejected cylinder in accordance with this paragraph (m). After reheat, a 
cylinder must pass all prescribed tests in this section to be 
acceptable. Repair of brazed seams by brazing and welded seams by 
welding is considered authorized. For cylinders with an outside diameter 
of less than or equal to six (6) inches, welded seam repairs greater 
than one (1) inch in length shall require reheat treatment of the 
cylinder. For cylinders greater than an outside diameter of six (6) 
inches, welded seam repairs greater than three (3) inches in length 
shall require reheat treatment.
    (n) Markings. (1) Markings must be as required in Sec.  178.35 and 
in addition must be stamped plainly and permanently in one of the 
following locations on the cylinder:
    (i) On shoulders and top heads whose wall thickness is not less than 
0.087 inch thick;
    (ii) On side wall adjacent to top head for side walls not less than 
0.090 inch thick;
    (iii) On a cylindrical portion of the shell that extends beyond the 
recessed bottom of the cylinder constituting an integral and non-
pressure part of the cylinder;
    (iv) On a plate attached to the top of the cylinder or permanent 
part thereof; sufficient space must be left on the plate to provide for 
stamping at least six retest dates; the plate must be at least \1/16\ 
inch thick and must be attached by welding, or by brazing at a 
temperature of at least 1100 [deg]F., throughout all edges of the plate;
    (v) On the neck, neckring, valve boss, valve protection sleeve, or 
similar part permanently attached to the top of the cylinder; or
    (vi) On the footring permanently attached to the cylinder, provided 
the water capacity of the cylinder does not exceed 30 pounds.
    (2) [Reserved]

[85 FR 85424, Dec. 28, 2020]



Sec.  178.53  Specification 4D welded steel cylinders for aircraft use.

    (a) Type, size, and service pressure. A DOT 4D cylinder is a welded 
steel sphere (two seamless hemispheres) or circumferentially welded 
cylinder (two seamless drawn shells) with a water capacity not over 100 
pounds and a service pressure of at least 300 but not over 500 psig. 
Cylinders closed in by spinning process are not authorized.
    (b) Steel. Open-hearth or electric steel of uniform and weldable 
quality must be used. Content may not exceed the following: Carbon, 
0.25; phosphorus, 0.045; sulphur, 0.050, except that the following 
steels commercially known as 4130X and Type 304, 316, 321, and 347 
stainless steels may be used with proper welding procedure. A heat of 
steel made under table 1 in this paragraph (b), check chemical analysis 
of which is slightly out of the specified range, is acceptable, if 
satisfactory in all other respects, provided the tolerances shown in 
table 2 in this paragraph (b) are not exceeded, except as approved by 
the Associate Administrator. The following chemical analyses are 
authorized:

                          Table 1--4130X Steel
------------------------------------------------------------------------
                   4130X                               Percent
------------------------------------------------------------------------
Carbon.....................................  0.25/0.35.
Manganese..................................  0.40/0.60.
Phosphorus.................................  0.04 max.
Sulphur....................................  0.05 max
Silicon....................................  0.15/0.35.
Chromium...................................  0.80/1.10.
Molybdenum.................................  0.15/0.25.
Zirconium..................................  None.
Nickel.....................................  None.
------------------------------------------------------------------------


                                      Table 2--Authorized Stainless Steels
----------------------------------------------------------------------------------------------------------------
                                                                         Stainless steels
                                                 ---------------------------------------------------------------
                                                   304 (percent)   316 (percent)   321 (percent)   347 (percent)
----------------------------------------------------------------------------------------------------------------
Carbon (max)....................................            0.08            0.08            0.08            0.08
Manganese (max).................................            2.00            2.00            2.00            2.00
Phosphorus (max)................................            .030            .045            .030            .030
Sulphur (max)...................................            .030            .030            .030            .030

[[Page 54]]

 
Silicon (max)...................................             .75            1.00             .75             .75
Nickel..........................................        8.0/11.0       10.0/14.0        9.0/13.0        9.0/13.0
Chromium........................................       18.0/20.0       16.0/18.0       17.0/20.0       17.0/20.0
Molybdenum......................................  ..............         2.0/3.0  ..............  ..............
Titanium........................................  ..............  ..............           (\1\)  ..............
Columbium.......................................  ..............  ..............  ..............           (\2\)
----------------------------------------------------------------------------------------------------------------
\1\ Titanium may not be less than 5C and not more than 0.60%.
\2\ Columbium may not be less than 10C and not more than 1.0%.


                                       Table 3--Check Analysis Tolerances
----------------------------------------------------------------------------------------------------------------
                                                                                        Tolerance (percent) over
                                                                                          the maximum limit or
                                                                                         under the minimum limit
            Element                       Limit or maximum specified (percent)         -------------------------
                                                                                           Under         Over
                                                                                          minimum      maximum
                                                                                           limit        limit
----------------------------------------------------------------------------------------------------------------
Carbon.........................  To 0.15 incl.........................................         0.01         0.01
                                 Over 0.15 to 0.40 incl...............................          .03          .04
Manganese......................  To 0.60 incl.........................................          .03          .03
                                 Over 1.15 to 2.50 incl...............................          .05          .05
Phosphorus \1\.................  All ranges...........................................  ...........          .01
Sulphur........................  All ranges...........................................  ...........          .01
Silicon........................  To 0.30 incl.........................................          .02          .03
                                 Over 0.30 to 1.00 incl...............................          .05          .05
Nickel.........................  Over 5.30 to 10.00 incl..............................          .10          .10
                                 Over 10.00 to 14.00 incl.............................          .15          .15
Chromium.......................  To 0.90 incl.........................................          .03          .03
                                 Over 0.90 to 2.10 incl...............................          .05          .05
                                 Over 15.00 to 20.00 incl.............................          .20          .20
Molybdenum.....................  To 0.20 incl.........................................          .01          .01
                                 Over 0.20 to 0.40 incl...............................          .02          .02
                                 Over 1.75 to 3.0 incl................................          .10          .10
Titanium.......................  All ranges...........................................          .05          .05
Columbium......................  All ranges...........................................          .05          .05
----------------------------------------------------------------------------------------------------------------
\1\ Rephosphorized steels not subject to check analysis for phosphorus.

    (c) Identification of material. Material must be identified by any 
suitable method except that plates and billets for hotdrawn cylinders 
must be marked with the heat number.
    (d) Manufacture. Cylinders must be manufactured using equipment and 
processes adequate to ensure that each cylinder produced conforms to the 
requirements of this subpart. No defect is permitted that is likely to 
weaken the finished container appreciably. A reasonably smooth and 
uniform surface finish is required. Welding procedures and operators 
must be qualified in accordance with CGA Pamphlet C-3 (IBR, see Sec.  
171.7 of this subchapter).
    (e) Wall thickness. The wall stress at the minimum test pressure may 
not exceed 24,000 psi, except where steels commercially known as 4130X, 
types 304, 316, 321, and 347 stainless steels are used, stress at the 
test pressures may not exceed 37,000 psi. The minimum wall thickness for 
any container having a capacity of 1,100 cubic inches or less is 0.04 
inch. The minimum wall thickness for any container having a capacity in 
excess of 1,100 cubic inches is 0.095 inch. Calculations must be done by 
the following:
    (1) Calculation for a ``sphere'' must be made by the formula:

S = PD / 4tE

Where:

S = wall stress in psi;
P = test pressure prescribed for water jacket test, i.e., at least two 
          times service pressure, in psig;
D = outside diameter in inches;
t = minimum wall thickness in inches;
E = 0.85 (provides 85 percent weld efficiency factor which must be 
          applied in the girth weld area and heat affected zones which

[[Page 55]]

          zone must extend a distance of 6 times wall thickness from 
          center line of weld);
E = 1.0 (for all other areas).

    (2) Calculation for a cylinder must be made by the formula:

S = [P(1.3D\2\ + 0.4d\2\)] / (D\2\ - d\T12\)

Where:

S = wall stress in psi;
P = test pressure prescribed for water jacket test, i.e., at least two 
          times service pressure, in psig;
D = outside diameter in inches;
d = inside diameter in inches.

    (f) Heat treatment. The completed cylinders must be uniformly and 
properly heat-treated prior to tests.
    (g) Openings in container. Openings in cylinders must comply with 
the following:
    (1) Each opening in the container, except those for safety devices, 
must be provided with a fitting, boss, or pad, securely attached to the 
container by brazing or by welding or by threads. If threads are used, 
they must comply with the following:
    (i) Threads must be clean cut, even, without checks, and tapped to 
gauge.
    (ii) Taper threads must be of a length not less than that specified 
for American Standard taper pipe threads.
    (iii) Straight threads, having at least 4 engaged threads, must have 
a tight fit and calculated shear strength of at least 10 times the test 
pressure of the container. Gaskets, adequate to prevent leakage, are 
required.
    (2) Closure of a fitting, boss, or pad must be adequate to prevent 
leakage.
    (h) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:
    (1) Lot testing. (i) At least one cylinder selected at random out of 
each lot of 200 or fewer must be tested by water-jacket or direct 
expansion as prescribed in CGA C-1 (IBR; see Sec.  171.7 of this 
subchapter). The testing equipment must be calibrated as prescribed in 
CGA C-1. All testing equipment and pressure indicating devices must be 
accurate within the parameters defined in CGA C-1.
    (ii) The selected cylinder must be tested to a minimum of three (3) 
times service pressure.
    (iii) The minimum test pressure must be maintained be maintained at 
least 30 seconds and sufficiently longer to ensure complete expansion. 
Any internal pressure applied after heat-treatment and prior to the 
official test may not exceed 90 percent of the test pressure. If, due to 
failure of the test apparatus or operator error, the test pressure 
cannot be maintained, the test may be repeated in accordance with CGA C-
1, section 5.7.2.
    (iv) Permanent volumetric expansion may not exceed 10 percent of the 
total volumetric expansion at test pressure.
    (2) Pressure testing. (i) The remaining cylinders in each lot must 
be tested by the proof pressure water-jacket or direct expansion test 
method as prescribed in CGA C-1. The minimum test pressure must be 
maintained for the specific timeframe and the testing equipment must be 
calibrated as prescribed in CGA C-1. Further, all testing equipment and 
pressure indicating devices must be accurate within the parameters 
defined in CGA C-1. Determination of expansion properties is not 
required.
    (ii) Each cylinder must be tested to a minimum of two (2) times 
service pressure and show no defect. If, due to failure of the test 
apparatus or operator error, the test pressure cannot be maintained, the 
test may be repeated in accordance with CGA C-1 5.7.2 or 7.1.2, as 
appropriate.
    (3) Alternative volumetric expansion testing. As an alternative to 
the testing prescribed in paragraphs (h)(1) and (2) of this section, 
every cylinder may be volumetrically expansion tested by the water 
jacket or direct expansion test method. The testing equipment must be 
calibrated as prescribed in CGA C-1. All testing equipment and pressure 
indicating devices must be accurate within the parameters defined in CGA 
C-1.
    (i) Each cylinder must be tested to a minimum of at least two (2) 
times its service pressure.
    (ii) The minimum test pressure must be maintained at least 30 
seconds and sufficiently longer to ensure complete expansion. Any 
internal pressure applied after heat-treatment and previous to the 
official test may not exceed 90 percent of the test pressure. If, due to 
failure of the test apparatus or operator error, the test pressure 
cannot be maintained, the test may be repeated

[[Page 56]]

in accordance with CGA C-1, section 5.7.2.
    (iii) Permanent volumetric expansion may not exceed 10 percent of 
total volumetric expansion at test pressure.
    (i) Flattening test for spheres and cylinders. Spheres and cylinders 
must be subjected to a flattening test as follows:
    (1) One sphere taken at random out of each lot of 200 or less must 
be subjected to a flattening test as follows:
    (i) The test must be performed after the hydrostatic test.
    (ii) The test must be between parallel steel plates on a press with 
a welded seam at right angles to the plates. Any projecting 
appurtenances may be cut off (by mechanical means only) prior to 
crushing.
    (2) One cylinder taken at random out of each lot of 200 or less must 
be subjected to a flattening test, as follows:
    (i) The test must be performed after the hydrostatic test.
    (ii) The test must be between knife edges, wedge shaped, 60[deg] 
angle, rounded to \1/2\ inch radius. For lots of 30 or less, physical 
tests are authorized to be made on a ring at least 8 inches long cut 
from each cylinder and subjected to the same heat treatment as the 
finished cylinder.
    (j) Physical test and specimens for spheres and cylinders. Spheres 
and cylinders must be subjected to a physical test as follows:
    (1) Physical test for spheres are required on 2 specimens cut from a 
flat representative sample plate of the same heat taken at random from 
the steel used to produce the sphere. This flat steel from which the 2 
specimens are to be cut must receive the same heat-treatment as the 
spheres themselves. Sample plates must be taken for each lot of 200 or 
less spheres.
    (2) Specimens for spheres must have a gauge length 2 inches with a 
width not over 1\1/2\ inches, or a gauge length at least 24 times the 
thickness with a width not over 6 times the thickness is authorized when 
a wall is not over \3/16\ inch thick.
    (3) Physical test for cylinders is required on 2 specimens cut from 
1 cylinder taken at random out of each lot of 200 or less. For lots of 
30 or less, physical tests are authorized to be made on a ring at least 
8 inches long cut from each cylinder and subjected to the same heat 
treatment as the finished cylinder.
    (4) Specimens for cylinders must conform to the following:
    (i) A gauge length of 8 inches with a width not over 1\1/2\ inches, 
or a gauge length of 2 inches with a width not over 1\1/2\ inches, or a 
gauge length at least 24 times the thickness with a width not over 6 
times the thickness is authorized when a cylinder wall is not over \3/
16\ inch thick.
    (ii) The specimen, exclusive of grip ends, may not be flattened. 
Grip ends may be flattened to within 1 inch of each end of the reduced 
section. Heating of the specimen for any purpose is not authorized.
    (5) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gauge length. The following 
conditions apply:
    (i) The yield strength must be determined by either the ``offset'' 
method or the ``extension under load'' method as prescribed in ASTM E 8 
(IBR, see Sec.  171.7 of this subchapter).
    (ii) In using the ``extension under load'' method, the total strain 
(or ``extension under load'') corresponding to the stress at which the 
0.2 percent permanent strain occurs may be determined with sufficient 
accuracy by calculating the elastic extension of the gauge length under 
appropriate load and adding thereto 0.2 percent of the gauge length. 
Elastic extension calculations must be based on an elastic modulus of 
30,000,000. In the event of controversy, the entire stress-strain 
diagram must be plotted and the yield strength determined from the 0.2 
percent offset.
    (iii) For the purpose of strain measurement, the initial strain must 
be set while the specimen is under a stress of 12,000 psi and the strain 
indicator reading being set at the calculated corresponding strain.
    (iv) Cross-head speed of the testing machine may not exceed \1/8\ 
inch per minute during yield strength determination.
    (k) Acceptable results for physical and flattening tests. Either of 
the following is an acceptable result:

[[Page 57]]

    (1) An elongation of at least 40 percent for a 2 inch gauge length 
or at least 20 percent in other cases and yield strength not over 73 
percent of tensile strength. In this instance, the flattening test is 
not required.
    (2) An elongation of at least 20 percent for a 2 inch gauge length 
or 10 percent in other cases. Flattening is required to 50 percent of 
the original outside diameter without cracking.
    (l) Rejected cylinders. Reheat-treatment is authorized for rejected 
cylinders. Subsequent thereto, containers must pass all prescribed tests 
to be acceptable. Repair of welded seams by welding prior to reheat-
treatment is authorized.
    (m) Marking. Marking on each container by stamping plainly and 
permanently are only authorized where the metal is at least 0.09 inch 
thick, or on a metal nameplate permanently secured to the container by 
means other than soft solder, or by means that would not reduce the wall 
thickness.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended at 66 FR 45386, 
45388, Aug. 28, 2001; 67 FR 51653, Aug. 8, 2002; 68 FR 75748, Dec. 31, 
2003; 85 FR 85426, Dec. 28, 2020]



Sec.  178.55  Specification 4B240ET welded or brazed cylinders.

    (a) Type, spinning process, size and service pressure. A DOT 4B240ET 
cylinder is a brazed type cylinder made from electric resistance welded 
tubing. The maximum water capacity of this cylinder is 12 pounds or 333 
cubic inches and the service must be 240 psig. The maximum outside 
diameter of the shell must be five inches and maximum length of the 
shell is 21 inches. Cylinders closed in by a spinning process are 
authorized.
    (b) Steel. Open-hearth, basic oxygen, or electric steel of uniform 
quality must be used. Plain carbon steel content may not exceed the 
following: Carbon, 0.25; phosphorus, 0.045; sulfur, 0.050. The addition 
of other elements for alloying effect is prohibited.
    (c) Identification of material. Material must be identified by any 
suitable method.
    (d) Manufacture. Cylinders must be manufactured using equipment and 
processes adequate to ensure that each cylinder produced conforms to the 
requirements of this subpart. No defect is permitted that is likely to 
weaken the finished cylinder appreciably. A reasonably smooth and 
uniform surface finish is required. Heads may be attached to shells by 
lap brazing or may be formed integrally. The thickness of the bottom of 
cylinders welded or formed by spinning is, under no condition, to be 
less than two times the minimum wall thickness of the cylindrical shell. 
Such bottom thicknesses must be measured within an area bounded by a 
line representing the points of contact between the cylinder and the 
floor when the cylinder is in a vertical position. Seams must conform to 
the following:
    (1) Circumferential seams must be by brazing only. Heads must be 
attached to shells by the lap brazing method and must overlap not less 
than four times the wall thickness. Brazing material must have a melting 
point of not less than 1000 [deg]F. Heads must have a driving fit with 
the shell unless the shell is crimped, swedged, or curled over the skirt 
or flange of the head and be thoroughly brazed until complete 
penetration of the joint by the brazing material is secured. Brazed 
joints may be repaired by brazing.
    (2) Longitudinal seams in shell must be by electric resistance 
welded joints only. No repairs to longitudinal joints is permitted.
    (3) Welding procedures and operators must be qualified in accordance 
with CGA C-3 (IBR, see Sec.  171.7 of this subchapter).
    (e) Welding or brazing. Only the attachment, by welding or brazing, 
to the tops and bottoms of cylinders of neckrings, footrings, handles, 
bosses, pads, and valve protection rings is authorized. Provided that 
such attachments and the portion of the container to which they are 
attached are made of weldable steel, the carbon content of which may not 
exceed 0.25 percent.
    (f) Wall thickness. The wall stress must be at least two times the 
service pressure and may not exceed 18,000 psi. The minimum wall 
thickness is 0.044 inch. Calculation must be made by the following 
formula:

S = [P(1.3D\2\ + 0.4d\2\)] / (D\2\ - d\2\)

Where:


[[Page 58]]


S = wall stress in psig;
P = 2 times service pressure;
D = outside diameter in inches;
d = inside diameter in inches.

    (g) Heat treatment. Heads formed by drawing or pressing must be 
uniformly and properly heat treated prior to tests. Cylinders with 
integral formed heads or bases must be subjected to a normalizing 
operation. Normalizing and brazing operations may be combined, provided 
the operation is carried out at a temperature in excess of the upper 
critical temperature of the steel.
    (h) Openings in cylinders. Openings in cylinders must comply with 
the following:
    (1) Each opening in cylinders, except those for safety devices, must 
be provided with a fitting, boss, or pad, securely attached to the 
cylinder by brazing or by welding or by threads. A fitting, boss, or pad 
must be of steel suitable for the method of attachment employed, and 
which need not be identified or verified as to analysis, except that if 
attachment is by welding, carbon content may not exceed 0.25 percent. If 
threads are used, they must comply with the following:
    (i) Threads must be clean cut, even without checks, and tapped to 
gauge.
    (ii) Taper threads to be of length not less than as specified for 
American Standard taper pipe threads.
    (iii) Straight threads, having at least 4 engaged threads, to have 
tight fit and calculated shear strength at least 10 times the test 
pressure of the cylinder; gaskets required, adequate to prevent leakage.
    (2) Closure of a fitting, boss, or pad must be adequate to prevent 
leakage.
    (i) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:
    (1) Lot testing. (i) At least one (1) cylinder selected at random 
out of each lot of 200 or fewer must be tested by water-jacket or direct 
expansion method as prescribed in CGA C-1 (IBR; see Sec.  171.7 of this 
subchapter). The testing equipment must be calibrated as prescribed in 
CGA C-1. All testing equipment and pressure indicating devices must be 
accurate within the parameters defined in CGA C-1.
    (ii) Each cylinder must be tested to a minimum of two (2) times 
service pressure.
    (iii) The minimum test pressure must be maintained at least 30 
seconds and sufficiently longer to ensure complete expansion. Any 
internal pressure applied after heat-treatment and prior to the official 
test may not exceed 90 percent of the test pressure. If, due to failure 
of the test apparatus or operator error, the test pressure cannot be 
maintained, the test may be repeated in accordance with CGA C-1, section 
5.7.2.
    (iv) Permanent volumetric expansion may not exceed 10 percent of the 
total volumetric expansion at test pressure.
    (2) Pressure testing. (i) The remaining cylinders in each lot must 
be tested by the proof pressure water-jacket or direct expansion test 
method as prescribed in CGA C-1. The minimum test pressure must be 
maintained for the specific timeframe and the testing equipment must be 
calibrated as prescribed in CGA C-1. All testing equipment and pressure 
indicating devices must be accurate within the parameters defined in CGA 
C-1.
    (ii) Each cylinder must be tested to a minimum of two (2) times 
service pressure and show no defect. If, due to failure of the test 
apparatus or operator error, the test pressure cannot be maintained, the 
test may be repeated in accordance with CGA C-1 5.7.2 or 7.1.2. 
Determination of expansion properties is not required.
    (3) Burst testing. (i) For purposes of burst testing, each 1,000 
cylinders or fewer successively produced each day constitutes a lot. All 
cylinders of a lot must be of identical size, construction heat 
treatment, finish, and quality.
    (ii) One cylinder must be selected from each lot and be 
hydrostatically pressure tested to destruction. If this cylinder bursts 
below five (5) times the service pressure, then two additional cylinders 
from the same lot as the previously tested cylinder must be selected and 
subjected to this test. If either of these cylinders fails by bursting 
below five (5) times the service pressure then the entire lot must be 
rejected. All testing equipment and pressure indicating devices must be 
accurate within the parameters defined in CGA C-1.

[[Page 59]]

    (i) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:
    (1) Lot testing. (i) At least one (1) cylinder selected at random 
out of each lot of 200 or fewer must be tested by water-jacket or direct 
expansion method as prescribed in CGA C-1 (IBR; see Sec.  171.7 of this 
subchapter). The testing equipment must be calibrated as prescribed in 
CGA C-1. All testing equipment and pressure indicating devices must be 
accurate within the parameters defined in CGA C-1.
    (ii) Each cylinder must be tested to a minimum of two (2) times 
service pressure.
    (iii) The minimum test pressure must be maintained at least 30 
seconds and sufficiently longer to ensure complete expansion. Any 
internal pressure applied after heat-treatment and prior to the official 
test may not exceed 90 percent of the test pressure. If, due to failure 
of the test apparatus or operator error, the test pressure cannot be 
maintained, the test may be repeated in accordance with CGA C-1, section 
5.7.2.
    (iv) Permanent volumetric expansion may not exceed 10 percent of the 
total volumetric expansion at test pressure.
    (2) Pressure testing. (i) The remaining cylinders in each lot must 
be tested by the proof pressure water-jacket or direct expansion test 
method as prescribed in CGA C-1. The minimum test pressure must be 
maintained for the specific timeframe and the testing equipment must be 
calibrated as prescribed in CGA C-1. All testing equipment and pressure 
indicating devices must be accurate within the parameters defined in CGA 
C-1.
    (ii) Each cylinder must be tested to a minimum of two (2) times 
service pressure and show no defect. If, due to failure of the test 
apparatus or operator error, the test pressure cannot be maintained, the 
test may be repeated in accordance with CGA C-1 5.7.2 or 7.1.2. 
Determination of expansion properties is not required.
    (3) Burst testing. (i) For purposes of burst testing, each 1,000 
cylinders or fewer successively produced each day constitutes a lot. All 
cylinders of a lot must be of identical size, construction heat 
treatment, finish, and quality.
    (ii) One cylinder must be selected from each lot and be 
hydrostatically pressure tested to destruction. If this cylinder bursts 
below five (5) times the service pressure, then two additional cylinders 
from the same lot as the previously tested cylinder must be selected and 
subjected to this test. If either of these cylinders fails by bursting 
below five (5) times the service pressure then the entire lot must be 
rejected. All testing equipment and pressure indicating devices must be 
accurate within the parameters defined in CGA C-1.
    (j) Flattening test. Following the hydrostatic test, one cylinder 
taken at random out of each lot of 200 or less, must be subjected to a 
flattening test that is between knife edges, wedge shaped, 60[deg] 
angle, rounded to \1/2\ inch radius.
    (k) Physical test. A physical test must be conducted to determine 
yield strength, tensile strength, elongation, and reduction of area of 
material, as follows:
    (1) The test is required on 2 specimens cut from 1 cylinder, or part 
thereof heat-treated as required, taken at random out of each lot of 200 
or less in the case of cylinders of capacity greater than 86 cubic 
inches and out of each lot of 500 or less for cylinders having a 
capacity of 86 cubic inches or less.
    (2) Specimens must conform to the following:
    (i) A gauge length of 8 inches with a width not over 1\1/2\ inches, 
a gauge length of 2 inches with a width not over 1\1/2\ inches, or a 
gauge length at least 24 times the thickness with a width not over 6 
times the thickness is authorized when a cylinder wall is not over \3/
16\ inch thick.
    (ii) The specimen, exclusive of grip ends, may not be flattened. 
Grip ends may be flattened to within one inch of each end of the reduced 
section.
    (iii) When size of cylinder does not permit securing straight 
specimens, the specimens may be taken in any location or direction and 
may be

[[Page 60]]

straightened or flattened cold by pressure only, not by blows. When 
specimens are so taken and prepared, the inspector's report must show in 
connection with record of physical tests detailed information in regard 
to such specimens.
    (iv) Heating of a specimen for any purpose is not authorized.
    (3) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gauge length. The following 
conditions apply:
    (i) The yield strength must be determined by either the ``offset'' 
method or the ``extension under load'' method as prescribed in ASTM E 8 
(IBR, see Sec.  171.7 of this subchapter).
    (ii) In using the ``extension under load'' method, the total strain 
(or ``extension under load'') corresponding to the stress at which the 
0.2 percent permanent strain occurs may be determined with sufficient 
accuracy by calculating the elastic extension of the gauge length under 
appropriate load and adding thereto 0.2 percent of the gauge length. 
Elastic extension calculations must be based on an elastic modulus of 
30,000,000. In the event of controversy, the entire stress-strain 
diagram must be plotted and the yield strength determined from the 0.2 
percent offset.
    (iii) For the purpose of strain measurement, the initial strain must 
be set while the specimen is under a stress of 12,000 psi and the strain 
indicator reading being set at the calculated corresponding strain.
    (iv) Cross-head speed of the testing machine may not exceed \1/8\ 
inch per minute during yield strength determination.
    (l) Acceptable results for physical and flattening tests. Acceptable 
results for the physical and flattening tests are an elongation of at 
least 40 percent for a 2 inch gauge length or at least 20 percent in 
other cases and a yield strength not over 73 percent of tensile 
strength. In this instance the flattening test is required, without 
cracking, to six times the wall thickness with a weld 90[deg] from the 
direction of the applied load. Two rings cut from the ends of length of 
pipe used in production of a lot may be used for the flattening test 
provided the rings accompany the lot which they represent in all thermal 
processing operations. At least one of the rings must pass the 
flattening test.
    (m) Leakage test. All spun cylinders and plugged cylinders must be 
tested for leakage by gas or air pressure after the bottom has been 
cleaned and is free from all moisture, subject to the following 
conditions:
    (1) Pressure, approximately the same as but no less than service 
pressure, must be applied to one side of the finished bottom over an 
area of at least \1/16\ of the total area of the bottom but not less 
than \3/4\ inch in diameter, including the closure, for at least 1 
minute, during which time the other side of the bottom exposed to 
pressure must be covered with water and closely examined for indications 
of leakage. Except as provided in paragraph (n) of this section, 
cylinders which are leaking must be rejected.
    (2) A spun cylinder is one in which an end closure in the finished 
cylinder has been welded by the spinning process.
    (3) A plugged cylinder is one in which a permanent closure in the 
bottom of a finished cylinder has been effected by a plug.
    (4) As a safety precaution, if the manufacturer elects to make this 
test before the hydrostatic test, he should design his apparatus so that 
the pressure is applied to the smallest area practicable, around the 
point of closure, and so as to use the smallest possible volume of air 
or gas.
    (n) Rejected cylinders. Repairs of rejected cylinders is authorized. 
Cylinders that are leaking must be rejected, except that:
    (1) Spun cylinders rejected under the provisions of paragraph (m) of 
this section may be removed from the spun cylinder category by drilling 
to remove defective material, tapping, and plugging.
    (2) Brazed joints may be rebrazed.
    (3) Subsequent to the operations noted in paragraphs (n)(1) and 
(n)(2) of this section, acceptable cylinders must pass all prescribed 
tests.
    (o) Marking. Markings on each cylinder must be by stamping plainly 
and permanently on shoulder, top head, neck or valve protection collar 
which

[[Page 61]]

is permanently attached to the cylinders and forming an integral part 
thereof, provided that cylinders not less than 0.090 inch thick may be 
stamped on the side wall adjacent to top head.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended at 66 FR 45386, 
Aug. 28, 2001; 67 FR 51653, Aug. 8, 2002; 68 FR 75748, 75749, Dec. 31, 
2003; 85 FR 85426, Dec. 28, 2020]



Sec.  178.56  Specification 4AA480 welded steel cylinders.

    (a) Type, size, and service pressure. A DOT 4AA480 cylinder is a 
welded steel cylinder having a water capacity (nominal) not over 1,000 
pounds water capacity and a service pressure of 480 psig. Closures 
welded by spinning process not permitted.
    (b) Steel. The limiting chemical composition of steel authorized by 
this specification must be as shown in table I of appendix A to this 
part.
    (c) Identification of material. Material must be identified by any 
suitable method except that plates and billets for hotdrawn cylinders 
must be marked with the heat number.
    (d) Manufacture. Cylinders must be manufactured using equipment and 
processes adequate to ensure that each cylinder produced conforms to the 
requirements of this subpart. No defect is permitted that is likely to 
weaken the finished cylinder appreciably. A reasonably smooth and 
uniform surface finish is required. Exposed bottom welds on cylinders 
over 18 inches long must be protected by footrings. Minimum thickness of 
heads and bottoms may not be less than 90 percent of the required 
thickness of the side wall. Seams must be made as follows:
    (1) Circumferential seams must be welded. Brazing is not authorized.
    (2) Longitudinal seams are not permitted.
    (3) Welding procedures and operators must be qualified in accordance 
with CGA C-3 (IBR, see Sec.  171.7 of this subchapter).
    (e) Welding. Only the welding of neckrings, footrings, bosses, pads, 
and valve protection rings to the tops and bottoms of cylinders is 
authorized. Provided that such attachments are made of weldable steel, 
the carbon content of which does not exceed 0.25 percent.
    (f) Wall thickness. The wall thickness of the cylinder must conform 
to the following:
    (1) For cylinders with an outside diameter over 5 inches, the 
minimum wall thickness is 0.078 inch. In any case, the minimum wall 
thickness must be such that the calculated wall stress at the minimum 
test pressure (in paragraph (i) of this section) may not exceed the 
lesser value of either of the following:
    (i) One-half of the minimum tensile strength of the material 
determined as required in paragraph (j) of this section; or
    (ii) 35,000 psi.
    (2) Calculation must be made by the formula:

S = [P(1.3D\2\ + 0.4d\2\)] / (D\2\ - d\2\)

Where:

S = wall stress in psi;
P = minimum test pressure prescribed for water jacket test;
D = outside diameter in inches;
d = inside diameter in inches.

    (3) The ratio of tangential length to outside diameter may not 
exceed 4.0 for cylinders with a wall thickness less than 0.100 inch.
    (g) Heat treatment. Each cylinder must be uniformly and properly 
heat treated prior to tests. Any suitable heat treatment in excess of 
1100 [deg]F is authorized except that liquid quenching is not permitted. 
Heat treatment must be accomplished after all forming and welding 
operations. Heat treatment is not required after welding weldable low 
carbon parts to attachments of similar material which have been 
previously welded to the top or bottom of cylinders and properly heat 
treated, provided such subsequent welding does not produce a temperature 
in excess of 400 [deg]F., in any part of the top or bottom material.
    (h) Openings in cylinders. Openings in cylinders must conform to the 
following:
    (1) All openings must be in the heads or bases.
    (2) Each opening in the cylinder, except those for safety devices, 
must be provided with a fitting boss, or pad, securely attached to the 
cylinder by

[[Page 62]]

welding or by threads. If threads are used they must comply with the 
following:
    (i) Threads must be clean-cut, even without checks and cut to gauge.
    (ii) Taper threads to be of length not less than as specified for 
American Standard taper pipe threads.
    (iii) Straight threads having at least 6 engaged threads, must have 
a tight fit and a calculated shear strength at least 10 times the test 
pressure of the cylinder. Gaskets, adequate to prevent leakage, are 
required.
    (3) Closure of a fitting, boss or pad must be adequate to prevent 
leakage.
    (i) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:
    (1) Lot testing. (i) At least one (1) cylinder selected at random 
out of each lot of 200 or fewer must be tested by water-jacket or direct 
expansion method as prescribed in CGA C-1 (IBR; see Sec.  171.7 of this 
subchapter). The testing equipment must be calibrated as prescribed in 
CGA C-1. All testing equipment and pressure indicating devices must be 
accurate within the parameters defined in CGA C-1.
    (ii) The selected cylinder must be tested to a minimum of two (2) 
times service pressure.
    (iii) The minimum test pressure must be maintained at least 30 
seconds and sufficiently longer to ensure complete expansion. Any 
internal pressure applied after heat-treatment and prior to the official 
test may not exceed 90 percent of the test pressure. If, due to failure 
of the test apparatus or operator error, the test pressure cannot be 
maintained, the test may be repeated in accordance with CGA C-1, section 
5.7.2.
    (iv) Permanent volumetric expansion may not exceed 10 percent of the 
total volumetric expansion at test pressure.
    (v) If the selected cylinder fails, then two (2) additional 
specimens must be selected at random from the same lot and subjected to 
the prescribed testing. If either of these fails the test, then each 
cylinder in that lot must be tested as prescribed in paragraph (i)(l) of 
this section.
    (2) Pressure testing. (i) The remaining cylinders in each lot must 
be tested by the proof pressure, water-jacket, or direct expansion test 
method as prescribed in CGA C-1. The minimum test pressure must be 
maintained for the specific timeframe and the testing equipment must be 
calibrated as prescribed in CGA C-1. Further, all testing equipment and 
pressure indicating devices must be accurate within the parameters 
defined in CGA C-1.
    (ii) Each cylinder must be tested to a minimum of two (2) times 
service pressure and show no defect. A cylinder showing a defect must be 
rejected unless it may be requalified under paragraph (m) of this 
section. If, due to failure of the test apparatus or operator error, the 
test pressure cannot be maintained, the test may be repeated in 
accordance with CGA C-1 5.7.2 or 7.1.2, as appropriate. Determination of 
expansion properties is not required.
    (j) Physical test. A physical test must be conducted to determine 
yield strength, tensile strength, elongation, and reduction of area of 
material, as follows:
    (1) The test is required on 2 specimens cut from one cylinder having 
passed the hydrostatic test, or part thereof heat-treated as required, 
taken at random out of each lot of 200 or less.
    (2) Specimens must conform to the following:
    (i) A gauge length of 8 inches with a width not over 1\1/2\ inches, 
a gauge length of 2 inches with a width not over 1\1/2\ inches, or a 
gauge length at least 24 times the thickness with a width not over 6 
times thickness is authorized when the cylinder wall is not over \3/16\ 
inch thick.
    (ii) The specimen, exclusive of grip ends, may not be flattened. 
Grip ends may be flattened to within one inch of each end of the reduced 
section.
    (iii) When size of cylinder does not permit securing straight 
specimens, the specimens may be taken in any location or direction and 
may be straightened or flattened cold, by pressure only, not by blows. 
When specimens are so taken and prepared, the inspector's report must 
show in connection with record of physical tests detailed information in 
regard to such specimens.
    (iv) Heating of a specimen for any purpose is not authorized.

[[Page 63]]

    (3) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gauge length. The following 
conditions apply:
    (i) The yield strength must be determined by either the ``offset'' 
method or the ``extension under load'' method as prescribed in ASTM E 8 
(IBR, see Sec.  171.7 of this subchapter).
    (ii) In using the ``extension under load'' method, the total strain 
(or ``extension under load''), corresponding to the stress at which the 
0.2 percent permanent strain occurs may be determined with sufficient 
accuracy by calculating the elastic extension of the gauge length under 
appropriate load and adding thereto 0.2 percent of the gauge length. 
Elastic extension calculations must be based on an elastic modulus of 
30,000,000. In the event of controversy, the entire stress-strain 
diagram must be plotted and the yield strength determined from the 0.2 
percent offset.
    (iii) For the purpose of strain measurement, the initial strain 
reference must be set while the specimen is under a stress of 12,000 psi 
and the strain indicator reading being set at the calculated 
corresponding strain.
    (iv) Cross-head speed of the testing machine may not exceed \1/8\ 
inch per minute during yield strength determination.
    (k) Elongation. Physical test specimens must show at least a 40 
percent elongation for 2-inch gauge lengths or at least a 20 percent 
elongation in other cases. Except that these elongation percentages may 
be reduced numerically by 2 for 2-inch specimens and by 1 in other cases 
for each 7,500 psi increment of tensile strength above 50,000 psi to a 
maximum of four such increments.
    (l) Tests of welds. Welds must be tested as follows:
    (1) Tensile test. A specimen must be cut from one cylinder of each 
lot of 200 or less, or a welded test plate. The welded test plate must 
be of one of the heats in the lot of 200 or less which it represents, in 
the same condition and approximately the same thickness as the cylinder 
wall except that it may not be of a lesser thickness than that required 
for a quarter size Charpy impact specimen. The weld must be made by the 
same procedures and subjected to the same heat treatment as the major 
weld on the cylinder. The specimens must be taken across the major seam 
and must be prepared and tested in accordance with and must meet the 
requirements of CGA Pamphlet C-3. Should this specimen fail to meet the 
requirements, specimens may be taken from two additional cylinders or 
welded test plates from the same lot and tested. If either of the latter 
specimens fail to meet the requirements, the entire lot represented must 
be rejected.
    (2) Guided bend test. A root bend test specimen must be cut from the 
cylinder or a welded test plate, used for the tensile test specified in 
paragraph (l)(1) of this section. Specimens must be taken from across 
the major seam and must be prepared and tested in accordance with and 
must meet the requirements of CGA Pamphlet C-3.
    (3) Alternate guided-bend test. This test may be used and must be as 
required by CGA Pamphlet C-3. The specimen must be bent until the 
elongation at the outer surface, adjacent to the root of the weld, 
between the lightly scribed gage lines-a to b, is at least 20 percent, 
except that this percentage may be reduced for steels having a tensile 
strength in excess of 50,000 psi, as provided in paragraph (k) of this 
section.
    (m) Rejected cylinders. Reheat treatment of rejected cylinders is 
authorized. Subsequent thereto, cylinders must pass all prescribed tests 
to be acceptable. Repair of welded seams by welding is authorized.
    (n) Markings. Markings must be stamped plainly and permanently in 
one of the following locations on the cylinder:
    (1) On shoulders and top heads not less than 0.087 inch thick.
    (2) On neck, valve boss, valve protection sleeve, or similar part 
permanently attached to top end of cylinder.
    (3) On a plate attached to the top of the cylinder or permanent part 
thereof: sufficient space must be left on the plate to provide for 
stamping at least six retest dates: the plate must be at least \1/16\ 
inch thick and must be attached by welding or by brazing at a

[[Page 64]]

temperature of at least 1100 [deg]F, throughout all edges of the plate.
    (4) Variations in location of markings authorized only when 
necessitated by lack of space.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended at 66 FR 45386, 
Aug. 28, 2001; 67 FR 51653, Aug. 8, 2002; 68 FR 75748, 75749, Dec. 31, 
2003; 85 FR 85427, Dec. 28, 2020]



Sec.  178.57  Specification 4L welded insulated cylinders.

    (a) Type, size, service pressure, and design service temperature. A 
DOT 4L cylinder is a fusion welded insulated cylinder with a water 
capacity (nominal) not over 1,000 pounds water capacity and a service 
pressure of at least 40 but not greater than 500 psig conforming to the 
following requirements:
    (1) For liquefied hydrogen service, the cylinders must be designed 
to stand on end, with the axis of the cylindrical portion vertical.
    (2) The design service temperature is the coldest temperature for 
which a cylinder is suitable. The required design service temperatures 
for each cryogenic liquid is as follows:

------------------------------------------------------------------------
             Cryogenic liquid                Design service temperature
------------------------------------------------------------------------
Argon.....................................  Minus 320 [deg]F or colder.
Helium....................................  Minus 452 [deg]F or colder.
Hydrogen..................................  Minus 42 3 [deg]F or colder.
Neon......................................  Minus 411 [deg]F or colder.
Nitrogen..................................  Minus 320 [deg]F or colder.
Oxygen....................................  Minus 320 [deg]F or colder.
------------------------------------------------------------------------

    (b) Material. Material use in the construction of this specification 
must conform to the following:
    (1) Inner containment vessel (cylinder). Designations and limiting 
chemical compositions of steel authorized by this specification must be 
as shown in table 1 in paragraph (o) of this section.
    (2) Outer jacket. Steel or aluminum may be used subject to the 
requirements of paragraph (o)(2) of this section.
    (c) Identification of material. Material must be identified by any 
suitable method.
    (d) Manufacture. Cylinders must be manufactured using equipment and 
processes adequate to ensure that each cylinder produced conforms to the 
requirements of this subpart and to the following requirements:
    (1) No defect is permitted that is likely to weaken the finished 
cylinder appreciably. A reasonably smooth and uniform surface finish is 
required. The shell portion must be a reasonably true cylinder.
    (2) The heads must be seamless, concave side to the pressure, 
hemispherical or ellipsoidal in shape with the major diameter not more 
than twice the minor diameter. Minimum thickness of heads may not be 
less than 90 percent of the required thickness of the sidewall. The 
heads must be reasonably true to shape, have no abrupt shape changes, 
and the skirts must be reasonably true to round.
    (3) The surface of the cylinder must be insulated. The insulating 
material must be fire resistant. The insulation on non-evacuated jackets 
must be covered with a steel jacket not less than 0.060-inch thick or an 
aluminum jacket not less than 0.070 inch thick, so constructed that 
moisture cannot come in contact with the insulating material. If a 
vacuum is maintained in the insulation space, the evacuated jacket must 
be designed for a minimum collapsing pressure of 30 psig differential 
whether made of steel or aluminum. The construction must be such that 
the total heat transfer, from the atmosphere at ambient temperature to 
the contents of the cylinder, will not exceed 0.0005 Btu per hour, per 
Fahrenheit degree differential in temperature, per pound of water 
capacity of the cylinder. For hydrogen, cryogenic liquid service, the 
total heat transfer, with a temperature differential of 520 Fahrenheit 
degrees, may not exceed that required to vent 30 SCF of hydrogen gas per 
hour.
    (4) For a cylinder having a design service temperature colder than 
minus 320 [deg]F, a calculation of the maximum weight of contents must 
be made and that weight must be marked on the cylinder as prescribed in 
Sec.  178.35.
    (5) Welding procedures and operations must be qualified in 
accordance with CGA Pamphlet C-3 (IBR, see Sec.  171.7 of this 
subchapter). In addition, an impact test of the weld must be performed 
in accordance with paragraph (l) of this section as part of the 
qualification of each welding procedure and operator.

[[Page 65]]

    (e) Welding. Welding of the cylinder must be as follows:
    (1) All seams of the cylinder must be fusion welded. A means must be 
provided for accomplishing complete penetration of the joint. Only butt 
or joggle butt joints for the cylinder seams are authorized. All joints 
in the cylinder must have reasonably true alignment.
    (2) All attachments to the sidewalls and heads of the cylinder must 
be by fusion welding and must be of a weldable material complying with 
the impact requirements of paragraph (l) of this section.
    (3) For welding the cylinder, each procedure and operator must be 
qualified in accordance with the sections of CGA Pamphlet C-3 that 
apply. In addition, impact tests of the weld must be performed in 
accordance with paragraph (l) of this section as part of the 
qualification of each welding procedure and operator.
    (4) Brazing, soldering and threading are permitted only for joints 
not made directly to the cylinder body. Threads must comply with the 
requirements of paragraph (h) of this section.
    (f) Wall thickness. The minimum wall thickness of the cylinder must 
be such that the calculated wall stress at the minimum required test 
pressure may not exceed the least value of the following:
    (1) 45,000 psi.
    (2) One-half of the minimum tensile strength across the welded seam 
determined in paragraph (l) of this section.
    (3) One-half of the minimum tensile strength of the base metal 
determined as required in paragraph (j) of this section.
    (4) The yield strength of the base metal determined as required in 
paragraph (l) of this section.
    (5) Further provided that wall stress for cylinders having 
longitudinal seams may not exceed 85 percent of the above value, 
whichever applies.
    (6) Calculation must be made by the following formula:

S = [P(1.3D\2\ + 0.4d\2\)] / (D\2\ - d\2\)

where:

S = wall stress in pounds psi;
P = minimum test pressure prescribed for pressure test in psig;
D = outside diameter in inches;
d = inside diameter in inches.

    (g) Heat treatment. Heat treatment is not permitted.
    (h) Openings in cylinder. Openings in cylinders must conform to the 
following:
    (1) Openings are permitted in heads only. They must be circular and 
may not exceed 3 inches in diameter or one third of the cylinder 
diameter, whichever is less. Each opening in the cylinder must be 
provided with a fitting, boss or pad, either integral with, or securely 
attached to, the cylinder body by fusion welding. Attachments to a 
fitting, boss or pad may be made by welding, brazing, mechanical 
attachment, or threading.
    (2) Threads must comply with the following:
    (i) Threads must be clean-cut, even, without checks and cut to 
gauge.
    (ii) Taper threads to be of a length not less than that specified 
for NPT.
    (iii) Straight threads must have at least 4 engaged threads, tight 
fit and calculated shear strength at least 10 times the test pressure of 
the cylinder. Gaskets, which prevent leakage and are inert to the 
hazardous material, are required.
    (i) Pressure testing. Each cylinder, before insulating and 
jacketing, must successfully withstand a pressure test as follows:
    (1) The cylinder must be tested by the proof pressure, water-jacket, 
or direct expansion test method as prescribed in CGA C-1 (IBR; see Sec.  
171.7 of this subchapter). The testing equipment must be calibrated as 
prescribed in CGA C-1. All testing equipment and pressure indicating 
devices must be accurate within the parameters defined in CGA C-1.
    (2) Each cylinder must be tested to a minimum of two (2) times 
service pressure.
    (3) The minimum test pressure must be maintained at least 30 
seconds. Any internal pressure applied after heat-treatment and prior to 
the official test may not exceed 90 percent of the test pressure. If, 
due to failure of the test apparatus or operator error, the test 
pressure cannot be maintained, the test may be repeated in accordance 
with CGA C-1 5.7.2 or 7.1.2. Determination of expansion properties is 
not required.

[[Page 66]]

    (4) There must be no evidence of leakage, visible distortion or 
other defect.
    (j) Physical test. A physical test must be conducted to determine 
yield strength, tensile strength, and elongation as follows:
    (1) The test is required on 2 specimens selected from material of 
each heat and in the same condition as that in the completed cylinder.
    (2) Specimens must conform to the following:
    (i) A gauge length of 8 inches with a width not over 1\1/2\ inches, 
a gauge length of 2 inches with width not over 1\1/2\ inches, or a gauge 
length at least 24 times thickness with a width not over 6 times 
thickness (authorized when cylinder wall is not over \1/16\ inch thick).
    (ii) The specimen, exclusive of grip ends, may not be flattened. 
Grip ends may be flattened to within one inch of each end of the reduced 
section.
    (iii) When size of the cylinder does not permit securing straight 
specimens, the specimens may be taken in any location or direction and 
may be straightened or flattened cold by pressure only, not by blows. 
When specimens are so taken and prepared, the inspector's report must 
show in connection with record of physical tests detailed information in 
regard to such specimens.
    (iv) Heating of a specimen for any purpose is not authorized.
    (3) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gauge length. The following 
conditions apply:
    (i) The yield strength must be determined by either the ``offset'' 
method or the ``extension under load'' method as prescribed in ASTM E 8 
(IBR, see Sec.  171.7 of this subchapter).
    (ii) In using the ``extension under load'' method, the total strain 
(or ``extension under load''), corresponding to the stress at which the 
0.2 percent permanent strain occurs may be determined with sufficient 
accuracy by calculating the elastic expansion of the gauge length under 
appropriate load and adding thereto 0.2 percent of the gauge length. 
Elastic extension calculations must be based on the elastic modulus of 
the material used. In the event of controversy, the entire stress-strain 
diagram must be plotted and the yield strength determined from the 0.2 
percent offset.
    (iii) For the purpose of strain measurement, the initial strain 
reference must be set while the specimen is under a stress of 12,000 psi 
and the strain indicator reading being set at the calculated 
corresponding strain.
    (iv) Cross-head speed of the testing machine may not exceed \1/8\ 
inch per minute during yield strength determination.
    (k) Acceptable results for physical tests. Physical properties must 
meet the limits specified in paragraph (o)(1), table 1, of this section, 
for the particular steel in the annealed condition. The specimens must 
show at least a 20 percent elongation for a 2-inch gage length. Except 
that the percentage may be reduced numerically by 2 for each 7,500 psi 
increment of tensile strength above 100,000 psi to a maximum of 5 such 
increments. Yield strength and tensile strength must meet the 
requirements of paragraph (o)(1), table 1, of this section.
    (l) Tests of welds. Welds must be tested as follows:
    (1) Tensile test. A specimen must be cut from one cylinder of each 
lot of 200 or less, or welded test plate. The welded test plate must be 
of one of the heats in the lot of 200 or less which it represents, in 
the same condition and approximately the same thickness as the cylinder 
wall except that it may not be of a lesser thickness than that required 
for a quarter size Charpy impact specimen. The weld must be made by the 
same procedures and subjected to the same heat treatment as the major 
weld on the cylinder. The specimen must be taken across the major seam 
and must be prepared in accordance with and must meet the requirements 
of CGA Pamphlet C-3. Should this specimen fail to meet the requirements, 
specimens may be taken from two additional cylinders or welded test 
plates from the same lot and tested. If either of the latter specimens 
fails to meet the requirements, the entire lot represented must be 
rejected.
    (2) Guided bend test. A ``root'' bend test specimen must be cut from 
the cylinder or welded test plate, used for

[[Page 67]]

the tensile test specified in paragraph (l)(1) of this section and from 
any other seam or equivalent welded test plate if the seam is welded by 
a procedure different from that used for the major seam. Specimens must 
be taken across the particular seam being tested and must be prepared 
and tested in accordance with and must meet the requirements of CGA 
Pamphlet C-3.
    (3) Alternate guided-bend test. This test may be used and must be as 
specified in CGA Pamphlet C-3. The specimen must be bent until the 
elongation at the outer surface, adjacent to the root of the weld, 
between the lightly scribed gage lines a to b, is at least 20 percent, 
except that this percentage may be reduced for steels having a tensile 
strength in excess of 100,000 psig, as provided in paragraph (c) of this 
section.
    (4) Impact tests. One set of three impact test specimens (for each 
test) must be prepared and tested for determining the impact properties 
of the deposited weld metal--
    (i) As part of the qualification of the welding procedure.
    (ii) As part of the qualification of the operators.
    (iii) For each ``heat'' of welding rodor wire used.
    (iv) For each 1,000 feet of weld made with the same heat of welding 
rod or wire.
    (v) All impact test specimens must be of the charpy type, keyhole or 
milled U-notch, and must conform in all respects to ASTM E 23 (IBR, see 
Sec.  171.7 of this subchapter). Each set of impact specimens must be 
taken across the weld and have the notch located in the weld metal. When 
the cylinder material thickness is 2.5 mm or thicker, impact specimens 
must be cut from a cylinder or welded test plate used for the tensile or 
bend test specimens. The dimension along the axis of the notch must be 
reduced to the largest possible of 10 mm, 7.5 mm, 5 mm or 2.5 mm, 
depending upon cylinder thickness. When the material in the cylinder or 
welded test plate is not of sufficient thickness to prepare 2.5 mm 
impact test specimens, 2.5 mm specimens must be prepared from a welded 
test plate made from \1/8\ inch thick material meeting the requirements 
specified in paragraph (o)(1), table 1, of this section and having a 
carbon analysis of .05 minimum, but not necessarily from one of the 
heats used in the lot of cylinders. The test piece must be welded by the 
same welding procedure as used on the particular cylinder seam being 
qualified and must be subjected to the same heat treatment.
    (vi) Impact test specimens must be cooled to the design service 
temperature. The apparatus for testing the specimens must conform to 
requirements of ASTM Standard E 23. The test piece, as well as the 
handling tongs, must be cooled for a length of time sufficient to reach 
the service temperature. The temperature of the cooling device must be 
maintained within a range of plus or minus 3 [deg]F. The specimen must 
be quickly transferred from the cooling device to the anvil of the 
testing machine and broken within a time lapse of not more than six 
seconds.
    (vii) The impact properties of each set of impact specimens may not 
be less than the values in the following table:

------------------------------------------------------------------------
                                                 Minimum       Minimum
                                              impact value  impact value
                                              required for  permitted on
              Size of specimen                avg. of each   one only of
                                              set of three    a set of
                                                specimens    three (ft.-
                                                (ft.-lb.)       lb.)
------------------------------------------------------------------------
10 mm x 10 mm...............................          15            10
10 mm x 7.5 mm..............................          12.5           8.5
10 mm x 5 mm................................          10             7.0
10 mm x 2.5 mm..............................           5             3.5
------------------------------------------------------------------------

    (viii) When the average value of the three specimens equals or 
exceeds the minimum value permitted for a single specimen and the value 
for more than one specimen is below the required average value, or when 
the value for one specimen is below the minimum value permitted for a 
single specimen, a retest of three additional specimens must be made. 
The value of each of these retest specimens must equal or exceed the 
required average value. When an erratic result is caused by a defective 
specimen, or there is uncertainty in test procedure, a retest is 
authorized.
    (m) Radiographic examination. Cylinders must be subject to a 
radiographic examination as follows:

[[Page 68]]

    (1) The techniques and acceptability of radiographic inspection must 
conform to the standards set forth in CGA Pamphlet C-3.
    (2) One finished longitudinal seam must be selected at random from 
each lot of 100 or less successively produced and be radiographed 
throughout its entire length. Should the radiographic examination fail 
to meet the requirements of paragraph (m)(1) of this section, two 
additional seams of the same lot must be examined, and if either of 
these fail to meet the requirements of (m)(1) of this section, only 
those passing are acceptable.
    (n) Rejected cylinders. Reheat treatment of rejected cylinders is 
authorized. Subsequent thereto, cylinders must pass all prescribed tests 
to be acceptable. Welds may be repaired by suitable methods of fusion 
welding.
    (o) Authorized materials of construction. Authorized materials of 
construction are as follows:
    (1) Inner containment vessel (cylinder). Electric furnace steel of 
uniform quality must be used. Chemical analysis must conform to ASTM A 
240/A 240M (IBR, see Sec.  171.7 of this subchapter), Type 304 stainless 
steel. Chemical analysis must conform to ASTM A240, Type 304 Stainless 
Steel. A heat of steel made under table 1 and table 2 in this paragraph 
(o)(1) is acceptable, even though its check chemical analysis is 
slightly out of the specified range, if it is satisfactory in all other 
respects, provided the tolerances shown in table 3 in this paragraph 
(o)(1) are not exceeded. The following chemical analyses and physical 
properties are authorized:

                      Table 1--Authorized Materials
------------------------------------------------------------------------
                                           Chemical analysis, limits in
              Designation                            percent
------------------------------------------------------------------------
Carbon \1\.............................  0.08 max.
Manganese..............................  2.00 max.
Phosphorus.............................  0.045 max.
Sulphur................................  0.030 max.
Silicon................................  1.00 max.
Nickel.................................  8.00-10.50.
Chromium...............................  18.00-20.00.
Molybdenum.............................  None.
Titanium...............................  None.
Columbium..............................  None.
------------------------------------------------------------------------
\1\ The carbon analysis must be reported to the nearest hundredth of one
  percent.


                      Table 2--Physical Properties
------------------------------------------------------------------------
                                                               Physical
                                                              properties
                                                              (annealed)
------------------------------------------------------------------------
Tensile strength, p.s.i. (minimum)..........................    75,000
Yield strength, p.s.i. (minimum)............................    30,000
Elongation in 2 inches (minimum) percent....................        30.0
Elongation other permissible gauge lengths (minimum) percent        15.0
------------------------------------------------------------------------


                   Table 3--Check Analysis Tolerances
------------------------------------------------------------------------
                                                              Tolerance
                                                              over the
                                                               maximum
            Elements              Limit or specified range    limit or
                                         (percent)            under the
                                                               minimum
                                                                limit
------------------------------------------------------------------------
Carbon.........................  To 0.030, incl...........         0.005
                                 Over 0.30 to 0.20, incl..         0.01
Manganese......................  To 1.00 incl.............          .03
                                 Over 1.00 to 3.00, incl..         0.04
Phosphorus \1\.................  To 0.040, incl...........         0.005
                                 Over 0.040 to 0.020 incl.         0.010
Sulphur........................  To .40 incl..............         0.005
Silicon........................  To 1.00, incl............         0.05
Nickel.........................  Over 5.00 to 10.00, incl.         0.10
                                 Over 10.00 to 20.00, incl         0.15
Chromium.......................  Over 15.00 to 20.00, incl         0.20
------------------------------------------------------------------------
\1\ Rephosphorized steels not subject to check analysis for phosphorus.

    (2) Outer jacket. (i) Nonflammable cryogenic liquids. Cylinders 
intended for use in the transportation of nonflammable cryogenic liquid 
must have an outer jacket made of steel or aluminum.
    (ii) Flammable cryogenic liquids. Cylinders intended for use in the 
transportation of flammable cryogenic liquid must have an outer jacket 
made of steel.
    (p) Markings. (1) Markings must be stamped plainly and permanently 
on shoulder or top head of jacket or on a permanently attached plate or 
head protective ring.
    (2) The letters ``ST'', followed by the design service temperature 
(for example, ST-423F), must be marked on cylinders having a design 
service temperature of colder than minus 320 [deg]F only. Location to be 
just below the DOT mark.
    (3) The maximum weight of contents, in pounds (for example, ``Max. 
Content 51 ''), must be marked on cylinders having a design service 
temperature colder than minus 320 [deg]F only. Location to be near 
symbol.
    (4) Special orientation instructions must be marked on the cylinder 
(for

[[Page 69]]

example, THIS END UP), if the cylinder is used in an orientation other 
than vertical with openings at the top of the cylinder.
    (5) If the jacket of the cylinder is constructed of aluminum, the 
letters ``AL'' must be marked after the service pressure marking. 
Example: DOT-4L150 AL.
    (6) Except for serial number and jacket material designation, each 
marking prescribed in this paragraph (p) must be duplicated on each 
cylinder by any suitable means.
    (q) Inspector's report. In addition to the information required by 
Sec.  178.35, the inspector's reports must contain information on:
    (1) The jacket material and insulation type;
    (2) The design service temperature

([deg]F); and
    (3) The impact test results, on a lot basis.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended at 66 FR 45386, 
Aug. 28, 2001; 67 FR 51653, Aug. 8, 2002; 68 FR 75748, Dec. 31, 2003; 85 
FR 85427, Dec. 28, 2020]



Sec.  178.58  Specification 4DA welded steel cylinders for aircraft use.

    (a) Type, size, and service pressure. A DOT 4DA is a welded steel 
sphere (two seamless hemispheres) or a circumferentially welded cylinder 
(two seamless drawn shells) with a water capacity not over 100 pounds 
and a service pressure of at least 500 but not over 900 psig.
    (b) Steel. Open-hearth or electric steel of uniform quality must be 
used. A heat of steel made under table 1 in this paragraph (b), check 
chemical analysis of which is slightly out of the specified range, is 
acceptable, if satisfactory in all other respects, provided the 
tolerances shown in table 2 in this paragraph (b) are not exceeded 
except as approved by the Associate Administrator. The following 
chemical analyses are authorized:

                      Table 1--Authorized Materials
------------------------------------------------------------------------
                   4130                                Percent
------------------------------------------------------------------------
Carbon....................................  0.28/0.33.
Manganese.................................  0.40/0.60.
Phosphorus................................  0.040 max.
Sulfur....................................  0.040 max.
Silicon...................................  0.15/0.35.
Chromium..................................  0.80/1.10.
Molybdenum................................  0.15/0.25.
------------------------------------------------------------------------


                                       Table 2--Check Analysis Tolerances
----------------------------------------------------------------------------------------------------------------
                                                                  Tolerance (percent) over the maximum limit or
                                           Limit or maximum                  under the minimum limit
               Element                   specified (percent)   -------------------------------------------------
                                                                  Under minimum limit       Over maximum limit
----------------------------------------------------------------------------------------------------------------
Carbon...............................  Over 0.15 to 0.40 incl.  .03....................  .04
Manganese............................  To 0.60 incl...........  .03....................  .03
Phosphorus\1\........................  All ranges.............  .......................  .01
Sulphur..............................  All ranges.............  .......................  .01
Silicon..............................  To 0.30 incl...........  .02....................  .03
                                       Over 0.30 to 1.00 incl.  .05....................  .05
Chromium.............................  To 0.90 incl...........  .03....................  .03
                                       Over 0.90 to 2.10 incl.  .05....................  .05
Molybdenum...........................  To 0.20 incl...........  .01....................  .01
                                       Over 0.20 to 0.40, incl  .02....................  .02
----------------------------------------------------------------------------------------------------------------
\1\ Rephosphorized steels not subject to check analysis for phosphorus.

    (c) Identification of material. Materials must be identified by any 
suitable method except that plates and billets for hot-drawn containers 
must be marked with the heat number.
    (d) Manufacture. Cylinders must be manufactured in accordance with 
the following requirements:
    (1) By best appliances and methods. No defect is acceptable that is 
likely to weaken the finished container appreciably. A reasonably smooth 
and uniform surface finish is required. No abrupt change in wall 
thickness is permitted. Welding procedures and operators must be 
qualified in accordance with CGA Pamphlet C-3 (IBR, see Sec.  171.7 of 
this subchapter).
    (2) All seams of the sphere or cylinders must be fusion welded. 
Seams must be of the butt or joggle butt type and means must be provided 
for accomplishing complete penetration of the joint.
    (e) Welding. Attachments to the container are authorized by fusion 
welding provided that such attachments are made of weldable steel, the 
carbon content of which may not exceed 0.25 percent except in the case 
of 4130 steel.
    (f) Wall thickness. The minimum wall thickness must be such that the 
wall stress at the minimum specified test pressure may not exceed 67 
percent of

[[Page 70]]

the minimum tensile strength of the steel as determined from the 
physical and burst tests required and may not be over 70,000 p.s.i. For 
any diameter container, the minimum wall thickness is 0.040 inch. 
Calculations must be made by the formulas in (f)(1) or (f)(2) of this 
section:
    (1) Calculation for a sphere must be made by the following formula:

S = PD / 4tE

Where:

S = wall stress in pounds psi;
P = test pressure prescribed for water jacket test, i.e., at least 2 
          times service pressure, in psig;
D = outside diameter in inches;
t = minimum wall thickness in inches;
E = 0.85 (provides 85 percent weld efficiency factor which must be 
          applied in the girth weld area and heat affected zones which 
          zone must extend a distance of 6 times wall thickness from 
          center line of weld);
E = 1.0 (for all other areas).

    (2) Calculation for a cylinder must be made by the following 
formula:

S = [P(1.3D \2\ + 0.4d \2\)] / (D \2\ - d \2\)

Where:

S = wall stress in pounds psi;
P = test pressure prescribed for water jacket test, i.e., at least 2 
          times service pressure, in psig;
D = outside diameter in inches;
d = inside diameter in inches.

    (g) Heat treatment. The completed containers must be uniformly and 
properly heat-treated prior to tests. Heat-treatment of containers of 
the authorized analysis must be as follows:
    (1) All containers must be quenched by oil, or other suitable medium 
except as provided in paragraph (g)(4) of this section.
    (2) The steel temperature on quenching must be that recommended for 
the steel analysis, but may not exceed 1,750 [deg]F.
    (3) The steel must be tempered at the temperature most suitable for 
the analysis except that in no case shall the tempering temperature be 
less than 1,000 [deg]F.
    (4) The steel may be normalized at a temperature of 1,650 [deg]F 
instead of being quenched, and containers so normalized need not be 
tempered.
    (5) All cylinders, if water quenched or quenched with a liquid 
producing a cooling rate in excess of 80 percent of the cooling rate of 
water, must be inspected by the magnetic particle or dye penetrant 
method to detect the presence of quenching cracks. Any cylinder found to 
have a quench crack must be rejected and may not be requalified.
    (h) Openings in container. Openings in the container must comply 
with the following requirements:
    (1) Each opening in the container must be provided with a fitting, 
boss, or pad of weldable steel securely attached to the container by 
fusion welding.
    (2) Attachments to a fitting, boss, or pad must be adequate to 
prevent leakage. Threads must comply with the following:
    (i) Threads must be clean cut, even, without checks, and tapped to 
gauge.
    (ii) Taper threads to be of length not less than as specified for 
American Standard taper pipe threads.
    (iii) Straight threads, having at least 4 engaged threads, to have 
tight fit and calculated shear strength at least 10 times the test 
pressure of the container; gaskets required, adequate to prevent 
leakage.
    (i) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:
    (1) The test must be by water-jacket or direct expansion method as 
prescribed in CGA C-1 (IBR; see Sec.  171.7 of this subchapter). The 
testing equipment must be calibrated as prescribed in CGA C-1. All 
testing equipment and pressure indicating devices must be accurate 
within the parameters defined in CGA C-1.
    (2) Each cylinder must be tested to a minimum of two (2) times 
service pressure.
    (3) The minimum test pressure must be maintained at least 30 seconds 
and sufficiently longer to ensure complete expansion. Any internal 
pressure applied after heat-treatment and prior to the official test may 
not exceed 90 percent of the test pressure. If, due to failure of the 
test apparatus or operator error, the test pressure cannot be 
maintained, the test may be repeated in accordance with CGA C-1, section 
5.7.2.

[[Page 71]]

    (4) Permanent volumetric expansion may not exceed 10 percent of the 
total volumetric expansion at test pressure.
    (j) Burst test. One container taken at random out of 200 or less 
must be hydrostatically tested to destruction. The rupture pressure must 
be included as part of the inspector's report.
    (k) Flattening test. Spheres and cylinders must be subjected to a 
flattening test as follows:
    (1) Flattening test for spheres. One sphere taken at random out of 
each lot of 200 or less must be subjected to a flattening test as 
follows:
    (i) The test must be performed after the hydrostatic test.
    (ii) The test must be at the weld between the parallel steel plates 
on a press with a welded seam, at right angles to the plates. Any 
projecting appurtenances may be cut off (by mechanical means only) prior 
to crushing.
    (2) Flattening test for cylinders. One cylinder taken at random out 
of each lot of 200 or less, must be subjected to a flattening test as 
follows:
    (i) The test must be performed after the hydrostatic test.
    (ii) The test cylinder must be placed between wedge-shaped knife 
edges having a 60[deg] angle, rounded to a \1/2\-inch radius.
    (l) Radiographic inspection. Radiographic examinations is required 
on all welded joints which are subjected to internal pressure, except 
that at the discretion of the disinterested inspector, openings less 
than 25 percent of the sphere diameter need not be subjected to 
radiographic inspection. Evidence of any defects likely to seriously 
weaken the container must be cause for rejection.
    (m) Physical test and specimens for spheres and cylinders. Spheres 
and cylinders must be subjected to a physical test as follows:
    (1) A physical test for a sphere is required on 2 specimens cut from 
a flat representative sample plate of the same heat taken at random from 
the steel used to produce the sphere. This flat steel from which the 2 
specimens are to be cut must receive the same heat-treatment as the 
spheres themselves. Sample plates to be taken for each lot of 200 or 
less spheres.
    (2) Specimens for spheres have a gauge length of 2 inches with a 
width not over 1\1/2\ inches, or a gauge length at least 24 times 
thickness with a width not over 6 times thickness is authorized when 
wall of sphere is not over \3/16\ inch thick.
    (3) A physical test for cylinders is required on 2 specimens cut 
from 1 cylinder taken at random out of each lot of 200 or less.
    (4) Specimens for cylinder must conform to the following:
    (i) A gauge length of 8 inches with a width not over 1\1/2\ inches, 
a gauge length of 2 inches with a width not over 1\1/2\ inches, a gauge 
length at least 24 times thickness with a width not over 6 times 
thickness is authorized when a cylinder wall is not over \3/16\ inch 
thick.
    (ii) The specimen, exclusive of grip ends, may not be flattened. 
Grip ends may be flattened to within 1 inch of each end of the reduced 
section.
    (iii) Heating of a specimen for any purpose is not authorized.
    (5) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gauge length. The following 
conditions apply:
    (i) The yield strength must be determined by either the ``offset'' 
method or the ``extension under load'' method as prescribed in ASTM E 8 
(IBR, see Sec.  171.7 of this subchapter).
    (ii) In using the ``extension under load'' method, the total strain 
(or ``extension under load'') corresponding to the stress at which the 
0.2 percent permanent strain occurs may be determined with sufficient 
accuracy by calculating the elastic extension of the gauge length under 
appropriate load and adding thereto 0.2 percent of the gauge length. 
Elastic extension calculations must be based on an elastic modulus of 
30,000,000. In the event of controversy, the entire stress-strain 
diagram must be plotted and the yield strength determined from the 0.2 
percent offset.
    (iii) For the purpose of strain measurement, the initial strain must 
be set while the specimen is under a stress of 12,000 psi and the strain 
indicator reading being set at the calculated corresponding strain.

[[Page 72]]

    (iv) Cross-head speed of the testing machine may not exceed \1/8\ 
inch per minute during yield strength determination.
    (n) Acceptable results for physical, flattening, and burst tests. 
The following are acceptable results of the physical, flattening and 
burst test:
    (1) Elongation must be at least 20 percent for a 2-inch gauge length 
or 10 percent in other cases.
    (2) Flattening is required to 50 percent of the original outside 
diameter without cracking.
    (3) Burst pressure must be at least 3 times service pressure.
    (o) Rejected containers. Reheat-treatment of rejected cylinders is 
authorized. Subsequent thereto, containers must pass all prescribed 
tests to be acceptable. Repair of welded seams by welding prior to 
reheat-treatment is authorized.
    (p) Marking. Markings on each container must be stamped plainly and 
permanently on a permanent attachment or on a metal nameplate 
permanently secured to the container by means other than soft solder.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended at 66 FR 45386, 
45388, Aug. 28, 2001; 67 FR 51654, Aug. 8, 2002; 67 FR 61015, Sept. 27, 
2002; 68 FR 75748, Dec. 31, 2003; 85 FR 85427, Dec. 28, 2020]



Sec.  178.59  Specification 8 steel cylinders with porous fillings for 
acetylene.

    (a) Type and service pressure. A DOT 8 cylinder is a seamless 
cylinder with a service pressure of 250 psig. The following steel is 
authorized:
    (1) A longitudinal seam if forge lap welded;
    (2) Attachment of heads by welding or by brazing by dipping process; 
or
    (3) A welded circumferential body seam if the cylinder has no 
longitudinal seam.
    (b) Steel. Open-hearth, electric or basic oxygen process steel of 
uniform quality must be used. Content percent may not exceed the 
following: Carbon, 0.25; phosphorus, 0.045; sulphur, 0.050.
    (c) Identification of steel. Materials must be identified by any 
suitable method except that plates and billets for hot-drawn cylinders 
must be marked with the heat number.
    (d) Manufacture. Cylinders must be manufactured using equipment and 
processes adequate to ensure that each cylinder produced conforms to the 
requirements of this subpart. No defect is acceptable that is likely to 
weaken the finished cylinder appreciably. A reasonably smooth and 
uniform surface finish is required. Welding procedures and operators 
must be qualified in accordance with CGA Pamphlet C-3 (IBR, see Sec.  
171.7 of this subchapter).
    (e) Exposed bottom welds. Exposed bottom welds on cylinders over 18 
inches long must be protected by footrings.
    (f) Heat treatment. Body and heads formed by drawing or pressing 
must be uniformly and properly heat treated prior to tests.
    (g) Openings. Openings in the cylinders must comply with the 
following:
    (1) Standard taper pipe threads are required;
    (2) Length may not be less than as specified for American Standard 
pipe threads; tapped to gauge; clean cut, even, and without checks.
    (h) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:
    (1) Lot testing. (i) At least one (1) cylinder selected at random 
out of each lot of 200 or fewer must be tested by water-jacket or direct 
expansion method as prescribed in CGA C-1 (IBR; see Sec.  171.7 of this 
subchapter). The testing equipment must be calibrated as prescribed in 
CGA C-1. All testing equipment and pressure indicating devices must be 
accurate within the parameters defined in CGA C-1.
    (ii) The selected cylinder must be tested to a minimum of 750 psig.
    (iii) The minimum test pressure must be maintained at least 30 
seconds and sufficiently longer to ensure complete expansion. Any 
internal pressure applied after heat-treatment and prior to the official 
test may not exceed 90 percent of the test pressure. If, due to failure 
of the test apparatus or operator error, the test pressure cannot be 
maintained, the test may be repeated in accordance with CGA C-1, section 
5.7.2.
    (iv) Permanent volumetric expansion may not exceed 10 percent of the 
total volumetric expansion at test pressure.

[[Page 73]]

    (v) If the selected cylinder passes the volumetric expansion test, 
each remaining cylinder in the lot must be pressure tested in accordance 
with paragraph (h)(2) of this section. If the selected cylinder fails, 
each cylinder in the lot must be tested by water-jacket or direct 
expansion method as prescribed in CGA C-1 at 750 psig. Each cylinder 
with a permanent expansion that does not exceed 10% is acceptable.
    (2) Pressure testing. (i) If the selected cylinder passes the water-
jacket or direct expansion test, the remaining cylinders in each lot 
must be pressure tested by the proof pressure, water-jacket or direct 
expansion test method as prescribed in CGA C-1. The minimum test 
pressure must be maintained for the specific timeframe and the testing 
equipment must be calibrated as prescribed in CGA C-1. Further, all 
testing equipment and pressure indicating devices must be accurate 
within the parameters defined in CGA C-1.
    (ii) Each cylinder must be tested between 500 and 600 psig and show 
no defect. If, due to failure of the test apparatus or operator error, 
the test pressure cannot be maintained, the test may be repeated in 
accordance with CGA C-1 section 5.7.2 or 7.1.2, as appropriate. 
Determination of expansion properties is not required.
    (i) Leakage test. Cylinders with bottoms closed in by spinning must 
be subjected to a leakage test by setting the interior air or gas 
pressure to not less than the service pressure. Cylinders which leak 
must be rejected.
    (j) Physical test. A physical test must be conducted as follows:
    (1) The test is required on 2 specimens cut longitudinally from 1 
cylinder or part thereof taken at random out of each lot of 200 or less, 
after heat treatment.
    (2) Specimens must conform to a gauge length of 8 inches with a 
width not over 1\1/2\ inches, a gauge length of 2 inches with width not 
over 1\1/2\, or a gauge length at least 24 times thickness with a width 
not over 6 times thickness is authorized when a cylinder wall is not 
over \3/16\ inch thick.
    (3) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gauge length. The following 
conditions apply:
    (i) The yield strength must be determined by either the ``offset'' 
method or the ``extension under load'' method as prescribed in ASTM E 8 
(IBR, see Sec.  171.7 of this subchapter).
    (ii) In using the ``extension under load'' method, the total strain 
(or ``extension under load'') corresponding to the stress at which the 
0.2 percent permanent strain occurs may be determined with sufficient 
accuracy by calculating the elastic extension of the gauge length under 
appropriate load and adding thereto 0.2 percent of the gauge length. 
Elastic extension calculations must be based on an elastic modulus of 
30,000,000. In the event of controversy, the entire stress-strain 
diagram must be plotted and the yield strength determined from the 0.2 
offset.
    (iii) For the purpose of strain measurement, the initial strain must 
be set while the specimen is under a stress of 12,000 psi and the strain 
indicator reading being set at the calculated corresponding strain.
    (iv) Cross-head speed of the testing machine may not exceed \1/8\ 
inch per minute during yield strength determination.
    (4) Yield strength may not exceed 73 percent of tensile strength. 
Elongation must be at least 40 percent in 2 inch or 20 percent in other 
cases.
    (k) Rejected cylinders. Reheat treatment of rejected cylinder is 
authorized. Subsequent thereto, cylinders must pass all prescribed tests 
to be acceptable. Repair by welding is authorized.
    (l) Porous filling. (1) Cylinders must be filled with a porous 
material in accordance with the following:
    (i) The porous material may not disintegrate or sag when wet with 
solvent or when subjected to normal service;
    (ii) The porous filling material must be uniform in quality and free 
of voids, except that a well drilled into the filling material beneath 
the valve is authorized if the well is filled with a material of such 
type that the functions of the filling material are not impaired;
    (iii) Overall shrinkage of the filling material is authorized if the 
total clearance between the cylinder shell

[[Page 74]]

and filling material, after solvent has been added, does not exceed \1/
2\ of 1 percent of the respective diameter or length, but not to exceed 
\1/8\ inch, measured diametrically and longitudinally;
    (iv) The clearance may not impair the functions of the filling 
material;
    (v) The installed filling material must meet the requirements of CGA 
C-12 (IBR, see Sec.  171.7 of this subchapter); and
    (vi) Porosity of filling material may not exceed 80 percent except 
that filling material with a porosity of up to 92 percent may be used 
when tested with satisfactory results in accordance with CGA Pamphlet C-
12.
    (2) When the porosity of each cylinder is not known, a cylinder 
taken at random from a lot of 200 or less must be tested for porosity. 
If the test cylinder fails, each cylinder in the lot may be tested 
individually and those cylinders that pass the test are acceptable.
    (3) For filling that is molded and dried before insertion in 
cylinders, porosity test may be made on a sample block taken at random 
from material to be used.
    (4) The porosity of the filling material must be determined. The 
amount of solvent at 70 [deg]F for a cylinder:
    (i) Having shell volumetric capacity above 20 pounds water capacity 
(nominal) may not exceed the following:

------------------------------------------------------------------------
                                                               Maximum
                                                               acetone
                                                               solvent
                 Percent porosity of filler                    percent
                                                                shell
                                                             capacity by
                                                                volume
------------------------------------------------------------------------
90 to 92...................................................         43.4
87 to 90...................................................         42.0
83 to 87...................................................         40.0
80 to 83...................................................         38.6
75 to 80...................................................         36.2
70 to 75...................................................         33.8
65 to 70...................................................         31.4
------------------------------------------------------------------------

    (ii) Having volumetric capacity of 20 pounds or less water capacity 
(nominal), may not exceed the following:

------------------------------------------------------------------------
                                                               Maximum
                                                               acetone
                                                               solvent
                 Percent porosity of filler                    percent
                                                                shell
                                                             capacity by
                                                                volume
------------------------------------------------------------------------
90 to 92...................................................         41.8
83 to 90...................................................         38.5
80 to 83...................................................         37.1
75 to 80...................................................         34.8
70 to 75...................................................         32.5
65 to 70...................................................         30.2
------------------------------------------------------------------------

    (m) Tare weight. The tare weight is the combined weight of the 
cylinder proper, porous filling, valve, and solvent, without removable 
cap.
    (n) Duties of inspector. In addition to the requirements of Sec.  
178.35, the inspector is required to--
    (1) Certify chemical analyses of steel used, signed by manufacturer 
thereof; also verify by, check analyses of samples taken from each heat 
or from 1 out of each lot of 200 or less, plates, shells, or tubes used.
    (2) Verify compliance of cylinder shells with all shell 
requirements; inspect inside before closing in both ends; verify heat 
treatment as proper; obtain all samples for all tests and for check 
analyses; witness all tests; verify threads by gauge; report volumetric 
capacity and minimum thickness of wall noted.
    (3) Prepare report on manufacture of steel shells in form prescribed 
in Sec.  178.35. Furnish one copy to manufacturer and three copies to 
the company that is to complete the cylinders.
    (4) Determine porosity of filling and tare weights; verify 
compliance of marking with prescribed requirements; obtain necessary 
copies of steel shell reports; and furnish complete reports required by 
this specification to the person who has completed the manufacture of 
the cylinders and, upon request, to the purchaser. The test reports must 
be retained by the inspector for fifteen years from the original test 
date of the cylinder.
    (o) Marking. (1) Marking on each cylinder must be stamped plainly 
and permanently on or near the shoulder, top head, neck or valve 
protection collar which is permanently attached to the cylinder and 
forming integral part thereof.
    (2) Tare weight of cylinder, in pounds and ounces, must be marked on 
the cylinder.

[[Page 75]]

    (3) Cylinders, not completed, when delivered must each be marked for 
identification of each lot of 200 or less.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended at 66 FR 45386, 
Aug. 28, 2001; 67 FR 61016, Sept. 27, 2002; 67 FR 51654, Aug. 8, 2002; 
68 FR 75748, 75749, Dec. 31, 2003; 85 FR 85427, Dec. 28, 2020]



Sec.  178.60  Specification 8AL steel cylinders with porous fillings for 
acetylene.

    (a) Type and service pressure. A DOT 8AL cylinder is a seamless 
steel cylinder with a service pressure of 250 psig. However, the 
attachment of heads by welding or by brazing by dipping process and a 
welded circumferential body seam is authorized. Longitudinal seams are 
not authorized.
    (b) Authorized steel. The authorized steel is as specified in table 
I of appendix A to this part.
    (c) Identification of steel. Material must be identified by any 
suitable method except that plates and billets for hot-drawn cylinders 
must be marked with heat number.
    (d) Manufacture. Cylinders must be manufactured using equipment and 
processes adequate to ensure that each cylinder produced conforms to the 
requirements of this subpart. No defect is permitted that is likely to 
weaken the finished cylinder appreciably. A reasonably smooth and 
uniform surface finish is required. Welding procedures and operators 
must be qualified in accordance with CGA Pamphlet C-3 (IBR, see Sec.  
171.7 of this subchapter).
    (e) Footrings. Exposed bottom welds on cylinders over 18 inches long 
must be protected by footrings.
    (f) Welding or brazing. Welding or brazing for any purpose 
whatsoever is prohibited except as follows:
    (1) The attachment to the tops or bottoms of cylinders of neckrings, 
footrings, handlers, bosses, pads, and valve protecting rings is 
authorized provided that such attachments and the portion of the 
container to which they are attached are made of weldable steel, the 
carbon content of which may not exceed 0.25 percent.
    (2) Heat treatment is not required after welding or brazing weldable 
low carbon parts to attachments, specified in paragraph (f)(1) of this 
section, of similar material which have been previously welded or brazed 
to the top or bottom of cylinders and properly heat treated, provided 
such subsequent welding or brazing does not produce a temperature in 
excess of 400 [deg]F in any part of the top or bottom material.
    (g) Wall thickness; wall stress. The wall thickness/wall stress of 
the cylinder must conform to the following:
    (1) The calculated wall stress at 750 psi may not exceed 35,000 psi, 
or one-half of the minimum ultimate strength of the steel as determined 
in paragraph (l) of this section, whichever value is the smaller. The 
measured wall thickness may not include galvanizing or other protective 
coating.
    (i) Calculation of wall stress must be made by the formula:

S = [P(1.3D\2\ + 0.4d\2\)] / (D\2\ - d\2\)

Where:

S = wall stress in pounds psi;
P = 750 psig (minimum test pressure);
D = outside diameter in inches;
d = inside diameter in inches.

    (ii) Either D or d must be calculated from the relation D = d + 2t, 
where t = minimum wall thickness.
    (2) Cylinders with a wall thickness less than 0.100 inch, the ratio 
of straight side wall length to outside diameter may not exceed 3.5.
    (3) For cylinders having outside diameter over 5 inches, the minimum 
wall thickness must be 0.087 inch.
    (h) Heat treatment. Each cylinder must be uniformly and properly 
heat treated, prior to tests, by any suitable method in excess of 1100 
[deg]F. Heat treatment must be accomplished after all forming and 
welding operations, except that when brazed joints are used, heat 
treatment must follow any forming and welding operations but may be done 
before, during, or after the brazing operations. Liquid quenching is not 
authorized.
    (i) Openings. Standard taper pipe threads required in all openings. 
The length of the opening may not be less than as specified for American 
Standard pipe threads; tapped to gauge; clean cut, even, and without 
checks.
    (j) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:

[[Page 76]]

    (1) Lot testing. (i) At least one (1) cylinder selected at random 
out of each lot of 200 or less must be tested by water-jacket or direct 
expansion method as prescribed in CGA C-1 (IBR; see Sec.  171.7 of this 
subchapter). The testing equipment must be calibrated as prescribed in 
CGA C-1. All testing equipment and pressure indicating devices must be 
accurate within the parameters defined in CGA C-1.
    (ii) The selected cylinder must be tested to a minimum of 750 psig.
    (iii) The minimum test pressure must be maintained at least 30 
seconds and sufficiently longer to ensure complete expansion. Any 
internal pressure applied after heat-treatment and prior to the official 
test may not exceed 90 percent of the test pressure. If, due to failure 
of the test apparatus or operator error, the test pressure cannot be 
maintained, the test may be repeated in accordance with CGA C-1, section 
5.7.2.
    (iv) Permanent volumetric expansion may not exceed 10 percent of the 
total volumetric expansion at test pressure.
    (v) If the selected cylinder passes the volumetric expansion test, 
each remaining cylinder in the lot must be pressure tested in accordance 
with paragraph (h)(2) of this section. If the selected cylinder fails, 
each cylinder in the lot must be tested by water-jacket or direct 
expansion method as prescribed in CGA C-1 at 750 psig. Each cylinder 
with a permanent expansion that does not exceed 10% is acceptable.
    (2) Pressure testing. (i) If the selected cylinder passes the water-
jacket or direct expansion test, the remaining cylinders in each lot 
must be pressure tested by the proof pressure water-jacket or direct 
expansion test method as prescribed in CGA C-1. The minimum test 
pressure must be maintained for the specific timeframe and the testing 
equipment must be calibrated as prescribed in CGA C-1. Further, all 
testing equipment and pressure indicating devices must be accurate 
within the parameters defined in CGA C-1.
    (ii) Each cylinder must be tested between 500 and 600 psig and show 
no defect. If, due to failure of the test apparatus or operator error, 
the test pressure cannot be maintained, the test may be repeated in 
accordance with CGA C-1 section 5.7.2 or 7.1.2, as appropriate. 
Determination of expansion properties is not required.
    (k) Leakage test. Cylinders with bottoms closed in by spinning must 
be leakage tested by setting the interior air or gas pressure at not 
less than the service pressure. Any cylinder that leaks must be 
rejected.
    (l) Physical test. A physical test must be conducted as follows;
    (1) The test is required on 2 specimens cut longitudinally from 1 
cylinder or part thereof taken at random out of each lot of 200 or less, 
after heat treatment.
    (2) Specimens must conform to a gauge length of 8 inches with a 
width not over 1\1/2\ inches, a gauge length 2 inches with a width not 
over 1\1/2\ inches, or a gauge length at least 24 times thickness with a 
width not over 6 times thickness is authorized when a cylinder wall is 
not over \3/16\ inch thick.
    (3) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gauge length. The following 
conditions apply:
    (i) The yield strength must be determined by either the ``offset'' 
method or the ``extension under load'' method as prescribed in ASTM E 8 
(IBR, see Sec.  171.7 of this subchapter).
    (ii) In using the ``extension under load'' method, the total strain 
(or ``extension under load'') corresponding to the stress at which the 
0.2 percent permanent strain occurs may be determined with sufficient 
accuracy by calculating the elastic extension of the gauge length under 
appropriate load and adding thereto 0.2 percent of the gauge length. 
Elastic extension calculations must be based on an elastic modulus of 
30,000,000. In the event of controversy, the entire stress-strain 
diagram must be plotted and the yield strength determined from the 0.2 
offset.
    (iii) For the purpose of strain measurement, the initial strain must 
be set while the specimen is under a stress of 12,000 psi, the strain 
indicator reading being set at the calculated corresponding strain.
    (iv) Cross-head speed of the testing machine may not exceed \1/8\ 
inch per

[[Page 77]]

minute during yield strength determination.
    (m) Elongation. Physical test specimens must show at least a 40 
percent elongation for a 2 inch gauge length or at least a 20 percent 
elongation in other cases. Except that these elongation percentages may 
be reduced numerically by 2 for 2 inch specimens and 1 in other cases 
for each 7,500 psi increment of tensile strength above 50,000 psi to a 
maximum of four such increments.
    (n) Weld tests. Specimens taken across the circumferentially welded 
seam must be cut from one cylinder taken at random from each lot of 200 
or less cylinders after heat treatment and must pass satisfactorily the 
following tests:
    (1) Tensile test. A specimen must be cut from one cylinder of each 
lot of 200 or less, or welded test plate. The specimen must be taken 
from across the major seam and must be prepared and tested in accordance 
with and must meet the requirements of CGA Pamphlet C-3. Should this 
specimen fail to meet the requirements, specimens may be taken from two 
additional cylinders or welded test plates from the same lot and tested. 
If either of the latter specimens fail to meet the requirements, the 
entire lot represented must be rejected.
    (2) Guided bend test. A root bend test specimen must be cut from the 
cylinder or welded test plate, used for the tensile test specified in 
paragraph (n)(1) of this section. Specimens must be prepared and tested 
in accordance with and must meet the requirements of CGA Pamphlet C-3.
    (3) Alternate guided-bend test. This test may be used and must be as 
required by CGA Pamphlet C-3. The specimen must be bent until the 
elongation at the outer surface, adjacent to the root of the weld, 
between the lightly scribed gage lines-a to b, must be at least 20 
percent, except that this percentage may be reduced for steels having a 
tensile strength in excess of 50,000 psi, as provided in paragraph (m) 
of this section.
    (o) Rejected cylinders. Reheat treatment of rejected cylinders is 
authorized. Subsequent thereto, cylinders must pass all prescribed tests 
to be acceptable. Repair by welding is authorized.
    (p) Porous filling. (1) Cylinders must be filled with a porous 
material in accordance with the following:
    (i) The porous material may not disintegrate or sag when wet with 
solvent or when subjected to normal service;
    (ii) The filling material must be uniform in quality and free of 
voids, except that a well drilled into the filling material beneath the 
valve is authorized if the well is filled with a material of such type 
that the functions of the filling material are not impaired;
    (iii) Overall shrinkage of the filling material is authorized if the 
total clearance between the cylinder shell and filling material, after 
solvent has been added, does not exceed \1/2\ of 1 percent of the 
respective diameter or length but not to exceed \1/8\ inch, measured 
diametrically and longitudinally;
    (iv) The clearance may not impair the functions of the filling 
material;
    (v) The installed filling material must meet the requirements of CGA 
C-12 (IBR, see Sec.  171.7 of this subchapter); and
    (vi) Porosity of filling material may not exceed 80 percent except 
that filling material with a porosity of up to 92 percent may be used 
when tested with satisfactory results in accordance with CGA Pamphlet C-
12.
    (2) When the porosity of each cylinder is not known, a cylinder 
taken at random from a lot of 200 or less must be tested for porosity. 
If the test cylinder fails, each cylinder in the lot may be tested 
individually and those cylinders that pass the test are acceptable.
    (3) For filling that is molded and dried before insertion in 
cylinders, porosity test may be made on sample block taken at random 
from material to be used.
    (4) The porosity of the filling material must be determined; the 
amount of solvent at 70 [deg]F for a cylinder:
    (i) Having shell volumetric capacity above 20 pounds water capacity 
(nominal) may not exceed the following:

------------------------------------------------------------------------
                                                 Maximum acetone solvent
           Percent porosity of filler             percent shell capacity
                                                        by volume
------------------------------------------------------------------------
90 to 92.......................................                     43.4
87 to 90.......................................                     42.0

[[Page 78]]

 
83 to 87.......................................                     40.0
80 to 83.......................................                     38.6
75 to 80.......................................                     36.2
70 to 75.......................................                     33.8
65 to 70.......................................                     31.4
------------------------------------------------------------------------

    (ii) Having volumetric capacity of 20 pounds or less water capacity 
(nominal), may not exceed the following:

------------------------------------------------------------------------
                                                 Maximum acetone solvent
           Percent porosity of filler             percent shell capacity
                                                        by volume
------------------------------------------------------------------------
90 to 92.......................................                     41.8
83 to 90.......................................                     38.5
80 to 83.......................................                     37.1
75 to 80.......................................                     34.8
70 to 75.......................................                     32.5
65 to 70.......................................                     30.2
------------------------------------------------------------------------

    (q) Tare weight. The tare weight is the combined weight of the 
cylinder proper, porous filling, valve, and solvent, but without 
removable cap.
    (r) Duties of inspector. In addition to the requirements of Sec.  
178.35, the inspector shall--
    (1) Certify chemical analyses of steel used, signed by manufacturer 
thereof; also verify by check analyses, of samples taken from each heat 
or from 1 out of each lot of 200 or less plates, shells, or tubes used.
    (2) Verify compliance of cylinder shells with all shell 
requirements, inspect inside before closing in both ends, verify heat 
treatment as proper; obtain all samples for all tests and for check 
analyses, witness all tests; verify threads by gauge, report volumetric 
capacity and minimum thickness of wall noted.
    (3) Report percentage of each specified alloying element in the 
steel. Prepare report on manufacture of steel shells in form prescribed 
in Sec.  178.35. Furnish one copy to manufacturer and three copies to 
the company that is to complete the cylinders.
    (4) Determine porosity of filling and tare weights; verify 
compliance of marking with prescribed requirements; obtain necessary 
copies of steel shell reports prescribed in paragraph (b) of this 
section; and furnish complete test reports required by this 
specification to the person who has completed the manufacturer of the 
cylinders and, upon request, to the purchaser. The test reports must be 
retained by the inspector for fifteen years from the original test date 
of the cylinder.
    (s) Marking. (1) Tare weight of cylinder, in pounds and ounces, must 
be marked on the cylinder.
    (2) Cylinders, not completed, when delivered must each be marked for 
identification of each lot of 200 or less.
    (3) Markings must be stamped plainly and permanently in locations in 
accordance with the following:
    (i) On shoulders and top heads not less than 0.087 inch thick; or
    (ii) On neck, valve boss, valve protection sleeve, or similar part 
permanently attached to the top end of cylinder; or
    (iii) On a plate of ferrous material attached to the top of the 
cylinder or permanent part thereof; the plate must be at least \1/16\ 
inch thick, and must be attached by welding, or by brazing at a 
temperature of at least 1,100 [deg]F throughout all edges of the plate. 
Sufficient space must be left on the plate to provide for stamping at 
least four (4) retest dates.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended at 66 FR 45386, 
45388, Aug. 28, 2001; 67 FR 51654, Aug. 8, 2002; 68 FR 75748, 75749, 
Dec. 31, 2003; 85 FR 85428, Dec. 28, 2020]



Sec.  178.61  Specification 4BW welded steel cylinders with electric-arc 
welded seam.

    (a) Type, size, pressure, and application. A DOT 4BW cylinder has a 
spherical or cylindrical design, a water capacity of 1,000 pounds or 
less, and a service pressure range of 225 to 500 psig. Closures made by 
the spinning process are not authorized.
    (1) Spherical designs are permitted to have only one 
circumferentially electric-arc welded seam.
    (2) Cylindrical designs must be of circumferentially welded 
electric-arc construction; longitudinally electric-arc welded seams are 
permitted.
    (b) Steel. (1) The steel used in the construction of the cylinder 
must be as specified in table 1 of appendix A to this part. The cylinder 
manufacturer must maintain a record of intentionally added alloying 
elements.
    (2) Material for heads must meet the requirements of paragraph 
(b)(1) of this section or be open hearth, electric or

[[Page 79]]

basic oxygen carbon steel of uniform quality. Content percent may not 
exceed the following: Carbon 0.25, Manganese 0.60, Phosphorus 0.045, 
Sulfur 0.050. Heads must be hemispherical or ellipsoidal in shape with a 
maximum ratio of 2:1. If low carbon steel is used, the thickness of such 
heads must be determined by using a maximum wall stress of 24,000 psi in 
the formula described in paragraph (f)(2) of this section.
    (c) Identification of material. Pressure-retaining materials must be 
identified by any suitable method that does not compromise the integrity 
of the cylinder. Plates and billets for hotdrawn cylinders must be 
marked with the heat number.
    (d) Manufacture. Cylinders must be manufactured using equipment and 
processes adequate to ensure that each cylinder produced conforms to the 
requirements of this subpart and the following:
    (1) No defect is permitted that is likely to weaken the finished 
cylinder appreciably. A reasonably smooth and uniform surface is 
required. Exposed bottom welds on cylinders over 18 inches long must be 
protected by footrings. Minimum thickness of heads may not be less than 
90 percent of the required thickness of the sidewall. Heads must be 
concave to pressure.
    (2) Circumferential seams must be by electric-arc welding. Joints 
must be butt with one member offset (joggle butt) or with a lap joint. 
Joints must have a minimum overlap of at least four (4) times nominal 
sheet thickness.
    (3) Longitudinal electric-arc welded seams (in shells) must be of 
the butt welded type. Welds must be made by a machine process including 
automatic feed and welding guidance mechanisms. Longitudinal seams must 
have complete joint penetration, and must be free from undercuts, 
overlaps or abrupt ridges or valleys. Misalignment of mating butt edges 
may not exceed \1/6\ inch of nominal sheet thickness or \1/32\ inch 
whichever is less. All joints with nominal sheet thickness up to and 
including \1/8\ inch must be tightly butted. When nominal sheet 
thickness is greater than \1/8\ inch, the joint must be gapped with 
maximum distance equal to one-half the nominal sheet thickness or \1/32\ 
inch whichever is less. Joint design, preparation, and fit-up must be 
such that requirements of this paragraph (d) are satisfied.
    (4) Welding procedures and operators must be qualified in accordance 
with CGA C-3 (IBR, see Sec.  171.7 of this subchapter).
    (5)(i) Welds of the cylinders must be subjected to radioscopic or 
radiographic examination as follows:
    (ii) Radioscopy or radiography must be in conformance with CGA C-3 
(IBR; see Sec.  171.7 of this subchapter). Maximum joint efficiency will 
be 1.0 when each longitudinal seam is examined completely. Maximum joint 
efficiency will be 0.90 when one cylinder from each lot of 50 
consecutively welded cylinders is spot examined. In addition, one out of 
the first five cylinders welded following a shutdown of welding 
operations exceeding four hours must be spot examined. Spot radiographs, 
when required, must be made of a finished welded cylinder and must 
include the circumferential weld for 2 inches in both directions from 
the intersection of the longitudinal and circumferential welds and 
include at least 6 inches of the longitudinal weld. Maximum joint 
efficiency of 0.75 will be permissible without radiography or 
radioscopy. When fluoroscopic examination is used, permanent film 
records need not be retained. Circumferential welds need not be 
examined, except as part of spot examination.
    (e) Welding of attachments. The attachment to the tops and bottoms 
only of cylinders by welding of neckrings, footrings, handles, bosses, 
pads and valve protection rings is authorized provided that such 
attachments and the portion of the container to which they are attached 
are made of weldable steel, the carbon content of which may not exceed 
0.25 percent.
    (f) Wall thickness. (1) For outside diameters over 6 inches the 
minimum wall thickness must be 0.078 inch. In any case, the minimum wall 
thickness must be such that the wall stress calculated by the formula 
listed in paragraph (f)(2) of this section may not exceed the lesser 
value of any of the following:

[[Page 80]]

    (i) The value referenced in paragraph (b) of this section for the 
particular material under consideration.
    (ii) One-half of the minimum tensile strength of the material 
determined as required in paragraph (j) of this section.
    (iii) 35,000 psig.
    (2) Stress must be calculated by the following formula:

S = [2P(1.3D\2\ + 0.4d\2\)]/[E(D\2\ - d\2\)]

Where:
S = wall stress, psig;
P = service pressure, psig;
D = outside diameter, inches;
d = inside diameter, inches; and
E = joint efficiency of the longitudinal seam (from paragraph (d) of 
          this section).

    (3) For a cylinder with a wall thickness less than 0.100 inch, the 
ratio of tangential length to outside diameter may not exceed 4 to 1 
(4:1).
    (g) Heat treatment. Cylinders must be heat treated in accordance 
with the following requirements:
    (1) Each cylinder must be uniformly and properly heat treated prior 
to test by the applicable method referenced in table 1 of appendix A to 
this part. Heat treatment must be accomplished after all forming and 
welding operations, except that when brazed joints are used, heat 
treatment must follow any forming and welding operations, but may be 
done before, during or after the brazing operations (see paragraph (n) 
of this section for weld repairs).
    (2) Heat treatment is not required after welding of weldable low-
carbon parts to attachments of similar material which have been 
previously welded to the top or bottom of cylinders and properly heat 
treated, provided such subsequent welding does not produce a temperature 
in excess of 400 [deg]F in any part of the top or bottom material.
    (h) Openings in cylinders. Openings in cylinders must comply with 
the following requirements:
    (1) All openings must be in heads or bases.
    (2) Each opening in a spherical-type cylinder must be provided with 
a fitting, boss, or pad of weldable steel securely attached to the 
cylinder by fusion welding.
    (3) Each opening in a cylindrical-type cylinder must be provided 
with a fitting, boss, or pad securely attached to the cylinder by 
welding.
    (4) If threads are used, they must comply with the following:
    (i) Threads must be clean cut, even, without checks, and tapped to 
gauge.
    (ii) Taper threads must be of length not less than as specified for 
American Standard Taper Pipe Threads.
    (iii) Straight threads, having at least four (4) engaged threads, 
must have a tight fit and calculated shear strength at least ten (10) 
times the test pressure of the cylinder. Gaskets, adequate to prevent 
leakage, are required.
    (iv) A brass fitting may be brazed to the steel boss or flange on 
cylinders used as component parts of handheld fire extinguishers.
    (i) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:
    (1) Lot testing. (i) At least one (1) cylinder randomly selected out 
of each lot of 200 or fewer must be tested by the water-jacket or direct 
expansion method as prescribed in CGA C-1 (IBR, see Sec.  171.7 of this 
subchapter). The testing equipment must be calibrated as prescribed in 
CGA C-1. All testing equipment and pressure indicating devices must be 
accurate within the parameters defined in CGA C-1.
    (ii) Each selected cylinder must be tested to a minimum of two (2) 
times service pressure.
    (iii) The minimum test pressure must be maintained at least 30 
seconds and sufficiently longer to ensure complete expansion. Any 
internal pressure applied after heat-treatment and prior to the official 
test may not exceed 90 percent of the test pressure. If, due to failure 
of the test apparatus or operator error, the test pressure cannot be 
maintained, the test may be repeated in accordance with CGA C-1, section 
5.7.2.
    (iv) Permanent volumetric expansion may not exceed 10 percent of the 
total volumetric expansion at test pressure.
    (2) Pressure testing. (i) The remaining cylinders in each lot must 
be pressure tested by the proof pressure, water-jacket or direct 
expansion test method as prescribed in CGA C-1. The minimum test 
pressure must be maintained for the specific timeframe and

[[Page 81]]

the testing equipment must be calibrated as prescribed in CGA C-1. 
Further, all testing equipment and pressure indicating devices must be 
accurate within the parameters defined in CGA C-1.
    (ii) Each cylinder must be tested to a minimum of two (2) times 
service pressure and show no defect. If, due to failure of the test 
apparatus or operator error, the test pressure cannot be maintained, the 
test may be repeated in accordance with CGA C-1 5.7.2 or 7.1.2, as 
appropriate. Determination of expansion properties is not required.
    (3) Burst testing. One finished cylinder selected at random out of 
each lot of 500 or less successively produced must be hydrostatically 
tested to four (4) times service pressure without bursting. All testing 
equipment and pressure indicating devices must be accurate within the 
parameters defined in CGA C-1.
    (j) Mechanical tests. Mechanical tests must be conducted to 
determine yield strength, tensile strength, elongation as a percentage, 
and reduction of area of material as a percentage, as follows:
    (1) Specimens must be taken from one cylinder after heat treatment 
as illustrated in appendix A to this subpart, chosen at random from each 
lot of 200 or fewer, as follows:
    (i) One specimen must be taken longitudinally from the body section 
at least 90 degrees away from the weld.
    (ii) One specimen must be taken from either head on a cylinder when 
both heads are made of the same material. However, if the two heads are 
made of differing materials, a specimen must be taken from each head.
    (iii) If due to welded attachments on the top head there is 
insufficient surface from which to take a specimen, it may be taken from 
a representative head of the same heat treatment as the test cylinder.
    (2) Specimens must conform to the following:
    (i) When a cylinder wall is \3/16\ inch thick or less, one the 
following gauge lengths is authorized: A gauge length of 8 inches with a 
width not over1\1/2\ inches, a gauge length of 2 inches with a width not 
over 1\1/2\ inches, or a gauge length at least twenty-four (24) times 
the thickness with a width not over six (6) times the thickness.
    (ii) The specimen, exclusive of grip ends, may not be flattened. 
Grip ends may be flattened to within 1 inch of each end of the reduced 
section.
    (iii) When size of the cylinder does not permit securing straight 
specimens, the specimens may be taken in any location or direction and 
may be straightened or flattened cold, by pressure only, not by blows. 
When specimens are taken, and prepared in this manner, the inspector's 
report must show, in connection with the record of physical tests, 
detailed information in regard to such specimens.
    (iv) Heating of a specimen for any purpose is not authorized.
    (3) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gauge length. The following 
conditions apply:
    (i) The yield strength must be determined by either the ``off-set'' 
method or the ``extension under load'' method as prescribed in ASTM E 8 
(IBR, see Sec.  171.7 of this subchapter).
    (ii) In using the ``extension under load'' method, the total strain 
(or ``extension under load''), corresponding to the stress at which the 
0.2-percent permanent strain occurs may be determined with sufficient 
accuracy by calculating the elastic extension of the gauge length under 
appropriate load and adding thereto 0.2 percent of the gauge length. 
Elastic extension calculations must be based on an elastic modulus of 
30,000,000. In the event of controversy, the entire stress-strain 
diagram must be plotted and the yield strength determined from the 0.2-
percent offset.
    (iii) For strain measurement, the initial strain reference must be 
set while the specimen is under a stress of 12,000 psig, and the strain 
indicator reading must be set at the calculated corresponding strain.
    (iv) Cross-head speed of the testing machine may not exceed \1/8\ 
inch per minute during yield strength determination.
    (k) Elongation. Mechanical test specimens must show at least a 40 
percent elongation for a 2-inch gauge length or

[[Page 82]]

at least 20 percent in other cases. However, elongation percentages may 
be reduced numerically by 2 percent for 2-inch specimens, and by 1 
percent in other cases, for each 7,500 psi increase of tensile strength 
above 50,000 psig. The tensile strength may be incrementally increased 
by four increments of 7,500 psig for a maximum total of 30,000 psig.
    (l) Tests of welds. Welds must be subjected to the following tests:
    (1) Tensile test. A specimen must be removed from one cylinder of 
each lot of 200 or fewer. The specimen must be taken from across the 
longitudinal seam and must be prepared and tested in conformance with 
the requirements of CGA C-3 (IBR, see Sec.  171.7 of this subchapter).
    (2) Guided bend test. A root bend test specimen must be removed from 
the cylinder or welded test plate used for the tensile test specified in 
paragraph (m)(1) of this section. Specimens must be taken from across 
the longitudinal seam and must be prepared and tested in conformance 
with the requirements of CGA C-3. If the specimen fails to meet the 
requirements, one specimen each must be taken from two additional 
cylinders or welded test plates from the same lot as the previously 
tested cylinder or added test plate and tested. If either of these 
latter two specimens fails to meet the requirements, the entire lot 
represented must be rejected.
    (3) Alternate guided bend test. This test may be used and must be as 
required by CGA C-3. The specimen must be bent until the elongation at 
the outer surface, adjacent to the root of the weld, between the lightly 
scribed gauge lines a to b, must be at least 20 percent, except that 
this percentage may be reduced for steels having a tensile strength in 
excess of 50,000 psig, as provided in paragraph (k) of this section. 
Should this specimen fail to meet the requirements, one additional 
specimen must be taken from two additional cylinders or welded test 
plates from the same lot and tested as the previously tested cylinder or 
added test plate. If either of these latter two specimens fails to meet 
the requirements, the entire lot represented must be rejected.
    (m) Rejected cylinders. (1) Unless otherwise stated, if a sample 
cylinder or specimen taken from a lot of cylinders fails the prescribed 
test, then two additional specimens must be selected from the same lot 
and subjected to the prescribed test. If either of these fails the test, 
then the entire lot must be rejected.
    (2) Reheat treatment of rejected cylinders. Reheat treatment is 
authorized for a rejected cylinder in accordance with this paragraph 
(m)(2). After reheat treatment, a cylinder must pass all prescribed 
tests in this section to be considered acceptable. Repair of welded 
seams by welding is authorized. For cylinders less than or equal to an 
outside diameter of 6 inches, welded seam repairs greater than 1 inch in 
length shall require reheat treatment of the cylinder. For cylinders 
greater than an outside diameter of 6 inches, welded seam repairs 
greater than 3 inches in length shall require reheat treatment.
    (n) Markings. (1) Markings must be as required in Sec.  178.35 and 
in addition must be stamped plainly and permanently in one of the 
following locations on the cylinder:
    (i) On shoulders and top heads whose wall thickness is not less than 
0.087 inch thick.
    (ii) On side wall adjacent to top head for side walls not less than 
0.090 inch thick.
    (iii) On a cylindrical portion of the shell that extends beyond the 
recessed bottom of the cylinder constituting an integral and non-
pressure part of the cylinder.
    (iv) On a plate attached to the top of the cylinder or permanent 
part thereof; sufficient space must be left on the plate to provide for 
stamping at least six retest dates; the plate must be at least \1/16\-
inch thick and must be attached by welding at a temperature of 1,100 
[deg]F, throughout all edges of the plate.
    (v) On the neck, neckring, valve boss, valve protection sleeve, or 
similar part permanently attached to the top of the cylinder.
    (vi) On the footring permanently attached to the cylinder, provided 
the water capacity of the cylinder does not exceed 30 pounds.

[[Page 83]]

    (2) Embossing the cylinder head or side wall is not permitted.
    (o) Inspector's report. In addition to the information required by 
Sec.  178.35, the inspector's report must indicate the type and amount 
of radiography.

[85 FR 85428, Dec. 28, 2020]



Sec.  178.65  Specification 39 non-reusable (non-refillable) cylinders.

    (a) Type, size, service pressure, and test pressure. A DOT 39 
cylinder is a seamless, welded, or brazed cylinder with a service 
pressure not to exceed 80 percent of the test pressure. Spherical 
pressure vessels are authorized and covered by references to cylinders 
in this specification.
    (1) Size limitation. Maximum water capacity may not exceed: (i) 55 
pounds (1,526 cubic inches) for a service pressure of 500 p.s.i.g. or 
less, and (ii) 10 pounds (277 cubic inches) for a service pressure in 
excess of 500 p.s.i.g.
    (2) Test pressure. The minimum test pressure is the maximum pressure 
of contents at 130 [deg]F or 180 p.s.i.g. whichever is greater.
    (3) Pressure of contents. The term ``pressure of contents'' as used 
in this specification means the total pressure of all the materials to 
be shipped in the cylinder.
    (b) Material; steel or aluminum. The cylinder must be constructed of 
either steel or aluminum conforming to the following requirements:
    (1) Steel. (i) The steel analysis must conform to the following:

------------------------------------------------------------------------
                                                        Ladle     Check
                                                      analysis  analysis
------------------------------------------------------------------------
Carbon, maximum percent.............................      0.12      0.15
Phosphorus, maximum percent.........................       .04       .05
Sulfur, maximum percent.............................       .05       .06
------------------------------------------------------------------------

    (ii) For a cylinder made of seamless steel tubing with integrally 
formed ends, hot drawn, and finished, content percent for the following 
may not exceed: Carbon, 0.55; phosphorous, 0.045; sulfur, 0.050.
    (iii) For non-heat treated welded steel cylinders, adequately killed 
deep drawing quality steel is required.
    (iv) Longitudinal or helical welded cylinders are not authorized for 
service pressures in excess of 500 p.s.i.g.
    (2) Aluminum. Aluminum is not authorized for service pressures in 
excess of 500 psig. The analysis of the aluminum must conform to the 
Aluminum Association standard for alloys 1060, 1100, 1170, 3003, 5052, 
5086, 5154, 6061, and 6063, as specified in its publication entitled 
``Aluminum Standards and Data'' (IBR, see Sec.  171.7 of this 
subchapter).
    (3) Material with seams, cracks, laminations, or other injurious 
defects not permitted.
    (4) Material used must be identified by any suitable method.
    (c) Manufacture. (1) General manufacturing requirements are as 
follows:
    (i) The surface finish must be uniform and reasonably smooth.
    (ii) Inside surfaces must be clean, dry, and free of loose 
particles.
    (iii) No defect of any kind is permitted if it is likely to weaken a 
finished cylinder.
    (2) Requirements for seams:
    (i) Brazing is not authorized on aluminum cylinders.
    (ii) Brazing material must have a melting point of not lower than 
1,000 [deg]F.
    (iii) Brazed seams must be assembled with proper fit to ensure 
complete penetration of the brazing material throughout the brazed 
joint.
    (iv) Minimum width of brazed joints must be at least four times the 
thickness of the shell wall.
    (v) Brazed seams must have design strength equal to or greater than 
1.5 times the minimum strength of the shell wall.
    (vi) Welded seams must be properly aligned and welded by a method 
that provides clean, uniform joints with adequate penetration.
    (vii) Welded joints must have a strength equal to or greater than 
the minimum strength of the shell material in the finished cylinder.
    (3) Attachments to the cylinder are permitted by any means which 
will not be detrimental to the integrity of the cylinder. Welding or 
brazing of attachments to the cylinder must be completed prior to all 
pressure tests.
    (4) Welding procedures and operators must be qualified in accordance 
with CGA Pamphlet C-3 (IBR, see Sec.  171.7 of this subchapter).
    (d) Wall thickness. The minimum wall thickness must be such that the 
wall

[[Page 84]]

stress at test pressure does not exceed the yield strength of the 
material of the finished cylinder wall. Calculations must be made by the 
following formulas:
    (1) Calculation of the stress for cylinders must be made by the 
following formula:

S = [P(1.3D\2\ + 0.4d\2\)] / (D\2\ - d\2\)

Where:

S = Wall stress, in psi;
P = Test pressure in psig;
D = Outside diameter, in inches;
d = Inside diameter, in inches.

    (2) Calculation of the stress for spheres must be made by the 
following formula:

S = PD / 4t

Where:

S = Wall stress, in psi;
P = Test pressure i psig;
D = Outside diameter, in inches;
t = Minimum wall thickness, in inches.

    (e) Openings and attachments. Openings and attachments must conform 
to the following:
    (1) Openings and attachments are permitted on heads only.
    (2) All openings and their reinforcements must be within an 
imaginary circle, concentric to the axis of the cylinder. The diameter 
of the circle may not exceed 80 percent of the outside diameter of the 
cylinder. The plane of the circle must be parallel to the plane of a 
circumferential weld and normal to the long axis of the cylinder.
    (3) Unless a head has adequate thickness, each opening must be 
reinforced by a securely attached fitting, boss, pad, collar, or other 
suitable means.
    (4) Material used for welded openings and attachments must be of 
weldable quality and compatible with the material of the cylinder.
    (f) Pressure testing. (1) Each cylinder must be proof pressure 
tested as prescribed in CGA C-1 (IBR, see Sec.  171.7 of this 
subchapter). The minimum test pressure must be maintained for the 
specific timeframe and the testing equipment must be calibrated as 
prescribed in CGA C-1. All testing equipment and pressure indicating 
devices must be accurate within the parameters defined in CGA C-1.
    (i) The leakage test must be conducted by submersion under water or 
by some other method that will be equally sensitive.
    (ii) If the cylinder leaks, evidences visible distortion or 
evidences any other defect while under test, it must be rejected (see 
paragraph (h) of this section).
    (iii) If, due to failure of the test apparatus or operator error, 
the test pressure cannot be maintained, the test may be repeated in 
accordance with CGA, C-1 section 7.1.2.
    (2) One cylinder taken from the beginning of each lot, and one from 
each 1,000 or less successively produced within the lot thereafter, must 
be hydrostatically tested to destruction. The testing equipment must be 
calibrated as prescribed in CGA C-1. All testing equipment and pressure 
indicating devices must be accurate within the parameters defined in CGA 
C-1. The entire lot must be rejected (see paragraph (h) of this section) 
if:
    (i) A failure occurs at a gage pressure less than 2.0 times the test 
pressure;
    (ii) A failure initiates in a braze or a weld or the heat affected 
zone thereof;
    (iii) A failure is other than in the sidewall of a cylinder 
longitudinal with its long axis; or
    (iv) In a sphere, a failure occurs in any opening, reinforcement, or 
at a point of attachment.
    (3) A ``lot'' is defined as the quantity of cylinders successively 
produced per production shift (not exceeding 10 hours) having identical 
size, design, construction, material, heat treatment, finish, and 
quality.
    (g) Flattening test. One cylinder must be taken from the beginning 
of production of each lot (as defined in paragraph (f)(3) of this 
section) and subjected to a flattening test as follows:
    (1) The flattening test must be made on a cylinder that has been 
tested at test pressure.
    (2) A ring taken from a cylinder may be flattened as an alternative 
to a test on a complete cylinder. The test ring may not include the heat 
affected zone or any weld. However, for a sphere, the test ring may 
include the circumferential weld if it is located at a 45 degree angle 
to the ring, 5 degrees.

[[Page 85]]

    (3) The flattening must be between 60 degrees included-angle, wedge 
shaped knife edges, rounded to a 0.5 inch radius.
    (4) Cylinders and test rings may not crack when flattened so that 
their outer surfaces are not more than six times wall thickness apart 
when made of steel or not more than ten times wall thickness apart when 
made of aluminum.
    (5) If any cylinder or ring cracks when subjected to the specified 
flattening test, the lot of cylinders represented by the test must be 
rejected (see paragraph (h) of this section).
    (h) Rejected cylinders. Rejected cylinders must conform to the 
following requirements:
    (1) If the cause for rejection of a lot is determinable, and if by 
test or inspection defective cylinders are eliminated from the lot, the 
remaining cylinders must be qualified as a new lot under paragraphs (f) 
and (g) of this section.
    (2) Repairs to welds are permitted. Following repair, a cylinder 
must pass the pressure test specified in paragraph (f) of this section.
    (3) If a cylinder made from seamless steel tubing fails the 
flattening test described in paragraph (g) of this section, suitable 
uniform heat treatment must be used on each cylinder in the lot. All 
prescribed tests must be performed subsequent to this heat treatment.
    (i) Markings. (1) The markings required by this section must be 
durable and waterproof. The requirements of Sec.  178.35(h) do not apply 
to this section.
    (2) Required markings are as follows:
    (i) DOT-39.
    (ii) NRC.
    (iii) The service pressure.
    (iv) The test pressure.
    (v) The registration number (M****) of the manufacturer.
    (vi) The lot number.
    (vii) The date of manufacture if the lot number does not establish 
the date of manufacture.
    (viii) With one of the following statements:
    (A) For cylinders manufactured prior to October 1, 1996: ``Federal 
law forbids transportation if refilled-penalty up to $25,000 fine and 5 
years imprisonment (49 U.S.C. 1809)'' or ``Federal law forbids 
transportation if refilled-penalty up to $500,000 fine and 5 years 
imprisonment (49 U.S.C. 5124).''
    (B) For cylinders manufactured on or after October 1, 1996: 
``Federal law forbids transportation if refilled-penalty up to $500,000 
fine and 5 years imprisonment (49 U.S.C. 5124).''
    (3) The markings required by paragraphs (i)(2)(i) through (i)(2)(v) 
of this section must be in numbers and letters at least \1/8\ inch high 
and displayed sequentially. For example:

DOT-39 NRC 250/500 M1001.

    (4) No person may mark any cylinder with the specification 
identification ``DOT-39'' unless it was manufactured in compliance with 
the requirements of this section and its manufacturer has a registration 
number (M****) from the Associate Administrator.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended at 65 FR 58631, 
Sept. 29, 2000; 66 FR 45389, Aug. 28, 2001; 67 FR 51654, Aug. 8, 2002; 
68 FR 75748, 75749, Dec. 31, 2003; 85 FR 85430, Dec. 28, 2020]



Sec.  178.68  Specification 4E welded aluminum cylinders.

    (a) Type, size and service pressure. A DOT 4E cylinder is a welded 
aluminum cylinder with a water capacity (nominal) of not over 1,000 
pounds and a service pressure of at least 225 to not over 500 psig. The 
cylinder must be constructed of not more than two seamless drawn shells 
with no more than one circumferential weld. The circumferential weld may 
not be closer to the point of tangency of the cylindrical portion with 
the shoulder than 20 times the cylinder wall thickness. Cylinders or 
shells closed in by spinning process and cylinders with longitudinal 
seams are not authorized.
    (b) Authorized material. (1) The cylinder must be constructed of 
aluminum of uniform quality. The following chemical analyses are 
authorized:

            Table 1 to Paragraph (b)(1)--Authorized Materials
------------------------------------------------------------------------
                                          Chemical analysis--limits in
              Designation                         percent 5154
------------------------------------------------------------------------
Iron plus silicon.....................  0.45 maximum.
Copper................................  0.10 maximum.
Manganese.............................  0.10 maximum.
Magnesium.............................  3.10/3.90.

[[Page 86]]

 
Chromium..............................  0.15/0.35.
Zinc..................................  0.20 maximum.
Titanium..............................  0.20 maximum.
Others, each..........................  0.05 maximum.
Others, total.........................  0.15 maximum.
Aluminum..............................  remainder.
------------------------------------------------------------------------

    (2) The aluminum used in the construction of the cylinder must be as 
specified in Table 1 to paragraph (b)(1) of this section. Analyses must 
regularly be made only for the elements specifically mentioned in the 
table. If, however, the presence of other elements is indicated in the 
course of routine analysis, further analysis should be made to determine 
conformance with the limits specified for other elements. The cylinder 
manufacturer must maintain a record of intentionally added alloying 
elements.
    (c) Identification. Material must be identified by any suitable 
method that will identify the alloy and manufacturer's lot number.
    (d) Manufacture. Cylinders must be manufactured using equipment and 
processes adequate to ensure that each cylinder produced conforms to the 
requirements of this subpart. No defect is permitted that is likely to 
weaken the finished cylinder appreciably. A reasonably smooth and 
uniform surface finish is required. All welding must be by the gas 
shielded arc process.
    (e) Welding. The attachment to the tops and bottoms only of 
cylinders by welding of neckrings, flanges, footrings, handles, bosses, 
pads, and valve protection rings is authorized. However, such 
attachments and the portion of the cylinder to which it is attached must 
be made of weldable aluminum alloys.
    (f) Wall thickness. The wall thickness of the cylinder must conform 
to the following:
    (1) The minimum wall thickness of the cylinder must be 0.140 inch. 
In any case, the minimum wall thickness must be such that calculated 
wall stress at twice service pressure may not exceed the lesser value of 
either of the following:
    (i) 20,000 psi.
    (ii) One-half of the minimum tensile strength of the material as 
required in paragraph (j) of this section.
    (2) Calculation must be made by the following formula:

S = [P(1.3D\2\ + 0.4d\2\)] / (D\2\ - d\2\)

Where:

S = wall stress in psi;
P = minimum test pressure prescribed for water jacket test;
D = outside diameter in inches;
d = inside diameter in inches.

    (3) Minimum thickness of heads and bottoms may not be less than the 
minimum required thickness of the side wall.
    (g) Opening in cylinder. Openings in cylinders must conform to the 
following:
    (1) All openings must be in the heads or bases.
    (2) Each opening in cylinders, except those for safety devices, must 
be provided with a fitting, boss, or pad, securely attached to cylinder 
by welding by inert gas shielded arc process or by threads. If threads 
are used, they must comply with the following:
    (i) Threads must be clean-cut, even, without checks and cut to 
gauge.
    (ii) Taper threads to be of length not less than as specified for 
American Standard taper pipe threads.
    (iii) Straight threads, having at least 4 engaged threads, to have 
tight fit and calculated shear strength at least 10 times the test 
pressure of the cylinder; gaskets required, adequate to prevent leakage.
    (3) Closure of a fitting, boss, or pad must be adequate to prevent 
leakage.
    (h) Pressure testing. Each cylinder must successfully withstand a 
pressure test as follows:
    (1) Pressure test. All cylinders with a wall stress greater than 
18,000 psig must be tested by water-jacket or direct expansion method as 
prescribed in CGA C-1 (IBR, see Sec.  171.7 of this subchapter). The 
testing equipment must be calibrated as prescribed in CGA C-1. All 
testing equipment and pressure indicating devices must be accurate 
within the parameters defined in CGA C-1.
    (i) Each cylinder must be tested to a minimum of two (2) times 
service pressure.

[[Page 87]]

    (ii) The minimum test pressure must be maintained at least 30 
seconds and sufficiently longer to ensure complete expansion. Any 
internal pressure applied after heat-treatment and prior to the official 
test may not exceed 90 percent of the test pressure. If, due to failure 
of the test apparatus or operator error, the test pressure cannot be 
maintained, the test may be repeated in accordance with CGA C-1, section 
5.7.2.
    (iii) Permanent volumetric expansion may not exceed 12 percent of 
the total volumetric expansion at test pressure.
    (2) Lot testing. (i) Cylinders with a wall stress of 18,000 psig or 
less may be lot tested. At least one (1) cylinder randomly selected out 
of each lot of 200 or less must be tested by the water-jacket or direct 
expansion method as prescribed in CGA C-1. The testing equipment must be 
calibrated as prescribed in CGA C-1. All testing equipment and pressure 
indicating devices must be accurate within the parameters defined in CGA 
C-1. If, due to failure of the test apparatus or operator error, the 
test pressure cannot be maintained, the test may be repeated in 
accordance with CGA C-1, section 5.7.2.
    (ii) Each selected cylinder must be tested to a minimum of two (2) 
times service pressure.
    (iii) The minimum test pressure must be maintained at least 30 
seconds and sufficiently longer to ensure complete expansion. Any 
internal pressure applied after heat-treatment and prior to the official 
test may not exceed 90 percent of the test pressure.
    (iv) Permanent volumetric expansion may not exceed 12 percent of the 
total volumetric expansion at test pressure.
    (3) Pressure testing. (i) For cylinders with a wall stress of 18,000 
psig or less, the remaining cylinders of the lot must be pressure tested 
by the proof pressure, water-jacket, or direct expansion test method as 
defined in CGA C-1. The minimum test pressure must be maintained for the 
specific timeframe and the testing equipment must be calibrated as 
prescribed in CGA C-1. Further, all testing equipment and pressure 
indicating devices must be accurate within the parameters defined in CGA 
C-1.
    (ii) Each cylinder must be tested to a minimum of two (2) times 
service pressure and show no defect. If, due to failure of the test 
apparatus or operator error, the test pressure cannot be maintained, the 
test may be repeated in accordance with CGA C-1 5.7.2 or 7.1.2, as 
appropriate. Determination of expansion properties is not required.
    (4) Burst testing. One (1) finished cylinder selected at random out 
of each lot of 1000 or less must be hydrostatically tested to four (4) 
times service pressure without bursting. Inability to meet this 
requirement must result in rejection of the lot. All testing equipment 
and pressure indicating devices must be accurate within the parameters 
defined in CGA C-1.
    (i) Flattening test. After hydrostatic testing, a flattening test is 
required on one section of a cylinder, taken at random out of each lot 
of 200 or less as follows:
    (1) If the weld is not at midlength of the cylinder, the test 
section must be no less in width than 30 times the cylinder wall 
thickness. The weld must be in the center of the section. Weld 
reinforcement must be removed by machining or grinding so that the weld 
is flush with the exterior of the parent metal. There must be no 
evidence of cracking in the sample when it is flattened between flat 
plates to no more than 6 times the wall thickness.
    (2) If the weld is at midlength of the cylinder, the test may be 
made as specified in paragraph (i)(1) of this section or must be made 
between wedge shaped knife edges (60[deg] angle) rounded to a \1/2\ inch 
radius. There must be no evidence of cracking in the sample when it is 
flattened to no more than 6 times the wall thickness.
    (j) Mechanical test. A mechanical test must be conducted to 
determine yield strength, tensile strength, elongation as a percentage, 
and reduction of area of material as a percentage as follows:
    (1) The test is required on two (2) specimens removed from one 
cylinder or part thereof as illustrated in appendix A to this subpart 
taken at random out of each lot of 200 or fewer.
    (2) Specimens must conform to the following:
    (i) A gauge length of 8 inches with a width not over 1\1/2\ inches, 
a gauge

[[Page 88]]

length of 2 inches with a width not over 1\1/2\ inches.
    (ii) The specimen, exclusive of grip ends, may not be flattened. 
Grip ends may be flattened to within 1 inch of each end of the reduced 
section.
    (iii) When size of cylinder does not permit securing straight 
specimens, the specimens may be taken in any location or direction and 
may be straightened or flattened cold, by pressure only, not by blows; 
when specimens are so taken and prepared, the inspector's report must 
show in connection with record of physical test detailed information in 
regard to such specimens.
    (iv) Heating of a specimen for any purpose is not authorized.
    (3) The yield strength in tension must be the stress corresponding 
to a permanent strain of 0.2 percent of the gauge length. The following 
conditions apply:
    (i) The yield strength must be determined by the ``offset'' method 
as prescribed in ASTM E 8 (IBR, see Sec.  171.7 of this subchapter).
    (ii) Cross-head speed of the testing machine may not exceed \1/8\ 
inch per minute during yield strength determination.
    (k) Acceptable results for mechanical tests. An acceptable result of 
the mechanical test requires at least 7 percent and yield strength not 
over 80 percent of tensile strength.
    (l) Weld tests. Welds of the cylinder are required to pass the 
following tests successfully:
    (1) Reduced section tensile test. A specimen must be removed from 
the cylinder used for the mechanical tests specified in paragraph (j) of 
this section. The specimen must be taken from across the seam; edges 
must be parallel for a distance of approximately 2 inches on either side 
of the weld. The specimen must be fractured in tension. The actual 
breaking stress must be a minimum of 30,000 psi. The apparent breaking 
stress calculated on the minimum design wall thickness must be a minimum 
of two (2) times the stress calculated under paragraph (f)(2) of this 
section. If the specimen fails to meet the requirements, the lot must be 
rejected except that specimens may be taken from two (2) additional 
cylinders from the same lot as the previously tested specimens. If 
either of the latter specimens fails to meet requirements, the entire 
lot represented must be rejected.
    (2) Guided bend test. A bend test specimen must be removed from the 
cylinder used for the mechanical test specified in paragraph (j) of this 
section. The specimen must be taken across the circumferential seam, 
must be a minimum of 1\1/2\ inches wide, edges must be parallel and 
rounded with a file, and back-up strip, if used, must be removed by 
machining. The specimen must be tested as follows:
    (i) Standard guided bend test. The specimen must be bent to refusal 
in the guided bend test jig as illustrated in CGA C-3 (IBR, see Sec.  
171.7 of this subchapter). The root of the weld (inside surface of the 
cylinder) must be located away from the ram of the jig. The specimen 
must not show a crack or other open defect exceeding \1/8\ inch in any 
direction upon completion of the test. Should this specimen fail to meet 
the requirements, one additional specimen must be taken from two 
additional cylinders from the same lot and tested. If either of the 
latter specimens fails to meet requirements, the entire lot represented 
must be rejected.
    (ii) Alternate guided bend test. This test may be used as an 
alternate to the guided bend test. The test specimen must be in 
conformance with The Aluminum Association's ``Welding Aluminum: Theory 
and Practice, Fourth Edition, 2002'' (IBR, see Sec.  171.7 of this 
subchapter). If the specimen fails to meet the requirements, one 
additional specimen must be taken from two additional cylinders or 
welded test plates from the same lot and tested. If any of these latter 
two specimens fails to meet the requirements, the entire lot must be 
rejected.
    (m) Rejected cylinders. Repair of welded seams is authorized. 
Acceptable cylinders must pass all prescribed tests.
    (n) Markings. (1) Markings must be as required in Sec.  178.35 and 
in addition must be stamped plainly and permanently in one of the 
following locations on the cylinder:
    (i) On the neck, neckring, valve boss, valve protection sleeve, or 
similar part

[[Page 89]]

permanently attached to the top of the cylinder.
    (ii) On the footring permanently attached to the cylinder, provided 
the water capacity of the cylinder does not exceed 30 pounds.
    (2) Embossing the cylinder head or side wall is not permitted.
    (o) Inspector's report. In addition to the information required by 
Sec.  178.35, the record of chemical analyses must also include 
applicable information on iron, titanium, zinc, and magnesium used in 
the construction of the cylinder.

[Amdt. 178-114, 61 FR 25942, May 23, 1996, as amended at 62 FR 51561, 
Oct. 1, 1997; 66 FR 45386, Aug. 28, 2001; 67 FR 51654, Aug. 8, 2002; 68 
FR 75748, Dec. 31, 2003; 69 FR 54046, Sept. 7, 2004; 74 FR 16143, Apr. 
9, 2009; 85 FR 85431, Dec. 27, 2020]



Sec.  178.69  Responsibilities and requirements for manufacturers of 
UN pressure receptacles.

    (a) Each manufacturer of a UN pressure receptacle marked with 
``USA'' as a country of approval must comply with the requirements in 
this section. The manufacturer must maintain a quality system, obtain an 
approval for each initial pressure receptacle design type, and ensure 
that all production of UN pressure receptacles meets the applicable 
requirements.
    (1) Quality system. The manufacturer of a UN pressure receptacle 
must have its quality system approved by the Associate Administrator. 
The quality system will initially be assessed through an audit by the 
Associate Administrator or his or her representative to determine 
whether it meets the requirements of this section. The Associate 
Administrator will notify the manufacturer in writing of the results of 
the audit. The notification will contain the conclusions of the audit 
and any corrective action required. The Associate Administrator may 
perform periodic audits to ensure that the manufacturer operates in 
accordance with the quality system. Reports of periodic audits will be 
provided to the manufacturer. The manufacturer must bear the cost of 
audits.
    (2) Quality system documentation. The manufacturer must be able to 
demonstrate a documented quality system. Management must review the 
adequacy of the quality system to assure that it is effective and 
conforms to the requirements in Sec.  178.70. The quality system records 
must be in English and must include detailed descriptions of the 
following:
    (i) The organizational structure and responsibilities of personnel 
with regard to design and product quality;
    (ii) The design control and design verification techniques, 
processes, and procedures used when designing the pressure receptacles;
    (iii) The relevant procedures for pressure receptacle manufacturing, 
quality control, quality assurance, and process operation instructions;
    (iv) Inspection and testing methodologies, measuring and testing 
equipment, and calibration data;
    (v) The process for meeting customer requirements;
    (vi) The process for document control and document revision;
    (vii) The system for controlling non-conforming material and 
records, including procedures for identification, segregation, and 
disposition;
    (viii) Production, processing and fabrication, including purchased 
components, in-process and final materials; and
    (ix) Training programs for relevant personnel.
    (3) Maintenance of quality system. The manufacturer must maintain 
the quality system as approved by the Associate Administrator. The 
manufacturer shall notify the Associate Administrator of any intended 
changes to the approved quality system prior to making the change. The 
Associate Administrator will evaluate the proposed change to determine 
whether the amended quality system will satisfy the requirements. The 
Associate Administrator will notify the manufacturer of the findings.
    (b) Design type approvals. The manufacturer must have each pressure 
receptacle design type reviewed by an IIA and approved by the Associate 
Administrator in accordance with Sec.  178.70. A cylinder is considered 
to be of a new design, compared with an existing approved design, as 
stated in the applicable ISO design, construction and testing standard.

[[Page 90]]

    (c) Production inspection and certification. The manufacturer must 
ensure that each UN pressure receptacle is inspected and certified in 
accordance with Sec.  178.71.

[71 FR 33885, June 12, 2006]



Sec.  178.70  Approval of UN pressure receptacles.

    (a) Initial design-type approval. The manufacturer of a UN pressure 
receptacle must obtain an initial design type approval from the 
Associate Administrator. The initial design type approval must be of the 
pressure receptacle design as it is intended to be produced. The 
manufacturer must arrange for an IIA, approved by the Associate 
Administrator in accordance with subpart I of part 107 of this chapter, 
to perform a pre-audit of its pressure receptacle manufacturing 
operation prior to having an audit conducted by the Associate 
Administrator or his designee.
    (b) IIA pre-audit. The manufacturer must submit an application for 
initial design type approval to the IIA for review. The IIA will examine 
the manufacturer's application for initial design type approval for 
completeness. An incomplete application will be returned to the 
manufacturer with an explanation. If an application is complete, the IIA 
will review all technical documentation, including drawings and 
calculations, to verify that the design meets all requirements of the 
applicable UN pressure receptacle standard and specification 
requirements. If the technical documentation shows that the pressure 
receptacle prototype design conforms to the applicable standards and 
requirements in Sec.  178.70, the manufacturer will fabricate a 
prototype lot of pressure receptacles in conformance with the technical 
documentation representative of the design. The IIA will verify that the 
prototype lot conforms to the applicable requirements by selecting 
pressure receptacles and witnessing their testing. After prototype 
testing has been satisfactorily completed, showing the pressure 
receptacles fully conform to all applicable specification requirements, 
the certifying IIA must prepare a letter of recommendation and a design 
type approval certificate. The design type approval certificate must 
contain the name and address of the manufacturer and the IIA certifying 
the design type, the test results, chemical analyses, lot 
identification, and all other supporting data specified in the 
applicable ISO design, construction and testing standard. The IIA must 
provide the certificate and documentation to the manufacturer.
    (c) Application for initial design type approval. If the pre-audit 
is found satisfactory by the IIA, the manufacturer will submit the 
letter of recommendation from the IIA and an application for design type 
approval to the Associate Administrator. An application for initial 
design type approval must be submitted for each manufacturing facility. 
The application must be in English and, at a minimum, contain the 
following information:
    (1) The name and address of the manufacturing facility. If the 
application is submitted by an authorized representative on behalf of 
the manufacturer, the application must include the representative's name 
and address.
    (2) The name and title of the individual responsible for the 
manufacturer's quality system, as required by Sec.  178.69.
    (3) The designation of the pressure receptacle and the relevant 
pressure receptacle standard.
    (4) Details of any refusal of approval of a similar application by a 
designated approval agency of another country.
    (5) The name and address of the production IIA that will perform the 
functions prescribed in paragraph (e) of this section. The IIA must be 
approved in writing by the Associate Administrator in accordance with 
subpart I of part 107 of this chapter.
    (6) Documentation on the manufacturing facility as specified in 
Sec.  178.69.
    (7) Design specifications and manufacturing drawings, showing 
components and subassemblies if relevant, design calculations, and 
material specifications necessary to verify compliance with the 
applicable pressure receptacle design standard.
    (8) Manufacturing procedures and any applicable standards that 
describe in detail the manufacturing processes and control.

[[Page 91]]

    (9) Design type approval test reports detailing the results of 
examinations and tests conducted in accordance with the relevant 
pressure receptacle standard, to include any additional data, such as 
suitability for underwater applications or compatibility with hydrogen 
embrittlement gases.
    (d) Modification of approved pressure receptacle design type. 
Modification of an approved UN (ISO) pressure receptacle design type is 
not authorized without the approval of the Associate Administrator. 
However, modification of an approved UN (ISO) pressure receptacle design 
type is authorized without an additional approval of the Associate 
Administrator provided the design modification is covered under the UN 
(ISO) standard for the design type. A manufacturer seeking modification 
of an approved UN (ISO) pressure receptacle design type may be required 
to submit design qualification test data to the Associate Administrator 
before production. An audit may be required as part of the process to 
modify an approval.
    (e) Responsibilities of the production IIA. The production IIA is 
responsible for ensuring that each pressure receptacle conforms to the 
design type approval. The production IIA must perform the following 
functions:
    (1) Witness all inspections and tests specified in the UN pressure 
receptacle standard to ensure compliance with the standard and that the 
procedures adopted by the manufacturer meet the requirements of the 
standard;
    (2) Verify that the production inspections were performed in 
accordance with this section;
    (3) Select UN pressure receptacles from a prototype production lot 
and witness testing as required for the design type approval;
    (4) Ensure that the various design type approval examinations and 
tests are performed accurately;
    (5) Verify that each pressure receptacle is marked in accordance 
with the applicable requirements in Sec.  178.71; and
    (6) Furnish complete test reports to the manufacturer and upon 
request to the purchaser. The test reports and certificate of compliance 
must be retained by the IIA for at least 20 years from the original test 
date of the pressure receptacles.
    (f) Production inspection audit and certification. (1) If the 
application, design drawing and quality control documents are found 
satisfactory, PHMSA will schedule an on-site audit of the pressure 
receptacle manufacturer's quality system, manufacturing processes, 
inspections, and test procedures.
    (2) During the audit, the manufacturer will be required to produce 
pressure receptacles to the technical standards for which approval is 
sought.
    (3) The production IIA must witness the required inspections and 
verifications on the pressure receptacles during the production run. The 
IIA selected by the manufacturer for production inspection and testing 
may be different from the IIA who performed the design type approval 
verifications.
    (4) If the procedures and controls are deemed acceptable, test 
sample pressure receptacles will be selected at random from the 
production lot and sent to a laboratory designated by the Associate 
Administrator for verification testing.
    (5) If the pressure receptacle test samples are found to conform to 
all the applicable requirements, the Associate Administrator will issue 
approvals to the manufacturer and the production IIA to authorize the 
manufacture of the pressure receptacles. The approved design type 
approval certificate will be returned to the manufacturer.
    (6) Upon the receipt of the approved design type approval 
certificate from the Associate Administrator, the pressure receptacle 
manufacturer must sign the certificate.
    (g) Recordkeeping. The production IIA and the manufacturer must 
retain a copy of the design type approval certificate and certificate of 
compliance records for at least 20 years.
    (h) Denial of design type application. If the design type 
application is denied, the Associate Administrator will notify the 
applicant in writing and provide the reason for the denial. The 
manufacturer may request that the Associate Administrator reconsider the 
decision. The application request must--

[[Page 92]]

    (1) Be written in English and filed within 60 days of receipt of the 
decision;
    (2) State in detail any alleged errors of fact and law; and
    (3) Enclose any additional information needed to support the request 
to reconsider.
    (i) Appeal. (1) A manufacturer whose reconsideration request is 
denied may appeal to the PHMSA Administrator. The appeal must--
    (i) Be written in English and filed within 60 days of receipt of the 
Associate Administrator's decision on reconsideration;
    (ii) State in detail any alleged errors of fact and law;
    (iii) Enclose any additional information needed to support the 
appeal; and
    (iv) State in detail the modification of the final decision sought.
    (2) The PHMSA Administrator will grant or deny the relief and inform 
the appellant in writing of the decision. PHMSA Administrator's decision 
is the final administrative action.
    (j) Termination of a design type approval certificate. (1) The 
Associate Administrator may terminate an approval certificate issue 
under this section if it is determined that, because of a change in 
circumstances, the approval no longer is needed or no longer would be 
granted if applied for; information upon which the approval was based is 
fraudulent or substantially erroneous; or termination of the approval is 
necessary to adequately protect against risks to life and property.
    (2) Before an approval is terminated, the Associate Administrator 
will provide the manufacturer and the approval agency--
    (i) Written notice of the facts or conduct believed to warrant the 
withdrawal;
    (ii) Opportunity to submit oral and written evidence, and
    (iii) Opportunity to demonstrate or achieve compliance with the 
application requirement.
    (3) If the Associate Administrator determines that a certificate of 
approval must be withdrawn to preclude a significant and imminent 
adverse affect on public safety, the procedures in paragraph (j)(2)(ii) 
and (iii) of this section need not be provided prior to withdrawal of 
the approval, but shall be provided as soon as practicable thereafter.

[71 FR 33886, June 12, 2006, as amended at 71 FR 54397, Sept. 14, 2006; 
77 FR 60943, Oct. 5, 2012; 85 FR 85432, Dec. 28, 2020]



Sec.  178.71  Specifications for UN pressure receptacles.

    (a) General. Each UN pressure receptacle must meet the requirements 
of this section. UN pressure receptacles and service equipment 
constructed according to the standards applicable at the date of 
manufacture may continue in use subject to the continuing qualification 
and maintenance provisions of part 180 of this subchapter. Requirements 
for approval, qualification, maintenance, and testing are contained in 
Sec.  178.70, and subpart C of part 180 of this subchapter.
    (b) Definitions. The following definitions apply for the purposes of 
design and construction of UN pressure receptacles under this subpart:
    Alternative arrangement means an approval granted by the Associate 
Administrator for a MEGC that has been designed, constructed or tested 
to the technical requirements or testing methods other than those 
specified for UN pressure receptacles in part 178 or part 180 of this 
subchapter.
    Bundle of cylinders. See Sec.  171.8 of this subchapter.
    Design type means a pressure receptacle design as specified by a 
particular pressure receptacle standard.
    Design type approval means an overall approval of the manufacturer's 
quality system and design type of each pressure receptacle to be 
produced within the manufacturer's facility.
    UN tube. See Sec.  171.8 of this subchapter.
    (c) Following the final heat treatment, all cylinders, except those 
selected for batch testing must be subjected to a proof pressure or a 
hydraulic volumetric expansion test.
    (d) Service equipment. (1) Except for pressure relief devices, UN 
pressure receptacle equipment, including valves, piping, fittings, and 
other equipment subjected to pressure must be designed and constructed 
to withstand at least 1.5 times the test pressure of the pressure 
receptacle.

[[Page 93]]

    (2) Service equipment must be configured, or designed, to prevent 
damage that could result in the release of the pressure receptacle 
contents during normal conditions of handling and transport. Manifold 
piping leading to shut-off valves must be sufficiently flexible to 
protect the valves and the piping from shearing or releasing the 
pressure receptacle contents. The filling and discharge valves and any 
protective caps must be secured against unintended opening. The valves 
must conform to ISO 10297:2014(E) and ISO 10297:2014/Amd 1:2017(E) (IBR, 
see Sec.  171.7 of this subchapter), or for non-refillable pressure 
receptacles valves manufactured until December 31, 2020, ISO 
13340:2001(E), and be protected as specified in Sec.  173.301b(f) of 
this subchapter. Until December 31, 2022, the manufacture of a valve 
conforming to the requirements of ISO 10297:2014(E) is authorized. Until 
December 31, 2020, the manufacture of a valve conforming to the 
requirements in ISO 10297:2006(E) (IBR, see Sec.  171.7 of this 
subchapter) was authorized. Until December 31, 2008, the manufacture of 
a valve conforming to the requirements in ISO 10297:1999(E) (IBR, see 
Sec.  171.7 of this subchapter) was authorized. Additionally, valves 
must be initially inspected and tested in accordance with ISO 
14246:2014(E) and ISO 14246:2014/Amd 1:2017(E), (IBR, see Sec.  171.7 of 
this subchapter). For self-closing valves with inherent protection, the 
requirements of ISO 17879:2017(E) (IBR, see Sec.  171.7 of this 
subchapter) shall be met until further notice.
    (3) UN pressure receptacles that cannot be handled manually or 
rolled, must be equipped with devices (e.g., skids, rings, straps) 
ensuring that they can be safely handled by mechanical means and so 
arranged as not to impair the strength of, nor cause undue stresses, in 
the pressure receptacle.
    (4) Pressure receptacles filled by volume must be equipped with a 
level indicator.
    (e) Bundles of cylinders. UN pressure receptacles assembled in 
bundles must be structurally supported and held together as a unit and 
secured in a manner that prevents movement in relation to the structural 
assembly and movement that would result in the concentration of harmful 
local stresses. The frame design must ensure stability under normal 
operating conditions.
    (1) The frame must securely retain all the components of the bundle 
and must protect them from damage during conditions normally incident to 
transportation. The method of cylinder restraint must prevent any 
vertical or horizontal movement or rotation of the cylinder that could 
cause undue strain on the manifold. The total assembly must be able to 
withstand rough handling, including being dropped or overturned.
    (2) The frame must include features designed for the handling and 
transportation of the bundle. The lifting rings must be designed to 
withstand a design load of 2 times the maximum gross weight. Bundles 
with more than one lifting ring must be designed such that a minimum 
sling angle of 45 degrees to the horizontal can be achieved during 
lifting using the lifting rings. If four lifting rings are used, their 
design must be strong enough to allow the bundle to be lifted by two 
rings. Where two or four lifting rings are used, diametrically opposite 
lifting rings must be aligned with each other to allow for correct 
lifting using shackle pins. If the bundle is filled with forklift 
pockets, it must contain two forklift pockets on each side from which it 
is to be lifted. The forklift pockets must be positioned symmetrically 
consistent with the bundle center of gravity.
    (3) The frame structural members must be designed for a vertical 
load of 2 times the maximum gross weight of the bundle. Design stress 
levels may not exceed 0.9 times the yield strength of the material.
    (4) The frame must not contain any protrusions from the exterior 
frame structure that could cause a hazardous condition.
    (5) The frame design must prevent collection of water or other 
debris that would increase the tare weight of bundles filled by weight.
    (6) The floor of the bundle frame must not buckle during normal 
operating conditions and must allow for the drainage of water and debris 
from around the base of the cylinders.

[[Page 94]]

    (7) If the frame design includes movable doors or covers, they must 
be capable of being secured with latches or other means that will not 
become dislodged by operational impact loads. Valves that need to be 
operated in normal service or in an emergency must be accessible.
    (8) For bundles of cylinders, pressure receptacle marking 
requirements only apply to the individual cylinders of a bundle and not 
to any assembly structure.
    (f) Design and construction requirements for UN refillable welded 
cylinders and UN pressure drums. In addition to the general requirements 
of this section, UN refillable welded cylinders and UN pressure drums 
must conform to the following ISO standards, as applicable:
    (1) ISO 4706: Gas cylinders--Refillable welded steel cylinders--Test 
pressure 60 bar and below (IBR, see Sec.  171.7 of this subchapter).
    (2) ISO 18172-1: Gas cylinders--Refillable welded stainless steel 
cylinders--Part 1: Test pressure 6 MPa and below (IBR, see Sec.  171.7 
of this subchapter).
    (3) ISO 20703: Gas cylinders--Refillable welded aluminum-alloy 
cylinders--Design, construction and testing (IBR, see Sec.  171.7 of 
this subchapter).
    (4) ISO 21172-1:2015(E) Gas cylinders--Welded steel pressure drums 
up to 3,000 litres capacity for the transport of gases--Design and 
construction--Part 1: Capacities up to 1,000 litres (IBR, see Sec.  
171.7 of this subchapter). Irrespective of section 6.3.3.4 of this 
standard, welded steel gas pressure drums with dished ends convex to 
pressure may be used for the transport of corrosive substances provided 
all applicable additional requirements are met.
    (g) Design and construction requirements for UN refillable seamless 
steel cylinders. In addition to the general requirements of this 
section, UN refillable seamless steel cylinders must conform to the 
following ISO standards, as applicable:
    (1) ISO 9809-1:2010 Gas cylinders--Refillable seamless steel gas 
cylinders--Design, construction and testing--Part 1: Quenched and 
tempered steel cylinders with tensile strength less than 1100 MPa. (IBR, 
see Sec.  171.7 of this subchapter). Until December 31, 2018, the 
manufacture of a cylinder conforming to the requirements in ISO 9809-
1:1999 (IBR, see Sec.  171.7 of this subchapter) is authorized.
    (2) ISO 9809-2: Gas cylinders--Refillable seamless steel gas 
cylinders--Design, construction and testing--Part 2: Quenched and 
tempered steel cylinders with tensile strength greater than or equal to 
1100 MPa. (IBR, see Sec.  171.7 of this subchapter). Until December 31, 
2018, the manufacture of a cylinder conforming to the requirements in 
ISO 9809-2:2000 (IBR, see Sec.  171.7 of this subchapter) is authorized.
    (3) ISO 9809-3: Gas cylinders--Refillable seamless steel gas 
cylinders--Design, construction and testing--Part 3: Normalized steel 
cylinders. (IBR, see Sec.  171.7 of this subchapter). Until December 31, 
2018, the manufacture of a cylinder conforming to the requirements in 
ISO 9809-3:2000 (IBR, see Sec.  171.7 of this subchapter) is authorized.
    (4) ISO 9809-4:2014(E) (IBR, see Sec.  171.7 of this subchapter).
    (h) Design and construction requirements for UN refillable seamless 
aluminum alloy cylinders. In addition to the general requirements of 
this section, UN refillable seamless aluminum cylinders must conform to 
ISO 7866:2012(E) as modified by ISO 7866:2012/Cor.1:2014(E) (IBR, see 
Sec.  171.7 of this subchapter). Until December 31, 2020, the 
manufacture of a cylinder conforming to the requirements in ISO 7866(E) 
(IBR, see Sec.  171.7 of this subchapter) is authorized. The use of 
Aluminum alloy 6351-T6 or equivalent is prohibited.
    (i) Design and construction requirements for UN non-refillable metal 
cylinders. In addition to the general requirements of this section, UN 
non-refillable metal cylinders must conform to ISO 11118:2015(E) Gas 
cylinders--Non-refillable metallic gas cylinders--Specification and test 
methods (IBR, see Sec.  171.7 of this subchapter). Until December 31, 
2020, cylinders conforming to ISO 11118:1999(E) Gas cylinders--Non-
refillable metallic gas cylinders--Specification and test methods (IBR, 
see Sec.  171.7 of this subchapter) are authorized.
    (j) Design and construction requirements for UN refillable seamless 
steel

[[Page 95]]

tubes. In addition to the general requirements of this section, UN 
refillable seamless steel tubes must conform to ISO 11120:2015(E) Gas 
cylinders--Refillable seamless steel tubes of water capacity between 150 
L and 3,000 L--Design, construction and testing (IBR, see Sec.  171.7 of 
this subchapter). Until December 31, 2022, UN refillable seamless steel 
tubes may be manufactured in accordance with ISO 11120: Gas cylinders--
Refillable seamless steel tubes of water capacity between 150 L and 
3,000 L--Design, construction and testing (IBR, see Sec.  171.7 of this 
subchapter)
    (k) Design and construction requirements for UN acetylene cylinders. 
In addition to the general requirements of this section, UN acetylene 
cylinders must conform to the following ISO standards, as applicable:
    (1) For the cylinder shell:
    (i) ISO 9809-1:2010 Gas cylinders--Refillable seamless steel gas 
cylinders--Design, construction and testing--Part 1: Quenched and 
tempered steel cylinders with tensile strength less than 1100 MPa. Until 
December 31, 2018, the manufacture of a cylinder conforming to the 
requirements in ISO 9809-1:1999 (IBR, see Sec.  171.7 of this 
subchapter) is authorized.
    (ii) ISO 9809-3: Gas cylinders--Refillable seamless steel gas 
cylinders--Design, construction and testing--Part 3: Normalized steel 
cylinders. Until December 31, 2018, the manufacture of a cylinder 
conforming to the requirements in ISO 9809-3:2000 (IBR, see Sec.  171.7 
of this subchapter) is authorized.
    (2) The porous mass in an acetylene cylinder must conform to ISO 
3807:2013(E) (IBR, see Sec.  171.7 of this subchapter). Until December 
31, 2020, the manufacture of a cylinder conforming to the requirements 
in ISO 3807-2(E) (IBR, see Sec.  171.7 of this subchapter) is 
authorized.
    (l) Design and construction requirements for UN composite cylinders 
and tubes. (1) In addition to the general requirements of this section, 
UN composite cylinders and tubes must be designed for a design life of 
not less than 15 years. Composite cylinders and tubes with a design life 
longer than 15 years must not be filled after 15 years from the date of 
manufacture, unless the design has successfully passed a service life 
test program. The service life test program must be part of the initial 
design type approval and must specify inspections and tests to 
demonstrate that cylinders manufactured accordingly remain safe to the 
end of their design life. The service life test program and the results 
must be approved by the competent authority of the country of approval 
that is responsible for the initial approval of the cylinder design. The 
service life of a composite cylinder or tube must not be extended beyond 
its initial approved design life. Additionally, composite cylinders and 
tubes must conform to the following ISO standards, as applicable:
    (i) ISO 11119-1:2012(E) (IBR, see Sec.  171.7 of this subchapter). 
Until December 31, 2020, cylinders conforming to the requirements in ISO 
11119-1(E), (IBR, see Sec.  171.7 of this subchapter) are authorized.
    (ii) ISO 11119-2:2012(E) (ISO 11119-2:2012/Amd.1:2014(E)) (IBR, see 
Sec.  171.7 of this subchapter). Until December 31, 2020, cylinders 
conforming to the requirements in ISO 11119-2(E) (IBR, see Sec.  171.7 
of this subchapter) are authorized.
    (iii) ISO 11119-3:2013(E) (IBR, see Sec.  171.7 of this subchapter). 
Until December 31, 2020, cylinders conforming to the requirements in ISO 
11119-3(E) (IBR, see Sec.  171.7 of this subchapter) are authorized.
    (iv) ISO 11119-4:2016(E) (IBR, see Sec.  171.7 of this subchapter).
    (2) ISO 11119-2 and ISO 11119-3 gas cylinders of composite 
construction manufactured in accordance with the requirements for 
underwater use must bear the ``UW'' mark.
    (m) Design and construction requirements for UN metal hydride 
storage systems. In addition to the general requirements of this 
section, metal hydride storage systems must conform to the following ISO 
standards, as applicable: ISO 16111: Transportable gas storage devices--
Hydrogen absorbed in reversible metal hydride (IBR, see Sec.  171.7 of 
this subchapter).
    (n) Design and construction requirements for UN cylinders for the 
transportation of adsorbed gases. In addition to the general 
requirements of this section, UN cylinders for the transportation of 
adsorbed gases must conform

[[Page 96]]

to the following ISO standards, as applicable: ISO 11513:2011, Gas 
cylinders--Refillable welded steel cylinders containing materials for 
sub-atmospheric gas packaging (excluding acetylene)--Design, 
construction, testing, use and periodic inspection, or ISO 9809-1:2010: 
Gas cylinders--Refillable seamless steel gas cylinders--Design, 
construction and testing--Part 1: Quenched and tempered steel cylinders 
with tensile strength less than 1100 MPa. (IBR, see Sec.  171.7 of this 
subchapter.)
    (o) Material compatibility. In addition to the material requirements 
specified in the UN pressure receptacle design and construction ISO 
standards, and any restrictions specified in part 173 for the gases to 
be transported, the requirements of the following standards must be 
applied with respect to material compatibility:
    (1) ISO 11114-1:2012(E) and 11114-1:2012/Amd 1:2017(E) (IBR, see 
Sec.  171.7 of this subchapter).
    (2) ISO 11114-2:2013(E) (IBR, see Sec.  171.7 of this subchapter).
    (p) Protection of closures. Closures and their protection must 
conform to the requirements in Sec.  173.301(f) of this subchapter.
    (q) Marking of UN refillable pressure receptacles. UN refillable 
pressure receptacles must be marked clearly and legibly. The required 
markings must be permanently affixed by stamping, engraving, or other 
equivalent method, on the shoulder, top end or neck of the pressure 
receptacle or on a permanently affixed component of the pressure 
receptacle, such as a welded collar. Except for the ``UN'' mark, the 
minimum size of the marks must be 5 mm for pressure receptacles with a 
diameter greater than or equal to 140 mm, and 2.5 mm for pressure 
receptacles with a diameter less than 140 mm. The minimum size of the 
``UN'' mark must be 5 mm for pressure receptacles with a diameter less 
than 140 mm, and 10 mm for pressure receptacles with a diameter of 
greater than or equal to 140 mm. The depth of the markings must not 
create harmful stress concentrations. A refillable pressure receptacle 
conforming to the UN standard must be marked as follows:
    (1) The UN packaging symbol.
    [GRAPHIC] [TIFF OMITTED] TR19JA11.035
    
    (2) The ISO standard, for example ISO 9809-1, used for design, 
construction and testing. Acetylene cylinders must be marked to indicate 
the porous mass and the steel shell, for example: ``ISO 3807-2/ISO 9809-
1.''
    (3) The mark of the country where the approval is granted. The 
letters ``USA'' must be marked on UN pressure receptacles approved by 
the United States. The manufacturer must obtain an approval number from 
the Associate Administrator. The manufacturer approval number must 
follow the country of approval mark, separated by a slash (for example, 
USA/MXXXX). Pressure receptacles approved by more than one national 
authority may contain the mark of each country of approval, separated by 
a comma.
    (4) The identity mark or stamp of the IIA.
    (5) The date of the initial inspection, the year (four digits) 
followed by the month (two digits) separated by a slash, for example 
``2006/04''.
    (6) The test pressure in bar, preceded by the letters ``PH'' and 
followed by the letters ``BAR''.

[[Page 97]]

    (7) The rated charging pressure of the metal hydride storage system 
in bar, preceded by the letters ``RCP'' and followed by the letters 
``BAR.''
    (8) The empty or tare weight. Except for acetylene cylinders, empty 
weight is the mass of the pressure receptacle in kilograms, including 
all integral parts (e.g., collar, neck ring, foot ring, etc.), followed 
by the letters ``KG''. The empty weight does not include the mass of the 
valve, valve cap or valve guard or any coating. The empty weight must be 
expressed to three significant figures rounded up to the last digit. For 
cylinders of less than 1 kg, the empty weight must be expressed to two 
significant figures rounded down to the last digit. For acetylene 
cylinders, the tare weight must be marked on the cylinders in kilograms. 
The tare weight is the sum of the empty weight, mass of the valve, any 
coating and all permanently attached parts (e.g., fittings and 
accessories) that are not removed during filling. The tare weight must 
be expressed to two significant figures rounded down to the last digit. 
The tare weight does not include the cylinder cap or any outlet cap or 
plug not permanently attached to the cylinder.
    (9) The minimum wall thickness of the pressure receptacle in 
millimeters followed by the letters ``MM''. This mark is not required 
for pressure receptacles with a water capacity less than or equal to 1.0 
L or for composite cylinders.
    (10) For pressure receptacles intended for the transport of 
compressed gases and UN 1001 acetylene, dissolved, the working pressure 
in bar, proceeded by the letters ``PW''.
    (11) For liquefied gases, the water capacity in liters expressed to 
three significant digits rounded down to the last digit, followed by the 
letter ``L''. If the value of the minimum or nominal water capacity is 
an integer, the digits after the decimal point may be omitted.
    (12) Identification of the cylinder thread type (e.g., 25E). 
Information on the marks that may be used for identifying threads for 
cylinders is given in ISO/TR 11364, Gas Cylinders--Compilation of 
national and international valve stem/gas cylinder neck threads and 
their identification and marking system (IBR, see Sec.  171.7 of this 
subchapter).
    (13) The country of manufacture. The letters ``USA'' must be marked 
on cylinders manufactured in the United States.
    (14) The serial number assigned by the manufacturer.
    (15) For steel pressure receptacles, the letter ``H'' showing 
compatibility of the steel, as specified in ISO 11114-1.
    (16) Identification of aluminum alloy, if applicable.
    (17) Stamp for nondestructive testing, if applicable.
    (18) Stamp for underwater use of composite cylinders, if applicable.
    (19) For metal hydride storage systems having a limited life, the 
date of expiration indicated by the word ``FINAL,'' followed by the year 
(four digits), the month (two digits) and separated by a slash.
    (20) For composite cylinders and tubes having a limited design life, 
the letters ``FINAL'' followed by the design life shown as the year 
(four digits) followed by the month (two digits) separated by a slash 
(i.e. ``/'').
    (21) For composite cylinders and tubes having a limited design life 
greater than 15 years and for composite cylinders and tubes having non-
limited design life, the letters ``SERVICE'' followed by the date 15 
years from the date of manufacture (initial inspection) shown as the 
year (four digits) followed by the month (two digits) separated by a 
slash (i.e. ``/'').
    (r) Marking sequence. The marking required by paragraph (q) of this 
section must be placed in three groups as shown in the example below:
    (1) The top grouping contains manufacturing marks and must appear 
consecutively in the sequence given in paragraphs (q)(13) through (19) 
of this section.
    (2) The middle grouping contains operational marks described in 
paragraphs (q)(6) through (11) of this section.
    (3) The bottom grouping contains certification marks and must appear 
consecutively in the sequence given in paragraphs (q)(1) through (5) of 
this section.

[[Page 98]]

[GRAPHIC] [TIFF OMITTED] TR30MR17.035

    (s) Other markings. Other markings are allowed in areas other than 
the side wall, provided they are made in low stress areas and are not of 
a size and depth that will create harmful stress concentrations. Such 
marks must not conflict with required marks.
    (t) Marking of UN non-refillable pressure receptacles. Unless 
otherwise specified in this paragraph, each UN non-refillable pressure 
receptacle must be clearly and legibly marked as prescribed in paragraph 
(q) of this section. In addition, permanent stenciling is authorized. 
Except when stenciled, the marks must be on the shoulder, top end or 
neck of the pressure receptacle or on a permanently affixed component of 
the pressure receptacle (e.g., a welded collar).
    (1) The marking requirements and sequence listed in paragraphs 
(q)(1) through (19) of this section are required, except the markings in 
paragraphs (q)(8), (9), (12) and (18) are not applicable. The required 
serial number marking in paragraph (q)(14) may be replaced by the batch 
number.
    (2) Each receptacle must be marked with the words ``DO NOT REFILL'' 
in letters of at least 5 mm in height.
    (3) A non-refillable pressure receptacle, because of its size, may 
substitute the marking required by this paragraph with a label. 
Reduction in marking size is authorized only as prescribed in ISO 7225, 
Gas cylinders--Precautionary labels. (IBR, see Sec.  171.7 of this 
subchapter).
    (4) Each non-refillable pressure receptacle must also be legibly 
marked by stenciling the following statement: ``Federal law forbids 
transportation if refilled-penalty up to $500,000 fine and 5 years in 
imprisonment (49 U.S.C. 5124).''
    (u) Marking of bundles of cylinders. (1) Individual cylinders in a 
bundle of cylinders must be marked in accordance with paragraphs (q), 
(r), (s) and (t) of this section as appropriate.
    (2) Refillable UN bundles of cylinders must be marked clearly and 
legibly with certification, operational, and manufacturing marks. These 
marks must be permanently affixed (e.g., stamped, engraved, or etched) 
on a plate permanently attached to the frame of the bundle of cylinders. 
Except for the ``UN'' mark, the minimum size of the marks must be 5 mm. 
The minimum size of the ``UN'' mark must

[[Page 99]]

be 10 mm. A refillable UN bundle of cylinders must be marked with the 
following:
    (i) The UN packaging symbol;
    [GRAPHIC] [TIFF OMITTED] TR08JA15.002
    
    (ii) The ISO standard, for example ISO 9809-1, used for design, 
construction and testing. Acetylene cylinders must be marked to indicate 
the porous mass and the steel shell, for example: ``ISO 3807-2/ISO 9809-
1'';
    (iii) The mark of the country where the approval is granted. The 
letters ``USA'' must be marked on UN pressure receptacles approved by 
the United States. The manufacturer must obtain an approval number from 
the Associate Administrator. The manufacturer approval number must 
follow the country of approval mark, separated by a slash (for example, 
USA/MXXXX). Pressure receptacles approved by more than one national 
authority may contain the mark of each country of approval, separated by 
a comma;
    (iv) The identity mark or stamp of the IIA;
    (v) The date of the initial inspection, the year in four digits 
followed by the two digit month separated by a slash, for example 
``2006/04'';
    (vi) The test pressure in bar, preceded by the letters ``PH'' and 
followed by the letters ``BAR'';
    (vii) For pressure receptacles intended for the transport of 
compressed gases and UN 1001 acetylene, dissolved, the working pressure 
in bar, proceeded by the letters ``PW'';
    (viii) For liquefied gases, the water capacity in liters expressed 
to three significant digits rounded down to the last digit, followed by 
the letter ``L''. If the value of the minimum or nominal water capacity 
is an integer, the digits after the decimal point may be omitted;
    (ix) The total mass of the frame of the bundle and all permanently 
attached parts (cylinders, manifolds, fittings and valves). Bundles 
intended for the carriage of UN 1001 acetylene, dissolved must bear the 
tare mass as specified in clause N.4.2 of ISO 10961:2010;
    (x) The country of manufacture. The letters ``USA'' must be marked 
on cylinders manufactured in the United States;
    (xi) The serial number assigned by the manufacturer; and
    (xii) For steel pressure receptacles, the letter ``H'' showing 
compatibility of the steel, as specified in 1SO 11114-1.
    (v) Marking sequence. The marking required by paragraph (u) of this 
section must be placed in three groups as follows:
    (1) The top grouping contains manufacturing marks and must appear 
consecutively in the sequence given in paragraphs (u)(2)(x) through 
(u)(2)(xii) of this section as applicable.
    (2) The middle grouping contains operational marks described in 
paragraphs (u)(2)(vi) through (u)(2)(ix) of this section as applicable. 
When the operational mark specified in paragraph (u)(2)(vii) is 
required, it must immediately precede the operational mark specified in 
paragraph (u)(2)(vi).
    (3) The bottom grouping contains certification marks and must appear 
consecutively in the sequence given in paragraphs (u)(2)(i) through 
(u)(2)(v) of this section as applicable.

[76 FR 3385, Jan. 19, 2011, as amended at 76 FR 43532, July 20, 2011; 77 
FR 60943, Oct. 5, 2012; 78 FR 1096, Jan. 7, 2013; 80 FR 1166, Jan. 8, 
2015; 80 FR 72929, Nov. 23, 2015; 82 FR 15895, Mar. 30, 2017; 85 FR 
27900, May 11, 2020; 87 FR 44999, July 26, 2022]

[[Page 100]]



Sec.  178.74  Approval of MEGCs.

    (a) Application for design type approval. (1) Each new MEGC design 
type must have a design approval certificate. An owner or manufacturer 
must apply to an approval agency that is approved by the Associate 
Administrator in accordance with subpart E of part 107 of this chapter + 
to obtain approval of a new design. When a series of MEGCs is 
manufactured without change in the design, the certificate is valid for 
the entire series. The design approval certificate must refer to the 
prototype test report, the materials of construction of the manifold, 
the standards to which the pressure receptacles are made and an approval 
number. The compliance requirements or test methods applicable to MEGCs 
as specified in this subpart may be varied when the level of safety is 
determined to be equivalent to or exceed the requirements of this 
subchapter and is approved in writing by the Associate Administrator. A 
design approval may serve for the approval of smaller MEGCs made of 
materials of the same type and thickness, by the same fabrication 
techniques and with identical supports, equivalent closures and other 
appurtenances.
    (2) Each application for design approval must be in English and 
contain the following information:
    (i) Two complete copies of all engineering drawings, calculations, 
and test data necessary to ensure that the design meets the relevant 
specification.
    (ii) The manufacturer's serial number that will be assigned to each 
MEGC.
    (iii) A statement as to whether the design type has been examined by 
any approval agency previously and judged unacceptable. Affirmative 
statements must be documented with the name of the approval agency, 
reason for non-acceptance, and the nature of modifications made to the 
design type.
    (b) Actions by the approval agency. The approval agency must review 
the application for design type approval, including all drawings and 
calculations, to ensure that the design of the MEGC meets all 
requirements of the relevant specification and to determine whether it 
is complete and conforms to the requirements of this section. An 
incomplete application will be returned to the applicant with the 
reasons why the application was returned. If the application is complete 
and all applicable requirements of this section are met, the approval 
agency must prepare a MEGC design approval certificate containing the 
manufacturer's name and address, results and conclusions of the 
examination and necessary data for identification of the design type. If 
the Associate Administrator approves the Design Type Approval 
Certificate application, the approval agency and the manufacturer must 
each maintain a copy of the approved drawings, calculations, and test 
data for at least 20 years.
    (c) Approval agency's responsibilities. The approval agency is 
responsible for ensuring that the MEGC conforms to the design type 
approval. The approval agency must:
    (1) Witness all tests required for the approval of the MEGC 
specified in this section and Sec.  178.75.
    (2) Ensure, through appropriate inspection, that each MEGC is 
fabricated in all respects in conformance with the approved drawings, 
calculations, and test data.
    (3) Determine and ensure that the MEGC is suitable for its intended 
use and that it conforms to the requirements of this subchapter.
    (4) Apply its name, identifying mark or identifying number, and the 
date the approval was issued, to the metal identification marking plate 
attached to the MEGC upon successful completion of all requirements of 
this subpart. Any approvals by the Associate Administrator authorizing 
design or construction alternatives (Alternate Arrangements) of the MEGC 
(see paragraph (a) of this section) must be indicated on the metal 
identification plate as specified in Sec.  178.75(j).
    (5) Prepare an approval certificate for each MEGC or, in the case of 
a series of identical MEGCs manufactured to a single design type, for 
each series of MEGCs. The approval certificate must include all of the 
following information:
    (i) The information displayed on the metal identification plate 
required by Sec.  178.75(j);

[[Page 101]]

    (ii) The results of the applicable framework test specified in ISO 
1496-3 (IBR, see Sec.  171.7 of this subchapter);
    (iii) The results of the initial inspection and test specified in 
paragraph (h) of this section;
    (iv) The results of the impact test specified in Sec.  178.75(i)(4);
    (v) Certification documents verifying that the cylinders and tubes 
conform to the applicable standards; and
    (vi) A statement that the approval agency certifies the MEGC in 
accordance with the procedures in this section and that the MEGC is 
suitable for its intended purpose and meets the requirements of this 
subchapter. When a series of MEGCs is manufactured without change in the 
design type, the certificate may be valid for the entire series of MEGCs 
representing a single design type. The approval number must consist of 
the distinguishing sign or mark of the country (``USA'' for the United 
States of America) where the approval was granted and a registration 
number.
    (6) Retain on file a copy of each approval certificate for at least 
20 years.
    (d) Manufacturers' responsibilities. The manufacturer is responsible 
for compliance with the applicable specifications for the design and 
construction of MEGCs. The manufacturer of a MEGC must:
    (1) Comply with all the requirements of the applicable ISO standard 
specified in Sec.  178.71;
    (2) Obtain and use an approval agency to review the design, 
construction and certification of the MEGC;
    (3) Provide a statement in the manufacturers' data report certifying 
that each MEGC manufactured complies with the relevant specification and 
all the applicable requirements of this subchapter; and
    (4) Retain records for the MEGCs for at least 20 years. When 
required by the specification, the manufacturer must provide copies of 
the records to the approval agency, the owner or lessee of the MEGC, and 
to a representative of DOT, upon request.
    (e) Denial of application for approval. If the Associate 
Administrator finds that the MEGC will not be approved for any reason, 
the Associate Administrator will notify the applicant in writing and 
provide the reason for the denial. The manufacturer may request that the 
Associate Administrator reconsider the decision. The application request 
must--
    (1) Be written in English and filed within 90 days of receipt of the 
decision;
    (2) State in detail any alleged errors of fact and law; and
    (3) Enclose any additional information needed to support the request 
to reconsider.
    (f) Appeal. (1) A manufacturer whose reconsideration request is 
denied may appeal to the PHMSA Administrator. The appeal must--
    (i) Be in writing and filed within 90 days of receipt of the 
Associate Administrator s decision on reconsideration;
    (ii) State in detail any alleged errors of fact and law;
    (iii) Enclose any additional information needed to support the 
appeal; and
    (iv) State in detail the modification of the final decision sought.
    (2) The Administrator will grant or deny the relief and inform the 
appellant in writing of the decision. The Administrator's decision is 
the final administrative action.
    (g) Modifications to approved MEGCs. (1) Prior to modification of 
any approved MEGC that may affect conformance and safe use, and that may 
involve a change to the design type or affect its ability to retain the 
hazardous material in transportation, the MEGC's owner must inform the 
approval agency that prepared the initial approval certificate for the 
MEGC or, if the initial approval agency is unavailable, another approval 
agency, of the nature of the modification and request certification of 
the modification. The owner must supply the approval agency with all 
revised drawings, calculations, and test data relative to the intended 
modification. The MEGC's owner must also provide a statement as to 
whether the intended modification has been examined and determined to be 
unacceptable by any approval agency. The written statement must include 
the name of the approval agency, the reason for non-acceptance, and the 
nature of changes made to the modification since its original rejection.

[[Page 102]]

    (2) The approval agency must review the request for modification. If 
the approval agency determines that the proposed modification does not 
conform to the relevant specification, the approval agency must reject 
the request in accordance with paragraph (d) of this section. If the 
approval agency determines that the proposed modification conforms fully 
with the relevant specification, the request is accepted. If 
modification to an approved MEGC alters any information on the approval 
certificate, the approval agency must prepare a new approval certificate 
for the modified MEGC and submit the certificate to the Associate 
Administrator for approval. After receiving approval from the Associate 
Administrator, the approval agency must ensure that any necessary 
changes are made to the metal identification plate. A copy of each newly 
issued approval certificate must be retained by the approval agency and 
the MEGC's owner for at least 20 years. The approval agency must perform 
the following activities:
    (i) Retain a set of the approved revised drawings, calculations, and 
data as specified in Sec.  178.69(b)(4) for at least 20 years;
    (ii) Ensure through appropriate inspection that all modifications 
conform to the revised drawings, calculations, and test data; and
    (iii) Determine the extent to which retesting of the modified MEGC 
is necessary based on the nature of the proposed modification, and 
ensure that all required retests are satisfactorily performed.
    (h) Termination of Approval Certificate. (1) The Associate 
Administrator may terminate an approval issued under this section if he 
or she determines that--
    (i) Because of a change in circumstances, the approval no longer is 
needed or no longer would be granted if applied for;
    (ii) Information upon which the approval was based is fraudulent or 
substantially erroneous;
    (iii) Termination of the approval is necessary to adequately protect 
against risks to life and property; or
    (iv) The MEGC does not meet the specification.
    (2) Before an approval is terminated, the Associate Administrator 
will provide the person--
    (i) Written notice of the facts or conduct believed to warrant the 
termination;
    (ii) An opportunity to submit oral and written evidence; and
    (3) An opportunity to demonstrate or achieve compliance with the 
applicable requirements.
    (i) Imminent Danger. If the Associate Administrator determines that 
a certificate of approval must be terminated to preclude a significant 
and imminent adverse effect on public safety, the Associate 
Administrator may terminate the certificate immediately. In such 
circumstances, the opportunities of paragraphs (h)(2) and (3) of this 
section need not be provided prior to termination of the approval, but 
must be provided as soon as practicable thereafter.

[71 FR 33890, June 12, 2006]



Sec.  178.75  Specifications for MEGCs.

    (a) General. Each MEGC must meet the requirements of this section. 
In a MEGC that meets the definition of a ``container'' within the terms 
of the International Convention for Safe Containers (CSC) must meet the 
requirements of the CSC as amended and 49 CFR parts 450 through 453, and 
must have a CSC approval plate.
    (b) Alternate Arrangements. The technical requirements applicable to 
MEGCs may be varied when the level of safety is determined to be 
equivalent to or exceed the requirements of this subchapter. Such an 
alternate arrangement must be approved in writing by the Associate 
Administrator. MEGCs approved to an Alternate Arrangement must be marked 
as required by paragraph (j) of this section.
    (c) Definitions. The following definitions apply:
    Leakproofness test means a test using gas subjecting the pressure 
receptacles and the service equipment of the MEGC to an effective 
internal pressure of not less than 20% of the test pressure.
    Manifold means an assembly of piping and valves connecting the 
filling and/or discharge openings of the pressure receptacles.

[[Page 103]]

    Maximum permissible gross mass or MPGM means the heaviest load 
authorized for transport (sum of the tare mass of the MEGC, service 
equipment and pressure receptacle).
    Service equipment means manifold system (measuring instruments, 
piping and safety devices).
    Shut-off valve means a valve that stops the flow of gas.
    Structural equipment means the reinforcing, fastening, protective 
and stabilizing members external to the pressure receptacles.
    (d) General design and construction requirements. (1) The MEGC must 
be capable of being loaded and discharged without the removal of its 
structural equipment. It must possess stabilizing members external to 
the pressure receptacles to provide structural integrity for handling 
and transport. MEGCs must be designed and constructed with supports to 
provide a secure base during transport and with lifting and tie-down 
attachments that are adequate for lifting the MEGC including when loaded 
to its maximum permissible gross mass. The MEGC must be designed to be 
loaded onto a transport vehicle or vessel and equipped with skids, 
mountings or accessories to facilitate mechanical handling.
    (2) MEGCs must be designed, manufactured and equipped to withstand, 
without loss of contents, all normal handling and transportation 
conditions. The design must take into account the effects of dynamic 
loading and fatigue.
    (3) Each pressure receptacle of a MEGC must be of the same design 
type, seamless steel, or composite, and constructed and tested according 
to one of the following ISO standards, as appropriate:
    (i) ISO 9809-1: Gas cylinders--Refillable seamless steel gas 
cylinders--Design, construction and testing--Part 1: Quenched and 
tempered steel cylinders with tensile strength less than 1100 MPa. (IBR, 
see Sec.  171.7 of this subchapter). Until December 31, 2018, the 
manufacture of a cylinder conforming to the requirements in ISO 9809-
1:1999 (IBR, see Sec.  171.7 of this subchapter) is authorized;
    (ii) ISO 9809-2: Gas cylinders--Refillable seamless steel gas 
cylinders--Design, construction and testing--Part 2: Quenched and 
tempered steel cylinders with tensile strength greater than or equal to 
1100 MPa. (IBR, see Sec.  171.7 of this subchapter). Until December 31, 
2018, the manufacture of a cylinder conforming to the requirements in 
ISO 9809-2:2000 (IBR, see Sec.  171.7 of this subchapter) is authorized;
    (iii) ISO 9809-3: Gas cylinders--Refillable seamless steel gas 
cylinders--Design, construction and testing--Part 3: Normalized steel 
cylinders. (IBR, see Sec.  171.7 of this subchapter). Until December 31, 
2018, the manufacture of a cylinder conforming to the requirements in 
ISO 9809-3:2000 (IBR, see Sec.  171.7 of this subchapter) is authorized; 
or
    (iv) ISO 9809-4:2014(E) Gas cylinders--Refillable seamless steel gas 
cylinders--Design, construction and testing--Part 4: Stainless steel 
cylinders with an Rm value of less than 1 100 MPa (IBR, see Sec.  171.7 
of this subchapter).
    (v) ISO 11120:2015(E) Gas cylinders--Refillable seamless steel tubes 
of water capacity between 150 L and 3000 L--Design, construction and 
testing (IBR, see Sec.  171.7 of this subchapter). Until December 31, 
2022, pressure receptacles of a MEGC may be constructed and tested in 
accordance with ISO 11120:1999(E) Gas cylinders--Refillable seamless 
steel tubes of water capacity between 150 L and 3000 L--Design, 
construction and testing (IBR, see Sec.  171.7 of this subchapter).
    (vi) ISO 11119-1:2012(E), Gas cylinders--Refillable composite gas 
cylinders and tubes--Design, construction and testing--Part 1: Hoop 
wrapped fibre reinforced composite gas cylinders and tubes up to 450 l 
(IBR, see Sec.  171.7 of this subchapter).
    (vii) ISO 11119-2:2012(E) and ISO 11119-2:2012/Amd.1:2014(E), Gas 
cylinders--Refillable composite gas cylinders and tubes--Design, 
construction and testing--Part 2: Fully wrapped fibre reinforced 
composite gas cylinders and tubes up to 450 l with load-sharing metal 
liners (both IBR, see Sec.  171.7 of this subchapter).
    (viii) ISO 11119-3:2013(E) Gas cylinders--Refillable composite gas 
cylinders and tubes--Design, construction and testing--Part 3: Fully 
wrapped

[[Page 104]]

fibre reinforced composite gas cylinders and tubes up to 450 l with non-
load-sharing metallic or non-metallic liners (IBR, see Sec.  171.7 of 
this subchapter).
    (ix) ISO 11119-4:2016(E) Gas cylinders--Refillable composite gas 
cylinders--Design, construction and testing--Part 4: Fully wrapped fibre 
reinforced composite gas cylinders up to 150 l with load-sharing welded 
metallic liners (IBR, see Sec.  171.7 of this subchapter).
    (4) Pressure receptacles of MEGCs, fittings, and pipework must be 
constructed of a material that is compatible with the hazardous 
materials intended to be transported, as specified in this subchapter.
    (5) Contact between dissimilar metals that could result in damage by 
galvanic action must be prevented by appropriate means.
    (6) The materials of the MEGC, including any devices, gaskets, and 
accessories, must have no adverse effect on the gases intended for 
transport in the MEGC.
    (7) MEGCs must be designed to withstand, without loss of contents, 
at least the internal pressure due to the contents, and the static, 
dynamic and thermal loads during normal conditions of handling and 
transport. The design must take into account the effects of fatigue, 
caused by repeated application of these loads through the expected life 
of the MEGC.
    (8) MEGCs and their fastenings must, under the maximum permissible 
load, be capable of withstanding the following separately applied static 
forces (for calculation purposes, acceleration due to gravity (g) = 9.81 
m/s\2\):
    (i) In the direction of travel: 2g (twice the MPGM multiplied by the 
acceleration due to gravity);
    (ii) Horizontally at right angles to the direction of travel: 1g 
(the MPGM multiplied by the acceleration due to gravity. When the 
direction of travel is not clearly determined, the forces must be equal 
to twice the MPGM);
    (iii) Vertically upwards: 1g (the MPGM multiplied by the 
acceleration due to gravity); and
    (iv) Vertically downwards: 2g (twice the MPGM (total loading 
including the effect of gravity) multiplied by the acceleration due to 
gravity.
    (9) Under each of the forces specified in paragraph (d)(8) of this 
section, the stress at the most severely stressed point of the pressure 
receptacles must not exceed the values given in the applicable design 
specifications (e.g., ISO 11120).
    (10) Under each of the forces specified in paragraph (d)(8) of this 
section, the safety factor for the framework and fastenings must be as 
follows:
    (i) For steels having a clearly defined yield point, a safety factor 
of 1.5 in relation to the guaranteed yield strength; or
    (ii) For steels with no clearly defined yield point, a safety factor 
of 1.5 in relation to the guaranteed 0.2 percent proof strength and, for 
austenitic steels, the 1 percent proof strength.
    (11) MEGCs must be capable of being electrically grounded to prevent 
electrostatic discharge when intended for flammable gases.
    (12) The pressure receptacles of a MEGC must be secured in a manner 
to prevent movement that could result in damage to the structure and 
concentration of harmful localized stresses.
    (e) Service equipment. (1) Service equipment must be arranged so 
that it is protected from mechanical damage by external forces during 
handling and transportation. When the connections between the frame and 
the pressure receptacles allow relative movement between the 
subassemblies, the equipment must be fastened to allow movement to 
prevent damage to any working part. The manifolds, discharge fittings 
(pipe sockets, shut-off devices), and shut-off valves must be protected 
from damage by external forces. Manifold piping leading to shut-off 
valves must be sufficiently flexible to protect the valves and the 
piping from shearing, or releasing the pressure receptacle contents. The 
filling and discharge devices, including flanges or threaded plugs, and 
any protective caps must be capable of being secured against unintended 
opening.
    (2) Each pressure receptacle intended for the transport of Division 
2.3 gases must be equipped with an individual

[[Page 105]]

shut-off valve. The manifold for Division 2.3 liquefied gases must be 
designed so that each pressure receptacle can be filled separately and 
be kept isolated by a valve capable of being closed during transit. For 
Division 2.1 gases, the pressure receptacles must be isolated by an 
individual shut-off valve into assemblies of not more than 3,000 L.
    (3) For MEGC filling and discharge openings:
    (i) Two valves in series must be placed in an accessible position on 
each discharge and filling pipe. One of the valves may be a backflow 
prevention valve.
    (ii) The filling and discharge devices may be equipped to a 
manifold.
    (iii) For sections of piping which can be closed at both ends and 
where a liquid product can be trapped, a pressure-relief valve must be 
provided to prevent excessive pressure build-up.
    (iv) The main isolation valves on a MEGC must be clearly marked to 
indicate their directions of closure. All shutoff valves must close by a 
clockwise motion of the handwheel.
    (v) Each shut-off valve or other means of closure must be designed 
and constructed to withstand a pressure equal to or greater than 1.5 
times the test pressure of the MEGC.
    (vi) All shut-off valves with screwed spindles must close by a 
clockwise motion of the handwheel. For other shut-off valves, the open 
and closed positions and the direction of closure must be clearly shown.
    (vii) All shut-off valves must be designed and positioned to prevent 
unintentional opening.
    (viii) Ductile metals must be used in the construction of valves or 
accessories.
    (4) The piping must be designed, constructed and installed to avoid 
damage due to expansion and contraction, mechanical shock and vibration. 
Joints in tubing must be brazed or have an equally strong metal union. 
The melting point of brazing materials must be no lower than 525 [deg]C 
(977 [deg]F). The rated pressure of the service equipment and of the 
manifold must be not less than two-thirds of the test pressure of the 
pressure receptacles.
    (f) Pressure relief devices. Each pressure receptacle must be 
equipped with one or more pressure relief devices as specified in Sec.  
173.301(f) of this subchapter. When pressure relief devices are 
installed, each pressure receptacle or group of pressure receptacles of 
a MEGC that can be isolated must be equipped with one or more pressure 
relief devices. Pressure relief devices must be of a type that will 
resist dynamic forces including liquid surge and must be designed to 
prevent the entry of foreign matter, the leakage of gas and the 
development of any dangerous excess pressure.
    (1) The size of the pressure relief devices: CGA S-1.1, excluding 
paragraph 9.1.1, (IBR, see Sec.  171.7 of this subchapter) must be used 
to determine the relief capacity of individual pressure receptacles.
    (2) Connections to pressure-relief devices: Connections to pressure 
relief devices must be of sufficient size to enable the required 
discharge to pass unrestricted to the pressure relief device. A shut-off 
valve installed between the pressure receptacle and the pressure relief 
device is prohibited, except where duplicate devices are provided for 
maintenance or other reasons, and the shut-off valves serving the 
devices actually in use are locked open, or the shut-off valves are 
interlocked so that at least one of the duplicate devices is always 
operable and capable of meeting the requirements of paragraph (f)(1) of 
this section. No obstruction is permitted in an opening leading to or 
leaving from a vent or pressure-relief device that might restrict or 
cut-off the flow from the pressure receptacle to that device. The 
opening through all piping and fittings must have at least the same flow 
area as the inlet of the pressure relief device to which it is 
connected. The nominal size of the discharge piping must be at least as 
large as that of the pressure relief device.
    (3) Location of pressure-relief devices: For liquefied gases, each 
pressure relief device must, under maximum filling conditions, be in 
communication with the vapor space of the pressure receptacles. The 
devices, when installed, must be arranged to ensure the escaping vapor 
is discharged upwards and unrestrictedly to prevent

[[Page 106]]

impingement of escaping gas or liquid upon the MEGC, its pressure 
receptacles or personnel. For flammable, pyrophoric and oxidizing gases, 
the escaping gas must be directed away from the pressure receptacle in 
such a manner that it cannot impinge upon the other pressure 
receptacles. Heat resistant protective devices that deflect the flow of 
gas are permissible provided the required pressure relief device 
capacity is not reduced. Arrangements must be made to prevent access to 
the pressure relief devices by unauthorized persons and to protect the 
devices from damage caused by rollover.
    (g) Gauging devices. When a MEGC is intended to be filled by mass, 
it must be equipped with one or more gauging devices. Glass level-gauges 
and gauges made of other fragile material are prohibited.
    (h) MEGC supports, frameworks, lifting and tie-down attachments. (1) 
MEGCs must be designed and constructed with a support structure to 
provide a secure base during transport. MEGCs must be protected against 
damage to the pressure receptacles and service equipment resulting from 
lateral and longitudinal impact and overturning. The forces specified in 
paragraph (d)(8) of this section, and the safety factor specified in 
paragraph (d)(10) of this section must be considered in this aspect of 
the design. Skids, frameworks, cradles or other similar structures are 
acceptable. If the pressure receptacles and service equipment are so 
constructed as to withstand impact and overturning, additional 
protective support structure is not required (see paragraph (h)(4) of 
this section).
    (2) The combined stresses caused by pressure receptacle mountings 
(e.g. cradles, frameworks, etc.) and MEGC lifting and tie-down 
attachments must not cause excessive stress in any pressure receptacle. 
Permanent lifting and tie-down attachments must be equipped to all 
MEGCs. Any welding of mountings or attachments onto the pressure 
receptacles is prohibited.
    (3) The effects of environmental corrosion must be taken into 
account in the design of supports and frameworks.
    (4) When MEGCs are not protected during transport as specified in 
paragraph (h)(1) of this section, the pressure receptacles and service 
equipment must be protected against damage resulting from lateral or 
longitudinal impact or overturning. External fittings must be protected 
against release of the pressure receptacles' contents upon impact or 
overturning of the MEGC on its fittings. Particular attention must be 
paid to the protection of the manifold. Examples of protection include:
    (i) Protection against lateral impact, which may consist of 
longitudinal bars;
    (ii) Protection against overturning, which may consist of 
reinforcement rings or bars fixed across the frame;
    (iii) Protection against rear impact, which may consist of a bumper 
or frame;
    (iv) Protection of the pressure receptacles and service equipment 
against damage from impact or overturning by use of an ISO frame 
according to the relevant provisions of ISO 1496-3. (IBR, see Sec.  
171.7 of this subchapter).
    (i) Initial inspection and test. The pressure receptacles and items 
of equipment of each MEGC must be inspected and tested before being put 
into service for the first time (initial inspection and test). This 
initial inspection and test of an MEGC must include the following:
    (1) A check of the design characteristics.
    (2) An external examination of the MEGC and its fittings, taking 
into account the hazardous materials to be transported.
    (3) A pressure test performed at the test pressures specified in 
Sec.  173.304b(b)(1) and (2) of this subchapter. The pressure test of 
the manifold may be performed as a hydraulic test or by using another 
liquid or gas. A leakproofness test and a test of the satisfactory 
operation of all service equipment must also be performed before the 
MEGC is placed into service. When the pressure receptacles and their 
fittings have been pressure-tested separately, they must be subjected to 
a leakproof test after assembly.
    (4) An MEGC that meets the definition of ``container'' in the CSC 
(see 49 CFR 450.3(a)(2)) must be subjected to an impact test using a 
prototype representing each design type. The prototype MEGC must be 
shown to be capable of absorbing the forces resulting

[[Page 107]]

from an impact not less than 4 times (4 g) the MPGM of the fully loaded 
MEGC, at a duration typical of the mechanical shocks experienced in rail 
transport. A listing of acceptable methods for performing the impact 
test is provided in the UN Recommendations (IBR, see Sec.  171.7 of this 
subchapter).
    (j) Marking. (1) Each MEGC must be equipped with a corrosion 
resistant metal plate permanently attached to the MEGC in a conspicuous 
place readily accessible for inspection. The pressure receptacles must 
be marked according to this section. Affixing the metal plate to a 
pressure receptacle is prohibited. At a minimum, the following 
information must be marked on the plate by stamping or by any other 
equivalent method:


Country of manufacture

                                   UN
[GRAPHIC] [TIFF OMITTED] TR12JN06.002


Approval Country

Approval Number

Alternate Arrangements (see Sec.  178.75(b))

MEGC Manufacturer's name or mark

MEGC's serial number

Approval agency (Authorized body for the design approval)

Year of manufacture

Test pressure: ______ bar gauge

Design temperature range ______ [deg]C to ______ [deg]C

Number of pressure receptacles ______

Total water capacity ______ liters

Initial pressure test date and identification of the Approval Agency

Date and type of most recent periodic tests

Year ______ Month______ Type ______

(e.g. 2004-05, AE/UE, where ``AE'' represents acoustic emission and 
``UE'' represents ultrasonic examination)

    Stamp of the approval agency who performed or witnessed the most 
recent test
    (2) The following information must be marked on a metal plate firmly 
secured to the MEGC:


Name of the operator

Maximum permissible load mass ______ kg

Working pressure at 15 [deg]C: ______ bar gauge

Maximum permissible gross mass (MPGM) ______ kg

Unladen (tare) mass ______ kg

[71 FR 33892, June 12, 2006, as amended at 73 FR 4719, Jan. 28, 2008; 77 
FR 60943, Oct. 5, 2012; 80 FR 1168, Jan. 8, 2015; 82 FR 15896, Mar. 30, 
2017; 85 FR 27901, May 11, 2020; 85 FR 85432, Dec. 27, 2020; 87 FR 
44999, July 26, 2022]



   Sec. Appendix A to Subpart C of Part 178--Illustrations: Cylinder 
                             Tensile Sample

    The following figures illustrate the recommended locations for test 
specimens taken from welded cylinders:

[[Page 108]]

[GRAPHIC] [TIFF OMITTED] TR08AU02.013


[[Page 109]]


[GRAPHIC] [TIFF OMITTED] TR08AU02.014


[[Page 110]]


[GRAPHIC] [TIFF OMITTED] TR08AU02.015


[[Page 111]]


[GRAPHIC] [TIFF OMITTED] TR08AU02.016


[[Page 112]]


[GRAPHIC] [TIFF OMITTED] TR08AU02.017


[67 FR 51654, Aug. 8, 2002]

[[Page 113]]

Subparts D-G [Reserved]



               Subpart H_Specifications for Portable Tanks

    Source: 29 FR 18972, Dec. 29, 1964, unless otherwise noted. 
Redesignated at 32 FR 5606, Apr. 5, 1967.



Sec. Sec.  178.251--178.253-5  [Reserved]



Sec.  178.255  Specification 60; steel portable tanks.



Sec.  178.255-1  General requirements.

    (a) Tanks must be of fusion welded construction, cylindrical in 
shape with seamless heads concave to the pressure. Tank shells may be of 
seamless construction.
    (b) Tanks must be designed, constructed, certified, and stamped in 
accordance with Section VIII of the ASME Code (IBR, see Sec.  171.7 of 
this subchapter).
    (c) Tanks including all permanent attachments must be postweld heat 
treated as a unit.
    (d) Requirements concerning types of valves, retesting, and 
qualification of portable tanks contained in Sec. Sec.  173.32 and 
173.315 of this chapter must be observed.

[29 FR 18972, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 178-7, 34 FR 18250, Nov. 14, 1969; 68 FR 75750, 
Dec. 31, 2003]



Sec.  178.255-2  Material.

    (a) Material used in the tank must be steel of good weldable quality 
and conform with the requirements in Sections V, VIII, and IX of the 
ASME Code (IBR, see Sec.  171.7 of this subchapter).
    (b) The minimum thickness of metal, exclusive of lining material, 
for shell and heads of tanks shall be as follows:

------------------------------------------------------------------------
                                                                Minimum
                        Tank capacity                          thickness
                                                                (inch)
------------------------------------------------------------------------
Not more than 1,200 gallons.................................       \1/4\
Over 1,200 to 1,800 gallons.................................      \5/16\
Over 1,800 gallons..........................................       \3/8\
------------------------------------------------------------------------


[29 FR 18972, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 178-7, 34 FR 18250, Nov. 14, 1969; 68 FR 75750, 
Dec. 31, 2003]



Sec.  178.255-3  Expansion domes.

    (a) Expansion domes, if applied, must have a minimum capacity of one 
percent of the combined capacity of the tank and dome.
    (b) [Reserved]



Sec.  178.255-4  Closures for manholes and domes.

    (a) The manhole cover shall be designed to provide a secure closure 
of the manhole. All covers, not hinged to the tanks, shall be attached 
to the outside of the dome by at least \1/8\ inch chain or its 
equivalent. Closures shall be made tight against leakage of vapor and 
liquid by use of gaskets of suitable material.
    (b) [Reserved]



Sec.  178.255-5  Bottom discharge outlets.

    (a) Bottom discharge outlets prohibited, except on tanks used for 
shipments of sludge acid and alkaline corrosive liquids.
    (b) If installed, bottom outlets or bottom washout chambers shall be 
of metal not subject to rapid deterioration by the lading, and each 
shall be provided with a valve or plug at its upper end and liquid-tight 
closure at it lower end. Each valve or plug shall be designed to insure 
against unseating due to stresses or shocks incident to transportation. 
Bottom outlets shall be adequately protected against handling damage and 
outlet equipment must not extend to within less than one inch of the 
bottom bearing surface of the skids or tank mounting.

[29 FR 18972, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
as amended by Amdt. 178-104, 59 FR 49135, Sept. 26, 1994]



Sec.  178.255-6  Loading and unloading accessories.

    (a) When installed, gauging, loading and air inlet devices, 
including their valves, shall be provided with adequate means for their 
secure closure; and means shall also be provided for the closing of pipe 
connections of valves.
    (b) Interior heater coils, if installed, must be of extra heavy pipe 
and so constructed that breaking off of exterior connections will not 
cause leakage of tanks.

[[Page 114]]



Sec.  178.255-7  Protection of valves and accessories.

    (a) All valves, fittings, accessories, safety devices, gauging 
devices, and the like shall be adequately protected against mechanical 
damage by a housing closed with a cover plate.
    (b) Protective housing shall comply with the requirements under 
which the tanks are fabricated with respect to design and construction, 
and shall be designed with a minimum factor of safety of four to 
withstand loadings in any direction equal to two times the weight of the 
tank and attachments when filled with water.



Sec.  178.255-8  Safety devices.

    (a) See Sec.  173.315(i) of this subchapter.
    (b) [Reserved]

[Amdt. 178-83, 50 FR 11066, Mar. 19, 1985]



Sec.  178.255-9  Compartments.

    (a) When the interior of the tank is divided into compartments, each 
compartment shall be designed, constructed and tested as a separate 
tank. Thickness of shell and compartment heads shall be determined on 
the basis of total tank capacity.
    (b) [Reserved]



Sec.  178.255-10  Lining.

    (a) If a lining is required, the material used for lining the tank 
shall be homogeneous, nonporous, imperforate when applied, not less 
elastic than the metal of the tank proper. It shall be of substantially 
uniform thickness, not less than \1/32\ inch thick if metallic, and not 
less than \1/16\ inch thick if nonmetallic, and shall be directly bonded 
or attached by other equally satisfactory means. Rubber lining shall be 
not less than \3/16\ inch thick. Joints and seams in the lining shall be 
made by fusing the material together or by other equally satisfactory 
means. The interior of the tank shall be free from scale, oxidation, 
moisture and all foreign matter during the lining operation.
    (b) [Reserved]



Sec.  178.255-11  Tank mountings.

    (a) Tanks shall be designed and fabricated with mountings to provide 
a secure base in transit. ``Skids'' or similar devices shall be deemed 
to comply with this requirement.
    (b) All tank mountings such as skids, fastenings, brackets, cradles, 
lifting lugs, etc., intended to carry loadings shall be permanently 
secured to tanks in accordance with the requirements under which the 
tanks are fabricated, and shall be designed with a factor of safety of 
four, and built to withstand loadings in any direction equal to two 
times the weight of the tanks and attachments when filled to the maximum 
permissible loaded weight.
    (c) Lifting lugs or side hold-down lugs shall be provided on the 
tank mountings in a manner suitable for attaching lifting gear and hold-
down devices. Lifting lugs and hold-down lugs welded directly to the 
tank shall be of the pad-eye type. Doubling plates welded to the tank 
and located at the points of support shall be deemed to comply with this 
requirement.
    (d) All tank mountings shall be so designed as to prevent the 
concentration of excessive loads on the tank shell.



Sec.  178.255-12  Pressure test.

    (a) Each completed portable tank prior to application of lining 
shall be tested before being put into transportation service by 
completely filling the tank with water or other liquid having a similar 
viscosity, the temperature of which shall not exceed 100 [deg]F during 
the test, and applying a pressure of 60 psig. The tank shall be capable 
of holding the prescribed pressure for at least 10 minutes without 
leakage, evidence of impending failure, or failure. All closures shall 
be in place while the test is made and the pressure shall be gauged at 
the top of the tank. Safety devices and/or vents shall be plugged during 
this test.
    (b) [Reserved]

[29 FR 18972, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
as amended by Amdt. 178-104, 59 FR 49135, Sept. 26, 1994]



Sec.  178.255-13  Repair of tanks.

    (a) Tanks failing to meet the test may be repaired and retested, 
provided that repairs are made in complete compliance with the 
requirements of this specification.
    (b) [Reserved]

[[Page 115]]



Sec.  178.255-14  Marking.

    (a) In addition to markings required by Section VIII of the ASME 
Code (IBR, see Sec.  171.7 of this subchapter), every tank shall bear 
permanent marks at least 1/8-inch high stamped into the metal near the 
center of one of the tank heads or stamped into a plate permanently 
attached to the tank by means of brazing or welding or other suitable 
means as follows:

Manufacturer's name ______________ Serial No.___________________________
DOT specification_______________________________________________________
Nominal capacity ______________ (gallons)
Tare weight ______________ (pounds)
Date of manufacture_____________________________________________________

    (b) [Reserved]

[29 FR 18972, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 178-67, 46 FR 49906, Oct. 8, 1981; 68 FR 75750, 
Dec. 31, 2003]



Sec.  178.255-15  Report.

    (a) A copy of the manufacturer's data report required by Section 
VIII of the ASME Code (IBR, see Sec.  171.7 of this subchapter) under 
which the tank is fabricated must be furnished to the owner for each new 
tank.

 Place__________________________________________________________________
 Date___________________________________________________________________
 Portable tank
Manufactured for ______________ Company
Location________________________________________________________________
Manufactured by ______________ Company
Location________________________________________________________________
Consigned to __________________ Company
Location________________________________________________________________
Size ______ feet outside diameter by ______ long.
Marks on tank as prescribed by Sec.  178.255-14 of this specification 
are as follows:
Manufacturer's name_____________________________________________________
Serial number___________________________________________________________
Owner's serial number___________________________________________________
DOT specification_______________________________________________________
ASME Code Symbol (par U-201)____________________________________________
Date of manufacture_____________________________________________________
Nominal capacity ______________ gallons.
    It is hereby certified that this tank is in complete compliance with 
the requirements of DOT specification No. 60.
 (Signed)_______________________________________________________________
                                                   Manufacturer or owner

    (b) [Reserved]

[29 FR 18972, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 178-83, 50 FR 11066, Mar. 19, 1985; 68 FR 75750, 
Dec. 31, 2003]



Sec.  178.273  Approval of Specification UN portable tanks.

    (a) Application for approval. (1) An owner or manufacturer of a 
portable tank shall apply for approval to a designated approval agency 
authorized to approve the portable tank in accordance with the 
procedures in subpart E, part 107 of this subchapter.
    (2) Each application for approval must contain the following 
information:
    (i) Two complete copies of all engineering drawings, calculations, 
and test data necessary to ensure that the design meets the relevant 
specification.
    (ii) The manufacturer's serial number that will be assigned to each 
portable tank.
    (iii) A statement as to whether the design type has been examined by 
any approval agency previously and judged unacceptable. Affirmative 
statements must be documented with the name of the approval agency, 
reason for nonacceptance, and the nature of modifications made to the 
design type.
    (b) Action by approval agency. The approval agency must perform the 
following activities:
    (1) Review the application for approval to determine whether it is 
complete and conforms with the requirements of paragraph (a) of this 
section. If an application is incomplete, it will be returned to the 
applicant with an explanation as to why the application is incomplete.
    (2) Review all drawings and calculations to ensure that the design 
is in compliance with all requirements of the relevant specification. If 
the application is approved, one set of the approved drawings, 
calculations, and test data shall be returned to the applicant. The 
second (inspector's copy) set of approved drawings, calculations, and 
test data shall be retained by the approval agency. Maintain drawings 
and approval records for as long as the portable tank remains in 
service. The drawings and records must be provided to the Department of 
Transportation (DOT) upon request.
    (3) Witness all tests required for the approval of the portable tank 
specified in this section and part 180, subpart G of this subchapter.

[[Page 116]]

    (4) Ensure, through appropriate inspection that each portable tank 
is fabricated in all respects in conformance with the approved drawings, 
calculations, and test data.
    (5) Determine and ensure that the portable tank is suitable for its 
intended use and that it conforms to the requirements of this 
subchapter.
    (6) For UN portable tanks intended for non-refrigerated and 
refrigerated liquefied gases and Division 6.1 liquids which meet the 
inhalation toxicity criteria (Zone A or B) as defined in Sec.  173.132 
of this subchapter, or that are designated as toxic by inhalation 
materials in the Sec.  172.101 Table of this subchapter, the approval 
agency must ensure that:
    (i) The portable tank has been designed, constructed, certified, and 
stamped in accordance with the requirements in Division 1 of Section 
VIII of the ASME Code (IBR, see Sec.  171.7 of this subchapter). Other 
design codes may be used if approved by the Associate Administrator (see 
Sec.  178.274(b)(1));
    (ii) All applicable provisions of the design and construction have 
been met to the satisfaction of the designated approval agency in 
accordance with the rules established in the ASME Code and that the 
portable tank meets the requirements of the ASME Code and all the 
applicable requirements specified in this subchapter;
    (iii) The inspector has carried out all the inspections specified by 
the rules established in the ASME Code; and
    (iv) The portable tank is marked with a U stamp code symbol under 
the authority of the authorized independent inspector.
    (7) Upon successful completion of all requirements of this subpart, 
the approval agency must:
    (i) Apply its name, identifying mark or identifying number, and the 
date upon which the approval was issued, to the metal identification 
marking plate attached to the portable tank. Any approvals for UN 
portable tanks authorizing design or construction alternatives 
(Alternate Arrangements) approved by the Associate Administrator (see 
Sec.  178.274(a)(2)) must be indicated on the plate as specified in 
Sec.  178.274(i).
    (ii) Issue an approval certificate for each portable tank or, in the 
case of a series of identical portable tanks manufactured to a single 
design type, for each series of portable tanks. The approval certificate 
must include all the information required to be displayed on the metal 
identification plate required by Sec.  178.274(i). The approval 
certificate must certify that the approval agency designated to approve 
the portable tank has approved the portable tank in accordance with the 
procedures in subpart E of part 107 of this subchapter and that the 
portable tank is suitable for its intended purpose and meets the 
requirements of this subchapter. When a series of portable tanks is 
manufactured without change in the design type, the certificate may be 
valid for the entire series of portable tanks representing a single 
design type. For UN portable tanks, the certificate must refer to the 
prototype test report, the hazardous material or group of hazardous 
materials allowed to be transported, the materials of construction of 
the shell and lining (when applicable) and an approval number. The 
approval number must consist of the distinguishing sign or mark of the 
country (``USA'' for the United States of America) where the approval 
was granted and a registration number.
    (iii) Retain a copy of each approval certificate.
    (8) For UN portable tanks, the approval certificate must also 
include the following:
    (i) The results of the applicable framework and rail impact test 
specified in part 180, subpart G, of this subchapter; and
    (ii) The results of the initial inspection and test in Sec.  
178.274(j).
    (9) The approval agency shall be independent from the manufacturer. 
The approval agency and the authorized inspector may be the same entity.
    (c) Manufacturers' responsibilities. The manufacturer is responsible 
for compliance with the applicable specifications for the design and 
construction of portable tanks. In addition to responsibility for 
compliance, manufacturers are responsible for ensuring that the 
contracted approval agency and authorized inspector, if applicable, are 
qualified, reputable and competent. The manufacturer of a portable tank 
shall--

[[Page 117]]

    (1) Comply with all the applicable requirements of the ASME Code and 
of this subpart including, but not limited to, ensuring that the quality 
control, design calculations and required tests are performed and that 
all aspects of the portable tank meet the applicable requirements.
    (2) Obtain and use a designated approval agency, if applicable, and 
obtain and use a DOT-designated approval agency to approve the design, 
construction and certification of the portable tank.
    (3) Provide a statement in the manufacturers' data report certifying 
that each portable tank that is manufactured complies with the relevant 
specification and all the applicable requirements of this subchapter.
    (4) Maintain records of the qualification of portable tanks for at 
least 5 years and provide copies to the approval agency, the owner or 
lessee of the tank. Upon request, provide these records to a 
representative of DOT.
    (d) Denial of application for approval. If an approval agency finds 
that a portable tank cannot be approved for any reason, it shall notify 
the applicant in writing and shall provide the applicant with the 
reasons for which the approval is denied. A copy of the notification 
letter shall be provided to the Associate Administrator. An applicant 
aggrieved by a decision of an approval agency may appeal the decision in 
writing, within 90 days of receipt, to the Associate Administrator.
    (e) Modifications to approved portable tanks. (1) Prior to 
modification of any UN portable tank which may affect conformance and 
the safe use of the portable tank, which may involve a change to the 
design type or which may affect its ability to retain hazardous material 
in transportation, the person desiring to make such modification shall 
inform the approval agency that issued the initial approval of the 
portable tank (or if unavailable, another approval agency) of the nature 
of the modification and request approval of the modification. The person 
desiring to modify the tank must supply the approval agency with three 
sets of all revised drawings, calculations, and test data relative to 
the intended modification.
    (2) A statement as to whether the intended modification has been 
examined and determined to be unacceptable by any approval agency. The 
written statement must include the name of the approving agency, the 
reason for nonacceptance, and the nature of changes made to the 
modification since its original rejection.
    (3) The approval agency shall review the request for modification, 
and if it is determined that the proposed modification is in full 
compliance with the relevant DOT specification, including a UN portable 
tank, the request shall be approved and the approval agency shall 
perform the following activities:
    (i) Return one set of the approved revised drawings, calculations, 
and test data to the applicant. The second and third sets of the 
approved revised drawings, calculations, and data shall be retained by 
the approval agency as required in Sec.  107.404(a)(3) of this 
subchapter.
    (ii) Ensure through appropriate inspection that all modifications 
conform to the revised drawings, calculations, and test data.
    (iii) Determine the extent to which retesting of the modified tank 
is necessary based on the nature of the proposed modification, and 
ensure that all required retests are satisfactorily performed.
    (iv) If modification to an approved tank alters any information on 
the approval certificate, issue a new approval certificate for the 
modified tank and ensure that any necessary changes are made to the 
metal identification plate. A copy of each newly issued approval 
certificate shall be retained by the approval agency and by the owner of 
each portable tank.
    (4) If the approval agency determines that the proposed modification 
is not in compliance with the relevant DOT specification, the approval 
agency shall deny the request in accordance with paragraph (d) of this 
section.
    (f) Termination of Approval Certificate. (1) The Associate 
Administrator may terminate an approval issued under this section if he 
determines that--
    (i) Information upon which the approval was based is fraudulent or 
substantially erroneous; or

[[Page 118]]

    (ii) Termination of the approval is necessary to adequately protect 
against risks to life and property; or
    (iii) The approval was not issued by the approval agency in good 
faith; or
    (iv) The portable tank does not meet the specification.
    (2) Before an approval is terminated, the Associate Administrator 
gives the interested party(ies):
    (i) Written notice of the facts or conduct believed to warrant the 
termination;
    (ii) Opportunity to submit oral and written evidence; and
    (iii) Opportunity to demonstrate or achieve compliance with the 
applicable requirements.
    (3) If the Associate Administrator determines that a certificate of 
approval must be terminated to preclude a significant and imminent 
adverse affect on public safety, he may terminate the certificate 
immediately. In such circumstances, the opportunities of paragraphs 
(f)(2) (ii) and (iii) of this section need not be provided prior to 
termination of the approval, but shall be provided as soon as 
practicable thereafter.

[66 FR 33439, June 21, 2001, as amended at 67 FR 61016, Sept. 27, 2002; 
68 FR 75748, 75751, Dec. 31, 2003; 72 FR 55695, Oct. 1, 2007]



Sec.  178.274  Specifications for UN portable tanks.

    (a) General. (1) Each UN portable tank must meet the requirements of 
this section. In addition to the requirements of this section, 
requirements specific to UN portable tanks used for liquid and solid 
hazardous materials, non-refrigerated liquefied gases and refrigerated 
liquefied gases are provided in Sec. Sec.  178.275, 178.276 and 178.277, 
respectively. Requirements for approval, maintenance, inspection, 
testing and use are provided in Sec.  178.273 and part 180, subpart G, 
of this subchapter. Any portable tank which meets the definition of a 
``container'' within the terms of the International Convention for Safe 
Containers (CSC) must meet the requirements of the CSC as amended and 49 
CFR parts 450 through 453 and must have a CSC safety approval plate.
    (2) In recognition of scientific and technological advances, the 
technical requirements applicable to UN portable tanks may be varied if 
approved by the Associate Administrator and the portable tank is shown 
to provide a level of safety equal to or exceeding the requirements of 
this subchapter. Portable tanks approved to alternative technical 
requirements must be marked ``Alternative Arrangement'' as specified in 
paragraph (i) of this section.
    (3) Definitions. The following definitions apply for the purposes of 
design and construction of UN portable tanks under this subpart:
    Alternate Arrangement portable tank means a UN portable tank that 
has been approved to alternative technical requirements or testing 
methods other than those specified for UN portable tanks in part 178 or 
part 180 of this subchapter.
    Approval agency means the designated approval agency authorized to 
approve the portable tank in accordance with the procedures in subpart E 
of part 107 of this subchapter.
    Design pressure is defined according to the hazardous materials 
intended to be transported in the portable tank. See Sec. Sec.  178.275, 
178.276 and 178.277, as applicable.
    Design type means a portable tank or series of portable tanks made 
of materials of the same material specifications and thicknesses, 
manufactured by a single manufacturer, using the same fabrication 
techniques (for example, welding procedures) and made with equivalent 
structural equipment, closures, and service equipment.
    Fine grain steel means steel that has a ferritic grain size of 6 or 
finer when determined in accordance with ASTM E 112-96 (IBR, see Sec.  
171.7 of this subchapter).
    Fusible element means a non-reclosing pressure relief device that is 
thermally activated and that provides protection against excessive 
pressure buildup in the portable tank developed by exposure to heat, 
such as from a fire (see Sec.  178.275(g)).
    Jacket means the outer insulation cover or cladding which may be 
part of the insulation system.
    Leakage test means a test using gas to subject the shell and its 
service equipment to an internal pressure.

[[Page 119]]

    Maximum allowable working pressure (MAWP) is defined according to 
the hazardous materials intended to be transported in the portable tank. 
See Sec. Sec.  178.275, 178.276 and 178.277, as applicable.
    Maximum permissible gross mass (MPGM) means the sum of the tare mass 
of the portable tank and the heaviest hazardous material authorized for 
transportation.
    Mild steel means a steel with a guaranteed minimum tensile strength 
of 360 N/mm\2\ to 440 N/mm\2\ and a guaranteed minimum elongation at 
fracture as specified in paragraph (c)(10) of this section.
    Offshore portable tank means a portable tank specially designed for 
repeated use in the transportation of hazardous materials to, from and 
between offshore facilities. An offshore portable tank is designed and 
constructed in accordance with the Guidelines for the Approval of 
Containers Handled in Open Seas specified in the IMDG Code (IBR, see 
Sec.  171.7 of this subchapter).
    Reference steel means a steel with a tensile strength of 370 N/mm\2\ 
and an elongation at fracture of 27%.
    Service equipment means measuring instruments and filling, 
discharge, venting, safety, heating, cooling and insulating devices.
    Shell means the part of the portable tank which retains the 
hazardous materials intended for transportation, including openings and 
closures, but does not include service equipment or external structural 
equipment.
    Structural equipment means the reinforcing, fastening, protective 
and stabilizing members external to the shell.
    Test pressure means the maximum gauge pressure at the top of the 
shell during the hydraulic pressure test equal to not less than 1.5 
times the design pressure for liquids and 1.3 for liquefied compressed 
gases and refrigerated liquefied gases. In some instances a pneumatic 
test is authorized as an alternative to the hydraulic test. The minimum 
test pressures for portable tanks intended for specific liquid and solid 
hazardous materials are specified in the applicable portable tank T 
codes (such as T1-T23) assigned to these hazardous materials in the 
Sec.  172.101 Table of this subchapter.
    (b) General design and construction requirements. (1) The design 
temperature range for the shell must be -40 [deg]C to 50 [deg]C (-40 
[deg]F to 122 [deg]F) for hazardous materials transported under normal 
conditions of transportation, except for portable tanks used for 
refrigerated liquefied gases where the minimum design temperature must 
not be higher than the lowest (coldest) temperature (for example, 
service temperature) of the contents during filling, discharge or 
transportation. For hazardous materials handled under elevated 
temperature conditions, the design temperature must not be less than the 
maximum temperature of the hazardous material during filling, discharge 
or transportation. More severe design temperatures must be considered 
for portable tanks subjected to severe climatic conditions (for example, 
portable tanks transported in arctic regions). Shells must be designed 
and constructed in accordance with the requirements in Section VIII of 
the ASME Code (IBR, see Sec.  171.7 of this subchapter), except as 
limited or modified in this subchapter. For portable tanks used for 
liquid or solid hazardous materials, a design code other than the ASME 
Code may be used if approved by the Associate Administrator. Portable 
tanks must have an ASME certification and U stamp when used for Hazard 
Zone A or B toxic by inhalation liquids, or when used for non-
refrigerated or refrigerated liquefied compressed gases. Shells must be 
made of metallic materials suitable for forming. Non-metallic materials 
may be used for the attachments and supports between the shell and 
jacket, provided their material properties at the minimum and maximum 
design temperatures are proven to be sufficient. For welded shells, only 
a material whose weldability has been fully demonstrated may be used. 
Welds must be of high quality and conform to a level of integrity at 
least equivalent to the welding requirements specified in Section VIII 
of the ASME Code for the welding of pressure vessels. When the 
manufacturing process or the materials make it necessary, the shells 
must be suitably heat-treated to guarantee adequate toughness in the 
weld and in the heat-affected zones. In choosing the

[[Page 120]]

material, the design temperature range must be taken into account with 
respect to risk of brittle fracture, stress corrosion cracking, 
resistance to impact, and suitability for the hazardous materials 
intended for transportation in the portable tank. When fine grain steel 
is used, the guaranteed value of the yield strength must be not more 
than 460 N/mm\2\ and the guaranteed value of the upper limit of the 
tensile strength must be not more than 725 N/mm\2\ according to the 
material specification. Aluminum may not be used as a construction 
material for the shells of portable tanks intended for the transport of 
non-refrigerated liquefied gases. For portable tanks intended for the 
transport of liquid or solid hazardous materials, aluminum may only be 
used as a construction material for portable tank shells if approved by 
the Associate Administrator. Portable tank materials must be suitable 
for the external environment where they will be transported, taking into 
account the determined design temperature range. Portable tanks shall be 
designed to withstand, without loss of contents, at least the internal 
pressure due to the contents and the static, dynamic and thermal loads 
during normal conditions of handling and transportation. The design must 
take into account the effects of fatigue, caused by repeated application 
of these loads through the expected life of the portable tank.
    (2) Portable tank shells, fittings, and pipework shall be 
constructed from materials that are:
    (i) Compatible with the hazardous materials intended to be 
transported; or
    (ii) Properly passivated or neutralized by chemical reaction, if 
applicable; or
    (iii) For portable tanks used for liquid and solid materials, lined 
with corrosion-resistant material directly bonded to the shell or 
attached by equivalent means.
    (3) Gaskets and seals shall be made of materials that are compatible 
with the hazardous materials intended to be transported.
    (4) When shells are lined, the lining must be compatible with the 
hazardous materials intended to be transported, homogeneous, non-porous, 
free from perforations, sufficiently elastic and compatible with the 
thermal expansion characteristics of the shell. The lining of every 
shell, shell fittings and piping must be continuous and must extend 
around the face of any flange. Where external fittings are welded to the 
tank, the lining must be continuous through the fitting and around the 
face of external flanges. Joints and seams in the lining must be made by 
fusing the material together or by other equally effective means.
    (5) Contact between dissimilar metals which could result in damage 
by galvanic action must be prevented by appropriate measures.
    (6) The construction materials of the portable tank, including any 
devices, gaskets, linings and accessories, must not adversely affect or 
react with the hazardous materials intended to be transported in the 
portable tank.
    (7) Portable tanks must be designed and constructed with supports 
that provide a secure base during transportation and with suitable 
lifting and tie-down attachments.
    (c) Design criteria. (1) Portable tanks and their fastenings must, 
under the maximum permissible loads and maximum permissible working 
pressures, be capable of absorbing the following separately applied 
static forces (for calculation purposes, acceleration due to gravity (g) 
= 9.81m/s\2\):
    (i) In the direction of travel: 2g (twice the MPGM multiplied by the 
acceleration due to gravity);
    (ii) Horizontally at right angles to the direction of travel: 1g 
(the MPGM multiplied by the acceleration due to gravity);
    (iii) Vertically upwards: 1g (the MPGM multiplied by the 
acceleration due to gravity); and
    (iv) Vertically downwards: 2g (twice the MPGM multiplied by the 
acceleration due to gravity).
    (2) Under each of the forces specified in paragraph (c)(1) of this 
section, the safety factor must be as follows:
    (i) For metals having a clearly defined yield point, a design margin 
of 1.5 in relation to the guaranteed yield strength; or
    (ii) For metals with no clearly defined yield point, a design margin 
of 1.5 in relation to the guaranteed 0.2%

[[Page 121]]

proof strength and, for austenitic steels, the 1% proof strength.
    (3) The values of yield strength or proof strength must be the 
values according to recognized material standards. When austenitic 
steels are used, the specified minimum values of yield strength or proof 
strength according to the material standards may be increased by up to 
15% for portable tanks used for liquid and solid hazardous materials, 
other than toxic by inhalation liquids meeting the criteria of Hazard 
Zone A or Hazard Zone B (see Sec.  173.133 of this subchapter), when 
these greater values are attested in the material inspection 
certificate.
    (4) Portable tanks must be capable of being electrically grounded to 
prevent dangerous electrostatic discharge when they are used for Class 2 
flammable gases or Class 3 flammable liquids, including elevated 
temperature materials transported at or above their flash point.
    (5) For shells of portable tanks used for liquefied compressed 
gases, the shell must consist of a circular cross section. Shells must 
be of a design capable of being stress-analyzed mathematically or 
experimentally by resistance strain gauges as specified in UG-101 of 
Section VIII of the ASME Code, or other methods approved by the 
Associate Administrator.
    (6) Shells must be designed and constructed to withstand a hydraulic 
test pressure of not less than 1.5 times the design pressure for 
portable tanks used for liquids and 1.3 times the design pressure for 
portable tanks used for liquefied compressed gases. Specific 
requirements are provided for each hazardous material in the applicable 
T Code or portable tank special provision specified in the Sec.  172.101 
Table of this subchapter. The minimum shell thickness requirements must 
also be taken into account.
    (7) For metals exhibiting a clearly defined yield point or 
characterized by a guaranteed proof strength (0.2% proof strength, 
generally, or 1% proof strength for austenitic steels), the primary 
membrane stress [sigma] (sigma) in the shell must not exceed 0.75 Re or 
0.50 Rm, whichever is lower, at the test pressure, where:

Re = yield strength in N/mm\2\, or 0.2% proof strength or, for 
austenitic steels, 1% proof strength;
Rm = minimum tensile strength in N/mm\2\.

    (8) The values of Re and Rm to be used must be the specified minimum 
values according to recognized material standards. When austenitic 
steels are used, the specified minimum values for Re and Rm according to 
the material standards may be increased by up to 15% when greater values 
are attested in the material inspection certificate.
    (9) Steels which have a Re/Rm ratio of more than 0.85 are not 
allowed for the construction of welded shells. The values of Re and Rm 
to be used in determining this ratio must be the values specified in the 
material inspection certificate.
    (10) Steels used in the construction of shells must have an 
elongation at fracture, in percentage, of not less than 10,000/Rm with 
an absolute minimum of 16% for fine grain steels and 20% for other 
steels.
    (11) For the purpose of determining actual values for materials for 
sheet metal, the axis of the tensile test specimen must be at right 
angles (transversely) to the direction of rolling. The permanent 
elongation at fracture must be measured on test specimens of rectangular 
cross sections in accordance with ISO 6892 (IBR, see Sec.  171.7 of this 
subchapter), using a 50 mm gauge length.
    (d) Minimum shell thickness. (1) The minimum shell thickness must be 
the greatest thickness of the following:
    (i) the minimum thickness determined in accordance with the 
requirements of paragraphs (d)(2) through (d)(7) of this section;
    (ii) the minimum thickness determined in accordance with Section 
VIII of the ASME Code or other approved pressure vessel code; or
    (iii) the minimum thickness specified in the applicable T code or 
portable tank special provision indicated for each hazardous material in 
the Sec.  172.101 Table of this subchapter.
    (2) Shells (cylindrical portions, heads and manhole covers) not more 
than 1.80 m in diameter may not be less than 5 mm thick in the reference 
steel or of

[[Page 122]]

equivalent thickness in the metal to be used. Shells more than 1.80 m in 
diameter may not be less than 6 mm (0.2 inches) thick in the reference 
steel or of equivalent thickness in the metal to be used. For portable 
tanks used only for the transportation of powdered or granular solid 
hazardous materials of Packing Group II or III, the minimum thickness 
requirement may be reduced to 5 mm in the reference steel or of 
equivalent thickness in the metal to be used regardless of the shell 
diameter. For vacuum-insulated tanks, the aggregate thickness of the 
jacket and the shell must correspond to the minimum thickness prescribed 
in this paragraph, with the thickness of the shell itself not less than 
the minimum thickness prescribed in paragraph (d)(3) of this section.
    (3) When additional protection against shell damage is provided in 
the case of portable tanks used for liquid and solid hazardous materials 
requiring test pressures less than 2.65 bar (265.0 kPa), subject to 
certain limitations specified in the UN Recommendations (IBR, see Sec.  
171.7 of this subchapter), the Associate Administrator may approve a 
reduced minimum shell thickness.
    (4) The cylindrical portions, heads and manhole covers of all shells 
must not be less than 3 mm (0.1 inch) thick regardless of the material 
of construction, except for portable tanks used for liquefied compressed 
gases where the cylindrical portions, ends (heads) and manhole covers of 
all shells must not be less than 4 mm (0.2 inch) thick regardless of the 
material of construction.
    (5) When steel is used, that has characteristics other than that of 
reference steel, the equivalent thickness of the shell and heads must be 
determined according to the following formula:
[GRAPHIC] [TIFF OMITTED] TN21JN01.005

Where:

e1 = required equivalent thickness (in mm) of the metal to be 
          used;
e0 = minimum thickness (in mm) of the reference steel 
          specified in the applicable T code or portable tank special 
          provision indicated for each material in the Sec.  172.101 
          Table of this subchapter;
d1 = 1.8m, unless the formula is used to determine the 
          equivalent minimum thickness for a portable tank shell that is 
          required to have a minimum thickness of 8mm or 10mm according 
          to the applicable T code indicated in the Sec.  172.101 Table 
          of this subchapter. When reference steel thicknesses of 8mm or 
          10mm are specified, d1 is equal to the actual 
          diameter of the shell but not less than 1.8m;
Rm1 = guaranteed minimum tensile strength (in N/mm \2\) of 
          the metal to be used;
A1 = guaranteed minimum elongation at fracture (in %) of the 
          metal to be used according to recognized material standards.

    (6) The wall and all parts of the shell may not have a thickness 
less than that prescribed in paragraphs (d)(2), (d)(3) and (d)(4) of 
this section. This thickness must be exclusive of any corrosion 
allowance.
    (7) There must be no sudden change of plate thickness at the 
attachment of the heads to the cylindrical portion of the shell.
    (e) Service equipment. (1) Service equipment must be arranged so 
that it is protected against the risk of mechanical damage by external 
forces during handling and transportation. When the connections between 
the frame and the shell allow relative movement between the sub-
assemblies, the equipment must be fastened to allow such movement 
without risk of damage to any working part. The external discharge 
fittings (pipe sockets, shut-off devices) and the internal stop-valve 
and its seating must be protected against mechanical damage by external 
forces (for example, by using shear sections). Each internal self-
closing stop-valve must be protected by a shear section or sacrificial 
device located outboard of the valve. The shear section or sacrificial 
device must break at no more than 70% of the load that would cause 
failure of the internal self-closing stop valve. The filling and 
discharge devices (including flanges or threaded plugs) and any 
protective caps must be capable of being secured against unintended 
opening.
    (2) Each filling or discharge opening of a portable tank must be 
clearly marked to indicate its function.
    (3) Each stop-valve or other means of closure must be designed and 
constructed to a rated pressure not less than the MAWP of the shell 
taking

[[Page 123]]

into account the temperatures expected during transport. All stop-valves 
with screwed spindles must close by a clockwise motion of the handwheel. 
For other stop-valves, the position (open and closed) and direction of 
closure must be clearly indicated. All stop-valves must be designed to 
prevent unintentional opening.
    (4) Piping must be designed, constructed and installed to avoid the 
risk of damage due to thermal expansion and contraction, mechanical 
shock and vibration. All piping must be of a suitable metallic material. 
Welded pipe joints must be used wherever possible.
    (5) Joints in copper tubing must be brazed or have an equally strong 
metal union. The melting point of brazing materials must be no lower 
than 525 [deg]C (977 [deg]F). The joints must not decrease the strength 
of the tubing, such as may happen when cutting threads. Brazed joints 
are not authorized for portable tanks intended for refrigerated 
liquefied gases.
    (6) The burst pressure of all piping and pipe fittings must be 
greater than the highest of four times the MAWP of the shell or four 
times the pressure to which it may be subjected in service by the action 
of a pump or other device (except pressure relief devices).
    (7) Ductile metals must be used in the construction of valves and 
accessories.
    (f) Pressure relief devices--(1) Marking of pressure relief devices. 
Every pressure relief device must be clearly and permanently marked with 
the following:
    (i) the pressure (in bar or kPa) or temperature for fusible elements 
(in [deg]C) at which it is set to discharge;
    (ii) the allowable tolerance at the discharge pressure for reclosing 
devices;
    (iii) the reference temperature corresponding to the rated pressure 
for frangible discs;
    (iv) the allowable temperature tolerance for fusible elements;
    (v) The rated flow capacity of the spring loaded pressure relief 
devices, frangible disc or fusible elements in standard cubic meters of 
air per second (m\3\/s). For spring loaded pressure relief devices, the 
rated flow capacity must be determined according to ISO 4126-1 
(including Technical Corrigendum 1) and ISO 4126-7 (IBR, see Sec.  171.7 
of this subchapter); and
    (vi) The cross sectional flow areas of the spring loaded pressure 
relief devices, frangible discs, and fusible elements in mm\2\; and
    (vii) When practicable, the device must show the manufacturer's name 
and product number.
    (2) Connections to pressure relief devices. Connections to pressure 
relief devices must be of sufficient size to enable the required 
discharge to pass unrestricted to the safety device. No stop-valve may 
be installed between the shell and the pressure relief devices except 
where duplicate devices are provided for maintenance or other reasons 
and the stop-valves serving the devices actually in use are locked open 
or the stop-valves are interlocked so that at least one of the devices 
is always in use. There must be no obstruction in an opening leading to 
a vent or pressure relief device which might restrict or cut-off the 
flow from the shell to that device. Vents or pipes from the pressure 
relief device outlets, when used, must deliver the relieved vapor or 
liquid to the atmosphere in conditions of minimum back-pressure on the 
relieving devices.
    (3) Location of pressure relief devices. (i) Each pressure relief 
device inlet must be situated on top of the shell in a position as near 
the longitudinal and transverse center of the shell as reasonably 
practicable. All pressure relief device inlets must, under maximum 
filling conditions, be situated in the vapor space of the shell and the 
devices must be so arranged as to ensure that any escaping vapor is not 
restricted in any manner. For flammable hazardous materials, the 
escaping vapor must be directed away from the shell in such a manner 
that it cannot impinge upon the shell. For refrigerated liquefied gases, 
the escaping vapor must be directed away from the tank and in such a 
manner that it cannot impinge upon the tank. Protective devices which 
deflect the flow of vapor are permissible provided the required relief-
device capacity is not reduced.
    (ii) Provisions must be implemented to prevent unauthorized persons 
from access to the pressure relief devices and to protect the devices 
from damage

[[Page 124]]

caused by the portable tank overturning.
    (g) Gauging devices. Unless a portable tank is intended to be filled 
by weight, it must be equipped with one or more gauging devices. Glass 
level-gauges and gauges made of other fragile material, which are in 
direct communication with the contents of the tank are prohibited. A 
connection for a vacuum gauge must be provided in the jacket of a 
vacuum-insulated portable tank.
    (h) Portable tank supports, frameworks, lifting and tie-down 
attachments. (1) Portable tanks must be designed and constructed with a 
support structure to provide a secure base during transport. The forces 
and safety factors specified in paragraphs (c)(1) and (c)(2) of this 
section, respectively, must be taken into account in this aspect of the 
design. Skids, frameworks, cradles or other similar structures are 
acceptable.
    (2) The combined stresses caused by portable tank mountings (for 
example, cradles, framework, etc.) and portable tank lifting and tie-
down attachments must not cause stress that would damage the shell in a 
manner that would compromise its lading retention capability. Permanent 
lifting and tie-down attachments must be fitted to all portable tanks. 
Preferably they should be fitted to the portable tank supports but may 
be secured to reinforcing plates located on the shell at the points of 
support. Each portable tank must be designed so that the center of 
gravity of the filled tank is approximately centered within the points 
of attachment for lifting devices.
    (3) In the design of supports and frameworks, the effects of 
environmental corrosion must be taken into account.
    (4) Forklift pockets must be capable of being closed off. The means 
of closing forklift pockets must be a permanent part of the framework or 
permanently attached to the framework. Single compartment portable tanks 
with a length less than 3.65 m (12 ft.) need not have forklift pockets 
that are capable of being closed off provided that:
    (i) The shell, including all the fittings, are well protected from 
being hit by the forklift blades; and
    (ii) The distance between forklift pockets (measured from the center 
of each pocket) is at least half of the maximum length of the portable 
tank.
    (5) During transport, portable tanks must be adequately protected 
against damage to the shell, and service equipment resulting from 
lateral and longitudinal impact and overturning, or the shell and 
service equipment must be constructed to withstand the forces resulting 
from impact or overturning. External fittings must be protected so as to 
preclude the release of the shell contents upon impact or overturning of 
the portable tank on its fittings. Examples of protection include:
    (i) Protection against lateral impact which may consist of 
longitudinal bars protecting the shell on both sides at the level of the 
median line;
    (ii) Protection of the portable tank against overturning which may 
consist of reinforcement rings or bars fixed across the frame;
    (iii) Protection against rear impact which may consist of a bumper 
or frame;
    (iv) Protection of the shell against damage from impact or 
overturning by use of an ISO frame in accordance with ISO 1496-3 (IBR, 
see Sec.  171.7 of this subchapter); and
    (v) Protection of the portable tank from impact or damage that may 
result from overturning by an insulation jacket.
    (i) Marking. (1) Every portable tank must be fitted with a corrosion 
resistant metal plate permanently attached to the portable tank in a 
conspicuous place and readily accessible for inspection. When the plate 
cannot be permanently attached to the shell, the shell must be marked 
with at least the information required by Section VIII of the ASME Code. 
At a minimum, the following information must be marked on the plate by 
stamping or by any other equivalent method:

Country of manufacture
U N
Approval Country
Approval Number
Alternative Arrangements (see Sec.  178.274(a)(2)) ``AA''
Manufacturer's name or mark
Manufacturer's serial number
Approval Agency (Authorized body for the design approval)

[[Page 125]]

Owner's registration number
Year of manufacture
Pressure vessel code to which the shell is designed
Test pressure________bar gauge.
MAWP________bar gauge.
External design pressure (not required for portable tanks used for 
refrigerated liquefied gases)________bar gauge.
Design temperature range________ [deg]C to________ [deg]C. (For portable 
tanks used for refrigerated liquefied gases, the minimum design 
temperature must be marked.)
Water capacity at 20 [deg]C/________liters.
Water capacity of each compartment at 20 [deg]C________liters.
Initial pressure test date and witness identification.
MAWP for heating/cooling system________bar gauge.
Shell material(s) and material standard reference(s).
Equivalent thickness in reference steel________mm.
Lining material (when applicable).
Date and type of most recent periodic test(s).
Month________Year________ Test pressure________bar gauge.
Stamp of approval agency that performed or witnessed the most recent 
test.

    For portable tanks used for refrigerated liquefied gases:

Either ``thermally insulated'' or ``vacuum insulated''________.
Effectiveness of the insulation system (heat influx)________Watts (W).
Reference holding time________days or hours and initial 
pressure________bar/kPa gauge and degree of filling________in kg for 
each refrigerated liquefied gas permitted for transportation.

    (2) The following information must be marked either on the portable 
tank itself or on a metal plate firmly secured to the portable tank:

Name of the operator.
Name of hazardous materials being transported and maximum mean bulk 
temperature (except for refrigerated liquefied gases, the name and 
temperature are only required when the maximum mean bulk temperature is 
higher than 50 [deg]C).
Maximum permissible gross mass (MPGM)________kg.
Unladen (tare) mass________kg.

    Note to paragraph (i)(2): For the identification of the hazardous 
materials being transported refer to part 172 of this subchapter.

    (3) If a portable tank is designed and approved for open seas 
operations, such as offshore oil exploration, in accordance with the 
IMDG Code, the words ``OFFSHORE PORTABLE TANK'' must be marked on the 
identification plate.
    (j) Initial inspection and test. The initial inspection and test of 
a portable tank must include the following:
    (1) A check of the design characteristics.
    (2) An internal and external examination of the portable tank and 
its fittings, taking into account the hazardous materials to be 
transported. For UN portable tanks used for refrigerated liquefied 
gases, a pressure test using an inert gas may be conducted instead of a 
hydrostatic test. An internal inspection is not required for a portable 
tank used for the dedicated transportation of refrigerated liquefied 
gases that are not filled with an inspection opening.
    (3) A pressure test as specified in paragraph (i) of this section.
    (4) A leakage test.
    (5) A test of the satisfactory operation of all service equipment 
including pressure relief devices must also be performed. When the shell 
and its fittings have been pressure-tested separately, they must be 
subjected to a leakage test after reassembly. All welds, subject to full 
stress level in the shell, must be inspected during the initial test by 
radiographic, ultrasonic, or another suitable non-destructive test 
method. This does not apply to the jacket.
    (6) Effective January 1, 2008, each new UN portable tank design type 
meeting the definition of ``container'' in the Convention for Safe 
Containers (CSC) (see 49 CFR 450.3(a)(2)) must be subjected to the 
dynamic longitudinal impact test prescribed in Part IV, Section 40 of 
the UN Manual of Tests and Criteria (see IBR, Sec.  171.7 of this 
subchapter). A UN portable tank design type impact-tested prior to 
January 1, 2008, in accordance with the requirements of this section in 
effect on October 1, 2005, need not be retested. UN portable tanks used 
for the dedicated transportation of ``Helium, refrigerated liquid,'' 
UN1963, and ``Hydrogen, refrigerated liquid,'' UN1966, that are marked 
``NOT FOR RAIL TRANSPORT'' in letters of a minimum height of 10 cm (4 
inches) on at least two sides of the portable tank are excepted from the 
dynamic longitudinal impact test.

[[Page 126]]

    (7) The following tests must be completed on a portable tank or a 
series of portable tanks designed and constructed to a single design 
type that is also a CSC container without leakage or deformation that 
would render the portable tank unsafe for transportation and use:
    (i) Longitudinal inertia. The portable tank loaded to its maximum 
gross weight must be positioned with its longitudinal axis vertical. It 
shall be held in this position for five minutes by support at the lower 
end of the base structure providing vertical and lateral restraint and 
by support at the upper end of the base structure providing lateral 
restraint only.
    (ii) Lateral inertia. The portable tank loaded to its maximum gross 
weight must be positioned for five minutes with its transverse axis 
vertical. It shall be held in this position for five minutes by support 
at the lower side of the base structure providing vertical and lateral 
restraint and by support at the upper side of the base structure 
providing lateral restraint only.

[66 FR 33440, June 21, 2001, as amended at 67 FR 15744, Apr. 3, 2002; 68 
FR 45041, July 31, 2003; 68 FR 57633, Oct. 6, 2003; 68 FR 75751, Dec. 
31, 2003; 69 FR 76185, Dec. 20, 2004; 70 FR 34399, June 14, 2005; 71 FR 
78634, Dec. 29, 2006; 72 FR 55696, Oct. 1, 2007; 73 FR 4719, Jan. 28, 
2008; 78 FR 1096, Jan. 7, 2013]

    Editorial Note: At 68 FR 57633, Oct. 6, 2003, Sec.  178.274 was 
amended in paragraph (b)(1); however, the amendment could not be 
incorporated due to inaccurate amendatory instruction.



Sec.  178.275  Specification for UN Portable Tanks intended for the 
transportation of liquid and solid hazardous materials.

    (a) In addition to the requirements of Sec.  178.274, this section 
sets forth definitions and requirements that apply to UN portable tanks 
intended for the transportation of liquid and solid hazardous materials.
    (b) Definitions and requirements--(1) Design pressure means the 
pressure to be used in calculations required by the recognized pressure 
vessel code. The design pressure must not be less than the highest of 
the following pressures:
    (i) The maximum effective gauge pressure allowed in the shell during 
filling or discharge; or
    (ii) The sum of--
    (A) The absolute vapor pressure (in bar) of the hazardous material 
at 65 [deg]C, minus 1 bar (149 [deg]F, minus 100 kPa);
    (B) The partial pressure (in bar) of air or other gases in the 
ullage space, resulting from their compression during filling without 
pressure relief by a maximum ullage temperature of 65 [deg]C (149 
[deg]F) and a liquid expansion due to an increase in mean bulk 
temperature of 35 [deg]C (95 [deg]F); and
    (C) A head pressure determined on the basis of the forces specified 
in Sec.  178.274(c) of this subchapter, but not less than 0.35 bar (35 
kPa).
    (2) Maximum allowable working pressure (MAWP) means a pressure that 
must not be less than the highest of the following pressures measured at 
the top of the shell while in operating position:
    (i) The maximum effective gauge pressure allowed in the shell during 
filling or discharge; or
    (ii) The maximum effective gauge pressure to which the shell is 
designed which must be not less than the design pressure.
    (c) Service equipment. (1) In addition to the requirements specified 
in Sec.  178.274, for service equipment, all openings in the shell, 
intended for filling or discharging the portable tank must be fitted 
with a manually operated stop-valve located as close to the shell as 
reasonably practicable. Other openings, except for openings leading to 
venting or pressure relief devices, must be equipped with either a stop-
valve or another suitable means of closure located as close to the shell 
as reasonably practicable.
    (2) All portable tanks must be fitted with a manhole or other 
inspection openings of a suitable size to allow for internal inspection 
and adequate access for maintenance and repair of the interior. 
Compartmented portable tanks must have a manhole or other inspection 
openings for each compartment.
    (3) For insulated portable tanks, top fittings must be surrounded by 
a spill collection reservoir with suitable drains.
    (4) Piping must be designed, constructed and installed to avoid the 
risk of damage due to thermal expansion

[[Page 127]]

and contraction, mechanical shock and vibration. All piping must be of a 
suitable metallic material. Welded pipe joints must be used wherever 
possible.
    (d) Bottom openings. (1) Certain hazardous materials may not be 
transported in portable tanks with bottom openings. When the applicable 
T code or portable tank special provision, as referenced for materials 
in the Sec.  172.101 Table of this subchapter, specifies that bottom 
openings are prohibited, there must be no openings below the liquid 
level of the shell when it is filled to its maximum permissible filling 
limit. When an existing opening is closed, it must be accomplished by 
internally and externally welding one plate to the shell.
    (2) Bottom discharge outlets for portable tanks carrying certain 
solid, crystallizable or highly viscous hazardous materials must be 
equipped with at least two serially fitted and mutually independent 
shut-off devices. Use of only two shut-off devices is only authorized 
when this paragraph is referenced in the applicable T Code indicated for 
each hazardous material in the Sec.  172.101 Table of this subchapter. 
The design of the equipment must be to the satisfaction of the approval 
agency and must include:
    (i) An external stop-valve fitted as close to the shell as 
reasonably practicable; and
    (ii) A liquid tight closure at the end of the discharge pipe, which 
may be a bolted blank flange or a screw cap.
    (3) Except as provided in paragraph (d)(2) of this section, every 
bottom discharge outlet must be equipped with three serially fitted and 
mutually independent shut-off devices. The design of the equipment must 
include:
    (i) A self-closing internal stop-valve, which is a stop-valve within 
the shell or within a welded flange or its companion flange, such that:
    (A) The control devices for the operation of the valve are designed 
to prevent any unintended opening through impact or other inadvertent 
act;
    (B) The valve is operable from above or below;
    (C) If possible, the setting of the valve (open or closed) must be 
capable of being verified from the ground;
    (D) Except for portable tanks having a capacity less than 1,000 
liters (264.2 gallons), it must be possible to close the valve from an 
accessible position on the portable tank that is remote from the valve 
itself within 30 seconds of actuation; and
    (E) The valve must continue to be effective in the event of damage 
to the external device for controlling the operation of the valve;
    (ii) An external stop-valve fitted as close to the shell as 
reasonably practicable;
    (iii) A liquid tight closure at the end of the discharge pipe, which 
may be a bolted blank flange or a screw cap; and
    (iv) For UN portable tanks, with bottom outlets, used for the 
transportation of liquid hazardous materials that are Class 3, PG I or 
II, or PG III with a flash point of less than 100 [deg]F (38 [deg]C); 
Division 5.1, PG I or II; or Division 6.1, PG I or II, the remote means 
of closure must be capable of thermal activation. The thermal means of 
activation must activate at a temperature of not more than 250 [deg]F 
(121 [deg]C).
    (e) Pressure relief devices. All portable tanks must be fitted with 
at least one pressure relief device. All relief devices must be 
designed, constructed and marked in accordance with the requirements of 
this subchapter.
    (f) Vacuum-relief devices. (1) A shell which is to be equipped with 
a vacuum-relief device must be designed to withstand, without permanent 
deformation, an external pressure of not less than 0.21 bar (21.0 kPa). 
The vacuum-relief device must be set to relieve at a vacuum setting not 
greater than -0.21 bar (-21.0 kPa) unless the shell is designed for a 
higher external over pressure, in which case the vacuum-relief pressure 
of the device to be fitted must not be greater than the tank design 
vacuum pressure. A shell that is not fitted with a vacuum-relief device 
must be designed to withstand, without permanent deformation, an 
external pressure of not less than 0.4 bar (40.0 kPa).
    (2) Vacuum-relief devices used on portable tanks intended for the 
transportation of hazardous materials meeting the criteria of Class 3, 
including elevated temperature hazardous materials transported at or 
above their

[[Page 128]]

flash point, must prevent the immediate passage of flame into the shell 
or the portable tank must have a shell capable of withstanding, without 
leakage, an internal explosion resulting from the passage of flame into 
the shell.
    (g) Pressure relief devices. (1) Each portable tank with a capacity 
not less than 1,900 liters (501.9 gallons) and every independent 
compartment of a portable tank with a similar capacity, must be provided 
with one or more pressure relief devices of the reclosing type. Such 
portable tanks may, in addition, have a frangible disc or fusible 
element in parallel with the reclosing devices, except when the 
applicable T code assigned to a hazardous material requires that the 
frangible disc precede the pressure relief device, according to 
paragraph (g)(3) of this section, or when no bottom openings are 
allowed. The pressure relief devices must have sufficient capacity to 
prevent rupture of the shell due to over pressurization or vacuum 
resulting from filling, discharging, heating of the contents or fire.
    (2) Pressure relief devices must be designed to prevent the entry of 
foreign matter, the leakage of liquid and the development of any 
dangerous excess pressure.
    (3) When required for certain hazardous materials by the applicable 
T code or portable tank special provision specified for a hazardous 
material in the Sec.  172.101 Table of this subchapter, portable tanks 
must have a pressure relief device consistent with the requirements of 
this subchapter. Except for a portable tank in dedicated service that is 
fitted with an approved relief device constructed of materials 
compatible with the hazardous material, the relief device system must 
include a frangible disc preceding (such as, between the lading and the 
reclosing pressure relief device) a reclosing pressure relief device. A 
pressure gauge or suitable tell-tale indicator for the detection of disc 
rupture, pin-holing or leakage must be provided in the space between the 
frangible disc and the pressure relief device to allow the portable tank 
operator to check to determine if the disc is leak free. The frangible 
disc must rupture at a nominal pressure 10% above the start-to-discharge 
pressure of the reclosable pressure relief device.
    (4) Every portable tank with a capacity less than 1,900 liters 
(501.9 gallons) must be fitted with a pressure relief device which, 
except as provided in paragraph (g)(3) of this section, may be a 
frangible disc when this disc is set to rupture at a nominal pressure 
equal to the test pressure at any temperature within the design 
temperature range.
    (5) When the shell is fitted for pressure discharge, a suitable 
pressure relief device must provide the inlet line to the portable tank 
and set to operate at a pressure not higher than the MAWP of the shell, 
and a stop-valve must be fitted as close to the shell as practicable to 
minimize the potential for damage.
    (6) Setting of pressure relief devices. (i) Pressure relief devices 
must operate only in conditions of excessive rise in temperature. The 
shell must not be subject to undue fluctuations of pressure during 
normal conditions of transportation.
    (ii) The required pressure relief device must be set to start to 
discharge at a nominal pressure of five-sixths of the test pressure for 
shells having a test pressure of not more than 4.5 bar (450 kPa) and 
110% of two-thirds of the test pressure for shells having a test 
pressure of more than 4.5 bar (450 kPa). A self-closing relief device 
must close at a pressure not more than 10% below the pressure at which 
the discharge starts. The device must remain closed at all lower 
pressures. This requirement does not prevent the use of vacuum-relief or 
combination pressure relief and vacuum-relief devices.
    (h) Fusible elements. Fusible elements must operate at a temperature 
between 110 [deg]C (230 [deg]F) and 149 [deg]C (300.2 [deg]F), provided 
that the pressure in the shell at the fusing temperature will not exceed 
the test pressure. They must be placed at the top of the shell with 
their inlets in the vapor space and in no case may they be shielded from 
external heat. Fusible elements must not be utilized on portable tanks 
with a test pressure which exceeds 2.65 bar (265.0 kPa); however, 
fusible elements are authorized

[[Page 129]]

on portable tanks for the transportation of certain organometallic 
materials in accordance with Sec.  172.102, special provision TP36 of 
this subchapter. Fusible elements used on portable tanks intended for 
the transport of elevated temperature hazardous materials must be 
designed to operate at a temperature higher than the maximum temperature 
that will be experienced during transport and must be designed to the 
satisfaction of the approval agency.
    (i) Capacity of pressure relief devices. (1) The reclosing pressure 
relief device required by paragraph (g)(1) of this section must have a 
minimum cross sectional flow area equivalent to an orifice of 31.75 mm 
(1.3 inches) diameter. Vacuum-relief devices, when used, must have a 
cross sectional flow area not less than 284 mm \2\ (11.2 inches \2\).
    (2) The combined delivery capacity of the pressure relief system 
(taking into account the reduction of the flow when the portable tank is 
fitted with frangible-discs preceding spring-loaded pressure-relief 
devices or when the spring-loaded pressure-relief devices are provided 
with a device to prevent the passage of the flame), in condition of 
complete fire engulfment of the portable tank must be sufficient to 
limit the pressure in the shell to 20% above the start to discharge 
pressure limiting device (pressure relief device). The total required 
capacity of the relief devices may be determined using the formula in 
paragraph (i)(2)(i)(A) of this section or the table in paragraph 
(i)(2)(iii) of this section.
    (i)(A) To determine the total required capacity of the relief 
devices, which must be regarded as being the sum of the individual 
capacities of all the contributing devices, the following formula must 
be used:
[GRAPHIC] [TIFF OMITTED] TR26JY22.153

Where:

Q = minimum required rate of discharge in cubic meters of air per second 
          (\m\\3\/s) at conditions: 1 bar and 0 [deg]C (273 
          [deg]K);
F = for uninsulated shells: 1; for insulated shells: U(649-t)/13.6 but 
          in no case, is less than 0.25

Where:

U = heat transfer coefficient of the insulation, in kW 
          m-2K-1, at 38 [deg]C (100 [deg]F); and t 
          = actual temperature of the hazardous material during filling 
          (in [deg]C) or when this temperature is unknown, let t = 15 
          [deg]C (59 [deg]F). The value of F given in this paragraph 
          (i)(2)(i)(A) for insulated shells may only be used if the 
          insulation is in conformance with paragraph (i)(2)(iv) of this 
          section;
A = total external surface area of shell in square meters;
Z = the gas compressibility factor in the accumulating condition (when 
          this factor is unknown, let Z equal 1.0);
T = absolute temperature in Kelvin ( [deg]C + 273) above the pressure 
          relief devices in the accumulating condition;
L = the latent heat of vaporization of the liquid, in kJ/kg, in the 
          accumulating condition;
M = molecular weight of the hazardous material.
    (B) The constant C, as shown in the formula in paragraph 
(i)(2)(i)(A) of this section, is derived from one of the following 
formulas as a function of the ratio k of specific heats:
[GRAPHIC] [TIFF OMITTED] TR01OC08.001

Where:

cp is the specific heat at constant pressure; and
cv is the specific heat at constant volume.

    (C) When k 1:
    [GRAPHIC] [TIFF OMITTED] TR01OC08.002
    
    (D) When k = 1 or k is unknown, a value of 0.607 may be used for the 
constant C. C may also be taken from the following table:

[[Page 130]]



                         C Constant Value Table
------------------------------------------------------------------------
                 k                                    C
------------------------------------------------------------------------
                   1.00                                0.607
                   1.02                                0.611
                   1.04                                0.615
                   1.06                                0.620
                   1.08                                0.624
                   1.10                                0.628
                   1.12                                0.633
                   1.14                                0.637
                   1.16                                0.641
                   1.18                                0.645
                   1.20                                0.649
                   1.22                                0.652
                   1.24                                0.656
                   1.26                                0.660
                   1.28                                0.664
                   1.30                                0.667
                   1.32                                0.671
                   1.34                                0.674
                   1.36                                0.678
                   1.38                                0.681
                   1.40                                0.685
                   1.42                                0.688
                   1.44                                0.691
                   1.46                                0.695
                   1.48                                0.698
                   1.50                                0.701
                   1.52                                0.704
                   1.54                                0.707
                   1.56                                0.710
                   1.58                                0.713
                   1.60                                0.716
                   1.62                                0.719
                   1.64                                0.722
                   1.66                                0.725
                   1.68                                0.728
                   1.70                                0.731
                   2.00                                0.770
                   2.20                                0.793
 
------------------------------------------------------------------------

    (ii) As an alternative to the formula in paragraph (i)(2)(i)(A) of 
this section, relief devices for shells used for transporting liquids 
may be sized in accordance with the table in paragraph (i)(2)(iii) of 
this section. The table in paragraph (i)(2)(iii) of this section assumes 
an insulation value of F = 1 and must be adjusted accordingly when the 
shell is insulated. Other values used in determining the table in 
paragraph (i)(2)(iii) of this section are: L = 334.94 kJ/kg; M = 86.7; T 
= 394 [deg]K; Z = 1; and C = 0.607.
    (iii) Minimum emergency vent capacity, Q, in cubic meters of air per 
second at 1 bar and 0 [deg]C (273 [deg]K) shown in the following table:

                     Minimum Emergency Vent Capacity
                               [Q Values]
------------------------------------------------------------------------
                    Q (Cubic meters                      Q (Cubic meters
  A Exposed area       of air per      A Exposed area      of air per
 (square meters)        second)        (square meters)       second)
------------------------------------------------------------------------
          2              0.230               37.5             2.539
          3              0.320                 40             2.677
          4              0.405               42.5             2.814
          5              0.487                 45             2.949
          6              0.565               47.5             3.082
          7              0.641                 50             3.215
          8              0.715               52.5             3.346
          9              0.788                 55             3.476
         10              0.859               57.5             3.605
         12              0.998                 60             3.733
         14              1.132               62.5             3.860
         16              1.263                 65             3.987
         18              1.391               67.5             4.112
         20              1.517                 70             4.236
       22.5              1.670                 75             4.483
         25              1.821                 80             4.726
       27.5              1.969                 85             4.967
         30              2.115                 90             5.206
       32.5              2.258                 95             5.442
         35              2.400                100             5.676
------------------------------------------------------------------------

    (iv) Insulation systems, used for the purpose of reducing venting 
capacity, must be specifically approved by the approval agency. In all 
cases, insulation systems approved for this purpose must--
    (A) Remain effective at all temperatures up to 649 [deg]C (1200 
[deg]F); and
    (B) Be jacketed with a material having a melting point of 700 [deg]C 
(1292 [deg]F) or greater.
    (j) Approval, inspection and testing. Approval procedures for UN 
portable tanks are specified in Sec.  178.273. Inspection and testing 
requirements are specified in Sec.  180.605 of this subchapter.

[66 FR 33445, June 21, 2001, as amended at 68 FR 32414, May 30, 2003; 69 
FR 76185, Dec. 20, 2004; 73 FR 57006, Oct. 1, 2008; 76 FR 3388, Jan. 19, 
2011; 87 FR 44999, July 26, 2022]



Sec.  178.276  Requirements for the design, construction, inspection and   
testing of portable tanks intended for the transportation of non-refrigerated  
liquefied compressed gases.

    (a) In addition to the requirements of Sec.  178.274 applicable to 
UN portable tanks, the following requirements apply to UN portable tanks 
used for non-refrigerated liquefied compressed gases. In addition to the 
definitions in Sec.  178.274, the following definitions apply:
    (1) Design pressure means the pressure to be used in calculations 
required by the ASME Code, Section VIII (IBR, see

[[Page 131]]

Sec.  171.7 of this subchapter). The design pressure must be not less 
than the highest of the following pressures:
    (i) The maximum effective gauge pressure allowed in the shell during 
filling or discharge; or
    (ii) The sum of:
    (A) The maximum effective gauge pressure to which the shell is 
designed as defined in this paragraph under ``MAWP''; and
    (B) A head pressure determined on the basis of the dynamic forces 
specified in paragraph (h) of this section, but not less than 0.35 bar 
(35 kPa).
    (2) Design reference temperature means the temperature at which the 
vapor pressure of the contents is determined for the purpose of 
calculating the MAWP. The value for each portable tank type is as 
follows:
    (i) Shell with a diameter of 1.5 meters (4.9 ft.) or less: 65 [deg]C 
(149 [deg]F); or
    (ii) Shell with a diameter of more than 1.5 meters (4.9 ft.):
    (A) Without insulation or sun shield: 60 [deg]C (140 [deg]F);
    (B) With sun shield: 55 [deg]C (131 [deg]F); and
    (C) With insulation: 50 [deg]C (122 [deg]F).
    (3) Filling density means the average mass of liquefied compressed 
gas per liter of shell capacity (kg/l).
    (4) Maximum allowable working pressure (MAWP) means a pressure that 
must be not less than the highest of the following pressures measured at 
the top of the shell while in operating position, but in no case less 
than 7 bar (700 kPa):
    (i) The maximum effective gauge pressure allowed in the shell during 
filling or discharge; or
    (ii) The maximum effective gauge pressure to which the shell is 
designed, which must be:
    (A) Not less than the pressure specified for each liquefied 
compressed gas listed in the UN Portable Tank Table for Liquefied 
Compressed Gases in Sec.  173.313; and
    (B) Not less than the sum of:
    (1) The absolute vapor pressure (in bar) of the liquefied compressed 
gas at the design reference temperature minus 1 bar; and
    (2) The partial pressure (in bar) of air or other gases in the 
ullage space which is determined by the design reference temperature and 
the liquid phase expansion due to the increase of the mean bulk 
temperature of tr-tf (tf = filling 
temperature, usually 15 [deg]C, tr = 50 [deg]C maximum mean 
bulk temperature).
    (b) General design and construction requirements. (1) Shells must be 
of seamless or welded steel construction, or combination of both, and 
have a water capacity greater than 450 liters (118.9 gallons). Shells 
must be designed, constructed, certified and stamped in accordance with 
the ASME Code, Section VIII.
    (2) Portable tanks must be postweld heat-treated and radiographed as 
prescribed in Section VIII of the ASME Code, except that each portable 
tank constructed in accordance with part UHT of the ASME Code must be 
postweld heat-treated. Where postweld heat treatment is required, the 
portable tank must be treated as a unit after completion of all the 
welds in and/or to the shell and heads. The method must be as prescribed 
in the ASME Code. Welded attachments to pads may be made after postweld 
heat treatment is made. A portable tank used for anhydrous ammonia must 
be postweld heat-treated. The postweld heat treatment must be as 
prescribed in the ASME Code, but in no event at less than 1050 [deg]F 
tank metal temperature. Additionally, portable tanks constructed in 
accordance with part UHT of the ASME Code must conform to the following 
requirements:
    (i) Welding procedure and welder performance tests must be made 
annually in accordance with Section IX of the ASME Code. In addition to 
the essential variables named therein, the following must be considered 
to be essential variables: number of passes, thickness of plate, heat 
input per pass, and manufacturer's identification of rod and flux. The 
number of passes, thickness of plate and heat input per pass may not 
vary more than 25 percent from the qualified procedure. Records of the 
qualification must be retained for at least 5 years by the portable tank 
manufacturer or his designated agent and, upon request, made available 
to a representative of the Department of Transportation or the owner of 
the tank.

[[Page 132]]

    (ii) Impact tests must be made on a lot basis. A lot is defined as 
100 tons or less of the same heat and having a thickness variation no 
greater than plus or minus 25 percent. The minimum impact required for 
full-sized specimens shall be 20 foot-pounds (or 10 foot-pounds for 
half-sized specimens) at 0 [deg]F (-17.8 [deg]F) Charpy V-Notch in both 
the longitudinal and transverse direction. If the lot test does not pass 
this requirement, individual plates may be accepted if they individually 
meet this impact requirement.
    (3) When the shells intended for the transportation of non-
refrigerated liquefied compressed gases are equipped with thermal 
insulation, a device must be provided to prevent any dangerous pressure 
from developing in the insulating layer in the event of a leak, when the 
protective covering is closed it must be gas tight. The thermal 
insulation must not inhibit access to the fittings and discharge 
devices. In addition, the thermal insulation systems must satisfy the 
following requirements:
    (i) consist of a shield covering not less than the upper third, but 
not more than the upper half of the surface of the shell, and separated 
from the shell by an air space of approximately 40 mm (1.7 inches) 
across; or
    (ii) consist of a complete cladding of insulating materials. The 
insulation must be of adequate thickness and constructed to prevent the 
ingress of moisture and damage to the insulation. The insulation and 
cladding must have a thermal conductance of not more than 0.67 
(W[middot]m-2[middot]K-1) under normal conditions 
of transportation.
    (c) Service equipment. (1) Each opening with a diameter of more than 
1.5 mm (0.1 inch) in the shell of a portable tank, except openings for 
pressure-relief devices, inspection openings and closed bleed holes, 
must be fitted with at least three mutually independent shut-off devices 
in series: the first being an internal stop-valve, excess flow valve, 
integral excess flow valve, or excess flow feature (see Sec.  178.337-
1(g)), the second being an external stop-valve and the third being a 
blank flange, thread cap, plug or equivalent tight liquid closure 
device.
    (2) When a portable tank is fitted with an excess flow valve, the 
excess flow valve must be so fitted that its seating is inside the shell 
or inside a welded flange or, when fitted externally, its mountings must 
be designed so that in the event of impact it maintains its 
effectiveness. The excess flow valves must be selected and fitted so as 
to close automatically when the rated flow, specified by the 
manufacturer, is reached. Connections and accessories leading to or from 
such a valve must have a capacity for a flow more than the excess flow 
valve's rated flow.
    (3) For filling and discharge openings that are located below the 
liquid level, the first shut-off device must be an internal stop-valve 
and the second must be a stop-valve placed in an accessible position on 
each discharge and filling pipe.
    (4) For filling and discharge openings located below the liquid 
level of portable tanks intended for the transportation of flammable 
and/or toxic liquefied compressed gases, the internal stop-valve must be 
a self-closing safety device that fully closes automatically during 
filling or discharge in the event of fire engulfment. The device shall 
fully close within 30 seconds of actuation and the thermal means of 
closure must actuate at a temperature of not more than 121 [deg]C (250 
[deg]F). Except for portable tanks having a capacity less than 1,000 
liters (264.2 gallons), this device must be operable by remote control.
    (5) In addition to filling, discharge and gas pressure equalizing 
orifices, shells may have openings in which gauges, thermometers and 
manometers can be fitted. Connections for such instruments must be made 
by suitable welded nozzles or pockets and may not be connected by 
screwed connections through the shell.
    (6) All portable tanks must be fitted with manholes or other 
inspection openings of suitable size to allow for internal inspection 
and adequate access for maintenance and repair of the interior.
    (7) Inlets and discharge outlets on chlorine portable tanks. The 
inlet and discharge outlets on portable tanks used to transport chlorine 
must meet the requirements of Sec.  178.337-1(c)(2) and must

[[Page 133]]

be fitted with an internal excess flow valve. In addition to the 
internal excess flow valve, the inlet and discharge outlets must be 
equipped with an external stop valve (angle valve). Excess flow valves 
must conform to the standards of The Chlorine Institute, Inc. (IBR, see 
Sec.  171.7 of this subchapter) as follows:
    (i) A valve conforming to Drawing 101-7, dated July 1993, must be 
installed under each liquid angle valve.
    (ii) A valve conforming to Drawing 106-6, dated July 1993, must be 
installed under each gas angle valve. For portable tanks used to 
transport non-refrigerated liquefied gases.
    (8) External fittings must be grouped together as close as 
reasonably practicable. The following openings may be installed at 
locations other than on the top or end of the tank:
    (i) The openings for liquid level gauging devices, pressure gauges, 
or for safety devices, may be installed separately at the other location 
or in the side of the shell;
    (ii) One plugged opening of 2-inch National Pipe Thread or less 
provided for maintenance purposes may be located elsewhere;
    (iii) An opening of 3-inch National Pipe Size or less may be 
provided at another location, when necessary, to facilitate installation 
of condensing coils.
    (9) Filling and discharge connections are not required to be grouped 
and may be installed below the normal liquid level of the tank if:
    (i) The portable tank is permanently mounted in a full framework for 
containerized transport;
    (ii) For each portable tank design, a prototype portable tank, meets 
the requirements of parts 450 through 453 of this title for compliance 
with the requirements of Annex II of the International Convention for 
Safe Containers; and
    (iii) Each filling and discharge outlet meets the requirements of 
paragraph (c)(4) of this section.
    (d) Bottom openings. Bottom openings are prohibited on portable 
tanks when the UN Portable Tank Table for Liquefied Compressed Gases in 
Sec.  173.313 of this subchapter indicates that bottom openings are not 
allowed. In this case, there may be no openings located below the liquid 
level of the shell when it is filled to its maximum permissible filling 
limit.
    (e) Pressure relief devices. (1) Portable tanks must be provided 
with one or more reclosing pressure relief devices. The pressure relief 
devices must open automatically at a pressure not less than the MAWP and 
be fully open at a pressure equal to 110% of the MAWP. These devices 
must, after discharge, close at a pressure not less than 10% below the 
pressure at which discharge starts and must remain closed at all lower 
pressures. The pressure relief devices must be of a type that will 
resist dynamic forces including liquid surge. A frangible disc may only 
be used in series with a reclosing pressure relief device.
    (2) Pressure relief devices must be designed to prevent the entry of 
foreign matter, the leakage of gas and the development of any dangerous 
excess pressure.
    (3) A portable tank intended for the transportation of certain 
liquefied compressed gases identified in the UN Portable Tank Table for 
Liquefied Compressed Gases in Sec.  173.313 of this subchapter must have 
a pressure relief device which conforms to the requirements of this 
subchapter. Unless a portable tank, in dedicated service, is fitted with 
a relief device constructed of materials compatible with the hazardous 
material, the relief device must be comprised of a frangible disc 
preceded by a reclosing device. The space between the frangible disc and 
the device must be provided with a pressure gauge or a suitable tell-
tale indicator. This arrangement must facilitate the detection of disc 
rupture, pinholing or leakage which could cause a malfunction of the 
pressure relief device. The frangible disc must rupture at a nominal 
pressure 10% above the start-to-discharge pressure of the relief device.
    (4) In the case of portable tanks used for more than one gas, the 
pressure relief devices must open at a pressure indicated in paragraph 
(e)(1) of this section for the gas having the highest maximum allowable 
pressure of the gases allowed to be transported in the portable tank.

[[Page 134]]

    (f) Capacity of relief devices. The combined delivery capacity of 
the relief devices must be sufficient so that, in the event of total 
fire engulfment, the pressure inside the shell cannot exceed 120% of the 
MAWP. Reclosing relief devices must be used to achieve the full relief 
capacity prescribed. In the case of portable tanks used for more than 
gas, the combined delivery capacity of the pressure relief devices must 
be taken for the liquefied compressed gas which requires the highest 
delivery capacity of the liquefied compressed gases allowed to be 
transported in the portable tank. The total required capacity of the 
relief devices must be determined according to the requirements in Sec.  
178.275(i). These requirements apply only to liquefied compressed gases 
which have critical temperatures well above the temperature at the 
accumulating condition. For gases that have critical temperatures near 
or below the temperature at the accumulating condition, the calculation 
of the pressure relief device delivery capacity must consider the 
additional thermodynamic properties of the gas, for example see CGA S-
1.2 (IBR, see Sec.  171.7 of this subchapter).

[66 FR 33448, June 21, 2001, as amended at 68 FR 75748, 75752, Dec. 31, 
2003; 69 FR 54046, Sept. 7, 2004; 69 FR 76185, Dec. 20, 2004]



Sec.  178.277  Requirements for the design, construction, inspection and 
testing of portable tanks intended for the transportation of refrigerated 
liquefied gases.

    (a) In addition to the requirements of Sec.  178.274 applicable to 
UN portable tanks, the following requirements and definitions apply to 
UN portable tanks used for refrigerated liquefied gases:
    Design pressure For the purpose of this section the term ``design 
pressure'' is consistent with the definition for design pressure in the 
ASME Code, Section VIII (IBR, see Sec.  171.7 of this subchapter).
    Holding time is the time, as determined by testing, that will elapse 
from loading until the pressure of the contents, under equilibrium 
conditions, reaches the lowest set pressure of the pressure limiting 
device(s) (for example, pressure control valve or pressure relief 
device). Holding time must be determined as specified in Sec.  178.338-
9.
    Maximum allowable working pressure (MAWP) means the maximum 
effective gauge pressure permissible at the top of the shell of a loaded 
portable tank in its operating position including the highest effective 
pressure during filling and discharge;
    Minimum design temperature means the temperature which is used for 
the design and construction of the shell not higher than the lowest 
(coldest) service temperature of the contents during normal conditions 
of filling, discharge and transportation.
    Shell means the part of the portable tank which retains the 
refrigerated liquefied gas intended for transport, including openings 
and their closures, but does not include service equipment or external 
structural equipment.
    Tank means a construction which normally consists of either:
    (1) A jacket and one or more inner shells where the space between 
the shell(s) and the jacket is exhausted of air (vacuum insulation) and 
may incorporate a thermal insulation system; or
    (2) A jacket and an inner shell with an intermediate layer of solid 
thermally insulating material (for example, solid foam).
    (b) General design and construction requirements. (1) Portable tanks 
must be of seamless or welded steel construction and have a water 
capacity of more than 450 liters (118.9 gallons). Portable tanks must be 
designed, constructed, certified and stamped in accordance with Section 
VIII of the ASME Code.
    (2) Portable tanks must be postweld heat treated and radiographed as 
prescribed in Sections V and VIII of the ASME Code except that each tank 
constructed in accordance with part UHT in Section VIII of the ASME Code 
must be postweld heat treated. Where postweld heat treatment is 
required, the tank must be treated as a unit after completion of all the 
welds to the shell and heads. The method must be as prescribed in the 
ASME Code. Welded attachments to pads may be made after postweld heat 
treatment is made. The postweld heat treatment must be as prescribed in 
Section VIII of the ASME Code, but in no event at less than 1,050 [deg]F 
tank metal temperature.

[[Page 135]]

    (3) Welding procedure and welder performance tests must be made 
annually in accordance with Section IX of the ASME Code (IBR, see Sec.  
171.7 of this subchapter). In addition to the essential variables named 
in the ASME Code, the following must be considered as essential 
variables: number of passes, thickness of plate, heat input per pass, 
and the specified rod and flux. The number of passes, thickness of plate 
and heat input per pass may not vary more than 25% from the procedure 
qualification. Records of the qualification must be retained for at 
least 5 years by the portable tank manufacturer and made available to 
the approval agency and the owner of the portable tank as specified in 
Sec.  178.273.
    (4) Shells and jackets must be made of metallic materials suitable 
for forming. Jackets must be made of steel. Non-metallic materials may 
be used for the attachments and supports between the shell and jacket, 
provided their material properties at the minimum design temperature are 
proven to be sufficient. In choosing the material, the minimum design 
temperature must be taken into account with respect to risk of brittle 
fracture, to hydrogen embrittlement, to stress corrosion cracking and to 
resistance to impact.
    (5) Any part of a portable tank, including fittings, gaskets and 
pipe-work, which can be expected normally to come into contact with the 
refrigerated liquefied gas transported must be compatible with that 
refrigerated liquefied gas.
    (6) The thermal insulation system must include a complete covering 
of the shell with effective insulating materials. External insulation 
must be protected by a jacket so as to prevent the ingress of moisture 
and other damage under normal transport conditions.
    (7) When a jacket is so closed as to be gas-tight, a device must be 
provided to prevent any dangerous pressure from developing in the 
insulation space.
    (8) Materials which may react with oxygen or oxygen enriched 
atmospheres in a dangerous manner may not be used in portable tanks 
intended for the transport of refrigerated liquefied gases having a 
boiling point below minus 182 [deg]C at atmospheric pressure in 
locations with the thermal insulation where there is a risk of contact 
with oxygen or with oxygen enriched fluid.
    (9) Insulating materials must not deteriorate to an extent that the 
effectiveness of the insulation system, as determined in accordance with 
paragraph (b)(11) of this section, would be reduced in service.
    (10) A reference holding time must be determined for each 
refrigerated liquefied gas intended for transport in a portable tank. 
The reference holding time must be determined by testing in accordance 
with the requirements of Sec.  178.338-9, considering the following 
factors:
    (i) The effectiveness of the insulation system, determined in 
accordance with paragraph (b)(11) of this section;
    (ii) The lowest set pressure of the pressure limiting device;
    (iii) The initial filling conditions;
    (iv) An assumed ambient temperature of 30 [deg]C (86 [deg]F);
    (v) The physical properties of the individual refrigerated liquefied 
gas intended to be transported.
    (11) The effectiveness of the insulation system (heat influx in 
watts) may be determined by type testing the portable tank in accordance 
with a procedure specified in Sec.  178.338-9(c) or by using the holding 
time test in Sec.  178.338-9(b). This test must consist of either:
    (i) A constant pressure test (for example, at atmospheric pressure) 
when the loss of refrigerated liquefied gas is measured over a period of 
time; or
    (ii) A closed system test when the rise in pressure in the shell is 
measured over a period of time.
    (12) When performing the constant pressure test, variations in 
atmospheric pressure must be taken into account. When performing either 
test, corrections must be made for any variation of the ambient 
temperature from the assumed ambient temperature reference value of 30 
[deg]C (86 [deg]F).
    (13) The jacket of a vacuum-insulated double-wall tank must have 
either an external design pressure not less than 100 kPa (1 bar) gauge 
pressure calculated in accordance with Section VIII of the ASME Code or 
a calculated critical collapsing pressure of not less

[[Page 136]]

than 200 kPa (2 bar) gauge pressure. Internal and external 
reinforcements may be included in calculating the ability of the jacket 
to resist the external pressure.

    Note to paragraph (b): For the determination of the actual holding 
time, as indicated by paragraphs (b)(10), (11), (12), and (13), before 
each journey, refer to Sec.  178.338-9(b).

    (c) Design criteria. For shells with vacuum insulation, the test 
pressure must not be less than 1.3 times the sum of the MAWP and 100 kPa 
(1 bar). In no case may the test pressure be less than 300 kPa (3 bar) 
gauge pressure.
    (d) Service equipment. (1) Each filling and discharge opening in 
portable tanks used for the transport of flammable refrigerated 
liquefied gases must be fitted with at least three mutually independent 
shut-off devices in series: the first being a stop-valve situated as 
close as reasonably practicable to the jacket, the second being a stop-
valve and the third being a blank flange or equivalent device. The shut-
off device closest to the jacket must be a self-closing device, which is 
capable of being closed from an accessible position on the portable tank 
that is remote from the valve within 30 seconds of actuation. This 
device must actuate at a temperature of not more than 121 [deg]C (250 
[deg]F).
    (2) Each filling and discharge opening in portable tanks used for 
the transport of non-flammable refrigerated liquefied gases must be 
fitted with at least two mutually independent shut-off devices in 
series: the first being a stop-valve situated as close as reasonably 
practicable to the jacket and the second a blank flange or equivalent 
device.
    (3) For sections of piping which can be closed at both ends and 
where liquid product can be trapped, a method of automatic pressure 
relief must be provided to prevent excess pressure build-up within the 
piping.
    (4) Each filling and discharge opening on a portable tank must be 
clearly marked to indicate its function.
    (5) When pressure-building units are used, the liquid and vapor 
connections to that unit must be provided with a valve as close to the 
jacket as reasonably practicable to prevent the loss of contents in case 
of damage to the pressure-building unit. A check valve may be used for 
this purpose if it is located on the vapor side of the pressure build-up 
coil.
    (6) The materials of construction of valves and accessories must 
have satisfactory properties at the lowest operating temperature of the 
portable tank.
    (7) Vacuum insulated portable tanks are not required to have an 
inspection opening.
    (e) Pressure relief devices. (1) Every shell must be provided with 
not less than two independent reclosing pressure relief devices. The 
pressure relief devices must open automatically at a pressure not less 
than the MAWP and be fully open at a pressure equal to 110% of the MAWP. 
These devices must, after discharge, close at a pressure not lower than 
10% below the pressure at which discharge starts and must remain closed 
at all lower pressures. The pressure relief devices must be of the type 
that will resist dynamic forces including surge.
    (2) Except for portable tanks used for oxygen, portable tanks for 
non-flammable refrigerated liquefied gases (except oxygen) and hydrogen 
may in addition have frangible discs in parallel with the reclosing 
devices as specified in paragraphs (e)(4)(ii) and (e)(4)(iii) of this 
section.
    (3) Pressure relief devices must be designed to prevent the entry of 
foreign matter, the leakage of gas and the development of any dangerous 
excess pressure.
    (4) Capacity and setting of pressure relief devices. (i) In the case 
of the loss of vacuum in a vacuum-insulated tank or of loss of 20% of 
the insulation of a portable tank insulated with solid materials, the 
combined capacity of all pressure relief devices installed must be 
sufficient so that the pressure (including accumulation) inside the 
shell does not exceed 120% of the MAWP.
    (ii) For non-flammable refrigerated liquefied gases (except oxygen) 
and hydrogen, this capacity may be achieved by the use of frangible 
discs in parallel with the required safety-relief devices. Frangible 
discs must rupture at nominal pressure equal to the test pressure of the 
shell.

[[Page 137]]

    (iii) Under the circumstances described in paragraphs (e)(4)(i) and 
(e)(4)(ii) of this section, together with complete fire engulfment, the 
combined capacity of all pressure relief devices installed must be 
sufficient to limit the pressure in the shell to the test pressure.
    (iv) The required capacity of the relief devices must be calculated 
in accordance with CGA Pamphlet S-1.2 (IBR, see Sec.  171.7 of this 
subchapter).

[66 FR 33450, June 21, 2001, as amended at 68 FR 75748, 75752, Dec. 31, 
2003]

Subpart I [Reserved]



Subpart J_Specifications for Containers for Motor Vehicle Transportation

    Source: 29 FR 18975, Dec. 29, 1964, unless otherwise noted. 
Redesignated at 32 FR 5606, Apr. 5, 1967.



Sec.  178.318  Specification MC 201; container for detonators and 
percussion caps.



Sec.  178.318-1  Scope.

    (a) This specification pertains to a container to be used for the 
transportation of detonators and percussion caps in connection with the 
transportation of liquid nitroglycerin, desensitized liquid 
nitroglycerin or diethylene glycol dinitrate, where any or all of such 
types of caps may be used for the detonation of liquid nitroglycerin, 
desentitized liquid nitroglycerin or diethylene glycol dinitrate in 
blasting operations. This specification is not intended to take the 
place of any shipping or packing requirements of this Department where 
the caps in question are themselves articles of commerce.
    (b) [Reserved]

[29 FR 18975, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 178-60, 44 FR 70733, Dec. 10, 1979]



Sec.  178.318-2  Container.

    (a) Every container for detonators and percussion caps coming within 
the scope of this specification shall be constructed entirely of hard 
rubber, phenolresinous or other resinous material, or other nonmetallic, 
nonsparking material, except that metal parts may be used in such 
locations as not in any event to come in contact with any of the caps. 
Space shall be provided so that each detonator of whatever nature may be 
inserted in an individual cell in the body of the container, into which 
each such cap shall snugly fit. There shall be provided no more than 
twenty (20) such cellular spaces. Space may be provided into which a 
plurality of percussion caps may be carried, provided that such space 
may be closed with a screw cap, and further provided that each or any 
such space is entirely separate from any space provided for any 
detonator. Each cellular space into which a detonator is to be inserted 
and carried shall be capable of being covered by a rotary cover so 
arranged as to expose not more than one cell at any time, and capable of 
rotation to such a place that all cells will be covered at the same 
time, at which place means shall be provided to lock the cover in place. 
Means shall be provided to lock in place the cover for the cells 
provided for the carrying of detonators. The requirement that not more 
than one cell be exposed at one time need not apply in the case of 
detonators, although spaces for such caps and detonators shall be 
separate. Sufficient annular space shall be provided inside the cover 
for such detonators that, when the cover is closed, there will be 
sufficient space to accommodate the wires customarily attached to such 
caps. If the material is of such a nature as to require treatment to 
prevent the absorption of moisture, such treatment shall be applied as 
shall be necessary in order to provide against the penetration of water 
by permeation. A suitable carrying handle shall be provided, except for 
which handle no part of the container may project beyond the exterior of 
the body.
    (b) Exhibited in plates I and II are line drawings of a container 
for detonators and percussion caps, illustrative of the requirements set 
forth in Sec.  178.318-2(a). These plates shall not be construed as a 
part of this specification.

[[Page 138]]

[GRAPHIC] [TIFF OMITTED] TC02MR91.076



Sec.  178.318-3  Marking.

    Each container must be marked as prescribed in Sec.  178.2(b).

[Amdt. 178-40, 41 FR 38181, Sept. 9, 1976, as amended at 66 FR 45185, 
Aug. 28, 2001]



Sec.  178.320  General requirements applicable to all DOT specification 
cargo tank motor vehicles.

    (a) Definitions. For the purpose of this subchapter:
    Appurtenance means any attachment to a cargo tank that has no lading 
retention or containment function and provides no structural support to 
the cargo tank.
    Baffle means a non-liquid-tight transverse partition device that 
deflects, checks or regulates fluid motion in a tank.
    Bulkhead means a liquid-tight transverse closure at the ends of or 
between cargo tanks.
    Cargo tank means a bulk packaging that:
    (1) Is a tank intended primarily for the carriage of liquids, gases, 
solids, or

[[Page 139]]

semi-solids and includes appurtenances, reinforcements, fittings, and 
closures (for tank, see Sec. Sec.  178.337-1, 178.338-1, or 178.345-1, 
as applicable);
    (2) Is permanently attached to or forms a part of a motor vehicle, 
or is not permanently attached to a motor vehicle but that, by reason of 
its size, construction, or attachment to a motor vehicle, is loaded or 
unloaded without being removed from the motor vehicle; and
    (3) Is not fabricated under a specification for cylinders, 
intermediate bulk containers, multi-unit tank car tanks, portable tanks, 
or tank cars.
    Cargo tank motor vehicle means a motor vehicle with one or more 
cargo tanks permanently attached to or forming an integral part of the 
motor vehicle.
    Cargo tank wall means those parts of the cargo tank that make up the 
primary lading retention structure, including shell, bulkheads, and 
fittings and, when closed, yield the minimum volume of a completed cargo 
tank motor vehicle.
    Charging line means a hose, tube, pipe, or a similar device used to 
pressurize a tank with material other than the lading.
    Companion flange means one of two mating flanges where the flange 
faces are in contact or separated only by a thin leak-sealing gasket and 
are secured to one another by bolts or clamps.
    Connecting structure means the structure joining two cargo tanks.
    Constructed and certified in accordance with the ASME Code means a 
cargo tank is constructed and stamped in accordance with Section VIII of 
the ASME Code (IBR, see Sec.  171.7 of this subchapter), and is 
inspected and certified by an Authorized Inspector.
    Constructed in accordance with the ASME Code means a cargo tank is 
constructed in accordance with Section VIII of the ASME Code with 
authorized exceptions (see Sec. Sec.  178.346 through 178.348) and is 
inspected and certified by a Registered Inspector.
    Design type means one or more cargo tanks that are made--
    (1) To the same specification;
    (2) By the same manufacturer;
    (3) To the same engineering drawings and calculations, except for 
minor variations in piping that do not affect the lading retention 
capability of the cargo tank;
    (4) Of the same materials of construction;
    (5) To the same cross-sectional dimensions;
    (6) To a length varying by no more than 5 percent;
    (7) With the volume varying by no more than 5 percent (due to a 
change in length only); and
    (8) For the purposes of Sec.  178.338 only, with the same insulation 
system.
    External self-closing stop valve means a self-closing stop valve 
designed so that the self-stored energy source is located outside the 
cargo tank and the welded flange.
    Extreme dynamic loading means the maximum loading a cargo tank motor 
vehicle may experience during its expected life, excluding accident 
loadings resulting from an accident, such as overturn or collision.
    Flange means the structural ring for guiding or attachment of a pipe 
or fitting with another flange (companion flange), pipe, fitting or 
other attachment.
    Inspection pressure means the pressure used to determine leak 
tightness of the cargo tank when testing with pneumatic pressure.
    Internal self-closing stop valve means a self-closing stop valve 
designed so that the self-stored energy source is located inside the 
cargo tank or cargo tank sump, or within the welded flange, and the 
valve seat is located within the cargo tank or within one inch of the 
external face of the welded flange or sump of the cargo tank.
    Lading means the hazardous material contained in a cargo tank.
    Loading/unloading connection means the fitting in the loading/
unloading line farthest from the loading/unloading outlet to which the 
loading/unloading hose, pipe, or device is attached.
    Loading/unloading outlet means a cargo tank outlet used for normal 
loading/unloading operations.
    Loading/unloading stop valve means the stop valve farthest from the 
cargo tank loading/unloading outlet to which

[[Page 140]]

the loading/unloading connection is attached.
    Manufacturer means any person engaged in the manufacture of a DOT 
specification cargo tank, cargo tank motor vehicle, or cargo tank 
equipment that forms part of the cargo tank wall. This term includes 
attaching a cargo tank to a motor vehicle or to a motor vehicle 
suspension component that involves welding on the cargo tank wall. A 
manufacturer must register with the Department in accordance with 
subpart F of part 107 in subpart A of this chapter.
    Maximum allowable working pressure or MAWP means the maximum 
pressure allowed at the top of the tank in its normal operating 
position. The MAWP must be calculated as prescribed in Section VIII of 
the ASME Code. In use, the MAWP must be greater than or equal to the 
maximum lading pressure conditions prescribed in Sec.  173.33 of this 
subchapter for each material transported.
    Maximum lading pressure. See Sec.  173.33(c).
    Minimum thickness means the minimum required shell and head (and 
baffle and bulkhead when used as tank reinforcement) thickness needed to 
meet the specification. The minimum thickness is the greatest of the 
following values: (1)(i) For MC 330, MC 331, and MC 338 cargo tanks, the 
specified minimum thickness found the applicable specification(s); or
    (ii) For DOT 406, DOT 407 and DOT 412 cargo tanks, the specified 
minimum thickness found in Tables I and II of the applicable 
specification(s); or
    (iii) For MC 300, MC 301, MC 302, MC 303, MC 304, MC 305, MC 306, MC 
307, MC 310, MC 311, and MC 312 cargo tanks, the in-service minimum 
thickness prescribed in Tables I and II of Sec.  180.407(i)(5) of this 
subchapter, for the minimum thickness specified by Tables I and II of 
the applicable specification(s); or
    (2) The thickness necessary to meet with the structural integrity 
and accident damage requirements of the applicable specification(s); or
    (3) The thickness as computed per the ASME Code requirements (if 
applicable).
    Multi-specification cargo tank motor vehicle means a cargo tank 
motor vehicle equipped with two or more cargo tanks fabricated to more 
than one cargo tank specification.
    Normal operating loading means the loading a cargo tank motor 
vehicle may be expected to experience routinely in operation.
    Nozzle means a subassembly consisting of a pipe or tubular section 
with or without a welded or forged flange on one end.
    Outlet means any opening in the shell or head of a cargo tank, 
(including the means for attaching a closure), except that the following 
are not outlets: a threaded opening securely closed during 
transportation with a threaded plug or a threaded cap, a flanged opening 
securely closed during transportation with a bolted or welded blank 
flange, a manhole, a gauging device, a thermometer well, or a pressure 
relief device.
    Outlet stop valve means the stop valve at a cargo tank loading or 
unloading outlet.
    Pipe coupling means a fitting with internal threads on both ends.
    Rear bumper means the structure designed to prevent a vehicle or 
object from under-riding the rear of another motor vehicle. See Sec.  
393.86 of this title.
    Rear-end tank protection device means the structure designed to 
protect a cargo tank and any lading retention piping or devices in case 
of a rear end collision.
    Self-closing stop valve means a stop valve held in the closed 
position by means of self-stored energy, that opens only by application 
of an external force and that closes when the external force is removed.
    Shell means the circumferential portion of a cargo tank defined by 
the basic design radius or radii excluding the bulkheads.
    Stop valve means a valve that stops the flow of lading.
    Sump means a protrusion from the bottom of a cargo tank shell 
designed to facilitate complete loading and unloading of lading.
    Tank means a container, consisting of a shell and heads, that forms 
a pressure tight vessel having openings designed to accept pressure 
tight fittings

[[Page 141]]

or closures, but excludes any appurtenances, reinforcements, fittings, 
or closures.
    Test pressure means the pressure to which a tank is subjected to 
determine structural integrity.
    Toughness of material means the capability of a material to absorb 
energy represented by the area under a stress strain curve (indicating 
the energy absorbed per unit volume of the material) up to the point of 
rupture.
    Vacuum cargo tank means a cargo tank that is loaded by reducing the 
pressure in the cargo tank to below atmospheric pressure.
    Variable specification cargo tank means a cargo tank that is 
constructed in accordance with one specification, but that may be 
altered to meet another specification by changing relief device, 
closures, lading discharge devices, and other lading retention devices.
    Void means the space between tank heads or bulkheads and a 
connecting structure.
    Welded flange means a flange attached to the tank by a weld joining 
the tank shell to the cylindrical outer surface of the flange, or by a 
fillet weld joining the tank shell to a flange shaped to fit the shell 
contour.
    (b) Design certification. (1) Each cargo tank or cargo tank motor 
vehicle design type, including its required accident damage protection 
device, must be certified to conform to the specification requirements 
by a Design Certifying Engineer who is registered in accordance with 
subpart F of part 107 of this title. An accident damage protection 
device is a rear-end protection, overturn protection, or piping 
protection device.
    (2) The Design Certifying Engineer shall furnish to the manufacturer 
a certificate to indicate compliance with the specification 
requirements. The certificate must include the sketches, drawings, and 
calculations used for certification. Each certificate, including 
sketches, drawings, and calculations, shall be signed by the Design 
Certifying Engineer.
    (3) The manufacturer shall retain the design certificate at his 
principal place of business for as long as he manufactures DOT 
specification cargo tanks.
    (c) Exceptions to the ASME Code. Unless otherwise specified, when 
exceptions are provided in this subpart from compliance with certain 
paragraphs of the ASME Code, compliance with those paragraphs is not 
prohibited.

[Amdt. 178-89, 55 FR 37055, Sept. 7, 1990, as amended by Amdt. 178-98, 
58 FR 33306, June 16, 1993; Amdt. 178-118, 61 FR 51339, Oct. 1, 1996; 68 
FR 19277, Apr. 18, 2003; 68 FR 52370, Sept. 3, 2003; 68 FR 75752, Dec. 
31, 2003; 76 FR 43532, July 20, 2011]



Sec.  178.337  Specification MC 331; cargo tank motor vehicle primarily for 
transportation of compressed gases as defined in subpart G of part 173 of 
this subchapter.



Sec.  178.337-1  General requirements.

    (a) ASME Code construction. Tanks must be--
    (1) Seamless or welded construction, or a combination of both;
    (2) Designed, constructed, certified, and stamped in accordance with 
Section VIII of the ASME Code (IBR, see Sec.  171.7 of this subchapter);
    (3) Made of steel or aluminum; however, if aluminum is used, the 
cargo tank must be insulated and the hazardous material to be 
transported must be compatible with the aluminum (see Sec. Sec.  
178.337-1(e)(2), 173.315(a) table, and 178.337-2(a)(1) of this 
subchapter); and
    (4) Covered with a steel jacket if the cargo tank is insulated and 
used to transport a flammable gas (see Sec.  173.315(a) table Note 11 of 
this subchapter).
    (b) Design pressure. The design pressure of a cargo tank authorized 
under this specification shall be not less than the vapor pressure of 
the commodity contained therein at 115 [deg]F. or as prescribed for a 
particular commodity in Sec.  173.315(a) of this subchapter, except that 
in no case shall the design pressure of any cargo tank be less than 100 
p.s.i.g. nor more than 500 p.s.i.g.

    Note 1: The term design pressure as used in this specification, is 
identical to the term MAWP as used in the ASME Code.

    (c) Openings. (1) Excess pressure relief valves shall be located in 
the top of the cargo tank or heads.
    (2) A chlorine cargo tank shall have only one opening. That opening 
shall be in the top of the cargo tank and

[[Page 142]]

shall be fitted with a nozzle that meets the following requirements:
    (i) On a cargo tank manufactured on or before December 31, 1974, the 
nozzle shall be protected by a dome cover plate which conforms to either 
the standard of The Chlorine Institute, Inc., Dwg. 103-3, dated January 
23, 1958, or to the standard specified in paragraph (c) (2) (ii) of this 
section.
    (ii) On a cargo tank manufactured on or after January 1, 1975, the 
nozzle shall be protected by a manway cover which conforms to the 
standard of The Chlorine Institute, Inc., Dwg. 103-4, dated September 1, 
1971.
    (d) Reflective design. Every uninsulated cargo tank permanently 
attached to a cargo tank motor vehicle shall, unless covered with a 
jacket made of aluminum, stainless steel, or other bright nontarnishing 
metal, be painted a white, aluminum or similar reflecting color on the 
upper two-thirds of area of the cargo tank.
    (e) Insulation. (1) Each cargo tank required to be insulated must 
conform with the use and performance requirements contained in 
Sec. Sec.  173.315(a) table and 178.337-1 (a)(3) and (e)(2) of this 
subchapter.
    (2) Each cargo tank intended for chlorine; carbon dioxide, 
refrigerated liquid; or nitrous oxide, refrigerated liquid service must 
have suitable insulation of such thickness that the overall thermal 
conductance is not more than 0.08 Btu per square foot per [deg]F 
differential per hour. The conductance must be determined at 60 [deg]F. 
Insulation material used on cargo tanks for nitrous oxide, refrigerated 
liquid must be noncombustible. Insulating material used on cargo tanks 
for chlorine must be corkboard or polyurethane foam, with a minimum 
thickness of 4 inches, or 2 inches minimum thickness of ceramic fiber/
fiberglass of 4 pounds per cubic foot minimum density covered by 2 
inches minimum thickness of fiber.
    (f) Postweld heat treatment. Postweld heat treatment must be as 
prescribed in the ASME Code except that each cargo tank constructed in 
accordance with Part UHT of Section VIII of the ASME Code must be 
postweld heat treated. Each chlorine cargo tank must be fully 
radiographed and postweld heat treated in accordance with the provisions 
in Section VIII of the ASME Code under which it is constructed. Where 
postweld heat treatment is required, the cargo tank must be treated as a 
unit after completion of all the welds in and/or to the shells and 
heads. The method must be as prescribed in Section VIII of the ASME 
Code. Welded attachments to pads may be made after postweld heat 
treatment. A cargo tank used for anhydrous ammonia must be postweld heat 
treated. The postweld heat treatment must be as prescribed in Section 
VIII of the ASME Code, but in no event at less than 1,050 [deg]F cargo 
tank metal temperature.
    (g) Definitions. The following definitions apply to Sec. Sec.  
178.337-1 through 178.337-18:
    Emergency discharge control means the ability to stop a cargo tank 
unloading operation in the event of an unintentional release. Emergency 
discharge control can utilize passive or off-truck remote means to stop 
the unloading operation. A passive means of emergency discharge control 
automatically shuts off the flow of product without the need for human 
intervention within 20 seconds of an unintentional release caused by a 
complete separation of the liquid delivery hose. An off-truck remote 
means of emergency discharge control permits a qualified person 
attending the unloading operation to close the cargo tank's internal 
self-closing stop valve and shut off all motive and auxiliary power 
equipment at a distance from the cargo tank motor vehicle.
    Excess flow valve, integral excess flow valve, or excess flow 
feature means a component that will close automatically if the flow rate 
of a gas or liquid through the component reaches or exceeds the rated 
flow of gas or liquid specified by the original valve manufacturer when 
piping mounted directly on the valve is sheared off before the first 
valve, pump, or fitting downstream from the valve.
    Internal self-closing stop valve means a primary shut off valve 
installed in a product discharge outlet of a cargo tank and designed to 
be kept closed by self-stored energy.
    Primary discharge control system means a primary shut-off installed 
at a product discharge outlet of a cargo

[[Page 143]]

tank consisting of an internal self-closing stop valve that may include 
an integral excess flow valve or an excess flow feature, together with 
linkages that must be installed between the valve and remote actuator to 
provide manual and thermal on-truck remote means of closure.

[Order 59-B, 30 FR 579, Jan. 16, 1965. Redesignated at 32 FR 5606, Apr. 
5, 1967]

    Editorial Note: For Federal Register citations affecting Sec.  
178.337-1, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.govinfo.gov.



Sec.  178.337-2  Material.

    (a) General. (1) All material used for construction of the cargo 
tank and appurtenances must be suitable for use with the commodities to 
be transported therein and must conform to the requirements in Section 
II of the ASME Code (IBR, see Sec.  171.7 of this subchapter) and/or 
requirements of the American Society for Testing and Materials in all 
respects.
    (2) Impact tests are required on steel used in the fabrication of 
each cargo tank constructed in accordance with part UHT in Section VIII 
of the ASME Code. The tests must be made on a lot basis. A lot is 
defined as 100 tons or less of the same heat treatment processing lot 
having a thickness variation no greater than plus or minus 25 percent. 
The minimum impact required for full size specimens must be 20 foot-
pounds in the longitudinal direction at -30 [deg]F., Charpy V-Notch and 
15 foot-pounds in the transverse direction at -30 [deg]F., Charpy V-
Notch. The required values for subsize specimens must be reduced in 
direct proportion to the cross-sectional area of the specimen beneath 
the notch. If a lot does not meet this requirement, individual plates 
may be accepted if they individually meet this requirement.
    (3) The fabricator shall record the heat, and slab numbers, and the 
certified Charpy impact values, where required, of each plate used in 
each cargo tank on a sketch showing the location of each plate in the 
shell and heads of the cargo tank. Copies of each sketch shall be 
provided to the owner and retained for at least five years by the 
fabricator and made available to duly identified representatives of the 
Department of Transportation.
    (4) The direction of final rolling of the shell material shall be 
the circumferential orientation of the cargo tank shell.
    (b) For a chlorine cargo tank. Plates, the manway nozzle, and 
anchorage shall be made of carbon steel which meets the following 
requirements:
    (1) For a cargo tank manufactured on or before December 31, 1974--
    (i) Material shall conform to ASTM A 300, ``Steel Plates for 
Pressure Vessels for Service at Low Temperatures'' (IBR, see Sec.  171.7 
of this subchapter);
    (ii) Material shall be Class 1, Grade A, flange or firebox quality;
    (iii) Plate impact test specimens, as required under paragraph (a) 
of this section, shall be of the Charpy keyhole notch type; and
    (iv) Plate impact test specimens shall meet the impact test 
requirements in paragraph (a) of this section in both the longitudinal 
and transverse directions of rolling at a temperature of minus 45.5 C. 
(-50 [deg]F.).
    (2) For a cargo tank manufactured on or after January 1, 1975--
    (i) Material shall conform to ASTM A 612 (IBR, see Sec.  171.7 of 
this subchapter), Grade B or A 516/A 516M (IBR, see Sec.  171.7 of this 
subchapter), Grade 65 or 70;
    (ii) Material shall meet the Charpy V-notch test requirements of 
ASTM A 20/A 20M (IBR, see Sec.  171.7 of this subchapter); and
    (iii) Plate impact test specimens shall meet the impact test 
requirements in paragraph (a) of this section in both the longitudinal 
and transverse directions of rolling at a temperature of minus 40 
[deg]C. (-40 [deg]F.).
    (c) A cargo tank in anhydrous ammonia service must be constructed of 
steel. The use of copper, silver, zinc or their alloys is prohibited. 
Baffles made from aluminum may be used only if joined to the cargo tank 
by a process not requiring postweld heat treatment of the cargo tank.

[Order 59-B, 30 FR 579, Jan. 16, 1965. Redesignated at 32 FR 5606, Apr. 
5, 1967]

    Editorial Note: For Federal Register citations affecting Sec.  
178.337-2, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.govinfo.gov.

[[Page 144]]



Sec.  178.337-3  Structural integrity.

    (a) General requirements and acceptance criteria. (1) Except as 
provided in paragraph (d) of this section, the maximum calculated design 
stress at any point in the cargo tank may not exceed the maximum 
allowable stress value prescribed in Section VIII of the ASME Code (IBR, 
see Sec.  171.7 of this subchapter), or 25 percent of the tensile 
strength of the material used.
    (2) The relevant physical properties of the materials used in each 
cargo tank may be established either by a certified test report from the 
material manufacturer or by testing in conformance with a recognized 
national standard. In either case, the ultimate tensile strength of the 
material used in the design may not exceed 120 percent of the ultimate 
tensile strength specified in either the ASME Code or the ASTM standard 
to which the material is manufactured.
    (3) The maximum design stress at any point in the cargo tank must be 
calculated separately for the loading conditions described in paragraphs 
(b), (c), and (d) of this section. Alternate test or analytical methods, 
or a combination thereof, may be used in place of the procedures 
described in paragraphs (b), (c), and (d) of this section, if the 
methods are accurate and verifiable.
    (4) Corrosion allowance material may not be included to satisfy any 
of the design calculation requirements of this section.
    (b) Static design and construction. (1) The static design and 
construction of each cargo tank must be in accordance with Section VIII 
of the ASME Code. The cargo tank design must include calculation of 
stresses generated by design pressure, the weight of lading, the weight 
of structure supported by the cargo tank wall, and the effect of 
temperature gradients resulting from lading and ambient temperature 
extremes. When dissimilar materials are used, their thermal coefficients 
must be used in calculation of thermal stresses.
    (2) Stress concentrations in tension, bending and torsion which 
occur at pads, cradles, or other supports must be considered in 
accordance with appendix G in Section VIII of the ASME Code.
    (c) Shell design. Shell stresses resulting from static or dynamic 
loadings, or combinations thereof, are not uniform throughout the cargo 
tank motor vehicle. The vertical, longitudinal, and lateral normal 
operating loadings can occur simultaneously and must be combined. The 
vertical, longitudinal and lateral extreme dynamic loadings occur 
separately and need not be combined.
    (1) Normal operating loadings. The following procedure addresses 
stress in the tank shell resulting from normal operating loadings. The 
effective stress (the maximum principal stress at any point) must be 
determined by the following formula:

S = 0.5(Sy + Sx) [0.25(Sy - Sx)\2\ + 
Ss2]\0.5\


Where:

    (i) S = effective stress at any given point under the combination of 
static and normal operating loadings that can occur at the same time, in 
psi.
    (ii) Sy = circumferential stress generated by the MAWP 
and external pressure, when applicable, plus static head, in psi.
    (iii) Sx = The following net longitudinal stress 
generated by the following static and normal operating loading 
conditions, in psi:
    (A) The longitudinal stresses resulting from the MAWP and external 
pressure, when applicable, plus static head, in combination with the 
bending stress generated by the static weight of the fully loaded cargo 
tank motor vehicle, all structural elements, equipment and appurtenances 
supported by the cargo tank wall;
    (B) The tensile or compressive stress resulting from normal 
operating longitudinal acceleration or deceleration. In each case, the 
forces applied must be 0.35 times the vertical reaction at the 
suspension assembly, applied at the road surface, and as transmitted to 
the cargo tank wall through the suspension assembly of a trailer during 
deceleration; or the horizontal pivot of the truck tractor or converter 
dolly fifth wheel, or the drawbar hinge on the fixed dolly during 
acceleration; or anchoring and support members of a truck during 
acceleration and deceleration, as applicable. The vertical reaction must 
be calculated based on the

[[Page 145]]

static weight of the fully loaded cargo tank motor vehicle, all 
structural elements, equipment and appurtenances supported by the cargo 
tank wall. The following loadings must be included:
    (1) The axial load generated by a decelerative force;
    (2) The bending moment generated by a decelerative force;
    (3) The axial load generated by an accelerative force; and
    (4) The bending moment generated by an accelerative force; and
    (C) The tensile or compressive stress generated by the bending 
moment resulting from normal operating vertical accelerative force equal 
to 0.35 times the vertical reaction at the suspension assembly of a 
trailer; or the horizontal pivot of the upper coupler (fifth wheel) or 
turntable; or anchoring and support members of a truck, as applicable. 
The vertical reaction must be calculated based on the static weight of 
the fully loaded cargo tank motor vehicle, all structural elements, 
equipment and appurtenances supported by the cargo tank wall.
    (iv) Ss = The following shear stresses generated by the 
following static and normal operating loading conditions, in psi:
    (A) The static shear stress resulting from the vertical reaction at 
the suspension assembly of a trailer, and the horizontal pivot of the 
upper coupler (fifth wheel) or turntable; or anchoring and support 
members of a truck, as applicable. The vertical reaction must be 
calculated based on the static weight of the fully loaded cargo tank 
motor vehicle, all structural elements, equipment and appurtenances 
supported by the cargo tank wall;
    (B) The vertical shear stress generated by a normal operating 
accelerative force equal to 0.35 times the vertical reaction at the 
suspension assembly of a trailer; or the horizontal pivot of the upper 
coupler (fifth wheel) or turntable; or anchoring and support members of 
a truck, as applicable. The vertical reaction must be calculated based 
on the static weight of the fully loaded cargo tank motor vehicle, all 
structural elements, equipment and appurtenances supported by the cargo 
tank wall;
    (C) The lateral shear stress generated by a normal operating lateral 
accelerative force equal to 0.2 times the vertical reaction at each 
suspension assembly of a trailer, applied at the road surface, and as 
transmitted to the cargo tank wall through the suspension assembly of a 
trailer, and the horizontal pivot of the upper coupler (fifth wheel) or 
turntable; or anchoring and support members of a truck, as applicable. 
The vertical reaction must be calculated based on the static weight of 
the fully loaded cargo tank motor vehicle, all structural elements, 
equipment and appurtenances supported by the cargo tank wall; and
    (D) The torsional shear stress generated by the same lateral forces 
as described in paragraph (c)(1)(iv)(C) of this section.
    (2) Extreme dynamic loadings. The following procedure addresses 
stress in the tank shell resulting from extreme dynamic loadings. The 
effective stress (the maximum principal stress at any point) must be 
determined by the following formula:

S = 0.5(Sy + Sx) [0.25(Sy - Sx)\2\ + 
Ss2]\0.5\


Where:

    (i) S = effective stress at any given point under a combination of 
static and extreme dynamic loadings that can occur at the same time, in 
psi.
    (ii) Sy = circumferential stress generated by MAWP and 
external pressure, when applicable, plus static head, in psi.
    (iii) Sx = the following net longitudinal stress 
generated by the following static and extreme dynamic loading 
conditions, in psi:
    (A) The longitudinal stresses resulting from the MAWP and external 
pressure, when applicable, plus static head, in combination with the 
bending stress generated by the static weight of the fully loaded cargo 
tank motor vehicle, all structural elements, equipment and appurtenances 
supported by the tank wall;
    (B) The tensile or compressive stress resulting from extreme 
longitudinal acceleration or deceleration. In each case the forces 
applied must be 0.7 times the vertical reaction at the suspension 
assembly, applied at the road surface, and as transmitted to the

[[Page 146]]

cargo tank wall through the suspension assembly of a trailer during 
deceleration; or the horizontal pivot of the truck tractor or converter 
dolly fifth wheel, or the drawbar hinge on the fixed dolly during 
acceleration; or the anchoring and support members of a truck during 
acceleration and deceleration, as applicable. The vertical reaction must 
be calculated based on the static weight of the fully loaded cargo tank 
motor vehicle, all structural elements, equipment and appurtenances 
supported by the cargo tank wall. The following loadings must be 
included:
    (1) The axial load generated by a decelerative force;
    (2) The bending moment generated by a decelerative force;
    (3) The axial load generated by an accelerative force; and
    (4) The bending moment generated by an accelerative force; and
    (C) The tensile or compressive stress generated by the bending 
moment resulting from an extreme vertical accelerative force equal to 
0.7 times the vertical reaction at the suspension assembly of a trailer, 
and the horizontal pivot of the upper coupler (fifth wheel) or 
turntable; or the anchoring and support members of a truck, as 
applicable. The vertical reaction must be calculated based on the static 
weight of the fully loaded cargo tank motor vehicle, all structural 
elements, equipment and appurtenances supported by the cargo tank wall.
    (iv) Ss = The following shear stresses generated by 
static and extreme dynamic loading conditions, in psi:
    (A) The static shear stress resulting from the vertical reaction at 
the suspension assembly of a trailer, and the horizontal pivot of the 
upper coupler (fifth wheel) or turntable; or anchoring and support 
members of a truck, as applicable. The vertical reaction must be 
calculated based on the static weight of the fully loaded cargo tank 
motor vehicle, all structural elements, equipment and appurtenances 
supported by the cargo tank wall;
    (B) The vertical shear stress generated by an extreme vertical 
accelerative force equal to 0.7 times the vertical reaction at the 
suspension assembly of a trailer, and the horizontal pivot of the upper 
coupler (fifth wheel) or turntable; or anchoring and support members of 
a truck, as applicable. The vertical reaction must be calculated based 
on the static weight of the fully loaded cargo tank motor vehicle, all 
structural elements, equipment and appurtenances supported by the cargo 
tank wall;
    (C) The lateral shear stress generated by an extreme lateral 
accelerative force equal to 0.4 times the vertical reaction at the 
suspension assembly of a trailer, applied at the road surface, and as 
transmitted to the cargo tank wall through the suspension assembly of a 
trailer, and the horizontal pivot of the upper coupler (fifth wheel) or 
turntable; or anchoring and support members of a truck, as applicable. 
The vertical reaction must be calculated based on the static weight of 
the fully loaded cargo tank motor vehicle, all structural elements, 
equipment and appurtenances supported by the cargo tank wall; and
    (D) The torsional shear stress generated by the same lateral forces 
as described in paragraph (c)(2)(iv)(C) of this section.
    (d) In order to account for stresses due to impact in an accident, 
the design calculations for the cargo tank shell and heads must include 
the load resulting from the design pressure in combination with the 
dynamic pressure resulting from a longitudinal deceleration of ``2g''. 
For this loading condition the stress value used may not exceed the 
lesser of the yield strength or 75 percent of the ultimate tensile 
strength of the material of construction. For cargo tanks constructed of 
stainless steel the maximum design stress may not exceed 75 percent of 
the ultimate tensile strength of the type steel used.
    (e) The minimum metal thickness for the shell and heads on tanks 
with a design pressure of 100 psig or more must be 4.75 mm (0.187 inch) 
for steel and 6.86 mm (0.270 inch) for aluminum, except for chlorine and 
sulfur dioxide tanks. In all cases, the minimum thickness of the tank 
shell and head shall be determined using structural design requirements 
in Section VIII of the ASME Code or 25% of the tensile strength of the 
material used. For a cargo tank

[[Page 147]]

used in chlorine or sulfur dioxide service, the cargo tank must be made 
of steel. A corrosion allowance of 20 percent or 2.54 mm (0.10 inch), 
whichever is less, must be added to the thickness otherwise required for 
sulfur dioxide and chlorine tank material. In chlorine cargo tanks, the 
wall thickness must be at least 1.59 cm (0.625 inch), including 
corrosion allowance.
    (f) Where a cargo tank support is attached to any part of the cargo 
tank wall, the stresses imposed on the cargo tank wall must meet the 
requirements in paragraph (a) of this section.
    (g) The design, construction, and installation of an attachment, 
appurtenance to the cargo tank, structural support member between the 
cargo tank and the vehicle or suspension component, or accident 
protection device must conform to the following requirements:
    (1) Structural members, the suspension sub-frame, accident 
protection structures, and external circumferential reinforcement 
devices must be used as sites for attachment of appurtenances and other 
accessories to the cargo tank, when practicable.
    (2) A lightweight attachment to the cargo tank wall such as a 
conduit clip, brake line clip, skirting structure, lamp mounting 
bracket, or placard holder must be of a construction having lesser 
strength than the cargo tank wall materials and may not be more than 72 
percent of the thickness of the material to which it is attached. The 
lightweight attachment may be secured directly to the cargo tank wall if 
the device is designed and installed in such a manner that, if damaged, 
it will not affect the lading retention integrity of the tank. A 
lightweight attachment must be secured to the cargo tank shell or head 
by a continuous weld or in such a manner as to preclude formation of 
pockets which may become sites for corrosion. Attachments meeting the 
requirements of this paragraph are not authorized for cargo tanks 
constructed under part UHT in Section VIII of the ASME Code.
    (3) Except as prescribed in paragraphs (g)(1) and (g)(2) of this 
section, the welding of any appurtenance to the cargo tank wall must be 
made by attachment of a mounting pad so that there will be no adverse 
effect upon the lading retention integrity of the cargo tank if any 
force less than that prescribed in paragraph (b)(1) of this section is 
applied from any direction. The thickness of the mounting pad may not be 
less than that of the shell wall or head wall to which it is attached, 
and not more than 1.5 times the shell or head thickness. However, a pad 
with a minimum thickness of 0.25 inch may be used when the shell or head 
thickness is over 0.25 inch. If weep holes or tell-tale holes are used, 
the pad must be drilled or punched at the lowest point before it is 
welded to the tank. Each pad must--
    (i) Be fabricated from material determined to be suitable for 
welding to both the cargo tank material and the material of the 
appurtenance or structural support member; a Design Certifying Engineer 
must make this determination considering chemical and physical 
properties of the materials and must specify filler material conforming 
to the requirements in Section VIII of the ASME Code (IBR, see Sec.  
171.7 of this subchapter).
    (ii) Be preformed to an inside radius no greater than the outside 
radius of the cargo tank at the attachment location.
    (iii) Extend at least 2 inches in each direction from any point of 
attachment of an appurtenance or structural support member. This 
dimension may be measured from the center of the attached structural 
member.
    (iv) Have rounded corners, or otherwise be shaped in a manner to 
minimize stress concentrations on the shell or head.
    (v) Be attached by continuous fillet welding. Any fillet weld 
discontinuity may only be for the purpose of preventing an intersection 
between the fillet weld and a tank or jacket seam weld.

[Amdt. 178-89, 55 FR 37056, Sept. 7, 1990, as amended by Amdt. 178-104, 
59 FR 49135, Sept. 26, 1994; Amdt. 178-105, 60 FR 17401, Apr. 5, 1995; 
Amdt. 178-118, 61 FR 51340, Oct. 1, 1996; 65 FR 58631, Sept. 29, 2000; 
68 FR 19279, Apr. 18, 2003; 68 FR 52370, Sept. 3, 2003; 68 FR 75753, 
Dec. 31, 2003]

[[Page 148]]



Sec.  178.337-4  Joints.

    (a) Joints shall be as required in Section VIII of the ASME Code 
(IBR, see Sec.  171.7 of this subchapter), with all undercutting in 
shell and head material repaired as specified therein.
    (b) Welding procedure and welder performance must be in accordance 
with Section IX of the ASME Code. In addition to the essential variables 
named therein, the following must be considered as essential variables: 
Number of passes; thickness of plate; heat input per pass; and 
manufacturer's identification of rod and flux. When fabrication is done 
in accordance with part UHT in Section VIII of the ASME Code, filler 
material containing more than 0.08 percent vanadium must not be used. 
The number of passes, thickness of plate, and heat input per pass may 
not vary more than 25 percent from the procedure or welder 
qualifications. Records of the qualifications must be retained for at 
least 5 years by the cargo tank manufacturer and must be made available 
to duly identified representatives of the Department and the owner of 
the cargo tank.
    (c) All longitudinal shell welds shall be located in the upper half 
of the cargo tank.
    (d) Edge preparation of shell and head components may be by machine 
heat processes, provided such surfaces are remelted in the subsequent 
welding process. Where there will be no subsequent remelting of the 
prepared surface as in a tapered section, the final 0.050 inch of 
material shall be removed by mechanical means.
    (e) The maximum tolerance for misalignment and butting up shall be 
in accordance with the requirement in Section VIII of the ASME Code.
    (f) Substructures shall be properly fitted before attachment, and 
the welding sequence shall be such as to minimize stresses due to 
shrinkage of welds.

[Order 59-B, 30 FR 580, Jan. 16, 1965. Redesignated at 32 FR 5606, Apr. 
5, 1967]

    Editorial Note: For Federal Register citations affecting Sec.  
178.337-4, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.govinfo.gov.



Sec.  178.337-5  Bulkheads, baffles and ring stiffeners.

    (a) Not a specification requirement.
    (b) [Reserved]

[Order 59-B, 30 FR 580, Jan. 16, 1965. Redesignated at 32 FR 5606, Apr. 
5, 1967]



Sec.  178.337-6  Closure for manhole.

    (a) Each cargo tank marked or certified after April 21, 1994, must 
be provided with a manhole conforming to paragraph UG-46(g)(1) and other 
applicable requirements in Section VIII of the ASME Code (IBR, see Sec.  
171.7 of this subchapter), except that a cargo tank constructed of NQT 
steel having a capacity of 3,500 water gallons or less may be provided 
with an inspection opening conforming to paragraph UG-46 and other 
applicable requirements of the ASME Code instead of a manhole.
    (b) The manhole assembly of cargo tanks constructed after June 30, 
1979, may not be located on the front head of the cargo tank.

[Amdt. 178-7, 34 FR 18250, Nov. 14, 1969, as amended by Amdt. 178-52, 43 
FR 58820, Dec. 18, 1978; Amdt. 178-89, 54 FR 25017, June 12, 1989; 55 FR 
21038, May 22, 1990; 56 FR 27876, June 17, 1991; 58 FR 12905, Mar. 8, 
1993; Amdt. 178-118, 61 FR 51340, Oct. 1, 1996; 68 FR 75753, Dec. 31, 
2003]



Sec.  178.337-7  Overturn protection.

    (a) See Sec.  178.337-10.
    (b) [Reserved]

[Order 59-B, 30 FR 580, Jan. 16, 1965. Redesignated at 32 FR 5606, Apr. 
5, 1967]



Sec.  178.337-8  Openings, inlets, and outlets.

    (a) General. The requirements in this paragraph (a) apply to MC 331 
cargo tanks except for those used to transport chlorine. The 
requirements for inlets and outlets on chlorine cargo tanks are in 
paragraph (b) of this section.
    (1) An opening must be provided on each cargo tank used for the 
transportation of liquefied materials to permit complete drainage.
    (2) Except for gauging devices, thermometer wells, pressure relief 
valves, manhole openings, product inlet openings, and product discharge 
openings, each opening in a cargo tank must be

[[Page 149]]

closed with a plug, cap, or bolted flange.
    (3) Except as provided in paragraph (b) of this section, each 
product inlet opening, including vapor return lines, must be fitted with 
a back flow check valve or an internal self-closing stop valve located 
inside the cargo tank or inside a welded nozzle that is an integral part 
of the cargo tank. The valve seat must be located inside the cargo tank 
or within 2.54 cm (one inch) of the external face of the welded flange. 
Damage to parts exterior to the cargo tank or mating flange must not 
prevent effective seating of the valve. All parts of a valve inside a 
cargo tank or welded flange must be made of material that will not 
corrode or deteriorate in the presence of the lading.
    (4) Except as provided in paragraphs (a)(5), (b), and (c) of this 
section, each liquid or vapor discharge outlet must be fitted with a 
primary discharge control system as defined in Sec.  178.337-1(g). 
Thermal remote operators must activate at a temperature of 121.11 [deg]C 
(250 [deg]F) or less. Linkages between closures and remote operators 
must be corrosion resistant and effective in all types of environmental 
conditions incident to discharging of product.
    (i) On a cargo tank over 13,247.5 L (3,500 gallons) water capacity, 
thermal and mechanical means of remote closure must be installed at the 
ends of the cargo tank in at least two diagonally opposite locations. If 
the loading/unloading connection at the cargo tank is not in the general 
vicinity of one of the two locations specified in the first sentence of 
this paragraph (a)(4)(i), additional means of thermal remote closure 
must be installed so that heat from a fire in the loading/unloading 
connection area or the discharge pump will activate the primary 
discharge control system. The loading/unloading connection area is where 
hoses or hose reels are connected to the permanent metal piping.
    (ii) On a cargo tank of 13,247.5 L (3,500 gallons) water capacity or 
less, a thermal means of remote closure must be installed at or near the 
internal self-closing stop valve. A mechanical means of remote closure 
must be installed on the end of the cargo tank furthest away from the 
loading/unloading connection area. The loading/unloading connection area 
is where hoses or hose reels are connected to the permanent metal 
piping. Linkages between closures and remote operators must be corrosion 
resistant and effective in all types of environmental conditions 
incident to discharge of product.
    (iii) All parts of a valve inside a cargo tank or within a welded 
flange must be made of material that will not corrode or deteriorate in 
the presence of the lading.
    (iv) An excess flow valve, integral excess flow valve, or excess 
flow feature must close if the flow reaches the rated flow of a gas or 
liquid specified by the original valve manufacturer when piping mounted 
directly on the valve is sheared off before the first valve, pump, or 
fitting downstream from the excess flow valve, integral excess flow 
valve, or excess flow feature.
    (v) An integral excess flow valve or the excess flow feature of an 
internal self-closing stop valve may be designed with a bypass, not to 
exceed 0.1016 cm (0.040 inch) diameter opening, to allow equalization of 
pressure.
    (vi) The internal self-closing stop valve must be designed so that 
the self-stored energy source and the valve seat are located inside the 
cargo tank or within 2.54 cm (one inch) of the external face of the 
welded flange. Damage to parts exterior to the cargo tank or mating 
flange must not prevent effective seating of the valve.
    (5) A primary discharge control system is not required on the 
following:
    (i) A vapor or liquid discharge opening of less than 1\1/4\ NPT 
equipped with an excess flow valve together with a manually operated 
external stop valve in place of an internal self-closing stop valve.
    (ii) An engine fuel line on a truck-mounted cargo tank of not more 
than \3/4\ NPT equipped with a valve having an integral excess flow 
valve or excess flow feature.
    (iii) A cargo tank motor vehicle used to transport refrigerated 
liquids such as argon, carbon dioxide, helium, krypton, neon, nitrogen, 
and xenon, or mixtures thereof.

[[Page 150]]

    (6) In addition to the internal self-closing stop valve, each 
filling and discharge line must be fitted with a stop valve located in 
the line between the internal self-closing stop valve and the hose 
connection. A back flow check valve or excess flow valve may not be used 
to satisfy this requirement.
    (7) An excess flow valve may be designed with a bypass, not to 
exceed a 0.1016 centimeter (0.040 inch) diameter opening, to allow 
equalization of pressure.
    (b) Inlets and discharge outlets on chlorine tanks. The inlet and 
discharge outlets on a cargo tank used to transport chlorine must meet 
the requirements of Sec.  178.337-1(c)(2) and must be fitted with an 
internal excess flow valve. In addition to the internal excess flow 
valve, the inlet and discharge outlets must be equipped with an external 
stop valve (angle valve). Excess flow valves must conform to the 
standards of The Chlorine Institute, Inc., as follows:
    (1) A valve conforming to The Chlorine Institute, Inc., Dwg. 101-7 
(IBR, see Sec.  171.7 of this subchapter), must be installed under each 
liquid angle valve.
    (2) A valve conforming to The Chlorine Institute, Inc., Dwg. 106-6 
(IBR, see Sec.  171.7 of this subchapter), must be installed under each 
gas angle valve.
    (c) Discharge outlets on carbon dioxide, refrigerated liquid, cargo 
tanks. A discharge outlet on a cargo tank used to transport carbon 
dioxide, refrigerated liquid is not required to be fitted with an 
internal self-closing stop valve.

[64 FR 28049, May 24, 1999, as amended at 66 FR 45387, Aug. 28, 2001; 68 
FR 19279, Apr. 18, 2003; 68 FR 75753, Dec. 31, 2003]



Sec.  178.337-9  Pressure relief devices, piping, valves, hoses, and fittings.

    (a) Pressure relief devices. (1) See Sec.  173.315(i) of this 
subchapter.
    (2) On cargo tanks for carbon dioxide or nitrous oxide see Sec.  
173.315 (i) (9) and (10) of this subchapter.
    (3) Each valve must be designed, constructed, and marked for a rated 
pressure not less than the cargo tank design pressure at the temperature 
expected to be encountered.
    (b) Piping, valves, hose, and fittings. (1) The burst pressure of 
all piping, pipe fittings, hose and other pressure parts, except for 
pump seals and pressure relief devices, must be at least 4 times the 
design pressure of the cargo tank. Additionally, the burst pressure may 
not be less than 4 times any higher pressure to which each pipe, pipe 
fitting, hose or other pressure part may be subjected to in service. For 
chlorine service, see paragraph (b)(7) of this section.
    (2) Pipe joints must be threaded, welded, or flanged. If threaded 
pipe is used, the pipe and fittings must be Schedule 80 weight or 
heavier, except for sacrificial devices. Malleable metal, stainless 
steel, or ductile iron must be used in the construction of primary valve 
body parts and fittings used in liquid filling or vapor equalization. 
Stainless steel may be used for internal components such as shutoff 
discs and springs except where incompatible with the lading to be 
transported. Where copper tubing is permitted, joints must be brazed or 
be of equally strong metal union type. The melting point of the brazing 
material may not be lower than 538 [deg]C (1,000 [deg]F). The method of 
joining tubing may not reduce the strength of the tubing.
    (3) Each hose coupling must be designed for a pressure of at least 
120 percent of the hose design pressure and so that there will be no 
leakage when connected.
    (4) Piping must be protected from damage due to thermal expansion 
and contraction, jarring, and vibration. Slip joints are not authorized 
for this purpose.
    (5) [Reserved]
    (6) Cargo tank manufacturers and fabricators must demonstrate that 
all piping, valves, and fittings on a cargo tank are free from leaks. To 
meet this requirement, the piping, valves, and fittings must be tested 
after installation at not less than 80 percent of the design pressure 
marked on the cargo tank.
    (7) A hose assembler must:
    (i) Permanently mark each hose assembly with a unique identification 
number.
    (ii) Demonstrate that each hose assembly is free from leaks by 
performing the tests and inspections in Sec.  180.416(f) of this 
subchapter.

[[Page 151]]

    (iii) Mark each hose assembly with the month and year of its 
original pressure test.
    (8) Chlorine cargo tanks. Angle valves on cargo tanks intended for 
chlorine service must conform to the standards of the Chlorine 
Institute, Inc., Drawing; Dwg. 104-8; or ``Section 3, Pamphlet 166, 
Angle Valve Guidelines for Chlorine Bulk Transportation;'' or ``Sections 
4 through 6, Pamphlet 168, Guidelines for Dual Valve Systems for Bulk 
Chlorine Transport'' (IBR, see Sec.  171.7 of this subchapter). Before 
installation, each angle valve must be tested for leakage at not less 
than 225 psig using dry air or inert gas.
    (c) Marking inlets and outlets. Except for gauging devices, 
thermometer wells, and pressure relief valves, each cargo tank inlet and 
outlet must be marked ``liquid'' or ``vapor'' to designate whether it 
communicates with liquid or vapor when the cargo tank is filled to the 
maximum permitted filling density. A filling line that communicates with 
vapor may be marked ``spray-fill'' instead of ``vapor.''
    (d) Refrigeration and heating coils. (1) Refrigeration and heating 
coils must be securely anchored with provisions for thermal expansion. 
The coils must be pressure tested externally to at least the cargo tank 
test pressure, and internally to either the tank test pressure or twice 
the working pressure of the heating/refrigeration system, whichever is 
higher. A cargo tank may not be placed in service if any leakage occurs 
or other evidence of damage is found. The refrigerant or heating medium 
to be circulated through the coils must not be capable of causing any 
adverse chemical reaction with the cargo tank lading in the event of 
leakage. The unit furnishing refrigeration may be mounted on the motor 
vehicle.
    (2) Where any liquid susceptible to freezing, or the vapor of any 
such liquid, is used for heating or refrigeration, the heating or 
refrigeration system shall be arranged to permit complete drainage.

[Order 59-B, 30 FR 580, Jan. 16, 1965. Redesignated at 32 FR 5606, Apr. 
5, 1967]

    Editorial Note: For Federal Register citations affecting Sec.  
178.337-9, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.govinfo.gov.



Sec.  178.337-10  Accident damage protection.

    (a) All valves, fittings, pressure relief devices, and other 
accessories to the tank proper shall be protected in accordance with 
paragraph (b) of this section against such damage as could be caused by 
collision with other vehicles or objects, jack-knifing and overturning. 
In addition, pressure relief valves shall be so protected that in the 
event of overturn of the vehicle onto a hard surface, their opening will 
not be prevented and their discharge will not be restricted.
    (b) The protective devices or housing must be designed to withstand 
static loading in any direction equal to twice the weight of the tank 
and attachments when filled with the lading, using a safety factor of 
not less than four, based on the ultimate strength of the material to be 
used, without damage to the fittings protected, and must be made of 
metal at least \3/16\-inch thick.
    (c) Rear-end tank protection. Rear-end tank protection devices must:
    (1) Consist of at least one rear bumper designed to protect the 
cargo tank and all valves, piping and fittings located at the rear of 
the cargo tank from damage that could result in loss of lading in the 
event of a rear end collision. The bumper design must transmit the force 
of the collision directly to the chassis of the vehicle. The rear bumper 
and its attachments to the chassis must be designed to withstand a load 
equal to twice the weight of the loaded cargo tank motor vehicle and 
attachments, using a safety factor of four based on the tensile strength 
of the materials used, with such load being applied horizontally and 
parallel to the major axis of the cargo tank. The rear bumper dimensions 
must also meet the requirements of Sec.  393.86 of this title; or
    (2) Conform to the requirements of Sec.  178.345-8(d).
    (d) Chlorine tanks. A chlorine tank must be equipped with a 
protective housing and a manway cover to permit the use of standard 
emergency kits for controlling leaks in fittings on the

[[Page 152]]

dome cover plate. For tanks manufactured on or after October 1, 2009, 
the housing and manway cover must conform to the Chlorine Institute, 
Inc., Dwg. 137-5 (IBR, see Sec.  171.7 of this subchapter).
    (e) Piping and fittings. Piping and fittings must be grouped in the 
smallest practicable space and protected from damage as required in this 
section.
    (f) Shear section. A shear section or sacrificial device is required 
for the valves specified in the following locations:
    (1) A section that will break under strain must be provided adjacent 
to or outboard of each valve specified in Sec.  178.337-8(a)(3) and (4).
    (2) Each internal self-closing stop valve, excess flow valve, and 
check valve must be protected by a shear section or other sacrificial 
device. The sacrificial device must be located in the piping system 
outboard of the stop valve and within the accident damage protection to 
prevent any accidental loss of lading. The failure of the sacrificial 
device must leave the protected lading protection device and its 
attachment to the cargo tank wall intact and capable of retaining 
product.

[Order 59-B, 30 FR 581, Jan. 16, 1965. Redesignated at 32 FR 5606, Apr. 
5, 1967]

    Editorial Note: For Federal Register citations affecting Sec.  
178.337-10, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.govinfo.gov.



Sec.  178.337-11  Emergency discharge control.

    (a) Emergency discharge control equipment. Emergency discharge 
control equipment must be installed in a liquid discharge line as 
specified by product and service in Sec.  173.315(n) of this subchapter. 
The performance and certification requirements for emergency discharge 
control equipment are specified in Sec.  173.315(n) of this subchapter 
and are not a part of the cargo tank motor vehicle certification made 
under this specification.
    (b) Engine fuel lines. On a truck-mounted cargo tank, emergency 
discharge control equipment is not required on an engine fuel line of 
not more than \3/4\ NPT equipped with a valve having an integral excess 
flow valve or excess flow feature.

[64 FR 28050, May 24, 1999]



Sec.  178.337-12  [Reserved]



Sec.  178.337-13  Supporting and anchoring.

    (a) A cargo tank that is not permanently attached to or integral 
with a vehicle chassis must be secured by the use of restraining devices 
designed to prevent relative motion between the cargo tank and the 
vehicle chassis when the vehicle is in operation. Such restraining 
devices must be readily accessible for inspection and maintenance.
    (b) On a cargo tank motor vehicle designed and constructed so that 
the cargo tank constitutes in whole or in part the structural member 
used in place of a motor vehicle frame, the cargo tank must be supported 
by external cradles. A cargo tank mounted on a motor vehicle frame must 
be supported by external cradles or longitudinal members. Where used, 
the cradles must subtend at least 120 degrees of the shell 
circumference.
    (c) The design calculations of the support elements must satisfy the 
requirements of Sec.  178.337-3, (a), (b), (c), and (d).
    (d) Where any cargo tank support is attached to any part of a cargo 
tank head, the stresses imposed upon the head must be provided for as 
required in paragraph (c) of this section.

[68 FR 19280, Apr. 18, 2003]



Sec.  178.337-14  Gauging devices.

    (a) Liquid level gauging devices. See Sec.  173.315(h) of this 
subchapter.
    (b) Pressure gauges. (1) See Sec.  173.315(h) of this subchapter.
    (2) Each cargo tank used in carbon dioxide, refrigerated liquid or 
nitrous oxide, refrigerated liquid service must be provided with a 
suitable pressure gauge. A shut-off valve must be installed between the 
pressure gauge and the cargo tank.

[[Page 153]]

    (c) Orifices. See Sec.  173.315(h) (3) and (4) of this subchapter.

[Amdt. 178-29, 38 FR 27599, Oct. 5, 1973, as amended by Amdt. 178-89, 54 
FR 25018, June 12, 1989; Amdt. 178-118, 61 FR 51340, Oct. 1, 1996]



Sec.  178.337-15  Pumps and compressors.

    (a) Liquid pumps or gas compressors, if used, must be of suitable 
design, adequately protected against breakage by collision, and kept in 
good condition. They may be driven by motor vehicle power take-off or 
other mechanical, electrical, or hydraulic means. Unless they are of the 
centrifugal type, they shall be equipped with suitable pressure actuated 
by-pass valves permitting flow from discharge to suction or to the cargo 
tank.
    (b) A liquid chlorine pump may not be installed on a cargo tank 
intended for the transportation of chlorine.

[Amdt. 178-89, 54 FR 25018, June 12, 1989, as amended by Amdt. 178-118, 
61 FR 51340, Oct. 1, 1996]



Sec.  178.337-16  Testing.

    (a) Inspection and tests. Inspection of materials of construction of 
the cargo tank and its appurtenances and original test and inspection of 
the finished cargo tank and its appurtenances must be as required by 
Section VIII of the ASME Code (IBR, see Sec.  171.7 of this subchapter) 
and as further required by this specification, except that for cargo 
tanks constructed in accordance with part UHT in Section VIII of the 
ASME Code the original test pressure must be at least twice the cargo 
tank design pressure.
    (b) Weld testing and inspection. (1) Each cargo tank constructed in 
accordance with part UHT in Section VIII of the ASME Code must be 
subjected, after postweld heat treatment and hydrostatic tests, to a wet 
fluorescent magnetic particle inspection to be made on all welds in or 
on the cargo tank shell and heads both inside and out. The method of 
inspection must conform to appendix 6 in Section VIII of the ASME Code 
except that permanent magnets shall not be used.
    (2) On cargo tanks of over 3,500 gallons water capacity other than 
those described in paragraph (b)(1) of this section unless fully 
radiographed, a test must be made of all welds in or on the shell and 
heads both inside and outside by either the wet fluorescent magnetic 
particle method conforming to appendix U in Section VIII of the ASME 
Code, liquid dye penetrant method, or ultrasonic testing in accordance 
with appendix 12 in Section VIII of the ASME Code. Permanent magnets 
must not be used to perform the magnetic particle inspection.
    (c) All defects found shall be repaired, the cargo tanks shall then 
again be postweld heat treated, if such heat treatment was previously 
performed, and the repaired areas shall again be tested.

[Order 59-B, 30 FR 582, Jan. 16, 1965. Redesignated at 32 FR 5606, Apr. 
5, 1967, and amended by Amdt. 178-7, 34 FR 18250, Nov. 14, 1969; Amdt. 
178-99, 58 FR 51534, Oct. 1, 1993; Amdt. 178-118, 61 FR 51340, Oct. 1, 
1996; 68 FR 75753, Dec. 31, 2003]



Sec.  178.337-17  Marking.

    (a) General. Each cargo tank certified after October 1, 2004 must 
have a corrosion-resistant metal name plate (ASME Plate); and each cargo 
tank motor vehicle certified after October 1, 2004 must have a 
specification plate, permanently attached to the cargo tank by brazing, 
welding, or other suitable means on the left side near the front, in a 
place accessible for inspection. If the specification plate is attached 
directly to the cargo tank wall by welding, it must be welded to the 
tank before the cargo tank is postweld heat treated.
    (1) The plates must be legibly marked by stamping, embossing, or 
other means of forming letters into the metal of the plate, with the 
information required in paragraphs (b) and (c) of this section, in 
addition to that required by the ASME Code, in characters at least \3/
16\ inch high (parenthetical abbreviations may be used). All plates must 
be maintained in a legible condition.
    (2) Each insulated cargo tank must have additional plates, as 
described, attached to the jacket in the location specified unless the 
specification plate is attached to the chassis and has the information 
required in paragraphs (b) and (c) of this section.

[[Page 154]]

    (3) The information required for both the name and specification 
plate may be displayed on a single plate. If the information required by 
this section is displayed on a plate required by the ASME, the 
information need not be repeated on the name and specification plates.
    (4) The specification plate may be attached to the cargo tank motor 
vehicle chassis rail by brazing, welding, or other suitable means on the 
left side near the front head, in a place accessible for inspection. If 
the specification plate is attached to the chassis rail, then the cargo 
tank serial number assigned by the cargo tank manufacturer must be 
included on the plate.
    (b) Name plate. The following information must be marked on the name 
plate in accordance with this section:
    (1) DOT-specification number MC 331 (DOT MC 331).
    (2) Original test date (Orig. Test Date).
    (3) MAWP in psig.
    (4) Cargo tank design temperature (Design Temp. Range) ______ [deg]F 
to ______ [deg]F.
    (5) Nominal capacity (Water Cap.), in pounds.
    (6) Maximum design density of lading (Max. Lading density), in 
pounds per gallon.
    (7) Material specification number--shell (Shell matl, yyy***), where 
``yyy'' is replaced by the alloy designation and ``***'' is replaced by 
the alloy type.
    (8) Material specification number--heads (Head matl. yyy***), where 
``yyy'' is replaced by the alloy designation and ``***'' by the alloy 
type.
    (9) Minimum Thickness--shell (Min. Shell-thick), in inches. When 
minimum shell thicknesses are not the same for different areas, show 
(top____, side____, bottom____, in inches).
    (10) Minimum thickness--heads (Min. heads thick.), in inches.
    (11) Manufactured thickness--shell (Mfd. Shell thick.), top____, 
side____, bottom____, in inches. (Required when additional thickness is 
provided for corrosion allowance.)
    (12) Manufactured thickness--heads (Mfd. Heads thick.), in inches. 
(Required when additional thickness is provided for corrosion 
allowance.)
    (13) Exposed surface area, in square feet.

    Note to paragraph (b): When the shell and head materials are the 
same thickness, they may be combined, (Shell&head matl, yyy***).

    (c) Specification plate. The following information must be marked on 
the specification plate in accordance with this section:
    (1) Cargo tank motor vehicle manufacturer (CTMV mfr.).
    (2) Cargo tank motor vehicle certification date (CTMV cert. date).
    (3) Cargo tank manufacturer (CT mfr.).
    (4) Cargo tank date of manufacture (CT date of mfr.), month and 
year.
    (5) Maximum weight of lading (Max. Payload), in pounds
    (6) Lining materials (Lining), if applicable.
    (7) Heating system design pressure (Heating sys. press.), in psig, 
if applicable.
    (8) Heating system design temperature (Heating sys. temp.), in 
[deg]F, if applicable.
    (9) Cargo tank serial number, assigned by cargo tank manufacturer 
(CT serial), if applicable.

    Note 1 to paragraph (c): See Sec.  173.315(a) of this chapter 
regarding water capacity.
    Note 2 to paragraph (c): When the shell and head materials are the 
same thickness, they may be combined (Shell & head matl, yyy***).

    (d) The design weight of lading used in determining the loading in 
Sec. Sec.  178.337-3(b), 178.337-10(b) and (c), and 178.337-13(a) and 
(b), must be shown as the maximum weight of lading marking required by 
paragraph (c) of this section.

[68 FR 19280, Apr. 18, 2003; 68 FR 52370, Sept. 3, 2003, as amended at 
68 FR 57633, Oct. 6, 2003; 81 FR 35544, June 2, 2016]



Sec.  178.337-18  Certification.

    (a) At or before the time of delivery, the cargo tank motor vehicle 
manufacturer must supply and the owner must obtain, a cargo tank motor 
vehicle manufacturer's data report as required by Section VIII of the 
ASME Code (IBR, see Sec.  171.7 of this subchapter), and a certificate 
stating that the completed cargo tank motor vehicle conforms in all 
respects to Specification

[[Page 155]]

MC 331 and the ASME Code. The registration numbers of the manufacturer, 
the Design Certifying Engineer, and the Registered Inspector, as 
appropriate, must appear on the certificates (see subpart F, part 107 in 
subchapter A of this chapter).
    (1) For each design type, the certificate must be signed by a 
responsible official of the manufacturer and a Design Certifying 
Engineer; and
    (2) For each cargo tank motor vehicle, the certificate must be 
signed by a responsible official of the manufacturer and a Registered 
Inspector.
    (3) When a cargo tank motor vehicle is manufactured in two or more 
stages, each manufacturer who performs a manufacturing function or 
portion thereof on the incomplete cargo tank motor vehicle must provide 
to the succeeding manufacturer, at or before the time of delivery, a 
certificate that states the function performed by the manufacturer, 
including any certificates received from previous manufacturers, 
Registered Inspectors, and Design Certifying Engineers.
    (4) Specification shortages. When a cargo tank motor vehicle is 
manufactured in two or more stages, the manufacturer of the cargo tank 
must attach the name plate and specification plate as required by Sec.  
178.337-17(a) and (b) without the original date of certification stamped 
on the specification plate. Prior manufacturers must list the 
specification requirements that are not completed on the Certificate of 
Compliance. When the cargo tank motor vehicle is brought into full 
compliance with the applicable specification, the cargo tank motor 
vehicle manufacturer must have a Registered Inspector stamp the date of 
certification on the specification plate and issue a Certificate of 
Compliance to the owner of the cargo tank motor vehicle. The Certificate 
of Compliance must list the actions taken to bring the cargo tank motor 
vehicle into full compliance. In addition, the certificate must include 
the date of certification and the person (manufacturer, carrier or 
repair organization) accomplishing compliance.
    (5) The certificate must state whether or not it includes 
certification that all valves, piping, and protective devices conform to 
the requirements of the specification. If it does not so certify, the 
installer of any such valve, piping, or device shall supply and the 
owner shall obtain a certificate asserting complete compliance with 
these specifications for such devices. The certificate, or certificates, 
will include sufficient sketches, drawings, and other information to 
indicate the location, make, model, and size of each valve and the 
arrangement of all piping associated with the cargo tank.
    (6) The certificate must contain a statement indicating whether or 
not the cargo tank was postweld heat treated for anhydrous ammonia as 
specified in Sec.  178.337-1(f).
    (b) The owner shall retain the copy of the data report and 
certificates and related papers in his files throughout his ownership of 
the cargo tank motor vehicle and for at least one year thereafter; and 
in the event of change in ownership, retention by the prior owner of 
nonfading photographically reproduced copies will be deemed to satisfy 
this requirement. Each motor carrier using the cargo tank motor vehicle, 
if not the owner thereof, shall obtain a copy of the data report and 
certificate and retain them in his files during the time he uses the 
cargo tank motor vehicle and for at least one year thereafter.

[Order 59-B, 30 FR 583, Jan. 16, 1965. Redesignated at 32 FR 5606, Apr. 
5, 1967]

    Editorial Note: For Federal Register citations affecting Sec.  
178.337-18, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.govinfo.gov.



Sec.  178.338  Specification MC-338; insulated cargo tank motor vehicle.



Sec.  178.338-1  General requirements.

    (a) For the purposes of this section--
    (1) Design pressure means the ``MAWP'' as used in Section VIII of 
the ASME Code (IBR, see Sec.  171.7 of this subchapter), and is the 
gauge pressure at the top of the tank.
    (2) Design service temperature means the coldest temperature for 
which the tank is suitable (see Sec. Sec.  173.318 (a)(1) and (f) of 
this subchapter).
    (b) Each cargo tank must consist of a suitably supported welded 
inner vessel

[[Page 156]]

enclosed within an outer shell or jacket, with insulation between the 
inner vessel and outer shell or jacket, and having piping, valves, 
supports and other appurtenances as specified in this subchapter. For 
the purpose of this specification, tank means inner vessel and jacket 
means either the outer shell or insulation cover.
    (c) Each tank must be designed, constructed, certified, and stamped 
in accordance with Section VIII of the ASME Code.
    (d) The exterior surface of the tank must be insulated with a 
material compatible with the lading.
    (1) Each cargo tank must have an insulation system that will prevent 
the tank pressure from exceeding the pressure relief valve set pressure 
within the specified holding time when the tank is loaded with the 
specific cryogenic liquid at the design conditions of--
    (i) The specified temperature and pressure of the cryogenic liquid, 
and
    (ii) The exposure of the filled cargo tank to an average ambient 
temperature of 85 [deg]F.
    (2) For a cargo tank used to transport oxygen, the insulation may 
not sustain combustion in a 99.5 percent oxygen atmosphere at 
atmospheric pressure when contacted with a continuously heated glowing 
platinum wire. The cargo tank must be marked in accordance with Sec.  
178.338-18(b)(7).
    (3) Each vacuum-insulated cargo tank must be provided with a 
connection for a vacuum gauge to indicate the absolute pressure within 
the insulation space.
    (e) The insulation must be completely covered by a metal jacket. The 
jacket or the insulation must be so constructed and sealed as to prevent 
moisture from coming into contact with the insulation (see Sec.  
173.318(a)(3) of this subchapter). Minimum metal thicknesses are as 
follows:

------------------------------------------------------------------------
                                             Jacket         Jacket not
                                            evacuated       evacuated
               Type metal               --------------------------------
                                          Gauge  Inches   Gauge   Inches
------------------------------------------------------------------------
Stainless steel........................      18  0.0428      22   0.0269
Low carbon mild steel..................      12  0.0946      14   0.0677
Aluminum...............................  ......  0.125   ......   0.1000
------------------------------------------------------------------------

    (f) An evacuated jacket must be in compliance with the following 
requirements:
    (1) The jacket must be designed to sustain a minimum critical 
collapsing pressure of 30 psig.
    (2) If the jacket also supports additional loads, such as the weight 
of the tank and lading, the combined stress, computed according to the 
formula in Sec.  178.338-3(b), may not exceed 25 percent of the minimum 
specified tensile strength.

[Amdt. 178-77, 48 FR 27703, June 16, 1983, as amended at 49 FR 24316, 
June 12, 1984; Amdt. 178-104, 59 FR 49135, Sept. 26, 1994; 66 FR 45387, 
Aug. 28, 2001; 68 FR 75754, Dec. 31, 2003]



Sec.  178.338-2  Material.

    (a) All material used in the construction of a tank and its 
appurtenances that may come in contact with the lading must be 
compatible with the lading to be transported. All material used for tank 
pressure parts must conform to the requirements in Section II of the 
ASME Code (IBR, see Sec.  171.7 of this subchapter). All material used 
for evacuated jacket pressure parts must conform to the chemistry and 
steelmaking practices of one of the material specifications of Section 
II of the ASME Code or the following ASTM Specifications (IBR, see Sec.  
171.7 of this subchapter): A 242, A 441, A 514, A 572, A 588, A 606, A 
633, A 715, A 1008/A 1008M, A 1011/A 1011M.
    (b) All tie-rods, mountings, and other appurtenances within the 
jacket and all piping, fittings and valves must be of material suitable 
for use at the lowest temperature to be encountered.
    (c) Impact tests are required on all tank materials, except 
materials that are excepted from impact testing by the ASME Code, and 
must be performed using the procedure prescribed in Section VIII of the 
ASME Code.
    (d) The direction of final rolling of the shell material must be the 
circumferential orientation of the tank shell.
    (e) Each tank constructed in accordance with part UHT in Section 
VIII of the ASME Code must be postweld heat treated as a unit after 
completion of all welds to the shell and heads. Other tanks must be 
postweld heat treated as required in Section VIII of the ASME Code. For 
all tanks the method must be as prescribed in the ASME Code. Welded 
attachments to pads may be made after postweld heat treatment.

[[Page 157]]

    (f) The fabricator shall record the heat and slab numbers and the 
certified Charpy impact values of each plate used in the tank on a 
sketch showing the location of each plate in the shell and heads of the 
tank. A copy of the sketch must be provided to the owner of the cargo 
tank and a copy must be retained by the fabricator for at least five 
years and made available, upon request, to any duly identified 
representative of the Department.

(Approved by the Office of Management and Budget under control number 
2137-0017)

[Amdt. 178-77, 48 FR 27703, 27713, June 16, 1983, as amended at 49 FR 
24316, June 12, 1984; 68 FR 19281, Apr. 18, 2003; 68 FR 75754, Dec. 31, 
2003; 70 FR 34076, June 13, 2005]



Sec.  178.338-3  Structural integrity.

    (a) General requirements and acceptance criteria. (1) Except as 
permitted in paragraph (d) of this section, the maximum calculated 
design stress at any point in the tank may not exceed the lesser of the 
maximum allowable stress value prescribed in Section VIII of the ASME 
Code (IBR, see Sec.  171.7 of this subchapter), or 25 percent of the 
tensile strength of the material used.
    (2) The relevant physical properties of the materials used in each 
tank may be established either by a certified test report from the 
material manufacturer or by testing in conformance with a recognized 
national standard. In either case, the ultimate tensile strength of the 
material used in the design may not exceed 120 percent of the minimum 
ultimate tensile strength specified in either the ASME Code or the ASTM 
standard to which the material is manufactured.
    (3) The maximum design stress at any point in the tank must be 
calculated separately for the loading conditions described in paragraphs 
(b), (c), and (d) of this section. Alternate test or analytical methods, 
or a combination thereof, may be used in lieu of the procedures 
described in paragraphs (b), (c), and (d) of this section, if the 
methods are accurate and verifiable.
    (4) Corrosion allowance material may not be included to satisfy any 
of the design calculation requirements of this section.
    (b) Static design and construction. (1) The static design and 
construction of each tank must be in accordance with appendix G in 
Section VIII of the ASME Code (IBR, see Sec.  171.7 of this subchapter). 
The tank design must include calculation of stress due to the design 
pressure, the weight of lading, the weight of structures supported by 
the tank wall, and the effect of temperature gradients resulting from 
lading and ambient temperature extremes. When dissimilar materials are 
used, their thermal coefficients must be used in calculation of the 
thermal stresses.
    (2) Stress concentrations in tension, bending, and torsion which 
occur at pads, cradles, or other supports must be considered in 
accordance with appendix G in Section VIII of the ASME Code.
    (c) Stresses resulting from static and dynamic loadings, or a 
combination thereof, are not uniform throughout the cargo tank motor 
vehicle. The following is a simplified procedure for calculating the 
effective stress in the tank resulting from static and dynamic loadings. 
The effective stress (the maximum principal stress at any point) must be 
determined by the following formula:

S = 0.5 (Sy + Sx) (0.25(Sy - Sx)\2\ + 
Ss2) \0.5\


Where:

    (1) S = effective stress at any given point under the most severe 
combination of static and dynamic loadings that can occur at the same 
time, in psi.
    (2) Sy = circumferential stress generated by internal and 
external pressure when applicable, in psi.
    (3) Sx = the net longitudinal stress, in psi, generated 
by the following loading conditions:
    (i) The longitudinal tensile stress generated by internal pressure;
    (ii) The tensile or compressive stress generated by the axial load 
resulting from a decelerative force applied independently to each 
suspension assembly at the road surface using applicable static loadings 
specified in Sec.  178.338-13 (b);
    (iii) The tensile or compressive stress generated by the bending 
moment resulting from a decelerative force applied independently to each 
suspension assembly at the road surface using applicable static loadings 
specified in Sec.  178.338-13 (b);

[[Page 158]]

    (iv) The tensile or compressive stress generated by the axial load 
resulting from an accelerative force applied to the horizontal pivot of 
the fifth wheel supporting the vehicle using applicable static loadings 
specified in Sec.  178.338-13 (b);
    (v) The tensile or compressive stress generated by the bending 
moment resulting from an accelerative force applied to the horizontal 
pivot of the fifth wheel supporting the vehicle using applicable static 
loadings specified in Sec.  178.338-13 (b); and
    (vi) The tensile or compressive stress generated by a bending moment 
produced by a vertical force using applicable static loadings specified 
in Sec.  178.338-13 (b).
    (4) Ss = The following shear stresses that apply, in 
psi,: The vectorial sum of the applicable shear stresses in the plane 
under consideration, including direct shear generated by the static 
vertical loading; direct lateral and torsional shear generated by a 
lateral accelerative force applied at the road surface, using applicable 
static loads specified in Sec.  178.338-13 (b)
    (d) In order to account for stresses due to impact in an accident, 
the design calculations for the tank shell and heads must include the 
load resulting from the design pressure in combination with the dynamic 
pressure resulting from a longitudinal deceleration of ``2g''. For this 
loading condition the stress value used may not exceed the lesser of the 
yield strength or 75 percent of the ultimate tensile strength of the 
material of construction. For a cargo tank constructed of stainless 
steel, the maximum design stress may not exceed 75 percent of the 
ultimate tensile strength of the type steel used.
    (e) The minimum thickness of the shell or heads of the tank must be 
0.187 inch for steel and 0.270 inch for aluminum. However, the minimum 
thickness for steel may be 0.110 inches provided the cargo tank is:
    (1) Vacuum insulated, or
    (2) Double walled with a load bearing jacket designed to carry a 
proportionate amount of structural loads prescribed in this section.
    (f) Where a tank support is attached to any part of the tank wall, 
the stresses imposed on the tank wall must meet the requirements in 
paragraph (a) of this section.
    (g) The design, construction and installation of an attachment, 
appurtenance to the cargo tank or structural support member between the 
cargo tank and the vehicle or suspension component or accident 
protection device must conform to the following requirements:
    (1) Structural members, the suspension subframe, accident protection 
structures and external circumferential reinforcement devices must be 
used as sites for attachment of appurtenances and other accessories to 
the cargo tank, when practicable.
    (2) A lightweight attachment to the cargo tank wall such as a 
conduit clip, brakeline clip, skirting structure, lamp mounting bracket, 
or placard holder must be of a construction having lesser strength than 
the cargo tank wall materials and may not be more than 72 percent of the 
thickness of the material to which it is attached. The lightweight 
attachment may be secured directly to the cargo tank wall if the device 
is designed and installed in such a manner that, if damaged, it will not 
affect the lading retention integrity of the tank. A lightweight 
attachment must be secured to the cargo tank shell or head by a 
continuous weld or in such a manner as to preclude formation of pockets 
that may become sites for corrosion. Attachments meeting the 
requirements of this paragraph are not authorized for cargo tanks 
constructed under part UHT in Section VIII of the ASME Code.
    (3) Except as prescribed in paragraphs (g)(1) and (g)(2) of this 
section, the welding of any appurtenance the cargo tank wall must be 
made by attachment of a mounting pad so that there will be no adverse 
effect upon the lading retention integrity of the cargo tank if any 
force less than that prescribed in paragraph (b)(1) of this section is 
applied from any direction. The thickness of the mounting pad may not be 
less than that of the shell or head to which it is attached, and not 
more than 1.5 times the shell or head thickness. However, a pad with a 
minimum thickness of 0.187 inch may be used when the shell or head 
thickness is over 0.187 inch. If weep holes or tell-

[[Page 159]]

tale holes are used, the pad must be drilled or punched at the lowest 
point before it is welded to the tank. Each pad must:
    (i) Be fabricated from material determined to be suitable for 
welding to both the cargo tank material and the material of the 
appurtenance or structural support member; a Design Certifying Engineer 
must make this determination considering chemical and physical 
properties of the materials and must specify filler material conforming 
to the requirements in Section IX of the ASME Code (IBR, see Sec.  171.7 
of this subchapter).
    (ii) Be preformed to an inside radius no greater than the outside 
radius of the cargo tank at the attachment location.
    (iii) Extend at least 2 inches in each direction from any point of 
attachment of an appurtenance or structural support member. This 
dimension may be measured from the center of the attached structural 
member.
    (iv) Have rounded corners, or otherwise be shaped in a manner to 
minimize stress concentrations on the shell or head.
    (v) Be attached by continuous fillet welding. Any fillet weld 
discontinuity may only be for the purpose of preventing an intersection 
between the fillet weld and a tank or jacket seam weld.

[Amdt. 178-89, 55 FR 37057, Sept. 7, 1990, as amended by Amdt. 178-89, 
56 FR 27876, June 17, 1991; 56 FR 46354, Sept. 11, 1991; 68 FR 19281, 
Apr. 18, 2003; 68 FR 57633, Oct. 6, 2003; 68 FR 75754, Dec. 31, 2003; 81 
FR 25618, Apr. 29, 2016]



Sec.  178.338-4  Joints.

    (a) All joints in the tank, and in the jacket if evacuated, must be 
as prescribed in Section VIII of the ASME Code (IBR, see Sec.  171.7 of 
this subchapter), except that a butt weld with one plate edge offset is 
not authorized.
    (b) Welding procedure and welder performance tests must be made in 
accordance with Section IX of the ASME Code. Records of the 
qualification must be retained by the tank manufacturer for at least 
five years and must be made available, upon request, to any duly 
identified representative of the Department, or the owner of the cargo 
tank.
    (c) All longitudinal welds in tanks and load bearing jackets must be 
located so as not to intersect nozzles or supports other than load rings 
and stiffening rings.
    (d) Substructures must be properly fitted before attachment and the 
welding sequence must minimize stresses due to shrinkage of welds.
    (e) Filler material containing more than 0.05 percent vanadium may 
not be used with quenched and tempered steel.
    (f) All tank nozzle-to-shell and nozzle-to-head welds must be full 
penetration welds.

(Approved by the Office of Management and Budget under control number 
2137-0017)

[Amdt. 178-77, 48 FR 27704, 27713, June 16, 1983, as amended at 49 FR 
24316, June 12, 1984; 68 FR 75754, Dec. 31, 2003]



Sec.  178.338-5  Stiffening rings.

    (a) A tank is not required to be provided with stiffening rings, 
except as prescribed in Section VIII of the ASME Code (IBR, see Sec.  
171.7 of this subchapter).
    (b) If a jacket is evacuated, it must be constructed in compliance 
with Sec.  178.338-1(f). Stiffening rings may be used to meet these 
requirements.

[Amdt. 178-77, 48 FR 27704, June 16, 1983, as amended at 68 FR 75754, 
Dec. 31, 2003]



Sec.  178.338-6  Manholes.

    (a) Each tank in oxygen service must be provided with a manhole as 
prescribed in Section VIII of the ASME Code (IBR, see Sec.  171.7 of 
this subchapter).
    (b) Each tank having a manhole must be provided with a means of 
entrance and exit through the jacket, or the jacket must be marked to 
indicate the manway location on the tank.
    (c) A manhole with a bolted closure may not be located on the front 
head of the tank.

[Amdt. 178-77, 48 FR 27704, June 16, 1983, as amended at 49 FR 24316, 
June 12, 1984; 68 FR 75754, Dec. 31, 2003]

[[Page 160]]



Sec.  178.338-7  Openings.

    (a) The inlet to the liquid product discharge opening of each tank 
intended for flammable ladings must be at the bottom centerline of the 
tank.
    (b) If the leakage of a single valve, except a pressure relief 
valve, pressure control valve, full trycock or gas phase manual vent 
valve, would permit loss of flammable material, an additional closure 
that is leak tight at the tank design pressure must be provided outboard 
of such valve.

[Amdt. 178-77, 48 FR 27704, June 16, 1983]



Sec.  178.338-8  Pressure relief devices, piping, valves, and fittings.

    (a) Pressure relief devices. Each tank pressure relief device must 
be designed, constructed, and marked in accordance with Sec.  173.318(b) 
of this subchapter.
    (b) Piping, valves, and fittings. (1) The burst pressure of all 
piping, pipe fittings, hoses and other pressure parts, except for pump 
seals and pressure relief devices, must be at least 4 times the design 
pressure of the tank. Additionally, the burst pressure may not be less 
than 4 times any higher pressure to which each pipe, pipe fitting, hose 
or other pressure part may be subjected to in service.
    (2) Pipe joints must be threaded, welded or flanged. If threaded 
pipe is used, the pipe and fittings must be Schedule 80 weight or 
heavier. Malleable metals must be used in the construction of valves and 
fittings. Where copper tubing is permitted, joints shall be brazed or be 
of equally strong metal union type. The melting point of the brazing 
materials may not be lower than 1000 [deg]F. The method of joining 
tubing may not reduce the strength of the tubing, such as by the cutting 
of threads.
    (3) Each hose coupling must be designed for a pressure of at least 
120 percent of the hose design pressure and so that there will be no 
leakage when connected.
    (4) Piping must be protected from damage due to thermal expansion 
and contraction, jarring, and vibration. Slip joints are not authorized 
for this purpose.
    (5) All piping, valves and fittings on a cargo tank must be proved 
free from leaks. This requirement is met when such piping, valves, and 
fittings have been tested after installation with gas or air and proved 
leak tight at not less than the design pressure marked on the cargo 
tank. This requirement is applicable to all hoses used in a cargo tank, 
except that hose may be tested before or after installation on the tank.
    (6) Each valve must be suitable for the tank design pressure at the 
tank design service temperature.
    (7) All fittings must be rated for the maximum tank pressure and 
suitable for the coldest temperature to which they will be subjected in 
actual service.
    (8) All piping, valves, and fittings must be grouped in the smallest 
practicable space and protected from damage as required by Sec.  
178.338-10.
    (9) When a pressure-building coil is used on a tank designed to 
handle oxygen or flammable ladings, the vapor connection to that coil 
must be provided with a valve or check valve as close to the tank shell 
as practicable to prevent the loss of vapor from the tank in case of 
damage to the coil. The liquid connection to that coil must also be 
provided with a valve.

[Amdt. 178-77, 48 FR 27704, June 16, 1983, as amended by Amdt. 178-89, 
54 FR 25019, June 12, 1989]



Sec.  178.338-9  Holding time.

    (a) ``Holding time'' is the time, as determined by testing, that 
will elapse from loading until the pressure of the contents, under 
equilibrium conditions, reaches the level of the lowest pressure control 
valve or pressure relief valve setting.
    (b) Holding time test. (1) The test to determine holding time must 
be performed by charging the tank with a cryogenic liquid having a 
boiling point, at a pressure of one atmosphere, absolute, no lower than 
the design service temperature of the tank. The tank must be charged to 
its maximum permitted filling density with that liquid and stabilized to 
the lowest practical pressure, which must be equal to or less than the 
pressure to be used for loading. The cargo tank together with its 
contents must then be exposed to ambient temperature.

[[Page 161]]

    (2) The tank pressure and ambient temperature must be recorded at 3-
hour intervals until the pressure level of the contents reaches the set-
to-discharge pressure of the pressure control valve or pressure relief 
valve with the lowest setting. This total time lapse in hours represents 
the measured holding time at the actual average ambient temperature. 
This measured holding time for the test cryogenic liquid must be 
adjusted to an equivalent holding time for each cryogenic liquid that is 
to be identified on or adjacent to the specification plate, at an 
average ambient temperature of 85 [deg]F. This is the rated holding time 
(RHT). The marked rated holding time (MRHT) displayed on or adjacent to 
the specification plate (see Sec.  178.338-18(c)(10)) may not exceed 
this RHT.
    (c) Optional test regimen. (1) If more than one cargo tank is made 
to the same design, only one cargo tank must be subjected to the full 
holding time test at the time of manufacture. However, each subsequent 
cargo tank made to the same design must be performance tested during its 
first trip. The holding time determined in this test may not be less 
than 90 percent of the marked rated holding time. This test must be 
performed in accordance with Sec. Sec.  173.318(g)(3) and 177.840(h) of 
this subchapter, regardless of the classification of the cryogenic 
liquid.
    (2) Same design. The term ``same design'' as used in this section 
means cargo tanks made to the same design type. See Sec.  178.320(a) for 
definition of ``design type''.
    (3) For a cargo tank used in nonflammable cryogenic liquid service, 
in place of the holding time tests prescribed in paragraph (b) of this 
section, the marked rated holding time (MRHT) may be determined as 
follows:
    (i) While the cargo tank is stationary, the heat transfer rate must 
be determined by measuring the normal evaporation rate (NER) of the test 
cryogenic liquid (preferably the lading, where feasible) maintained at 
approximately one atmosphere. The calculated heat transfer rate must be 
determined from:

q = [n([Delta] h)(85-t1)] / [ts - tf]

Where:

q = calculated heat transfer rate to cargo tank with lading, Btu/hr.
n = normal evaporation rate (NER), which is the rate of evaporation, 
          determined by the test of a test cryogenic liquid in a cargo 
          tank maintained at a pressure of approximately one atmosphere, 
          absolute, lb/hr.
[Delta] h = latent heat of vaporization of test fluid at test pressure, 
          Btu/lb.
ts = average temperature of outer shell during test, [deg]F.
t1 = equilibrium temperature of lading at maximum loading 
          pressure, [deg]F.
tf = equilibrium temperature of test fluid at one atmosphere, 
          [deg]F.

    (ii) The rated holding time (RHT) must be calculated as follows:

RHT = [(U2 - U1) W] / q

Where:

RHT = rated holding time, in hours
U1 and U2 = internal energy for the combined 
          liquid and vapor lading at the pressure offered for 
          transportation, and the set pressure of the applicable 
          pressure control valve or pressure relief valve, respectively, 
          Btu/lb.
W = total weight of the combined liquid and vapor lading in the cargo 
          tank, pounds.
q = calculated heat transfer rate to cargo tank with lading, Btu/hr.

    (iii) The MRHT (see Sec.  178.338-18(b)(9) of this subchapter) may 
not exceed the RHT.

[Amdt. 178-77, 48 FR 27704, June 16, 1983; 48 FR 50442, Nov. 1, 1983, as 
amended at 49 FR 24316, June 12, 1984; 49 FR 43965, Nov. 1, 1984; 59 FR 
55173, Nov. 3, 1994; Amdt. 178-118, 61 FR 51340, Oct. 1, 1996; 68 FR 
57634, Oct. 6, 2003; 71 FR 54397, Sept. 14, 2006]



Sec.  178.338-10  Accident damage protection.

    (a) All valves, fittings, pressure relief devices and other 
accessories to the tank proper, which are not isolated from the tank by 
closed intervening shut-off valves or check valves, must be installed 
within the motor vehicle framework or within a suitable collision 
resistant guard or housing, and appropriate ventilation must be 
provided. Each pressure relief device must be protected so that in the 
event of the upset of the vehicle onto a hard surface, the device's 
opening will not be prevented and its discharge will not be restricted.
    (b) Each protective device or housing, and its attachment to the 
vehicle

[[Page 162]]

structure, must be designed to withstand static loading in any direction 
that it may be loaded as a result of front, rear, side, or sideswipe 
collision, or the overturn of the vehicle. The static loading shall 
equal twice the loaded weight of the tank and attachments. A safety 
factor of four, based on the tensile strength of the material, shall be 
used. The protective device or the housing must be made of steel at 
least \3/16\-inch thick, or other material of equivalent strength.
    (c) Rear-end tank protection. Rear-end tank protections devices 
must:
    (1) Consist of at least one rear bumper designed to protect the 
cargo tank and piping in the event of a rear-end collision. The rear-end 
tank protection device design must transmit the force of the collision 
directly to the chassis of the vehicle. The rear-end tank protection 
device and its attachments to the chassis must be designed to withstand 
a load equal to twice the weight of the loaded cargo tank and 
attachments, using a safety factor of four based on the tensile strength 
of the materials used, with such load being applied horizontally and 
parallel to the major axis of the cargo tank. The rear-end tank 
protection device dimensions must meet the requirements of Sec.  393.86 
of this title and extend vertically to a height adequate to protect all 
valves and fittings located at the rear of the cargo tank from damage 
that could result in loss of lading; or
    (2) Conform to the requirements of Sec.  178.345-8(d).
    (d) Every part of the loaded cargo tank, and any associated valve, 
pipe, enclosure, or protective device or structure (exclusive of wheel 
assemblies), must be at least 14 inches above level ground.

[Amdt. 178-77, 48 FR 27705, June 16, 1983, as amended at 49 FR 24316, 
June 12, 1984; Amdt. 178-99, 58 FR 51534, Oct. 1, 1993; 68 FR 19282, 
Apr. 18, 2003; 68 FR 52371, Sept. 3, 2003; 85 FR 83402, Dec. 21, 2020; 
87 FR 79784, Dec. 27, 2022]



Sec.  178.338-11  Discharge control devices.

    (a) Excess-flow valves are not required.
    (b) Each liquid filling and liquid discharge line must be provided 
with a shut-off valve located as close to the tank as practicable. 
Unless this valve is manually operable at the valve, the line must also 
have a manual shut-off valve.
    (c) Except for a cargo tank that is used to transport argon, carbon 
dioxide, helium, krypton, neon, nitrogen, xenon, or mixtures thereof, 
each liquid filling and liquid discharge line must be provided with an 
on-vehicle remotely controlled self-closing shutoff valve.
    (1) If pressure from a reservoir or from an engine-driven pump or 
compressor is used to open this valve, the control must be of fail-safe 
design and spring-biased to stop the admission of such pressure into the 
cargo tank. If the jacket is not evacuated, the seat of the valve must 
be inside the tank, in the opening nozzle or flange, or in a companion 
flange bolted to the nozzle. If the jacket is evacuated, the remotely 
controlled valve must be located as close to the tank as practicable.
    (2) Each remotely controlled shut off valve must be provided with 
on-vehicle remote means of automatic closure, both mechanical and 
thermal. One means may be used to close more than one remotely 
controlled valve. Cable linkage between closures and remote operators 
must be corrosion resistant and effective in all types of environment 
and weather. The thermal means must consist of fusible elements actuated 
at a temperature not exceeding 121 [deg]C (250 [deg]F), or equivalent 
devices. The loading/unloading connection area is where hoses are 
connected to the permanent metal piping. The number and location of 
remote operators and thermal devices shall be as follows:
    (i) On a cargo tank motor vehicle over 3,500 gallons water capacity, 
remote means of automatic closure must be installed at the ends of the 
cargo tank in at least two diagonally opposite locations. If the 
loading/unloading connection at the cargo tank is not in the general 
vicinity of one of these locations, at least one additional thermal 
device must be installed so that heat from a fire in the loading/
unloading connection area will activate the emergency control system.
    (ii) On a cargo tank motor vehicle of 3,500 gallons water capacity 
or less, at least one remote means of automatic

[[Page 163]]

closure must be installed on the end of the cargo tank farthest away 
from the loading/unloading connection area. At least one thermal device 
must be installed so that heat from a fire in the loading/unloading 
connection area will activate the emergency control system.

[Amdt. 178-77, 48 FR 27705, June 16, 1983, as amended by Amdt. 178-105, 
59 FR 55173, Nov. 3, 1994; 60 FR 17402, Apr. 5, 1995; 68 FR 19282, Apr. 
18, 2003]



Sec.  178.338-12  Shear section.

    Unless the valve is located in a rear cabinet forward of and 
protected by the bumper (see Sec.  178.338-10(c)), the design and 
installation of each valve, damage to which could result in loss of 
liquid or vapor, must incorporate a shear section or breakage groove 
adjacent to, and outboard of, the valve. The shear section or breakage 
groove must yield or break under strain without damage to the valve that 
would allow the loss of liquid or vapor. The protection specified in 
Sec.  178.338-10 is not a substitute for a shear section or breakage 
groove.

[Amdt. 178-77, 49 FR 24316, June 12, 1984]



Sec.  178.338-13  Supporting and anchoring.

    (a) On a cargo tank motor vehicle designed and constructed so that 
the cargo tank constitutes in whole or in part the structural member 
used in place of a motor vehicle frame, the cargo tank or the jacket 
must be supported by external cradles or by load rings. For a cargo tank 
mounted on a motor vehicle frame, the tank or jacket must be supported 
by external cradles, load rings, or longitudinal members. If cradles are 
used, they must subtend at least 120 degrees of the cargo tank 
circumference. The design calculations for the supports and load-bearing 
tank or jacket, and the support attachments must include beam stress, 
shear stress, torsion stress, bending moment, and acceleration stress 
for the loaded vehicle as a unit, using a safety factor of four, based 
on the tensile strength of the material, and static loading that uses 
the weight of the cargo tank and its attachments when filled to the 
design weight of the lading (see appendix G in Section VIII of the ASME 
Code) (IBR, see Sec.  171.7 of this subchapter), multiplied by the 
following factors. The effects of fatigue must also be considered in the 
calculations. Minimum static loadings must be as follows:
    (1) For a vacuum-insulated cargo tank--
    (i) Vertically downward of 2;
    (ii) Vertically upward of 2;
    (iii) Longitudinally of 2; and
    (iv) Laterally of 2.
    (2) For any other insulated cargo tank--
    (i) Vertically downward of 3;
    (ii) Vertically upward of 2;
    (iii) Longitudinally of 2; and
    (iv) Laterally of 2.
    (b) When a loaded tank is supported within the vacuum jacket by 
structural members, the design calculations for the tank and its 
structural members must be based on a safety factor of four and the 
tensile strength of the material at ambient temperature. The enhanced 
tensile strength of the material at actual operating temperature may be 
substituted for the tensile strength at ambient temperature to the 
extent recognized in the ASME Code for static loadings. Static loadings 
must take into consideration the weight of the tank and the structural 
members when the tank is filled to the design weight of lading (see 
Appendix G of Section VIII, Division 1 of the ASME Code), multiplied by 
the following factors. Static loadings must take into consideration the 
weight of the tank and the structural members when the tank is filled to 
the design weight of lading (see appendix G in Section VIII of the ASME 
Code), multiplied by the following factors. When load rings in the 
jacket are used for supporting the tank, they must be designed to carry 
the fully loaded tank at the specified static loadings, plus external 
pressure. Minimum static loadings must be as follows:
    (1) Vertically downward of 2;
    (2) Vertically upward of 1\1/2\;
    (3) Longitudinally of 1\1/2\; and, (4) Laterally of 1\1/2\.

[68 FR 19282, Apr. 18, 2003, as amended at 68 FR 75754, Dec. 31, 2003]



Sec.  178.338-14  Gauging devices.

    (a) Liquid level gauging devices. (1) Unless a cargo tank is 
intended to be

[[Page 164]]

filled by weight, it must be equipped with one or more gauging devices, 
which accurately indicate the maximum permitted liquid level at the 
loading pressure, in order to provide a minimum of two percent outage 
below the inlet of the pressure control valve or pressure relief valve 
at the condition of incipient opening of that valve. A fixed-length dip 
tube, a fixed trycock line, or a differential pressure liquid level 
gauge must be used as the primary control for filling. Other gauging 
devices, except gauge glasses, may be used, but not as the primary 
control for filling.
    (2) The design pressure of each liquid level gauging device must be 
at least that of the tank.
    (3) If a fixed length dip tube or trycock line gauging device is 
used, it must consist of a pipe or tube of small diameter equipped with 
a valve at or near the jacket and extending into the cargo tank to a 
specified filling height. The fixed height at which the tube ends in the 
cargo tank must be such that the device will function when the liquid 
reaches the maximum level permitted in loading.
    (4) The liquid level gauging device used as a primary control for 
filling must be designed and installed to accurately indicate the 
maximum filling level at the point midway of the tank both 
longitudinally and laterally.
    (b) Pressure gauges. Each cargo tank must be provided with a 
suitable pressure gauge indicating the lading pressure and located on 
the front of the jacket so it can be read by the driver in the rear view 
mirror. Each gauge must have a reference mark at the cargo tank design 
pressure or the set pressure of the pressure relief valve or pressure 
control valve, whichever is lowest.
    (c) Orifices. All openings for dip tube gauging devices and pressure 
gauges in flammable cryogenic liquid service must be restricted at or 
inside the jacket by orifices no larger than 0.060-inch diameter. 
Trycock lines, if provided, may not be greater than \1/2\-inch nominal 
pipe size.

[Amdt. 178-77, 48 FR 27706, June 16, 1983, as amended at 49 FR 24317, 
June 12, 1984]



Sec.  178.338-15  Cleanliness.

    A cargo tank constructed for oxygen service must be thoroughly 
cleaned to remove all foreign material in accordance with CGA G-4.1 
(IBR, see Sec.  171.7 of this subchapter). All loose particles from 
fabrication, such as weld beads, dirt, grinding wheel debris, and other 
loose materials, must be removed prior to the final closure of the 
manhole of the tank. Chemical or solvent cleaning with a material 
compatible with the intending lading must be performed to remove any 
contaminants likely to react with the lading.

[68 FR 75755, Dec. 31, 2003]



Sec.  178.338-16  Inspection and testing.

    (a) General. The material of construction of a tank and its 
appurtenances must be inspected for conformance to Section VIII of the 
ASME Code (IBR, see Sec.  171.7 of this subchapter). The tank must be 
subjected to either a hydrostatic or pneumatic test. The test pressure 
must be one and one-half times the sum of the design pressure, plus 
static head of lading, plus 101.3 kPa (14.7 psi) if subjected to 
external vacuum, except that for tanks constructed in accordance with 
Part UHT in Section VIII of the ASME Code the test pressure must be 
twice the design pressure.
    (b) Additional requirements for pneumatic test. A pneumatic test may 
be used in place of the hydrostatic test. Due regard for protection of 
all personnel should be taken because of the potential hazard involved 
in a pneumatic test. The pneumatic test pressure in the tank must be 
reached by gradually increasing the pressure to one-half of the test 
pressure. Thereafter, the test pressure must be increased in steps of 
approximately one-tenth of the test pressure until the required test 
pressure has been reached. Then the pressure must be reduced to a value 
equal to four-fifths of the test pressure and held for a sufficient time 
to permit inspection of the cargo tank for leaks.
    (c) Weld inspection. All tank shell or head welds subject to 
pressure shall be radiographed in accordance with Section VIII of the 
ASME Code. A tank which has been subjected to inspection

[[Page 165]]

by the magnetic particle method, the liquid penetrant method, or any 
method involving a material deposit on the interior tank surface, must 
be cleaned to remove any such residue by scrubbing or equally effective 
means, and all such residue and cleaning solution must be removed from 
the tank prior to final closure of the tank.
    (d) Defect repair. All cracks and other defects must be repaired as 
prescribed in Section VIII of the ASME Code. The welder and the welding 
procedure must be qualified in accordance with Section IX of the ASME 
Code (IBR, see Sec.  171.7 of this subchapter). After repair, the tank 
must again be postweld heat-treated, if such heat treatment was 
previously performed, and the repaired areas must be retested.
    (e) Verification must be made of the interior cleanliness of a tank 
constructed for oxygen service by means that assure that all 
contaminants that are likely to react with the lading have been removed 
as required by Sec.  178.338-15.

[Amdt. 178-77, 48 FR 27706, June 16, 1983, as amended at 49 FR 24317, 
June 12, 1984; 49 FR 42736, Oct. 24, 1984; 68 FR 75755, Dec. 31, 2003]



Sec.  178.338-17  Pumps and compressors.

    (a) Liquid pumps and gas compressors, if used, must be of suitable 
design, adequately protected against breakage by collision, and kept in 
good condition. They may be driven by motor vehicle power take-off or 
other mechanical, electrical, or hydraulic means. Unless they are of the 
centrifugal type, they shall be equipped with suitable pressure actuated 
by-pass valves permitting flow from discharge to suction to the tank.
    (b) A valve or fitting made of aluminum with internal rubbing or 
abrading aluminum parts that may come in contact with oxygen (cryogenic 
liquid) may not be installed on any cargo tank used to transport oxygen 
(cryogenic liquid) unless the parts are anodized in accordance with ASTM 
B 580 (IBR, see Sec.  171.7 of this subchapter).

[Amdt. 178-89, 54 FR 25020, June 12, 1989, as amended at 55 FR 37058, 
Sept. 7, 1990; 67 FR 61016, Sept. 27, 2002; 68 FR 75755, Dec. 31, 2003]



Sec.  178.338-18  Marking.

    (a) General. Each cargo tank certified after October 1, 2004 must 
have a corrosion-resistant metal name plate (ASME Plate) and 
specification plate permanently attached to the cargo tank by brazing, 
welding, or other suitable means on the left side near the front, in a 
place accessible for inspection. If the specification plate is attached 
directly to the cargo tank wall by welding, it must be welded to the 
tank before the cargo tank is postweld heat treated.
    (1) The plates must be legibly marked by stamping, embossing, or 
other means of forming letters into the metal of the plate, with the 
information required in paragraphs (b) and (c) of this section, in 
addition to that required by Section VIII of the ASME Code (IBR, see 
Sec.  171.7 of this subchapter), in characters at least \3/16\ inch high 
(parenthetical abbreviations may be used). All plates must be maintained 
in a legible condition.
    (2) Each insulated cargo tank must have additional plates, as 
described, attached to the jacket in the location specified unless the 
specification plate is attached to the chassis and has the information 
required in paragraphs (b) and (c) of this section.
    (3) The information required for both the name and specification 
plate may be displayed on a single plate. If the information required by 
this section is displayed on a plate required by Section VIII of the 
ASME Code, the information need not be repeated on the name and 
specification plates.
    (4) The specification plate may be attached to the cargo tank motor 
vehicle chassis rail by brazing, welding, or other suitable means on the 
left side near the front head, in a place accessible for inspection. If 
the specification plate is attached to the chassis rail, then the cargo 
tank serial number assigned by the cargo tank manufacturer must be 
included on the plate.
    (b) Name plate. The following information must be marked on the name 
plate in accordance with this section:
    (1) DOT-specification number MC 338 (DOT MC 338).
    (2) Original test date (Orig, Test Date).
    (3) MAWP in psig.

[[Page 166]]

    (4) Cargo tank test pressure (Test P), in psig.
    (5) Cargo tank design temperature (Design Temp. Range) ____ [deg]F 
to ____ [deg]F.
    (6) Nominal capacity (Water Cap.), in pounds.
    (7) Maximum design density of lading (Max. Lading density), in 
pounds per gallon.
    (8) Material specification number--shell (Shell matl, yyy * * *), 
where ``yyy'' is replaced by the alloy designation and ``* * *'' is 
replaced by the alloy type.
    (9) Material specification number--heads (Head matl. yyy * * *), 
where ``yyy'' is replaced by the alloy designation and ``* * *'' by the 
alloy type.

    Note: When the shell and heads materials are the same thickness, 
they may be combined, (Shell & head matl, yyy * * *).

    (10) Weld material (Weld matl.).
    (11) Minimum Thickness-shell (Min. Shell-thick), in inches. When 
minimum shell thicknesses are not the same for different areas, show 
(top ____, side ____, bottom ____, in inches).
    (12) Minimum thickness-heads (Min heads thick.), in inches.
    (13) Manufactured thickness-shell (Mfd. Shell thick.), top ____, 
side ____, bottom ____, in inches. (Required when additional thickness 
is provided for corrosion allowance.)
    (14) Manufactured thickness-heads (Mfd. Heads thick.), in inches. 
(Required when additional thickness is provided for corrosion 
allowance.)
    (15) Exposed surface area, in square feet.
    (c) Specification plate. The following information must be marked on 
the specification plate in accordance with this section:
    (1) Cargo tank motor vehicle manufacturer (CTMV mfr.).
    (2) Cargo tank motor vehicle certification date (CTMV cert. date).
    (3) Cargo tank manufacturer (CT mfr.).
    (4) Cargo tank date of manufacture (CT date of mfr.), month and 
year.
    (5) Maximum weight of lading (Max. Payload), in pounds.
    (6) Maximum loading rate in gallons per minute (Max. Load rate, 
GPM).
    (7) Maximum unloading rate in gallons per minute (Max Unload rate).
    (8) Lining materials (Lining), if applicable.
    (9) ``Insulated for oxygen service'' or ``Not insulated for oxygen 
service'' as appropriate.
    (10) Marked rated holding time for at least one cryogenic liquid, in 
hours, and the name of that cryogenic liquid (MRHT ____ hrs, name of 
cryogenic liquid). Marked rated holding marking for additional cryogenic 
liquids may be displayed on or adjacent to the specification plate.
    (11) Cargo tank serial number (CT serial), as assigned by cargo tank 
manufacturer, if applicable.

    Note 1 to paragraph (c): See Sec.  173.315(a) of this chapter 
regarding water capacity.
    Note 2 to paragraph (c): When the shell and head materials are the 
same thickness, they may be combined (Shell & head matl, yyy***).

    (d) The design weight of lading used in determining the loading in 
Sec. Sec.  178.338-3 (b), 178.338-10 (b) and (c), and 178.338-13 (b), 
must be shown as the maximum weight of lading marking required by 
paragraph (c) of this section.

[68 FR 19283, Apr. 18, 2003, as amended at 68 FR 57634, Oct. 6, 2003; 68 
FR 75755, Dec. 31, 2003]



Sec.  178.338-19  Certification.

    (a) At or before the time of delivery, the manufacturer of a cargo 
tank motor vehicle shall furnish to the owner of the completed vehicle 
the following:
    (1) The tank manufacturer's data report as required by the ASME Code 
(IBR, see Sec.  171.7 of this subchapter), and a certificate bearing the 
manufacturer's vehicle serial number stating that the completed cargo 
tank motor vehicle conforms to all applicable requirements of 
Specification MC 338, including Section VIII of the ASME Code (IBR, see 
Sec.  171.7 of this subchapter) in effect on the date (month, year) of 
certification. The registration numbers of the manufacturer, the Design 
Certifying Engineer, and the Registered Inspector, as appropriate, must 
appear on the certificates (see subpart F, part 107 in subchapter B of 
this chapter).
    (2) A photograph, pencil rub, or other facsimile of the plates 
required by paragraphs (a) and (b) of Sec.  178.338-18.

[[Page 167]]

    (b) In the case of a cargo tank vehicle manufactured in two or more 
stages, each manufacturer who performs a manufacturing operation on the 
incomplete vehicle or portion thereof shall furnish to the succeeding 
manufacturer, at or before the time of delivery, a certificate covering 
the particular operation performed by that manufacturer, and any 
certificates received from previous manufacturers, Registered 
Inspectors, and Design Certifying Engineers. The certificates must 
include sufficient sketches, drawings, and other information to indicate 
the location, make, model and size of each valve and the arrangement of 
all piping associated with the tank. Each certificate must be signed by 
an official of the manufacturing firm responsible for the portion of the 
complete cargo tank vehicle represented thereby, such as basic tank 
fabrication, insulation, jacket, or piping. The final manufacturer shall 
furnish the owner with all certificates, as well as the documents 
required by paragraph (a) of this section.
    (c) The owner shall retain the data report, certificates, and 
related papers throughout his ownership of the cargo tank. In the event 
of change of ownership, the prior owner shall retain non-fading 
photographically reproduced copies of these documents for at least one 
year. Each operator using the cargo tank vehicle, if not the owner 
thereof, shall obtain a copy of the data report and the certificate or 
certificates and retain them during the time he uses the cargo tank and 
for at least one year thereafter.

(Approved by the Office of Management and Budget under control number 
2137-0017)

[Amdt. 178-77, 48 FR 27707, 27713, June 16, 1983, as amended by Amdt. 
178-89, 55 FR 37058, Sept. 7, 1990; Amdt. 178-99, 58 FR 51534, Oct. 1, 
1993; 62 FR 51561, Oct. 1, 1997; 68 FR 75755, Dec. 31, 2003]



Sec. Sec.  178.340-178.343  [Reserved]



Sec.  178.345  General design and construction requirements applicable to  
Specification DOT 406 (Sec.  178.346), DOT 407 (Sec.  178.347), and DOT 412 
(Sec.  178.348) cargo tank motor vehicles. 



Sec.  178.345-1  General requirements.

    (a) Specification DOT 406, DOT 407 and DOT 412 cargo tank motor 
vehicles must conform to the requirements of this section in addition to 
the requirements of the applicable specification contained in Sec. Sec.  
178.346, 178.347 or 178.348.
    (b) All specification requirements are minimum requirements.
    (c) Definitions. See Sec.  178.320(a) for the definition of certain 
terms used in Sec. Sec.  178.345, 178.346, 178.347, and 178.348. In 
addition, the following definitions apply to Sec. Sec.  178.345, 
178.346, 178.347, and 178.348:
    Appurtenance means any cargo tank accessory attachment that has no 
lading retention or containment function and provides no structural 
support to the cargo tank.
    Baffle means a non-liquid-tight transverse partition device that 
deflects, checks or regulates fluid motion in a tank.
    Bulkhead means a liquid-tight transverse closure at the ends of or 
between cargo tanks.
    Charging line means a hose, tube, pipe, or similar device used to 
pressurize a tank with material other than the lading.
    Companion flange means one of two mating flanges where the flange 
faces are in contact or separated only by a thin leak sealing gasket and 
are secured to one another by bolts or clamps.
    Connecting structure means the structure joining two cargo tanks.
    Constructed and certified in conformance with the ASME Code means 
the cargo tank is constructed and stamped in accordance with the ASME 
Code, and is inspected and certified by an Authorized Inspector.
    Constructed in accordance with the ASME Code means the cargo tank is 
constructed in accordance with the ASME Code with the authorized 
exceptions (see Sec. Sec.  178.346, 178.347, and 178.348)

[[Page 168]]

and is inspected and certified by a Registered Inspector.
    External self-closing stop-valve means a self-closing stop-valve 
designed so that the self-stored energy source is located outside the 
cargo tank and the welded flange.
    Extreme dynamic loading means the maximum single-acting loading a 
cargo tank motor vehicle may experience during its expected life, 
excluding accident loadings.
    Flange means the structural ring for guiding or attachment of a pipe 
or fitting with another flange (companion flange), pipe, fitting or 
other attachment.
    Inspection pressure means the pressure used to determine leak 
tightness of the cargo tank when testing with pneumatic pressure.
    Internal self-closing stop-valve means a self-closing stop-valve 
designed so that the self-stored energy source is located inside the 
cargo tank or cargo tank sump, or within the welded flange, and the 
valve seat is located within the cargo tank or within one inch of the 
external face of the welded flange or sump of the cargo tank.
    Lading means the hazardous material contained in a cargo tank.
    Loading/unloading connection means the fitting in the loading/
unloading line farthest from the loading/unloading outlet to which the 
loading/unloading hose or device is attached.
    Loading/unloading outlet means the cargo tank outlet used for normal 
loading/unloading operations.
    Loading/unloading stop-valve means the stop valve farthest from the 
cargo tank loading/unloading outlet to which the loading/unloading 
connection is attached.
    MAWP. See Sec.  178.320(a).
    Multi-specification cargo tank motor vehicle means a cargo tank 
motor vehicle equipped with two or more cargo tanks fabricated to more 
than one cargo tank specification.
    Normal operating loading means the loading a cargo tank motor 
vehicle may be expected to experience routinely in operation.
    Nozzle means the subassembly consisting of a pipe or tubular section 
with or without a welded or forged flange on one end.
    Outlet means any opening in the shell or head of a cargo tank, 
(including the means for attaching a closure), except that the following 
are not outlets: A threaded opening securely closed during 
transportation with a threaded plug or a threaded cap, a flanged opening 
securely closed during transportation with a bolted or welded blank 
flange, a manhole, or gauging devices, thermometer wells, and safety 
relief devices.
    Outlet stop-valve means the stop-valve at the cargo tank loading/
unloading outlet.
    Pipe coupling means a fitting with internal threads on both ends.
    Rear bumper means the structure designed to prevent a vehicle or 
object from under-riding the rear of a motor vehicle. See Sec.  393.86 
of this title.
    Rear-end tank protection device means the structure designed to 
protect a cargo tank and any lading retention piping or devices in case 
of a rear end collision.
    Sacrificial device means an element, such as a shear section, 
designed to fail under a load in order to prevent damage to any lading 
retention part or device. The device must break under strain at no more 
than 70 percent of the strength of the weakest piping element between 
the cargo tank and the sacrificial device. Operation of the sacrificial 
device must leave the remaining piping and its attachment to the cargo 
tank intact and capable of retaining lading.
    Self-closing stop-valve means a stop-valve held in the closed 
position by means of self-stored energy, which opens only by application 
of an external force and which closes when the external force is 
removed.
    Shear section means a sacrificial device fabricated in such a manner 
as to abruptly reduce the wall thickness of the adjacent piping or valve 
material by at least 30 percent.
    Shell means the circumferential portion of a cargo tank defined by 
the basic design radius or radii excluding the closing heads.
    Stop-valve means a valve that stops the flow of lading.
    Sump means a protrusion from the bottom of a cargo tank shell 
designed

[[Page 169]]

to facilitate complete loading and unloading of lading.
    Tank means a container, consisting of a shell and heads, that forms 
a pressure tight vessel having openings designed to accept pressure 
tight fittings or closures, but excludes any appurtenances, 
reinforcements, fittings, or closures.
    Test pressure means the pressure to which a tank is subjected to 
determine pressure integrity.
    Toughness of material means the capability of a material to absorb 
the energy represented by the area under the stress strain curve 
(indicating the energy absorbed per unit volume of the material) up to 
the point of rupture.
    Vacuum cargo tank means a cargo tank that is loaded by reducing the 
pressure in the cargo tank to below atmospheric pressure.
    Variable specification cargo tank means a cargo tank that is 
constructed in accordance with one specification, but which may be 
altered to meet another specification by changing relief device, 
closures, lading discharge devices, and other lading retention devices.
    Void means the space between tank heads or bulkheads and a 
connecting structure.
    Welded flange means a flange attached to the tank by a weld joining 
the tank shell to the cylindrical outer surface of the flange, or by a 
fillet weld joining the tank shell to a flange shaped to fit the shell 
contour.
    (d) A manufacturer of a cargo tank must hold a current ASME 
certificate of authorization and must be registered with the Department 
in accordance with part 107, subpart F of this chapter.
    (e) All construction must be certified by an Authorized Inspector or 
by a Registered Inspector as applicable to the cargo tank.
    (f) Each cargo tank must be designed and constructed in conformance 
with the requirements of the applicable cargo tank specification. Each 
DOT 412 cargo tank with a ``MAWP'' greater than 15 psig, and each DOT 
407 cargo tank with a maximum allowable working pressure greater than 35 
psig must be ``constructed and certified in conformance with Section 
VIII of the ASME Code'' (IBR, see Sec.  171.7 of this subchapter) except 
as limited or modified by the applicable cargo tank specification. Other 
cargo tanks must be ``constructed in accordance with Section VIII of the 
ASME Code,'' except as limited or modified by the applicable cargo tank 
specification.
    (g) Requirements relating to parts and accessories on motor 
vehicles, which are contained in part 393 of the Federal Motor Carrier 
Safety Regulations of this title, are incorporated into these 
specifications.
    (h) Any additional requirements prescribed in part 173 of this 
subchapter that pertain to the transportation of a specific lading are 
incorporated into these specifications.
    (i) Cargo tank motor vehicle composed of multiple cargo tanks. (1) A 
cargo tank motor vehicle composed of more than one cargo tank may be 
constructed with the cargo tanks made to the same specification or to 
different specifications. Each cargo tank must conform in all respects 
with the specification for which it is certified.
    (2) The strength of the connecting structure joining multiple cargo 
tanks in a cargo tank motor vehicle must meet the structural design 
requirements in Sec.  178.345-3. Any void within the connecting 
structure must be equipped with a drain located on the bottom centerline 
that is accessible and kept open at all times. For carbon steel, self-
supporting cargo tanks, the drain configuration may consist of a single 
drain of at least 1.0 inch diameter, or two or more drains of at least 
0.5 inch diameter, 6.0 inches apart, one of which is located as close to 
the bottom centerline as practicable. Vapors trapped in a void within 
the connecting structure must be allowed to escape to the atmosphere 
either through the drain or a separate vent.
    (j) Variable specification cargo tank. A cargo tank that may be 
physically altered to conform to another cargo tank specification must 
have the required physical alterations to convert from

[[Page 170]]

one specification to another clearly indicated on the variable 
specification plate.

[Amdt. 178-89, 54 FR 25020, June 12, 1989, as amended at 55 FR 37058, 
Sept. 7, 1990; Amdt. 178-105, 59 FR 55173, Nov. 3, 1994; Amdt. 178-118, 
61 FR 51340, Oct. 1, 1996; 66 FR 45387, 45389, Aug. 28, 2001; 68 FR 
19283, Apr. 18, 2003; 68 FR 52371, Sept. 3, 2003; 68 FR 75755, Dec. 31, 
2003; 70 FR 56099, Sept. 23, 2005; 76 FR 43532, July 20, 2011]



Sec.  178.345-2  Material and material thickness.

    (a) All material for shell, heads, bulkheads, and baffles must 
conform to Section II of the ASME Code (IBR, see Sec.  171.7 of this 
subchapter) except as follows:
    (1) The following steels are also authorized for cargo tanks 
``constructed in accordance with the ASME Code'', Section VIII.

ASTM A 569
ASTM A 570
ASTM A 572
ASTM A 622
ASTM A 656
ASTM A 715
ASTM A 1008/ A 1008M, ASTM A 1011/A 1011M

    (2) Aluminum alloys suitable for fusion welding and conforming with 
the 0, H32 or H34 tempers of one of the following ASTM specifications 
may be used for cargo tanks ``constructed in accordance with the ASME 
Code'':

ASTM B-209 Alloy 5052
ASTM B-209 Alloy 5086
ASTM B-209 Alloy 5154
ASTM B-209 Alloy 5254
ASTM B-209 Alloy 5454
ASTM B-209 Alloy 5652


All heads, bulkheads and baffles must be of 0 temper (annealed) or 
stronger tempers. All shell materials shall be of H 32 or H 34 tempers 
except that the lower ultimate strength tempers may be used if the 
minimum shell thicknesses in the tables are increased in inverse 
proportion to the lesser ultimate strength.
    (b) Minimum thickness. The minimum thickness for the shell and heads 
(or baffles and bulkheads when used as tank reinforcement) must be no 
less than that determined under criteria for minimum thickness specified 
in Sec.  178.320(a).
    (c) Corrosion or abrasion protection. When required by 49 CFR part 
173 for a particular lading, a cargo tank or a part thereof, subject to 
thinning by corrosion or mechanical abrasion due to the lading, must be 
protected by providing the tank or part of the tank with a suitable 
increase in thickness of material, a lining or some other suitable 
method of protection.
    (1) Corrosion allowance. Material added for corrosion allowance need 
not be of uniform thickness if different rates of attack can reasonably 
be expected for various areas of the cargo tank.
    (2) Lining. Lining material must consist of a nonporous, homogeneous 
material not less elastic than the parent metal and substantially immune 
to attack by the lading. The lining material must be bonded or attached 
by other appropriate means to the cargo tank wall and must be 
imperforate when applied. Any joint or seam in the lining must be made 
by fusing the materials together, or by other satisfactory means.

[Amdt. 178-89, 54 FR 25021, June 12, 1989, as amended at 55 FR 37059, 
Sept. 7, 1990; 56 FR 27876, June 17, 1991; Amdt. 178-97, 57 FR 45465, 
Oct. 1, 1992; Amdt. 178-118, 61 FR 51341, Oct. 1, 1996; 68 FR 19283, 
Apr. 18, 2003; 68 FR 75755, Dec. 31, 2003; 70 FR 34076, June 13, 2005]



Sec.  178.345-3  Structural integrity.

    (a) General requirements and acceptance criteria. (1) The maximum 
calculated design stress at any point in the cargo tank wall may not 
exceed the maximum allowable stress value prescribed in Section VIII of 
the ASME Code (IBR, see Sec.  171.7 of this subchapter), or 25 percent 
of the tensile strength of the material used at design conditions.
    (2) The relevant physical properties of the materials used in each 
cargo tank may be established either by a certified test report from the 
material manufacturer or by testing in conformance with a recognized 
national standard. In either case, the ultimate tensile strength of the 
material used in the design may not exceed 120 percent of the minimum 
ultimate tensile strength specified in either the ASME Code or the ASTM 
standard to which the material is manufactured.

[[Page 171]]

    (3) The maximum design stress at any point in the cargo tank must be 
calculated separately for the loading conditions described in paragraphs 
(b) and (c) of this section. Alternate test or analytical methods, or a 
combination thereof, may be used in place of the procedures described in 
paragraphs (b) and (c) of this section, if the methods are accurate and 
verifiable. TTMA RP 96-01, Structural Integrity of DOT 406, DOT 407, and 
DOT 412 Cylindrical Cargo Tanks, may be used as guidance in performing 
the calculations.
    (4) Corrosion allowance material may not be included to satisfy any 
of the design calculation requirements of this section.
    (b) ASME Code design and construction. The static design and 
construction of each cargo tank must be in accordance with Section VIII 
of the ASME Code. The cargo tank design must include calculation of 
stresses generated by the MAWP, the weight of the lading, the weight of 
structures supported by the cargo tank wall and the effect of 
temperature gradients resulting from lading and ambient temperature 
extremes. When dissimilar materials are used, their thermal coefficients 
must be used in the calculation of thermal stresses.
    (1) Stress concentrations in tension, bending and torsion which 
occur at pads, cradles, or other supports must be considered in 
accordance with appendix G in Section VIII of the ASME Code.
    (2) Longitudinal compressive buckling stress for ASME certified 
vessels must be calculated using paragraph UG-23(b) in Section VIII of 
the ASME Code. For cargo tanks not required to be certified in 
accordance with the ASME Code, compressive buckling stress may be 
calculated using alternative analysis methods which are accurate and 
verifiable. When alternative methods are used, calculations must include 
both the static loads described in this paragraph and the dynamic loads 
described in paragraph (c) of this section.
    (3) Cargo tank designers and manufacturers must consider all of the 
conditions specified in Sec.  173.33(c) of this subchapter when matching 
a cargo tank's performance characteristic to the characteristic of each 
lading transported.
    (c) Shell design. Shell stresses resulting from static or dynamic 
loadings, or combinations thereof, are not uniform throughout the cargo 
tank motor vehicle. The vertical, longitudinal, and lateral normal 
operating loadings can occur simultaneously and must be combined. The 
vertical, longitudinal and lateral extreme dynamic loadings occur 
separately and need not be combined.
    (1) Normal operating loadings. The following procedure addresses 
stress in the cargo tank shell resulting from normal operating loadings. 
The effective stress (the maximum principal stress at any point) must be 
determined by the following formula:

S = 0.5(Sy + SX)  
[0.25(Sy - SX)\2\ + SS\2\]\0.5\


Where:
    (i) S = effective stress at any given point under the combination of 
static and normal operating loadings that can occur at the same time, in 
psi.
    (ii) Sy = circumferential stress generated by the MAWP 
and external pressure, when applicable, plus static head, in psi.
    (iii) Sx = The following net longitudinal stress 
generated by the following static and normal operating loading 
conditions, in psi:
    (A) The longitudinal stresses resulting from the MAWP and external 
pressure, when applicable, plus static head, in combination with the 
bending stress generated by the static weight of the fully loaded cargo 
tank motor vehicle, all structural elements, equipment and appurtenances 
supported by the cargo tank wall;
    (B) The tensile or compressive stress resulting from normal 
operating longitudinal acceleration or deceleration. In each case, the 
forces applied must be 0.35 times the vertical reaction at the 
suspension assembly, applied at the road surface, and as transmitted to 
the cargo tank wall through the suspension assembly of a trailer during 
deceleration; or the horizontal pivot of the truck tractor or converter 
dolly fifth wheel, or the drawbar hinge on the fixed dolly during 
acceleration; or anchoring and support members of a

[[Page 172]]

truck during acceleration and deceleration, as applicable. The vertical 
reaction must be calculated based on the static weight of the fully 
loaded cargo tank motor vehicle, all structural elements, equipment and 
appurtenances supported by the cargo tank wall. The following loadings 
must be included:
    (1) The axial load generated by a decelerative force;
    (2) The bending moment generated by a decelerative force;
    (3) The axial load generated by an accelerative force; and
    (4) The bending moment generated by an accelerative force; and
    (C) The tensile or compressive stress generated by the bending 
moment resulting from normal operating vertical accelerative force equal 
to 0.35 times the vertical reaction at the suspension assembly of a 
trailer; or the horizontal pivot of the upper coupler (fifth wheel) or 
turntable; or anchoring and support members of a truck, as applicable. 
The vertical reaction must be calculated based on the static weight of 
the fully loaded cargo tank motor vehicle, all structural elements, 
equipment and appurtenances supported by the cargo tank wall.
    (iv) SS = The following shear stresses generated by the 
following static and normal operating loading conditions, in psi:
    (A) The static shear stress resulting from the vertical reaction at 
the suspension assembly of a trailer, and the horizontal pivot of the 
upper coupler (fifth wheel) or turntable; or anchoring and support 
members of a truck, as applicable. The vertical reaction must be 
calculated based on the static weight of the fully loaded cargo tank 
motor vehicle, all structural elements, equipment and appurtenances 
supported by the cargo tank wall;
    (B) The vertical shear stress generated by a normal operating 
accelerative force equal to 0.35 times the vertical reaction at the 
suspension assembly of a trailer; or the horizontal pivot of the upper 
coupler (fifth wheel) or turntable; or anchoring and support members of 
a truck, as applicable. The vertical reaction must be calculated based 
on the static weight of the fully loaded cargo tank motor vehicle, all 
structural elements, equipment and appurtenances supported by the cargo 
tank wall;
    (C) The lateral shear stress generated by a normal operating lateral 
accelerative force equal to 0.2 times the vertical reaction at each 
suspension assembly of a trailer, applied at the road surface, and as 
transmitted to the cargo tank wall through the suspension assembly of a 
trailer, and the horizontal pivot of the upper coupler (fifth wheel) or 
turntable; or anchoring and support members of a truck, as applicable. 
The vertical reaction must be calculated based on the static weight of 
the fully loaded cargo tank motor vehicle, all structural elements, 
equipment and appurtenances supported by the cargo tank wall; and
    (D) The torsional shear stress generated by the same lateral forces 
as described in paragraph (c)(1)(iv)(C) of this section.
    (2) Extreme dynamic loadings. The following procedure addresses 
stress in the cargo tank shell resulting from extreme dynamic loadings. 
The effective stress (the maximum principal stress at any point) must be 
determined by the following formula:

S = 0.5(Sy + Sx) [0.25(Sy - Sx)\2\ + 
SS\2\]\0.5\


Where:

    (i) S = effective stress at any given point under a combination of 
static and extreme dynamic loadings that can occur at the same time, in 
psi.
    (ii) Sy = circumferential stress generated by MAWP and 
external pressure, when applicable, plus static head, in psi.
    (iii) Sx = the following net longitudinal stress 
generated by the following static and extreme dynamic loading 
conditions, in psi:
    (A) The longitudinal stresses resulting from the MAWP and external 
pressure, when applicable, plus static head, in combination with the 
bending stress generated by the static weight of the fully loaded cargo 
tank motor vehicle, all structural elements, equipment and appurtenances 
supported by the tank wall;
    (B) The tensile or compressive stress resulting from extreme 
longitudinal acceleration or deceleration. In each case the forces 
applied must be 0.7

[[Page 173]]

times the vertical reaction at the suspension assembly, applied at the 
road surface, and as transmitted to the cargo tank wall through the 
suspension assembly of a trailer during deceleration; or the horizontal 
pivot of the truck tractor or converter dolly fifth wheel, or the 
drawbar hinge on the fixed dolly during acceleration; or the anchoring 
and support members of a truck during acceleration and deceleration, as 
applicable. The vertical reaction must be calculated based on the static 
weight of the fully loaded cargo tank motor vehicle, all structural 
elements, equipment and appurtenances supported by the cargo tank wall. 
The following loadings must be included:
    (1) The axial load generated by a decelerative force;
    (2) The bending moment generated by a decelerative force;
    (3) The axial load generated by an accelerative force; and
    (4) The bending moment generated by an accelerative force; and
    (C) The tensile or compressive stress generated by the bending 
moment resulting from an extreme vertical accelerative force equal to 
0.7 times the vertical reaction at the suspension assembly of a trailer, 
and the horizontal pivot of the upper coupler (fifth wheel) or 
turntable; or the anchoring and support members of a truck, as 
applicable. The vertical reaction must be calculated based on the static 
weight of the fully loaded cargo tank motor vehicle, all structural 
elements, equipment and appurtenances supported by the cargo tank wall.
    (iv) SS = The following shear stresses generated by 
static and extreme dynamic loading conditions, in psi:
    (A) The static shear stress resulting from the vertical reaction at 
the suspension assembly of a trailer, and the horizontal pivot of the 
upper coupler (fifth wheel) or turntable; or anchoring and support 
members of a truck, as applicable. The vertical reaction must be 
calculated based on the static weight of the fully loaded cargo tank 
motor vehicle, all structural elements, equipment and appurtenances 
supported by the cargo tank wall;
    (B) The vertical shear stress generated by an extreme vertical 
accelerative force equal to 0.7 times the vertical reaction at the 
suspension assembly of a trailer, and the horizontal pivot of the upper 
coupler (fifth wheel) or turntable; or anchoring and support members of 
a truck, as applicable. The vertical reaction must be calculated based 
on the static weight of the fully loaded cargo tank motor vehicle, all 
structural elements, equipment and appurtenances supported by the cargo 
tank wall;
    (C) The lateral shear stress generated by an extreme lateral 
accelerative force equal to 0.4 times the vertical reaction at the 
suspension assembly of a trailer, applied at the road surface, and as 
transmitted to the cargo tank wall through the suspension assembly of a 
trailer, and the horizontal pivot of the upper coupler (fifth wheel) or 
turntable; or anchoring and support members of a truck, as applicable. 
The vertical reaction must be calculated based on the static weight of 
the fully loaded cargo tank motor vehicle, all structural elements, 
equipment and appurtenances supported by the cargo tank wall; and
    (D) The torsional shear stress generated by the same lateral forces 
as described in paragraph (c)(2)(iv)(C) of this section.
    (d) In no case may the minimum thickness of the cargo tank shells 
and heads be less than that prescribed in Sec.  178.346-2, Sec.  
178.347-2, or Sec.  178.348-2, as applicable.
    (e) For a cargo tank mounted on a frame or built with integral 
structural supports, the calculation of effective stresses for the 
loading conditions in paragraph (c) of this section may include the 
structural contribution of the frame or the integral structural 
supports.
    (f) The design, construction, and installation of an attachment, 
appurtenance to a cargo tank, structural support member between the 
cargo tank and the vehicle or suspension component must conform to the 
following requirements:
    (1) Structural members, the suspension sub-frame, accident 
protection structures and external circumferential reinforcement devices 
must be used as sites for attachment of appurtenances and other 
accessories to the cargo tank, when practicable.

[[Page 174]]

    (2) A lightweight attachment to a cargo tank wall such as a conduit 
clip, brake line clip, skirting structure, lamp mounting bracket, or 
placard holder must be of a construction having lesser strength than the 
cargo tank wall materials and may not be more than 72 percent of the 
thickness of the material to which it is attached. The lightweight 
attachment may be secured directly to the cargo tank wall if the device 
is designed and installed in such a manner that, if damaged, it will not 
affect the lading retention integrity of the tank. A lightweight 
attachment must be secured to the cargo tank shell or head by continuous 
weld or in such a manner as to preclude formation of pockets which may 
become sites for corrosion.
    (3) Except as prescribed in paragraphs (f)(1) and (f)(2) of this 
section, the welding of any appurtenance to the cargo tank wall must be 
made by attachment of a mounting pad so that there will be no adverse 
effect upon the lading retention integrity of the cargo tank if any 
force less than that prescribed in paragraph (b)(1) of this section is 
applied from any direction. The thickness of the mounting pad may not be 
less than that of the shell or head to which it is attached, and not 
more than 1.5 times the shell or head thickness. However, a pad with a 
minimum thickness of 0.187 inch may be used when the shell or head 
thickness is over 0.187 inch. If weep holes or tell-tale holes are used, 
the pad must be drilled or punched at the lowest point before it is 
welded to the tank. Each pad must:
    (i) Be fabricated from material determined to be suitable for 
welding to both the cargo tank material and the material of the 
appurtenance or structural support member; a Design Certifying Engineer 
must make this determination considering chemical and physical 
properties of the materials and must specify filler material conforming 
to the requirements of the ASME Code (incorporated by reference; see 
Sec.  171.7 of this subchapter).
    (ii) Be preformed to an inside radius no greater than the outside 
radius of the cargo tank at the attachment location.
    (iii) Extend at least 2 inches in each direction from any point of 
attachment of an appurtenance or structural support member. This 
dimension may be measured from the center of the structural member 
attached.
    (iv) Have rounded corners, or otherwise be shaped in a manner to 
minimize stress concentrations on the shell or head.
    (v) Be attached by continuous fillet welding. Any fillet weld 
discontinuity may only be for the purpose of preventing an intersection 
between the fillet weld and the tank or jacket seam weld.

[Amdt. 178-89, 55 FR 37059, Sept. 7, 1990, as amended by Amdt. 178-89, 
56 FR 27876, June 17, 1991; Amdt. 178-104, 59 FR 49135, Sept. 26, 1994; 
Amdt. 178-105, 59 FR 55173, 55174, 55175, Nov. 3, 1994; 60 FR 17402, 
Apr. 5, 1995; Amdt. 178-118, 61 FR 51341, Oct. 1, 1996; 65 FR 58631, 
Sept. 29, 2000; 68 FR 19283, Apr. 18, 2003; 68 FR 75755, Dec. 31, 2003; 
74 FR 16143, Apr. 9, 2009; 78 FR 60755, Oct. 2, 2013; 81 FR 35545, June 
2, 2016]



Sec.  178.345-4  Joints.

    (a) All joints between the cargo tank shell, heads, baffles, baffle 
attaching rings, and bulkheads must be welded in conformance with 
Section VIII of the ASME Code (IBR, see Sec.  171.7 of this subchapter).
    (b) Where practical all welds must be easily accessible for 
inspection.

[Amdt. 178-89, 54 FR 25022, June 12, 1989, as amended by Amdt. 178-118, 
61 FR 51341, Oct. 1, 1996; 68 FR 75756, Dec. 31, 2003]



Sec.  178.345-5  Manhole assemblies.

    (a) Each cargo tank with capacity greater than 400 gallons must be 
accessible through a manhole at least 15 inches in diameter.
    (b) Each manhole, fill opening and washout assembly must be 
structurally capable of withstanding, without leakage or permanent 
deformation that would affect its structural integrity, a static 
internal fluid pressure of at least 36 psig, or cargo tank test 
pressure, whichever is greater. The manhole assembly manufacturer shall 
verify compliance with this requirement by hydrostatically testing at 
least one percent (or one manhole closure, whichever is greater) of all 
manhole

[[Page 175]]

closures of each type produced each 3 months, as follows:
    (1) The manhole, fill opening, or washout assembly must be tested 
with the venting devices blocked. Any leakage or deformation that would 
affect the product retention capability of the assembly shall constitute 
a failure.
    (2) If the manhole, fill opening, or washout assembly tested fails, 
then five more covers from the same lot must be tested. If one of these 
five covers fails, then all covers in the lot from which the tested 
covers were selected are to be 100% tested or rejected for service.
    (c) Each manhole, filler and washout cover must be fitted with a 
safety device that prevents the cover from opening fully when internal 
pressure is present.
    (d) Each manhole and fill cover must be secured with fastenings that 
will prevent opening of the covers as a result of vibration under normal 
transportation conditions or shock impact due to a rollover accident on 
the roadway or shoulder where the fill cover is not struck by a 
substantial obstacle.
    (e) On cargo tank motor vehicles manufactured after October 1, 2004, 
each manhole assembly must be permanently marked on the outside by 
stamping or other means in a location visible without opening the 
manhole assembly or fill opening, with:
    (1) Manufacturer's name;
    (2) Test pressure ____ psig;
    (3) A statement certifying that the manhole cover meets the 
requirements in Sec.  178.345-5.
    (f) All components mounted on a manhole cover that form part of the 
lading retention structure of the cargo tank wall must withstand the 
same static internal fluid pressure as that required for the manhole 
cover. The component manufacturer shall verify compliance using the same 
test procedure and frequency of testing as specified in Sec.  178.345-
5(b).

[Amdt. 178-89, 54 FR 25022, June 12, 1989, as amended by Amdt. 178-105, 
59 FR 55175, Nov. 3, 1994; 68 FR 19284, Apr. 18, 2003; 74 FR 16144, Apr. 
9, 2009]



Sec.  178.345-6  Supports and anchoring.

    (a) A cargo tank with a frame not integral to the cargo tank must 
have the tank secured by restraining devices to eliminate any motion 
between the tank and frame that may abrade the tank shell due to the 
stopping, starting, or turning of the cargo tank motor vehicle. The 
design calculations of the support elements must include the stresses 
indicated in Sec.  178.345-3(b) and as generated by the loads described 
in Sec.  178.345-3(c). Such restraining devices must be readily 
accessible for inspection and maintenance, except that insulation and 
jacketing are permitted to cover the restraining devices.
    (b) A cargo tank designed and constructed so that it constitutes, in 
whole or in part, the structural member used in lieu of a frame must be 
supported in such a manner that the resulting stress levels in the cargo 
tank do not exceed those specified in Sec.  178.345-3(a). The design 
calculations of the support elements must include the stresses indicated 
in Sec.  178.345-3(b) and as generated by the loads described in Sec.  
178.345-3(c).

[Amdt. 178-89, 54 FR 25023, June 12, 1989, as amended by Amdt. 178-105, 
59 FR 55175, Nov. 3, 1994; Amdt. 178-118, 61 FR 51341, Oct. 1, 1996]



Sec.  178.345-7  Circumferential reinforcements.

    (a) A cargo tank with a shell thickness of less than \3/8\ inch must 
be circumferentially reinforced with bulkheads, baffles, ring 
stiffeners, or any combination thereof, in addition to the cargo tank 
heads.
    (1) Circumferential reinforcement must be located so that the 
thickness and tensile strength of the shell material in combination with 
the frame and reinforcement produces structural integrity at least equal 
to that prescribed in Sec.  178.345-3 and in such a manner that the 
maximum unreinforced portion of the shell does not exceed 60 inches. For 
cargo tanks designed to be loaded by vacuum, spacing of circumferential 
reinforcement may exceed 60 inches provided the maximum unreinforced 
portion of the shell conforms with the requirements in Section VIII of 
the ASME Code (IBR, see Sec.  171.7 of this subchapter).
    (2) Where circumferential joints are made between conical shell 
sections, or between conical and cylindrical shell

[[Page 176]]

sections, and the angle between adjacent sections is less than 160 
degrees, circumferential reinforcement must be located within one inch 
of the shell joint, unless otherwise reinforced with structural members 
capable of maintaining shell stress levels authorized in Sec.  178.345-
3. When the joint is formed by the large ends of adjacent conical shell 
sections, or by the large end of a conical shell and a cylindrical shell 
section, this angle is measured inside the shell; when the joint is 
formed by the small end of a conical shell section and a cylindrical 
shell section, it is measured outside the shell.
    (b) Except for doubler plates and knuckle pads, no reinforcement may 
cover any circumferential joint.
    (c) When a baffle or baffle attachment ring is used as a 
circumferential reinforcement member, it must produce structural 
integrity at least equal to that prescribed in Sec.  178.345-3 and must 
be circumferentially welded to the cargo tank shell. The welded portion 
may not be less than 50 percent of the total circumference of the cargo 
tank and the length of any unwelded space on the joint may not exceed 40 
times the shell thickness unless reinforced external to the cargo tank.
    (d) When a ring stiffener is used as a circumferential reinforcement 
member, whether internal or external, reinforcement must be continuous 
around the circumference of the cargo tank shell and must be in 
accordance with the following:
    (1) The section modulus about the neutral axis of the ring section 
parallel to the shell must be at least equal to that derived from the 
applicable formula:

I/C = 0.00027WL, for MS, HSLA and SS; or
I/C = 0.000467WL, for aluminum alloys;

Where:

I/C = Section modulus in inches \3\
W = Tank width, or diameter, inches
L = Spacing of ring stiffener, inches; i.e., the maximum longitudinal 
          distance from the midpoint of the unsupported shell on one 
          side of the ring stiffener to the midpoint of the unsupported 
          shell on the opposite side of the ring stiffener.

    (2) If a ring stiffener is welded to the cargo tank shell, a portion 
of the shell may be considered as part of the ring section for purposes 
of computing the ring section modulus. This portion of the shell may be 
used provided at least 50 percent of the total circumference of the 
cargo tank is welded and the length of any unwelded space on the joint 
does not exceed 40 times the shell thickness. The maximum portion of the 
shell to be used in these calculations is as follows:

------------------------------------------------------------------------
  Number of circumferential ring
     stiffener-to-shell welds              J \1\          Shell section
------------------------------------------------------------------------
1................................  ....................  20t
2................................  Less than 20t.......  20t + J
2................................  20t or more.........  40t
------------------------------------------------------------------------
\1\ where:
t = Shell thickness, inches;
J = Longitudinal distance between parallel circumferential ring
  stiffener-to-shell welds.

    (3) When used to meet the vacuum requirements of this section, ring 
stiffeners must be as prescribed in Section VIII of the ASME Code.
    (4) If configuration of internal or external ring stiffener encloses 
an air space, this air space must be arranged for venting and be 
equipped with drainage facilities which must be kept operative at all 
times.
    (5) Hat shaped or open channel ring stiffeners which prevent visual 
inspection of the cargo tank shell are prohibited on cargo tank motor 
vehicles constructed of carbon steel.

[Amdt. 178-89, 55 FR 37060, Sept. 7, 1990, as amended by Amdt. 178-89, 
56 FR 27876, June 17, 1991; 56 FR 46354, Sept. 11, 1991; Amdt. 178-104, 
59 FR 49135, Sept. 26, 1994; Amdt. 178-118, 61 FR 51341, Oct. 1, 1996; 
68 FR 75756, Dec. 31, 2003]



Sec.  178.345-8  Accident damage protection.

    (a) General. Each cargo tank motor vehicle must be designed and 
constructed in accordance with the requirements of this section and the 
applicable individual specification to minimize the potential for the 
loss of lading due to an accident.
    (1) Any dome, sump, or washout cover plate projecting from the cargo 
tank wall that retains lading in any tank orientation, must be as strong 
and tough as the cargo tank wall and have a thickness at least equal to 
that specified by the appropriate cargo tank

[[Page 177]]

specification. Any such projection located in the lower \1/3\ of the 
tank circumference (or cross section perimeter for non-circular cargo 
tanks) that extends more than half its diameter at the point of 
attachment to the tank or more than 4 inches from the cargo tank wall, 
or located in the upper \2/3\ of the tank circumference (or cross 
section perimeter for non-circular cargo tanks) that extends more than 
\1/4\ its diameter or more than 2 inches from the point of attachment to 
the tank must have accident damage protection devices that are:
    (i) As specified in this section;
    (ii) 125 percent as strong as the otherwise required accident damage 
protection device; or
    (iii) Attached to the cargo tank in accordance with the requirements 
of paragraph (a)(3) of this section.
    (2) Outlets, valves, closures, piping, or any devices that if 
damaged in an accident could result in a loss of lading from the cargo 
tank must be protected by accident damage protection devices as 
specified in this section.
    (3) Accident damage protection devices attached to the wall of a 
cargo tank must be able to withstand or deflect away from the cargo tank 
the loads specified in this section. They must be designed, constructed 
and installed so as to maximize the distribution of loads to the cargo 
tank wall and to minimize the possibility of adversely affecting the 
lading retention integrity of the cargo tank. Accident induced stresses 
resulting from the appropriate accident damage protection device 
requirements in combination with the stresses from the cargo tank 
operating at the MAWP may not result in a cargo tank wall stress greater 
than the ultimate strength of the material of construction using a 
safety factor of 1.3. Deformation of the protection device is acceptable 
provided the devices being protected are not damaged when loads 
specified in this section are applied.
    (4) Any piping that extends beyond an accident damage protection 
device must be equipped with a stop-valve and a sacrificial device such 
as a shear section. The sacrificial device must be located in the piping 
system outboard of the stop-valve and within the accident damage 
protection device to prevent any accidental loss of lading. The device 
must break at no more than 70 percent of the load that would be required 
to cause the failure of the protected lading retention device, part or 
cargo tank wall. The failure of the sacrificial device must leave the 
protected lading retention device and its attachment to the cargo tank 
wall intact and capable of retaining product.
    (5) Minimum road clearance. The minimum road clearance of any cargo 
tank motor vehicle component or protection device located between any 
two adjacent axles on a vehicle or vehicle combination must be at least 
one-half inch for each foot separating the component or device from the 
nearest axle of the adjacent pair, but in no case less than twelve (12) 
inches, except that the minimum road clearance for landing gear or other 
attachments within ten (10) feet of an axle must be no less than ten 
(10) inches. These measurements must be calculated at the gross vehicle 
weight rating of the cargo tank motor vehicle.
    (b) Each outlet, projection or piping located in the lower \1/3\ of 
the cargo tank circumference (or cross section perimeter for non-
circular cargo tanks) that could be damaged in an accident that may 
result in the loss of lading must be protected by a bottom damage 
protection device, except as provided by paragraph (a)(1) of this 
section and Sec.  173.33(e) of this subchapter. Outlets, projections and 
piping may be grouped or clustered together and protected by a single 
protection device.
    (1) Any bottom damage protection device must be able to withstand a 
force of 155,000 pounds (based on the ultimate strength of the 
material), from the front, side, and rear uniformly distributed, applied 
in each direction of the device, over an area not to exceed 6 square 
feet, and a width not to exceed 6 feet. Suspension components and 
structural mounting members may be used to provide all, or part, of this 
protection. The device must extend no less than 6 inches beyond any 
component that may contain lading in transit.
    (2) A lading discharge opening equipped with an internal self-
closing stop-valve need not conform to paragraph (b)(1) of this section 
provided it

[[Page 178]]

is protected so as to reasonably assure against the accidental loss of 
lading. This protection must be provided by a sacrificial device located 
outboard of each internal self-closing stop-valve and within 4 inches of 
the major radius of the cargo tank shell or within 4 inches of a sump, 
but in no case more than 8 inches from the major radius of the tank 
shell. The device must break at no more than 70 percent of the load that 
would be required to cause the failure of the protected lading retention 
device, part or cargo tank wall. The failure of the sacrificial device 
must leave the protected lading retention device or part and its 
attachment to the cargo tank wall intact and capable of retaining 
product.
    (c) Each closure for openings, including but not limited to the 
manhole, filling or inspection openings, and each valve, fitting, 
pressure relief device, vapor recovery stop valve or lading retaining 
fitting located in the upper \2/3\ of a cargo tank circumference (or 
cross section perimeter for non-circular tanks) must be protected by 
being located within or between adjacent rollover damage protection 
devices, or by being 125 percent of the strength that would be provided 
by the otherwise required damage protection device.
    (1) A rollover damage protection device on a cargo tank motor 
vehicle must be designed and installed to withstand loads equal to twice 
the weight of the loaded cargo tank motor vehicle applied as follows: 
normal to the cargo tank shell (perpendicular to the cargo tank 
surface); and tangential (perpendicular to the normal load) from any 
direction. The stresses shall not exceed the ultimate strength of the 
material of construction. These design loads may be considered to be 
uniformly distributed and independently applied. If more than one 
rollover protection device is used, each device must be capable of 
carrying its proportionate share of the required loads and in each case 
at least one-fourth the total tangential load. The design must be proven 
capable of carrying the required loads by calculations, tests or a 
combination of tests and calculations.
    (2) A rollover damage protection device that would otherwise allow 
the accumulation of liquid on the top of the cargo tank, must be 
provided with a drain that directs the liquid to a safe point of 
discharge away from any structural component of the cargo tank motor 
vehicle.
    (d) Rear-end tank protection. Each cargo tank motor vehicle must be 
provided with a rear-end tank protection device to protect the cargo 
tank and piping in the event of a rear-end collision and reduce the 
likelihood of damage that could result in the loss of lading. Nothing in 
this paragraph relieves the manufacturer of responsibility for complying 
with the requirements of Sec.  393.86 of this title and, if applicable, 
paragraph (b) of this section. The rear-end tank protection device must 
conform to the following requirements:
    (1) The rear-end cargo tank protection device must be designed so 
that it can deflect at least 6 inches horizontally forward with no 
contact between any part of the cargo tank motor vehicle which contains 
lading during transit and with any part of the rear-end protection 
device, or with a vertical plane passing through the outboard surface of 
the protection device.
    (2) The dimensions of the rear-end cargo tank protection device 
shall conform to the following:
    (i) The bottom surface of the rear-end protection device must be at 
least 4 inches below the lower surface of any part at the rear of the 
cargo tank motor vehicle which contains lading during transit and not 
more than 60 inches from the ground when the vehicle is empty.
    (ii) The maximum width of a notch, indentation, or separation 
between sections of a rear-end cargo tank protection device may not 
exceed 24 inches. A notched, indented, or separated rear-end protection 
device may be used only when the piping at the rear of the cargo tank is 
equipped with a sacrificial device outboard of a shut-off valve.
    (iii) The widest part of the motor vehicle at the rear may not 
extend more than 18 inches beyond the outermost ends of the device or 
(if separated) devices on either side of the vehicle.
    (3) The structure of the rear-end protection device and its 
attachment to the vehicle must be designed to satisfy the conditions 
specified in paragraph (d)(1) of this section when subjected to

[[Page 179]]

an impact of the cargo tank motor vehicle at rated payload, at a 
deceleration of 2 ``g''. Such impact must be considered as being 
uniformly applied in the horizontal plane at an angle of 10 degrees or 
less to the longitudinal axis of the vehicle.
    (e) Longitudinal deceleration protection. In order to account for 
stresses due to longitudinal impact in an accident, the cargo tank shell 
and heads must be able to withstand the load resulting from the design 
pressure in combination with the dynamic pressure resulting from a 
longitudinal deceleration of 2 ``g''. For this loading condition, the 
allowable stress value used may not exceed the ultimate strength of the 
material of construction using a safety factor of 1.3. Performance 
testing, analytical methods, or a combination thereof, may be used to 
prove this capability provided the methods are accurate and verifiable. 
For cargo tanks with internal baffles, the decelerative force may be 
reduced by 0.25 ``g'' for each baffle assembly, but in no case may the 
total reduction in decelerative force exceed 1.0 ``g''.

[Amdt. 178-89, 54 FR 25023, June 12, 1989, as amended at 55 FR 37061, 
Sept. 7, 1990; Amdt. 178-105, 59 FR 55175, Nov. 3, 1994; Amdt. 178-118, 
61 FR 51341, Oct. 1, 1996; 68 FR 19284, Apr. 18, 2003; 85 FR 83402, Dec. 
21, 2020]



Sec.  178.345-9  Pumps, piping, hoses and connections.

    (a) Suitable means must be provided during loading or unloading 
operations to ensure that pressure within a cargo tank does not exceed 
test pressure.
    (b) Each hose, piping, stop-valve, lading retention fitting and 
closure must be designed for a bursting pressure of the greater of 100 
psig or four times the MAWP.
    (c) Each hose coupling must be designed for a bursting pressure of 
the greater of 120 psig or 4.8 times the MAWP of the cargo tank, and 
must be designed so that there will be no leakage when connected.
    (d) Suitable provision must be made to allow for and prevent damage 
due to expansion, contraction, jarring, and vibration. Slip joints may 
not be used for this purpose in the lading retention system.
    (e) Any heating device, when installed, must be so constructed that 
the breaking of its external connections will not cause leakage of the 
cargo tank lading.
    (f) Any gauging, loading or charging device, including associated 
valves, must be provided with an adequate means of secure closure to 
prevent leakage.
    (g) The attachment and construction of each loading/unloading or 
charging line must be of sufficient strength, or be protected by a 
sacrificial device, such that any load applied by loading/unloading or 
charging lines connected to the cargo tank cannot cause damage resulting 
in loss of lading from the cargo tank.
    (h) Use of a nonmetallic pipe, valve or connection that is not as 
strong and heat resistant as the cargo tank material is authorized only 
if such attachment is located outboard of the lading retention system.

[Amdt. 178-89, 54 FR 25025, June 12, 1989, as amended at 55 FR 37061, 
Sept. 7, 1990, Amdt. 178-89, 56 FR 27877, June 17, 1991; Amdt. 178-118, 
61 FR 51341, Oct. 1, 1996]



Sec.  178.345-10  Pressure relief.

    (a) Each cargo tank must be equipped to relieve pressure and vacuum 
conditions in conformance with this section and the applicable 
individual specification. The pressure and vacuum relief system must be 
designed to operate and have sufficient capacity to prevent cargo tank 
rupture or collapse due to over-pressurization or vacuum resulting from 
loading, unloading, or from heating and cooling of lading. Pressure 
relief systems are not required to conform to the ASME Code.
    (b) Type and construction of relief systems and devices. (1) Each 
cargo tank must be provided with a primary pressure relief system 
consisting of one or more reclosing pressure relief valves. A secondary 
pressure relief system consisting of another pressure relief valve in 
parallel with the primary pressure relief system may be used to augment 
the total venting capacity of the cargo tank. Non-reclosing pressure 
relief devices are not authorized in any cargo tank except when in 
series with a reclosing pressure relief device. Gravity

[[Page 180]]

actuated reclosing valves are not authorized on any cargo tank.
    (2) When provided by Sec.  173.33(c)(1)(iii) of this subchapter, 
cargo tanks may be equipped with a normal vent. Such vents must be set 
to open at not less than 1 psig and must be designed to prevent loss of 
lading through the device in case of vehicle overturn.
    (3) Each pressure relief system must be designed to withstand 
dynamic pressure surges in excess of the design set pressure as 
specified in paragraphs (b)(3) (i) and (ii) of this section. Set 
pressure is a function of MAWP as set forth in paragraph (d) of this 
section.
    (i) Each pressure relief device must be able to withstand dynamic 
pressure surge reaching 30 psig above the design set pressure and 
sustained above the set pressure for at least 60 milliseconds with a 
total volume of liquid released not exceeding one gallon before the 
relief device recloses to a leak-tight condition. This requirement must 
be met regardless of vehicle orientation. This capability must be 
demonstrated by testing. An acceptable method is outlined in TTMA RP No. 
81-97 ``Performance of Spring Loaded Pressure Relief Valves on MC 306, 
MC 307, MC 312, DOT 406, DOT 407, and DOT 412 Tanks'' (incorporated by 
reference; see Sec.  171.7 of this subchapter).
    (ii) After August 31, 1995, each pressure relief device must be able 
to withstand a dynamic pressure surge reaching 30 psig above the design 
set pressure and sustained above the design set pressure for at least 60 
milliseconds with a total volume of liquid released not exceeding 1 L 
before the relief valve recloses to a leak-tight condition. This 
requirement must be met regardless of vehicle orientation. This 
capability must be demonstrated by testing. TTMA RP No. 81, cited in 
paragraph (b)(3)(i) of this section, is an acceptable test procedure.
    (4) Each reclosing pressure relief valve must be constructed and 
installed in such a manner as to prevent unauthorized adjustment of the 
relief valve setting.
    (5) No shut-off valve or other device that could prevent venting 
through the pressure relief system may be installed in a pressure relief 
system.
    (6) The pressure relief system must be mounted, shielded and 
drainable so as to minimize the accumulation of material that could 
impair the operation or discharge capability of the system by freezing, 
corrosion or blockage.
    (c) Location of relief devices. Each pressure relief device must 
communicate with the vapor space above the lading as near as practicable 
to the center of the vapor space. For example, on a cargo tank designed 
to operate in a level attitude, the device should be positioned at the 
horizontal and transverse center of the cargo tank; on cargo tanks 
sloped to the rear, the device should be located in the forward half of 
the cargo tank. The discharge from any device must be unrestricted. 
Protective devices which deflect the flow of vapor are permissible 
provided the required vent capacity is maintained.
    (d) Settings of pressure relief system. The set pressure of the 
pressure relief system is the pressure at which it starts to open, 
allowing discharge.
    (1) Primary pressure relief system. The set pressure of each primary 
relief valve must be no less than 120 percent of the MAWP, and no more 
than 132 percent of the MAWP. The valve must reclose at not less than 
108 percent of the MAWP and remain closed at lower pressures.
    (2) Secondary pressure relief system. The set pressure of each 
pressure relief valve used as a secondary relief device must be not less 
than 120 percent of the MAWP.
    (e) Venting capacity of pressure relief systems. The pressure relief 
system (primary and secondary, including piping) must have sufficient 
venting capacity to limit the cargo tank internal pressure to not more 
than the cargo tank test pressure. The total venting capacity, rated at 
not more than the cargo tank test pressure, must be at least that 
specified in table I, except as provided in Sec.  178.348-4.

                Table I--Minimum Emergency Vent Capacity
          [In cubic feet free air/hour at 60 [deg]F and 1 atm.]
------------------------------------------------------------------------
                                                              Cubic feet
                Exposed area in square feet                    free air
                                                               per hour
------------------------------------------------------------------------
20.........................................................       15,800

[[Page 181]]

 
30.........................................................       23,700
40.........................................................       31,600
50.........................................................       39,500
60.........................................................       47,400
70.........................................................       55,300
80.........................................................       63,300
90.........................................................       71,200
100........................................................       79,100
120........................................................       94,900
140........................................................      110,700
160........................................................      126,500
180........................................................      142,300
200........................................................      158,100
225........................................................      191,300
250........................................................      203,100
275........................................................      214,300
300........................................................      225,100
350........................................................      245,700
400........................................................      265,000
450........................................................      283,200
500........................................................      300,600
550........................................................      317,300
600........................................................      333,300
650........................................................      348,800
700........................................................      363,700
750........................................................      378,200
800........................................................      392,200
850........................................................      405,900
900........................................................      419,300
950........................................................      432,300
1,000......................................................      445,000
------------------------------------------------------------------------
Note 1: Interpolate for intermediate sizes.

    (1) Primary pressure relief system. Unless otherwise specified in 
the applicable individual specification, the primary relief system must 
have a minimum venting capacity of 12,000 SCFH per 350 square feet of 
exposed cargo tank area, but in any case at least one fourth the 
required total venting capacity for the cargo tank.
    (2) Secondary pressure relief system. If the primary pressure relief 
system does not provide the required total venting capacity, additional 
capacity must be provided by a secondary pressure relief system.
    (f) Certification of pressure relief devices. The manufacturer of 
any pressure relief device, including valves, frangible (rupture) disks, 
vacuum vents and combination devices must certify that the device model 
was designed and tested in accordance with this section and the 
appropriate cargo tank specification. The certificate must contain 
sufficient information to describe the device and its performance. The 
certificate must be signed by a responsible official of the manufacturer 
who approved the flow capacity certification.
    (g) Rated flow capacity certification test. Each pressure relief 
device model must be successfully flow capacity certification tested 
prior to first use. Devices having one design, size and set pressure are 
considered to be one model. The testing requirements are as follows:
    (1) At least 3 devices of each specific model must be tested for 
flow capacity at a pressure not greater than the test pressure of the 
cargo tank. For a device model to be certified, the capacities of the 
devices tested must fall within a range of plus or minus 5 percent of 
the average for the devices tested.
    (2) The rated flow capacity of a device model may not be greater 
than 90 percent of the average value for the devices tested.
    (3) The rated flow capacity derived for each device model must be 
certified by a responsible official of the device manufacturer.
    (h) Marking of pressure relief devices. Each pressure relief device 
must be permanently marked with the following:
    (1) Manufacturer's name;
    (2) Model number;
    (3) Set pressure, in psig; and
    (4) Rated flow capacity, in SCFH at the rating pressure, in psig.

[Amdt. 178-89, 54 FR 25025, June 12, 1989, as amended at 55 FR 21038, 
May 22, 1990; 55 FR 37062, Sept. 7, 1990; Amdt. 178-89, 56 FR 27877, 
June 17, 1991; Amdt. 178-105, 59 FR 55175, Nov. 3, 1994; Amdt. 178-118, 
61 FR 51341, Oct. 1, 1996; 65 FR 58631, Sept. 29, 2000; 66 FR 45389, 
Aug. 28, 2001; 68 FR 19284, Apr. 18, 2003]



Sec.  178.345-11  Tank outlets.

    (a) General. As used in this section, ``loading/unloading outlet'' 
means any opening in the cargo tank wall used for loading or unloading 
of lading, as distinguished from outlets such as manhole covers, vents, 
vapor recovery devices, and similar closures. Cargo tank outlets, 
closures and associated piping must be protected in accordance with 
Sec.  178.345-8.
    (b) Each cargo tank loading/unloading outlet must be equipped with 
an internal self-closing stop-valve, or alternatively, with an external 
stop-valve

[[Page 182]]

located as close as practicable to the cargo tank wall. Each cargo tank 
loading/unloading outlet must be in accordance with the following 
provisions:
    (1) Each loading/unloading outlet must be fitted with a self-closing 
system capable of closing all such outlets in an emergency within 30 
seconds of actuation. During normal operations the outlets may be closed 
manually. The self-closing system must be designed according to the 
following:
    (i) Each self-closing system must include a remotely actuated means 
of closure located more than 10 feet from the loading/unloading outlet 
where vehicle length allows, or on the end of the cargo tank farthest 
away from the loading/unloading outlet. The actuating mechanism must be 
corrosion-resistant and effective in all types of environment and 
weather.
    (ii) If the actuating system is accidentally damaged or sheared off 
during transportation, each loading/unloading outlet must remain 
securely closed and capable of retaining lading.
    (iii) When required by part 173 of this subchapter for materials 
which are flammable, pyrophoric, oxidizing, or Division 6.1 (poisonous 
liquid) materials, the remote means of closure must be capable of 
thermal activation. The means by which the self-closing system is 
thermally activated must be located as close as practicable to the 
primary loading/unloading connection and must actuate the system at a 
temperature not over 250 [deg]F. In addition, outlets on these cargo 
tanks must be capable of being remotely closed manually or mechanically.
    (2) Bottom loading outlets which discharge lading into the cargo 
tank through fixed internal piping above the maximum liquid level of the 
cargo tank need not be equipped with a self-closing system.
    (c) Any loading/unloading outlet extending beyond an internal self-
closing stop-valve, or beyond the innermost external stop-valve which is 
part of a self-closing system, must be fitted with another stop-valve or 
other leak-tight closure at the end of such connection.
    (d) Each cargo tank outlet that is not a loading/unloading outlet 
must be equipped with a stop-valve or other leak-tight closure located 
as close as practicable to the cargo tank outlet. Any connection 
extending beyond this closure must be fitted with another stop-valve or 
other leak-tight closure at the end of such connection.

[Amdt. 178-89, 56 FR 27877, June 17, 1991, as amended by Amdt. 178-97, 
57 FR 45465, Oct. 1, 1992; Amdt. 178-118, 61 FR 51341, Oct. 1, 1996]



Sec.  178.345-12  Gauging devices.

    Each cargo tank, except a cargo tank intended to be filled by 
weight, must be equipped with a gauging device that indicates the 
maximum permitted liquid level to within 0.5 percent of the nominal 
capacity as measured by volume or liquid level. Gauge glasses are not 
permitted.

[Amdt. 178-89, 55 FR 37062, Sept. 7, 1990, as amended by Amdt. 178-118, 
61 FR 51342, Oct. 1, 1996]



Sec.  178.345-13  Pressure and leakage tests.

    (a) Each cargo tank must be pressure and leakage tested in 
accordance with this section and Sec. Sec.  178.346-5, 178.347-5, or 
178.348-5.
    (b) Pressure test. Each cargo tank or cargo tank compartment must be 
tested hydrostatically or pneumatically. Each cargo tank of a multi-
cargo tank motor vehicle must be tested with the adjacent cargo tanks 
empty and at atmospheric pressure. Each closure, except pressure relief 
devices and loading/unloading venting devices rated at less than the 
prescribed test pressure, must be in place during the test. If the 
venting device is not removed during the test, such device must be 
rendered inoperative by a clamp, plug or other equally effective 
restraining device, which may not prevent the detection of leaks, or 
damage the device. Restraining devices must be removed immediately after 
the test is completed.
    (1) Hydrostatic method. Each cargo tank, including its domes, must 
be filled with water or other liquid having similar viscosity, the 
temperature of which may not exceed 100 [deg]F. The cargo tank must then 
be pressurized as prescribed in the applicable specification. The 
pressure must be gauged at the top of the cargo tank. The prescribed 
test pressure must be maintained for at least 10 minutes during which 
time the

[[Page 183]]

cargo tank must be inspected for leakage, bulging, or other defect.
    (2) Pneumatic method. A pneumatic test may be used in place of the 
hydrostatic test. However, pneumatic pressure testing may involve higher 
risk than hydrostatic testing. Therefore, suitable safeguards must be 
provided to protect personnel and facilities should failure occur during 
the test. The cargo tank must be pressurized with air or an inert gas. 
Test pressure must be reached gradually by increasing the pressure to 
one half of test pressure. Thereafter, the pressure must be increased in 
steps of approximately one tenth of the test pressure until test 
pressure is reached. Test pressure must be held for at least 5 minutes. 
The pressure must then be reduced to the inspection pressure which must 
be maintained while the entire cargo tank surface is inspected for 
leakage and other sign of defects. The inspection method must consist of 
coating all joints and fittings with a solution of soap and water or 
other equally sensitive method.
    (c) Leakage test. The cargo tank with all its accessories in place 
and operable must be leak tested at not less than 80 percent of tank's 
MAWP with the pressure maintained for at least 5 minutes.
    (d) Any cargo tank that leaks, bulges or shows any other sign of 
defect must be rejected. Rejected cargo tanks must be suitably repaired 
and retested successfully prior to being returned to service. The retest 
after any repair must use the same method of test under which the cargo 
tank was originally rejected.

[Amdt. 178-89, 54 FR 25026, June 12, 1989, as amended at 55 FR 37063, 
Sept. 7, 1990; Amdt. 178-105, 59 FR 55176, Nov. 3, 1994; Amdt. 178-118, 
61 FR 51342, Oct. 1, 1996; 65 FR 58631, Sept. 29, 2000; 68 FR 19284, 
Apr. 18, 2003]



Sec.  178.345-14  Marking.

    (a) General. The manufacturer shall certify that each cargo tank 
motor vehicle has been designed, constructed and tested in accordance 
with the applicable Specification DOT 406, DOT 407 or DOT 412 
(Sec. Sec.  178.345, 178.346, 178.347, 178.348) cargo tank requirements 
and, when applicable, with Section VIII of the ASME Code (IBR, see Sec.  
171.7 of this subchapter). The certification shall be accomplished by 
marking the cargo tank as prescribed in paragraphs (b) and (c) of this 
section, and by preparing the certificate prescribed in Sec.  178.345-
15. Metal plates prescribed by paragraphs (b), (c), (d) and (e) of this 
section, must be permanently attached to the cargo tank or its integral 
supporting structure, by brazing, welding or other suitable means. These 
plates must be affixed on the left side of the vehicle near the front of 
the cargo tank (or the frontmost cargo tank of a multi-cargo tank motor 
vehicle), in a place readily accessible for inspection. The plates must 
be permanently and plainly marked in English by stamping, embossing or 
other means in characters at least \3/16\ inch high. The information 
required by paragraphs (b) and (c) of this section may be combined on 
one specification plate.
    (b) Nameplate. Each cargo tank must have a corrosion resistant 
nameplate permanently attached to it. The following information, in 
addition to any applicable information required by the ASME Code, must 
be marked on the tank nameplate (parenthetical abbreviations may be 
used):
    (1) DOT-specification number DOT XXX (DOT XXX) where ``XXX'' is 
replaced with the applicable specification number. For cargo tanks 
having a variable specification plate, the DOT-specification number is 
replaced with the words ``See variable specification plate.''
    (2) Original test date, month and year (Orig. Test Date).
    (3) Tank MAWP in psig.
    (4) Cargo tank test pressure (Test P), in psig.
    (5) Cargo tank design temperature range (Design temp. range),__ 
[deg]F to __ [deg]F.
    (6) Nominal capacity (Water cap.), in gallons.
    (7) Maximum design density of lading (Max. lading density), in 
pounds per gallon.
    (8) Material specification number--shell (Shell matl, yyy***), where 
``yyy'' is replaced by the alloy designation and ``***'' by the alloy 
type.
    (9) Material specification number--heads (Head matl, yyy***), where 
``yyy'' is replaced by the alloy designation and ``***'' by the alloy 
type.


[[Page 184]]


    Note: When the shell and heads materials are the same thickness, 
they may be combined, (Shell&head matl, yyy***).

    (10) Weld material (Weld matl.).
    (11) Minimum thickness--shell (Min. shell-thick), in inches. When 
minimum shell thicknesses are not the same for different areas, show 
(top __, side __, bottom __, in inches).
    (12) Minimum thickness--heads (Min. heads thick.), in inches.
    (13) Manufactured thickness--shell (Mfd. shell thick.), top __, side 
__, bottom __, in inches. (Required when additional thickness is 
provided for corrosion allowance.)
    (14) Manufactured thickness--heads (Mfd. heads thick.), in inches. 
(Required when additional thickness is provided for corrosion 
allowance.)
    (15) Exposed surface area, in square feet.
    (c) Specification plate. Each cargo tank motor vehicle must have an 
additional corrosion resistant metal specification plate attached to it. 
The specification plate must contain the following information 
(parenthetical abbreviations may be used):
    (1) Cargo tank motor vehicle manufacturer (CTMV mfr.).
    (2) Cargo tank motor vehicle certification date (CTMV cert. date), 
if different from the cargo tank certification date.
    (3) Cargo tank manufacturer (CT mfr.).
    (4) Cargo tank date of manufacture (CT date of mfr.), month and 
year.
    (5) Maximum weight of lading (Max. Payload), in pounds.
    (6) Maximum loading rate in gallons per minute (Max. Load rate, 
GPM).
    (7) Maximum unloading rate in gallons per minute (Max. Unload rate).
    (8) Lining material (Lining), if applicable.
    (9) Heating system design pressure (Heating sys. press.), in psig, 
if applicable.
    (10) Heating system design temperature (Heating sys. temp.), in 
[deg]F, if applicable.
    (d) Multi-cargo tank motor vehicle. For a multi-cargo tank motor 
vehicle having all its cargo tanks not separated by any void, the 
information required by paragraphs (b) and (c) of this section may be 
combined on one specification plate. When separated by a void, each 
cargo tank must have an individual nameplate as required in paragraph 
(b) of this section, unless all cargo tanks are made by the same 
manufacturer with the same materials, manufactured thickness, minimum 
thickness and to the same specification. The cargo tank motor vehicle 
may have a combined nameplate and specification plate. When only one 
plate is used, the plate must be visible and not covered by insulation. 
The required information must be listed on the plate from front to rear 
in the order of the corresponding cargo tank location.
    (e) Variable specification cargo tank. Each variable specification 
cargo tank must have a corrosion resistant metal variable specification 
plate attached to it. The mounting of this variable specification plate 
must be such that only the plate identifying the applicable 
specification under which the tank is being operated is legible.
    (1) The following information must be included (parenthetical 
abbreviations are authorized):

    Specification DOT XXX (DOT XXX), where ``XXX'' is replaced with the 
applicable specification number.

 
            Equipment required                  Required rating \1\
 
Pressure relief devices:
    Pressure actuated type...............  ____________
    Frangible type.......................  ____________
    Lading discharge devices.............  ____________
    Top..................................  ____________
    Bottom...............................  ____________
    Pressure unloading fitting...........  ____________
Closures:
    Manhole..............................  ____________
    Fill openings........................  ____________
    Discharge openings...................  ____________
 
\1\ Required rating--to meet the applicable specification.

    (2) If no change of information in the specification plate is 
required, the letters ``NC'' must follow the rating required. If the 
cargo tank is not so equipped, the word ``None'' must be inserted.
    (3) Those parts to be changed or added must be stamped with the 
appropriate MC or DOT Specification markings.

[[Page 185]]

    (4) The alterations that must be made in order for the tank to be 
modified from one specification to another must be clearly indicated on 
the manufacturer's certificate and on the variable specification plate.

[Amdt. 178-89, 54 FR 25027, June 12, 1989, as amended at 55 FR 37063, 
Sept. 7, 1990; Amdt. 178-99, 58 FR 51534, Oct. 1, 1993; Amdt. 178-104, 
59 FR 49135, Sept. 26, 1994; Amdt. 178-105, 59 FR 55176, Nov. 3, 1994; 
60 FR 17402, Apr. 5, 1995; Amdt. 178-118, 61 FR 51342, Oct. 1, 1996; 66 
FR 45389, Aug. 28, 2001; 68 FR 19284, Apr. 18, 2003; 68 FR 52371, Sept. 
3, 2003; 68 FR 75756, Dec. 31, 2003]



Sec.  178.345-15  Certification.

    (a) At or before the time of delivery, the manufacturer of a cargo 
tank motor vehicle must provide certification documents to the owner of 
the cargo tank motor vehicle. The registration numbers of the 
manufacturer, the Design Certifying Engineer, and the Registered 
Inspector, as appropriate, must appear on the certificates (see subpart 
F, part 107 in subchapter A of this chapter).
    (b) The manufacturer of a cargo tank motor vehicle made to any of 
these specifications must provide:
    (1) For each design type, a certificate signed by a responsible 
official of the manufacturer and a Design Certifying Engineer certifying 
that the cargo tank motor vehicle design meets the applicable 
specification; and
    (2) For each ASME cargo tank, a cargo tank manufacturer's data 
report as required by Section VIII of the ASME Code (IBR, see Sec.  
171.7 of this subchapter). For each cargo tank motor vehicle, a 
certificate signed by a responsible official of the manufacturer and a 
Registered Inspector certifying that the cargo tank motor vehicle is 
constructed, tested and completed in conformance with the applicable 
specification.
    (c) The manufacturer of a variable specification cargo tank motor 
vehicle must provide:
    (1) For each design type, a certificate signed by a responsible 
official of the manufacturer and a Design Certifying Engineer certifying 
that the cargo tank motor vehicle design meets the applicable 
specifications; and
    (2) For each variable specification cargo tank motor vehicle, a 
certificate signed by a responsible official of the manufacturer and a 
Registered Inspector certifying that the cargo tank motor vehicle is 
constructed, tested and completed in conformance with the applicable 
specifications. The certificate must include all the information 
required and marked on the variable specification plate.
    (d) In the case of a cargo tank motor vehicle manufactured in two or 
more stages, each manufacturer who performs a manufacturing operation on 
the incomplete vehicle or portion thereof shall provide to the 
succeeding manufacturer, at or before the time of delivery, a 
certificate covering the particular operation performed by that 
manufacturer, including any certificates received from previous 
manufacturers, Registered Inspectors, and Design Certifying Engineers. 
Each certificate must indicate the portion of the complete cargo tank 
motor vehicle represented thereby, such as basic cargo tank fabrication, 
insulation, jacket, lining, or piping. The final manufacturer shall 
provide all applicable certificates to the owner.
    (e) Specification shortages. If a cargo tank is manufactured which 
does not meet all applicable specification requirements, thereby 
requiring subsequent manufacturing involving the installation of 
additional components, parts, appurtenances or accessories, the cargo 
tank manufacturer may affix the name plate and specification plate, as 
required by Sec.  178.345-14 (b) and (c), without the original date of 
certification stamped on the specification plate. The manufacturer shall 
state the specification requirements not complied with on the 
manufacturer's Certificate of Compliance. When the cargo tank is brought 
into full compliance with the applicable specification, the Registered 
Inspector shall stamp the date of compliance on the specification plate. 
The Registered Inspector shall issue a Certificate of Compliance stating 
details of the particular operations performed on the cargo tank, and 
the date and person (manufacturer, carrier,

[[Page 186]]

or repair organization) accomplishing the compliance.

[Amdt. 178-89, 55 FR 37063, Sept. 7, 1990, as amended by Amdt. 178-98, 
58 FR 33306, June 16, 1993; Amdt. 178-105, 59 FR 55176, Nov. 3, 1994; 
Amdt. 178-118, 61 FR 51342, Oct. 1, 1996; 68 FR 75756, Dec. 31, 2003]



Sec.  178.346  Specification DOT 406; cargo tank motor vehicle.



Sec.  178.346-1  General requirements.

    (a) Each Specification DOT 406 cargo tank motor vehicle must meet 
the general design and construction requirements in Sec.  178.345, in 
addition to the specific requirements contained in this section.
    (b) MAWP: The MAWP of each cargo tank must be no lower than 2.65 
psig and no higher than 4 psig.
    (c) Vacuum loaded cargo tanks must not be constructed to this 
specification.
    (d) Each cargo tank must be ``constructed in accordance with Section 
VIII of the ASME Code'' (IBR, see Sec.  171.7 of this subchapter) except 
as modified herein:
    (1) The record-keeping requirements contained in the ASME Code 
Section VIII do not apply. Parts UG-90 through 94 in Section VIII do not 
apply. Inspection and certification must be made by an inspector 
registered in accordance with subpart F of part 107.
    (2) Loadings must be as prescribed in Sec.  178.345-3.
    (3) The knuckle radius of flanged heads must be at least three times 
the material thickness, and in no case less than 0.5 inch. Stuffed 
(inserted) heads may be attached to the shell by a fillet weld. The 
knuckle radius and dish radius versus diameter limitations of UG-32 do 
not apply. Shell sections of cargo tanks designed with a non-circular 
cross section need not be given a preliminary curvature, as prescribed 
in UG-79(b).
    (4) Marking, certification, data reports, and nameplates must be as 
prescribed in Sec. Sec.  178.345-14 and 178.345-15.
    (5) Manhole closure assemblies must conform to Sec. Sec.  178.345-5 
and 178.346-5.
    (6) Pressure relief devices must be as prescribed in Sec.  178.346-
3.
    (7) The hydrostatic or pneumatic test must be as prescribed in Sec.  
178.346-5.
    (8) The following paragraphs in parts UG and UW in Section VIII of 
the ASME Code do not apply: UG-11, UG-12, UG-22(g), UG-32(e), UG-34, UG-
35, UG-44, UG-76, UG-77, UG-80, UG-81, UG-96, UG-97, UW-13(b)(2), UW-
13.1(f) and the dimensional requirements found in Figure UW-13.1.
    (9) Single full fillet lap joints without plug welds may be used for 
arc or gas welded longitudinal seams without radiographic examination 
under the following conditions:
    (i) For a truck-mounted cargo tank, no more than two such joints may 
be used on the top half of the tank and no more than two joints may be 
used on the bottom half. They may not be located farther from the top 
and bottom centerline than 16 percent of the shell's circumference.
    (ii) For a self-supporting cargo tank, no more than two such joints 
may be used on the top of the tank. They may not be located farther from 
the top centerline than 12.5 percent of the shell's circumference.
    (iii) Compliance test. Two test specimens of the material to be used 
in the manufacture of a cargo tank must be tested to failure in tension. 
The test specimens must be of the same thicknesses and joint 
configuration as the cargo tank, and joined by the same welding 
procedures. The test specimens may represent all the tanks that are made 
of the same materials and welding procedures, have the same joint 
configuration, and are made in the same facility within 6 months after 
the tests are completed. Before welding, the fit-up of the joints on the 
test specimens must represent production conditions that would result in 
the least joint strength. Evidence of joint fit-up and test results must 
be retained at the manufacturers' facility.
    (iv) Weld joint efficiency. The lower value of stress at failure 
attained in the two tensile test specimens shall be used to compute the 
efficiency of the joint as follows: Determine the failure ratio by 
dividing the stress at failure by the mechanical properties of the 
adjacent metal; this value, when multiplied by 0.75, is the design weld 
joint efficiency.

[[Page 187]]

    (10) The requirements of paragraph UW-9(d) in Section VIII of the 
ASME Code do not apply.

[Amdt. 178-89, 54 FR 25028, June 12, 1989, as amended at 55 FR 37063, 
Sept. 7, 1990; Amdt. 178-89, 56 FR 27877, June 17, 1991; Amdt. 178-105, 
59 FR 55176, Nov. 3, 1994; 65 FR 58631, Sept. 29, 2000; 66 FR 45387, 
Aug. 28, 2001; 68 FR 19285, Apr. 18, 2003; 68 FR 75756, Dec. 31, 2003]



Sec.  178.346-2  Material and thickness of material.

    The type and thickness of material for DOT 406 specification cargo 
tanks must conform to Sec.  178.345-2, but in no case may the thickness 
be less than that determined by the minimum thickness requirements in 
Sec.  178.320(a). The following Tables I and II identify the specified 
minimum thickness values to be employed in that determination.

 Table I--Specified Minimum Thickness of Heads (or Bulkheads and Baffles When Used as Tank Reinforcement) Using
   Mild Steel (MS), High Strength Low Alloy Steel (HSLA), Austenitic Stainless Steel (SS), or Aluminum (AL)--
                                 Expressed in Decimals of an Inch After Forming
----------------------------------------------------------------------------------------------------------------
                                                  Volume capacity in gallons per inch of length
                                --------------------------------------------------------------------------------
            Material                     14 or less               Over 14 to 23                 Over 23
                                --------------------------------------------------------------------------------
                                    MS    HSLA SS     AL       MS    HSLA SS     AL       MS    HSLA SS     AL
----------------------------------------------------------------------------------------------------------------
Thickness......................     .100     .100     .160     .115     .115     .173     .129     .129     .187
----------------------------------------------------------------------------------------------------------------


  Table II--Specified Minimum Thickness of Shell Using Mild Steel (MS),
 High Strength Low Alloy Steel (HSLA), Austenitic Stainless Steel (SS),
  or Aluminum (AL)--Expressed in Decimals of an Inch After Forming \1\
------------------------------------------------------------------------
 Cargo tank motor vehicle rated capacity
                (gallons)                     MS      SS/HSLA      AL
------------------------------------------------------------------------
More than 0 to at least 4,500............     0.100      0.100     0.151
More than 4,500 to at least 8,000........     0.115      0.100     0.160
More than 8,000 to at least 14,000.......     0.129      0.129     0.173
More than 14,000.........................     0.143      0.143     0.187
------------------------------------------------------------------------
\1\ Maximum distance between bulkheads, baffles, or ring stiffeners
  shall not exceed 60 inches.


[Amdt. 178-89, 54 FR 25028, June 12, 1989, as amended at 55 FR 37064, 
Sept. 7, 1990; Amdt. 178-105, 59 FR 55176, Nov. 3, 1994; 68 FR 19285, 
Apr. 18, 2003]



Sec.  178.346-3  Pressure relief.

    (a) Each cargo tank must be equipped with a pressure relief system 
in accordance with Sec.  178.345-10 and this section.
    (b) Type and construction. In addition to the pressure relief 
devices required in Sec.  178.345-10:
    (1) Each cargo tank must be equipped with one or more vacuum relief 
devices;
    (2) When intended for use only for lading meeting the requirements 
of Sec.  173.33(c)(1)(iii) of this subchapter, the cargo tank may be 
equipped with a normal vent. Such vents must be set to open at not less 
than 1 psig and must be designed to prevent loss of lading through the 
device in case of vehicle upset; and
    (3) Notwithstanding the requirements in Sec.  178.345-10(b), after 
August 31, 1996, each pressure relief valve must be able to withstand a 
dynamic pressure surge reaching 30 psig above the design set pressure 
and sustained above the set pressure for at least 60 milliseconds with a 
total volume of liquid released not exceeding 1 L before the relief 
valve recloses to a leak-tight condition. This requirement must be met 
regardless of vehicle orientation. This capability must be demonstrated 
by testing. TTMA RP No. 81 (IBR, see Sec.  171.7 of this subchapter), 
cited at Sec.  178.345-10(b)(3)(i), is an acceptable test procedure.
    (c) Pressure settings of relief valves. (1) Notwithstanding the 
requirements in Sec.  178.345-10(d), the set pressure of each

[[Page 188]]

primary relief valve must be not less than 110 percent of the MAWP or 
3.3 psig, whichever is greater, and not more than 138 percent of the 
MAWP. The valve must close at not less than the MAWP and remain closed 
at lower pressures.
    (2) Each vacuum relief device must be set to open at no more than 6 
ounces vacuum.
    (d) Venting capacities. (1) Notwithstanding the requirements in 
Sec.  178.345-10 (e) and (g), the primary pressure relief valve must 
have a venting capacity of at least 6,000 SCFH, rated at not greater 
than 125 percent of the tank test pressure and not greater than 3 psig 
above the MAWP. The venting capacity required in Sec.  178.345-10(e) may 
be rated at these same pressures.
    (2) Each vacuum relief system must have sufficient capacity to limit 
the vacuum to 1 psig.
    (3) If pressure loading or unloading devices are provided, the 
relief system must have adequate vapor and liquid capacity to limit the 
tank pressure to the cargo tank test pressure at maximum loading or 
unloading rate. The maximum loading and unloading rates must be included 
on the metal specification plate.

[Amdt. 178-89, 54 FR 25029, June 12, 1989, as amended at 55 FR 37064, 
Sept. 7, 1990; Amdt. 178-105, 59 FR 55176, Nov. 3, 1994. Redesignated by 
Amdt. 178-112, 61 FR 18934, Apr. 29, 1996; 66 FR 45389, Aug. 28, 2001; 
68 FR 75756, Dec. 31, 2003]



Sec.  178.346-4  Outlets.

    (a) All outlets on each tank must conform to Sec.  178.345-11 and 
this section.
    (b) External self-closing stop-valves are not authorized as an 
alternative to internal self-closing stop-valves on loading/unloading 
outlets.

[Amdt. 178-89, 54 FR 25029, June 12, 1989. Redesignated by Amdt. 178-
112, 61 FR 18934, Apr. 29, 1996]



Sec.  178.346-5  Pressure and leakage tests.

    (a) Each cargo tank must be tested in accordance with Sec.  178.345-
13 and this section.
    (b) Pressure test. Test pressure must be as follows:
    (1) Using the hydrostatic test method, the test pressure must be the 
greater of 5.0 psig or 1.5 times the cargo tank MAWP.
    (2) Using the pneumatic test method, the test pressure must be the 
greater of 5.0 psig or 1.5 times the cargo tank MAWP, and the inspection 
pressure must be the cargo tank MAWP.
    (c) Leakage test. A cargo tank used to transport a petroleum 
distillate fuel that is equipped with vapor recovery equipment may be 
leakage tested in accordance with 40 CFR 63.425(e). To satisfy the 
leakage test requirements of this paragraph, the test specified in 40 
CFR 63.425(e)(1) must be conducted using air. The hydrostatic test 
alternative permitted under Appendix A to 40 CFR Part 60 (``Method 27--
Determination of Vapor Tightness of Gasoline Delivery Tank Using 
Pressure-Vacuum Test'') may not be used to satisfy the leakage test 
requirements of this paragraph. A cargo tank tested in accordance with 
40 CFR 63.425(e) may be marked as specified in Sec.  180.415 of this 
subchapter.

[Amdt. 178-89, 54 FR 25029, June 12, 1989, as amended at 55 FR 37064, 
Sept. 7, 1990; Amdt. 178-105, 59 FR 55176, Nov. 3, 1994. Redesignated by 
Amdt. 178-112, 61 FR 18934, Apr. 29, 1996; 68 FR 19285, Apr. 18, 2003]



Sec.  178.347  Specification DOT 407; cargo tank motor vehicle.



Sec.  178.347-1  General requirements.

    (a) Each specification DOT 407 cargo tank motor vehicle must conform 
to the general design and construction requirements in Sec.  178.345 in 
addition to the specific requirements contained in this section.
    (b) Each tank must be of a circular cross-section and have an MAWP 
of at least 25 psig.
    (c) Any cargo tank motor vehicle built to this specification with a 
MAWP greater than 35 psig or any cargo tank motor vehicle built to this 
specification designed to be loaded by vacuum must be constructed and 
certified in accordance with Section VIII of the ASME Code (IBR, see 
Sec.  171.7 of this subchapter). The external design pressure for a 
cargo tank loaded by vacuum must be at least 15 psi.
    (d) Any cargo tank motor vehicle built to this specification with a 
MAWP of 35 psig or less or any cargo

[[Page 189]]

tank motor vehicle built to this specification designed to withstand 
full vacuum but not equipped to be loaded by vacuum must be constructed 
in accordance with Section VIII of the ASME Code.
    (1) The record-keeping requirements contained in Section VIII of the 
ASME Code do not apply. The inspection requirements of parts UG-90 
through 94 do not apply. Inspection and certification must be made by an 
inspector registered in accordance with subpart F of part 107.
    (2) Loadings must be as prescribed in Sec.  178.345-3.
    (3) The knuckle radius of flanged heads must be at least three times 
the material thickness, and in no case less than 0.5 inch. Stuffed 
(inserted) heads may be attached to the shell by a fillet weld. The 
knuckle radius and dish radius versus diameter limitations of UG-32 do 
not apply for cargo tank motor vehicles with a MAWP of 35 psig or less.
    (4) Marking, certification, data reports and nameplates must be as 
prescribed in Sec. Sec.  178.345-14 and 178.345-15.
    (5) Manhole closure assemblies must conform to Sec.  178.347-3.
    (6) Pressure relief devices must be as prescribed in Sec.  178.347-
4.
    (7) The hydrostatic or pneumatic test must be as prescribed in Sec.  
178.347-5.
    (8) The following paragraphs in parts UG and UW in Section VIII the 
ASME Code do not apply: UG-11, UG-12, UG-22(g), UG-32(e), UG-34, UG-35, 
UG-44, UG-76, UG-77, UG-80, UG-81, UG-96, UG-97, UW-12, UW-13(b)(2), UW-
13.1(f), and the dimensional requirements found in Figure UW-13.1.
    (9) UW-12 in Section VIII of the ASME Code does not apply to a weld 
seam in a bulkhead that has not been radiographically examined, under 
the following conditions:
    (i) The strength of the weld seam is assumed to be 0.85 of the 
strength of the bulkhead.
    (ii) The welded seam must be a full penetration butt weld.
    (iii) No more than one seam may be used per bulkhead.
    (iv) The welded seam must be completed before forming the dish 
radius and knuckle radius.
    (v) Compliance test: Two test specimens of materials representative 
of those to be used in the manufacture of a cargo tank bulkhead must be 
tested to failure in tension. The test specimen must be of the same 
thickness and joined by the same welding procedure. The test specimens 
may represent all the tanks that are made in the same facility within 6 
months after the tests are completed. Before welding, the fit-up of the 
joints on the test specimens must represent production conditions that 
would result in the least joint strength. Evidence of joint fit-up and 
test results must be retained at the manufacturer's facility for at 
least 5 years.
    (vi) Acceptance criteria: The ratio of the actual tensile stress at 
failure to the actual tensile strength of the adjacent material of all 
samples of a test lot must be greater than 0.85.

[Amdt. 178-89, 54 FR 25029, June 12, 1989, as amended at 55 FR 37064, 
Sept. 7, 1990; Amdt. 178-89, 56 FR 27877, June 17, 1991; 65 FR 58632, 
Sept. 29, 2000; 66 FR 45387, Aug. 28, 2001; 68 FR 19285, Apr. 18, 2003; 
68 FR 75756, Dec. 31, 2003; 76 FR 3388, Jan. 19, 2011; 76 FR 43532, July 
20, 2011]



Sec.  178.347-2  Material and thickness of material.

    (a) The type and thickness of material for DOT 407 specification 
cargo tanks must conform to Sec.  178.345-2, but in no case may the 
thickness be less than that determined by the minimum thickness 
requirements in Sec.  178.320(a). Tables I and II identify the specified 
minimum thickness values to be employed in that the determination:

 Table I--Specified Minimum Thickness of Heads (or Bulkheads and Baffles When Used as Tank Reinforcement) Using
   Mild Steel (MS), High Strength Low Alloy Steel (HSLA), Austenitic Stainless Steel (SS), or Aluminum (AL)--
                                 Expressed in Decimals of an Inch After Forming
----------------------------------------------------------------------------------------------------------------
                                              10 or    Over 10   Over 14   Over 18   Over 22   Over 26
    Volume capacity in gallons per inch       less      to 14     to 18     to 22     to 26     to 30    Over 30
----------------------------------------------------------------------------------------------------------------
Thickness (MS)............................     0.100     0.100     0.115     0.129     0.129     0.143     0.156

[[Page 190]]

 
Thickness (HSLA)..........................     0.100     0.100     0.115     0.129     0.129     0.143     0.156
Thickness (SS)............................     0.100     0.100     0.115     0.129     0.129     0.143     0.156
Thickness (AL)............................     0.160     0.160     0.173     0.187     0.194     0.216     0.237
----------------------------------------------------------------------------------------------------------------


   Table II--Specified Minimum Thickness of Shell Using Mild Steel (MS), High Strength Low Alloy Steel (HSLA),
        Austenitic Stainless Steel (SS), or Aluminum (AL)--Expressed in Decimals of an Inch After Forming
----------------------------------------------------------------------------------------------------------------
                                              10 or    Over 10   Over 14   Over 18   Over 22   Over 26
    Volume capacity in gallons per inch       less      to 14     to 18     to 22     to 26     to 30    Over 30
----------------------------------------------------------------------------------------------------------------
Thickness (MS)............................     0.100     0.100     0.115     0.129     0.129     0.143     0.156
Thickness (HSLA)..........................     0.100     0.100     0.115     0.129     0.129     0.143     0.156
Thickness (SS)............................     0.100     0.100     0.115     0.129     0.129     0.143     0.156
Thickness (AL)............................     0.151     0.151     0.160     0.173     0.194     0.216     0.237
----------------------------------------------------------------------------------------------------------------

    (b) [Reserved]

[Amdt. 178-89, 54 FR 25030, June 12, 1989, as amended at 55 FR 37064, 
Sept. 7, 1990; Amdt. 178-104, 59 FR 49135, Sept. 26, 1994; 68 FR 19285, 
Apr. 18, 2003]



Sec.  178.347-3  Manhole assemblies.

    Each manhole assembly must conform to Sec.  178.345-5, except that 
each manhole assembly must be capable of withstanding internal fluid 
pressures of 40 psig or test pressure of the tank, whichever is greater.

[Amdt. 178-89, 54 FR 25030, June 12, 1989. Redesignated by Amdt. 178-
112, 61 FR 18934, Apr. 29, 1996]



Sec.  178.347-4  Pressure relief.

    (a) Each cargo tank must be equipped with a pressure and vacuum 
relief system in accordance with Sec.  178.345-10 and this section.
    (b) Type and construction. Vacuum relief devices are not required 
for cargo tank motor vehicles that are designed to be loaded by vacuum 
in accordance with Sec.  178.347-1(c) or built to withstand full vacuum 
in accordance with Sec.  178.347-1(d).
    (c) Pressure settings of relief valves. The setting of pressure 
relief valves must be in accordance with Sec.  178.345-10(d).
    (d) Venting capacities. (1) The vacuum relief system must limit the 
vacuum to less than 80 percent of the design vacuum capability of the 
cargo tank.
    (2) If pressure loading or unloading devices are provided, the 
relief system must have adequate vapor and liquid capacity to limit the 
tank pressure to the cargo tank test pressure at maximum loading or 
unloading rate. The maximum loading or unloading rate must be included 
on the metal specification plate.

[Amdt. 178-89, 54 FR 25030, June 12, 1989, as amended at 55 FR 37064, 
Sept. 7, 1990. Redesignated by Amdt. 178-112, 61 FR 18934, Apr. 29, 
1996; 76 FR 43532, July 20, 2011]



Sec.  178.347-5  Pressure and leakage test.

    (a) Each cargo tank must be tested in accordance with Sec.  178.345-
13 and this section.
    (b) Pressure test. Test pressure must be as follows:
    (1) Using the hydrostatic test method, the test pressure must be at 
least 40 psig or 1.5 times tank MAWP, whichever is greater.
    (2) Using the pneumatic test method, the test pressure must be 40 
psig or 1.5

[[Page 191]]

times tank MAWP, whichever is greater, and the inspection pressure is 
tank MAWP.

[Amdt. 178-89, 54 FR 25030, June 12, 1989. Redesignated by Amdt. 178-
112, 61 FR 18934, Apr. 29, 1996]



Sec.  178.348  Specification DOT 412; cargo tank motor vehicle.



Sec.  178.348-1  General requirements.

    (a) Each specification DOT 412 cargo tank motor vehicle must conform 
to the general design and construction requirements in Sec.  178.345 in 
addition to the specific requirements of this section.
    (b) The MAWP of each cargo tank must be at least 5 psig.
    (c) The MAWP for each cargo tank designed to be loaded by vacuum 
must be at least 25 psig internal and 15 psig external.
    (d) Each cargo tank having a MAWP greater than 15 psig must be of 
circular cross-section.
    (e) Each cargo tank having a--
    (1) MAWP greater than 15 psig must be ``constructed and certified in 
conformance with Section VIII of the ASME Code'' (IBR, see Sec.  171.7 
of this subchapter); or
    (2) MAWP of 15 psig or less must be ``constructed in accordance with 
Section VIII of the ASME Code,'' except as modified herein:
    (i) The recordkeeping requirements contained in Section VIII of the 
ASME Code do not apply. Parts UG-90 through 94 in Section VIII do not 
apply. Inspection and certification must be made by an inspector 
registered in accordance with subpart F of part 107.
    (ii) Loadings must be as prescribed in Sec.  178.345-3.
    (iii) The knuckle radius of flanged heads must be at least three 
times the material thickness, and in no case less than 0.5 inch. Stuffed 
(inserted) heads may be attached to the shell by a fillet weld. The 
knuckle radius and dish radius versus diameter limitations of UG-32 do 
not apply for cargo tank motor vehicles with a MAWP of 15 psig or less. 
Shell sections of cargo tanks designed with a non-circular cross section 
need not be given a preliminary curvature, as prescribed in UG-79(b).
    (iv) Marking, certification, data reports, and nameplates must be as 
prescribed in Sec. Sec.  178.345-14 and 178.345-15.
    (v) Manhole closure assemblies must conform to Sec. Sec.  178.345-5.
    (vi) Pressure relief devices must be as prescribed in Sec.  178.348-
4.
    (vii) The hydrostatic or pneumatic test must be as prescribed in 
Sec.  178.348-5.
    (viii) The following paragraphs in parts UG and UW in Section VIII 
of the ASME Code do not apply: UG-11, UG-12, UG-22(g), UG-32(e), UG-34, 
UG-35, UG-44, UG-76, UG-77, UG-80, UG-81, UG-96, UG-97, UW-13(b)(2), UW-
13.1(f), and the dimensional requirements found in Figure UW-13.1.

[Amdt. 178-89, 54 FR 25031, June 12, 1989, as amended at 55 FR 37065, 
Sept. 7, 1990; Amdt. 178-89, 56 FR 27877, June 17, 1991; 65 FR 58632, 
Sept. 29, 2000; 68 FR 19285, Apr. 18, 2003; 68 fR 75756, Dec. 31, 2003]



Sec.  178.348-2  Material and thickness of material.

    (a) The type and thickness of material for DOT 412 specification 
cargo tanks must conform to Sec.  178.345-2, but in no case may the 
thickness be less than that determined by the minimum thickness 
requirements in Sec.  178.320(a). The following Tables I and II identify 
the ``Specified Minimum Thickness'' values to be employed in that 
determination.

[[Page 192]]



 Table I--Specified Minimum Thickness of Heads (or Bulkheads and Baffles When Used as Tank Reinforcement) Using Mild Steel (MS), High Strength Low Alloy
                     Steel (HSLA), Austenitic Stainless Steel (SS), or Aluminum (AL)--Expressed in Decimals of an Inch After Forming
--------------------------------------------------------------------------------------------------------------------------------------------------------
   Volume capacity (gallons per inch)               10 or less                     Over 10 to 14               Over 14 to 18            18 and over
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
Lading density at 60 [deg]F in pounds     10 lbs    Over    Over    Over  10 lbs    Over    Over    Over  10 lbs    Over    Over  10 lbs    Over    Over
 per gallon.............................     and   10 to   13 to  16 lbs     and   10 to   13 to  16 lbs     and   10 to   13 to     and   10 to   13 to
                                            less  13 lbs  16 lbs            less  13 lbs  16 lbs            less  13 lbs  16 lbs    less  13 lbs  16 lbs
Thickness (inch), steel.................    .100    .129    .157    .187    .129    .157    .187    .250    .157    .250    .250    .157    .250    .312
Thickness (inch), aluminum..............    .144    .187    .227    .270    .187    .227    .270    .360    .227    .360    .360    .227    .360    .450
--------------------------------------------------------------------------------------------------------------------------------------------------------


Table II--Specified Minimum Thickness of Shell Using Mild Steel (MS), High Strength Low Alloy Steel (HSLA), Austenitic Stainless Steel (SS), or Aluminum
                                                  (AL)--Expressed in Decimals of an Inch After Forming
--------------------------------------------------------------------------------------------------------------------------------------------------------
   Volume capacity in gallons per inch              10 or less                     Over 10 to 14               Over 14 to 18            18 and over
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
Lading density at 60 [deg]F in pounds     10 lbs    Over    Over    Over  10 lbs    Over    Over    Over  10 lbs    Over    Over  10 lbs    Over    Over
 per gallon.............................     and   10 to   13 to  16 lbs     and   10 to   13 to  16 lbs     and   10 to   13 to     and   10 to   13 to
                                            less  13 lbs  16 lbs            less  13 lbs  16 lbs            less  13 lbs  16 lbs    less  13 lbs  16 lbs
Thickness (steel):
    Distances between heads (and
     bulkheads baffles and ring
     stiffeners when used as tank
     reinforcement):
        36 in. or less..................    .100    .129    .157    .187    .100    .129    .157    .187    .100    .129    .157    .129    .157    .187
        Over 36 in. to 54 inches........    .100    .129    .157    .187    .100    .129    .157    .187    .129    .157    .187    .157    .250    .250
        Over 54 in. to 60 inches........    .100    .129    .157    .187    .129    .157    .187    .250    .157    .250    .250    .187    .250    .312
Thickness (aluminum):
    Distances between heads (and
     bulkheads baffles and ring
     stiffeners when used as tank
     reinforcement):
        36 in. or less..................    .144    .187    .227    .270    .144    .187    .227    .270    .144    .187    .227    .187    .227    .270
        Over 36 in. to 54 inches........    .144    .187    .227    .270    .144    .187    .227    .270    .187    .227    .270    .157    .360    .360
        Over 54 in. to 60 inches........    .144    .187    .227    .270    .187    .227    .270    .360    .227    .360    .360    .270    .360    .450
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 193]]

    (b) [Reserved]

[Amdt. 178-89, 54 FR 25031, June 12, 1989; 54 FR 28750, July 7, 1989, as 
amended at 55 FR 37065, Sept. 7, 1990; 68 FR 19285, Apr. 18, 2003]



Sec.  178.348-3  Pumps, piping, hoses and connections.

    Each pump and all piping, hoses and connections on each cargo tank 
motor vehicle must conform to Sec.  178.345-9, except that the use of 
nonmetallic pipes, valves, or connections are authorized on DOT 412 
cargo tanks.

[Amdt. 178-89, 55 FR 37065, Sept. 7, 1990. Redesignated by Amdt. 178-
112, 61 FR 18934, Apr. 29, 1996]



Sec.  178.348-4  Pressure relief.

    (a) Each cargo tank must be equipped with a pressure and vacuum 
relief system in accordance with Sec.  178.345-10 and this section.
    (b) Type and construction. Vacuum relief devices are not required 
for cargo tanks designed to be loaded by vacuum or built to withstand 
full vacuum.
    (c) Pressure settings of relief valves. The setting of the pressure 
relief devices must be in accordance with Sec.  178.345-10(d), except as 
provided in paragraph (d)(3) of this section.
    (d) Venting capacities. (1) The vacuum relief system must limit the 
vacuum to less than 80 percent of the design vacuum capability of the 
cargo tank.
    (2) If pressure loading or unloading devices are provided, the 
pressure relief system must have adequate vapor and liquid capacity to 
limit tank pressure to the cargo tank test pressure at the maximum 
loading or unloading rate. The maximum loading and unloading rates must 
be included on the metal specification plate.
    (3) Cargo tanks used in dedicated service for materials classed as 
corrosive material, with no secondary hazard, may have a total venting 
capacity which is less than required by Sec.  178.345-10(e). The minimum 
total venting capacity for these cargo tanks must be determined in 
accordance with the following formula (use of approximate values given 
for the formula is acceptable):

                       Formula in Nonmetric Units

Q = 37,980,000 A\0.82\ (ZT)\0.5\ / (LC)(M\0.5\)

Where:

Q = The total required venting capacity, in cubic meters of air per hour 
          at standard conditions of 15.6 [deg]C and 1 atm (cubic feet of 
          air per hour at standard conditions of 60 [deg]F and 14.7 
          psia);
T = The absolute temperature of the vapor at the venting conditions--
          degrees Kelvin ([deg]C + 273) [degrees Rankine ([deg]F + 
          460)];
A = The exposed surface area of tank shell--square meters (square feet);
L = The latent heat of vaporization of the lading--calories per gram 
          (BTU/lb);
Z = The compressibility factor for the vapor (if this factor is unknown, 
          let Z equal 1.0);
M = The molecular weight of vapor;
C = A constant derived from (K), the ratio of specific heats of the 
          vapor. If (K) is unknown, let C = 315.

C = 520[K(2/(K ++ 1))[(K + 1)/(K-1)]]\0.5\

Where:

K = Cp / Cv
Cp = The specific heat at constant pressure, in -calories per 
          gram degree centigrade (BTU/lb [deg]F.); and
Cv = The specific heat at constant volume, in -calories per 
          gram degree centigrade (BTU/lb [deg]F.).

[Amdt. 178-89, 54 FR 25032, June 12, 1989, as amended at 55 FR 37065, 
Sept. 7, 1990; Amdt. 178-104, 59 FR 49135, Sept. 26, 1994. Redesignated 
by Amdt. 178-112, 61 FR 18934, Apr. 29, 1996; 72 FR 55696, Oct. 1, 2007; 
72 FR 59146, Oct. 18, 2007]



Sec.  178.348-5  Pressure and leakage test.

    (a) Each cargo tank must be tested in accordance with Sec.  178.345-
13 and this section.
    (b) Pressure test. Test pressure must be as follows:
    (1) Using the hydrostatic test method, the test pressure must be at 
least 1.5 times MAWP.
    (2) Using the pneumatic test method, the test pressure must be at 
least 1.5 times tank MAWP, and the inspection pressure is tank MAWP.

[Amdt. 178-89, 54 FR 25032, June 12, 1989. Redesignated by Amdt. 178-
112, 61 FR 18934, Apr. 29, 1996]

[[Page 194]]



   Subpart K_Specifications for Packagings for Class 7 (Radioactive) 
                                Materials



Sec.  178.350  Specification 7A; general packaging, Type A.

    (a) Each packaging must meet all applicable requirements of subpart 
B of part 173 of this subchapter and be designed and constructed so that 
it meets the requirements of Sec. Sec.  173.403, 173.410, 173.412, 
173.415 and 173.465 of this subchapter for Type A packaging.
    (b) Each Specification 7A packaging must be marked on the outside 
``USA DOT 7A Type A.''
    (c) Each Specification 7A packaging must comply with the 
requirements of Sec. Sec.  178.2 and 178.3. In Sec.  178.3(a)(2) the 
term ``packaging manufacturer'' means the person certifying that the 
package meets all requirements of this section.

[Amdt. 178-109, 60 FR 50336, Sept. 28, 1995; 60 FR 54409, Oct. 23, 1995, 
as amended at 69 FR 3696, Jan. 26, 2004; 70 FR 56099, Sept. 23, 2005; 79 
FR 40618, July 11, 2014]



       Subpart L_Non-bulk Performance-Oriented Packaging Standards

    Source: Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, unless otherwise 
noted.



Sec.  178.500  Purpose, scope and definitions.

    (a) This subpart prescribes certain requirements for non-bulk 
packagings for hazardous materials. Standards for these packagings are 
based on the UN Recommendations.
    (b) Terms used in this subpart are defined in Sec.  171.8 of this 
subchapter.



Sec.  178.502  Identification codes for packagings.

    (a) Identification codes for designating kinds of packagings consist 
of the following:
    (1) A numeral indicating the kind of packaging, as follows:
    (i) ``1'' means a drum.
    (ii) ``2'' means a wooden barrel.
    (iii) ``3'' means a jerrican.
    (iv) ``4'' means a box.
    (v) ``5'' means a bag.
    (vi) ``6'' means a composite packaging.
    (vii) ``7'' means a pressure receptacle.
    (2) A capital letter indicating the material of construction, as 
follows:
    (i) ``A'' means steel (all types and surface treatments).
    (ii) ``B'' means aluminum.
    (iii) ``C'' means natural wood.
    (iv) ``D'' means plywood.
    (v) ``F'' means reconstituted wood.
    (vi) ``G'' means fiberboard.
    (vii) ``H'' means plastic.
    (viii) ``L'' means textile.
    (ix) ``M'' means paper, multi-wall.
    (x) ``N'' means metal (other than steel or aluminum).
    (xi) ``P'' means glass, porcelain or stoneware.
    (3) A numeral indicating the category of packaging within the kind 
to which the packaging belongs. For example, for steel drums (``1A''), 
``1'' indicates a non-removable head drum ( i.e., ``1A1'') and ``2'' 
indicates a removable head drum (i.e., ``1A2'').
    (b) For composite packagings, two capital letters are used in 
sequence in the second position of the code, the first indicating the 
material of the inner receptacle and the second, that of the outer 
packaging. For example, a plastic receptacle in a steel drum is 
designated ``6HA1''.
    (c) For combination packagings, only the code number for the outer 
packaging is used.
    (d) Identification codes are set forth in the standards for 
packagings in Sec. Sec.  178.504 through 178.523 of this subpart.

    Note to Sec.  178.502: Plastics materials include other polymeric 
materials such as rubber.

[Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, as amended by Amdt. 178-106, 
59 FR 67519, Dec. 29, 1994; 74 FR 2269, Jan. 14, 2009]



Sec.  178.503  Marking of packagings.

    (a) A manufacturer must mark every packaging that is represented as 
manufactured to meet a UN standard with the marks specified in this 
section. The markings must be durable, legible and placed in a location 
and of such a size relative to the packaging as to be readily visible, 
as specified in Sec.  178.3(a). Except as otherwise provided in this 
section, every reusable packaging liable to undergo a reconditioning 
process which might obliterate the packaging

[[Page 195]]

marks must bear the marks specified in paragraphs (a)(1) through (a)(6) 
and (a)(9) of this section in a permanent form (e.g. embossed) able to 
withstand the reconditioning process. A marking may be applied in a 
single line or in multiple lines provided the correct sequence is used. 
As illustrated by the examples in paragraph (e) of this section, the 
following information must be presented in the correct sequence. Slash 
marks should be used to separate this information. A packaging 
conforming to a UN standard must be marked as follows:
    (1) Except as provided in paragraph (e)(1)(ii) of this section, the 
United Nations symbol as illustrated in paragraph (e)(1)(i) of this 
section (for embossed metal receptacles, the letters ``UN'' may be 
applied in place of the symbol);
    (2) A packaging identification code designating the type of 
packaging, the material of construction and, when appropriate, the 
category of packaging under Sec. Sec.  178.504 through 178.523 of this 
subpart within the type to which the packaging belongs. The letter ``V'' 
must follow the packaging identification code on packagings tested in 
accordance with Sec.  178.601(g)(2); for example, ``4GV''. The letter 
``W'' must follow the packaging identification code on packagings when 
required by an approval under the provisions of Sec.  178.601(h) of this 
part;
    (3) A letter identifying the performance standard under which the 
packaging design type has been successfully tested, as follows:
    (i) X--for packagings meeting Packing Group I, II and III tests;
    (ii) Y--for packagings meeting Packing Group II and III tests; or
    (iii) Z--for packagings only meeting Packing Group III tests;
    (4) A designation of the specific gravity or mass for which the 
packaging design type has been tested, as follows:
    (i) For packagings without inner packagings intended to contain 
liquids, the designation shall be the specific gravity rounded down to 
the first decimal but may be omitted when the specific gravity does not 
exceed 1.2; and
    (ii) For packagings intended to contain solids or inner packagings, 
the designation shall be the maximum gross mass in kilograms;
    (5)(i) For single and composite packagings intended to contain 
liquids, the test pressure in kilopascals rounded down to the nearest 10 
kPa of the hydrostatic pressure test that the packaging design type has 
successfully passed;
    (ii) For packagings intended to contain solids or inner packagings, 
the letter ``S'';
    (6) The last two digits of the year of manufacture. Packagings of 
types 1H and 3H shall also be marked with the month of manufacture in 
any appropriate manner; this may be marked on the packaging in a 
different place from the remainder of the markings;
    (7) The state authorizing allocation of the mark. The letters `USA' 
indicate that the packaging is manufactured and marked in the United 
States in compliance with the provisions of this subchapter;
    (8) The name and address or symbol of the manufacturer or the 
approval agency certifying compliance with subpart L and subpart M of 
this part. Symbols, if used, must be registered with the Associate 
Administrator;
    (9) For metal or plastic drums or jerricans intended for reuse or 
reconditioning as single packagings or the outer packagings of a 
composite packaging, the thickness of the packaging material, expressed 
in mm (rounded to the nearest 0.1 mm), as follows:
    (i) Metal drums or jerricans must be marked with the nominal 
thickness of the metal used in the body. The marked nominal thickness 
must not exceed the minimum thickness of the steel used by more than the 
thickness tolerance stated in ISO 3574 (IBR, see Sec.  171.7 of this 
subchapter). (See appendix C of this part.) The unit of measure is not 
required to be marked. When the nominal thickness of either head of a 
metal drum is thinner than that of the body, the nominal thickness of 
the top head, body, and bottom head must be marked (e.g., ``1.0-1.2-
1.0'' or ``0.9-1.0-1.0'').
    (ii) Plastic drums or jerricans must be marked with the minimum 
thickness of the packaging material. Minimum thicknesses of plastic must 
be as determined in accordance with

[[Page 196]]

Sec.  173.28(b)(4). The unit of measure is not required to be marked;
    (10) In addition to the markings prescribed in paragraphs (a)(1) 
through (a)(9) of this section, every new metal drum having a capacity 
greater than 100 L must bear the marks described in paragraphs (a)(1) 
through (a)(6), and (a)(9)(i) of this section, in a permanent form, on 
the bottom. The markings on the top head or side of these packagings 
need not be permanent, and need not include the thickness mark described 
in paragraph (a)(9) of this section. This marking indicates a drum's 
characteristics at the time it was manufactured, and the information in 
paragraphs (a)(1) through (a)(6) of this section that is marked on the 
top head or side must be the same as the information in paragraphs 
(a)(1) through (a)(6) of this section permanently marked by the original 
manufacturer on the bottom of the drum; and
    (11) Rated capacity of the packaging expressed in liters may be 
marked.
    (b) For a packaging with a removable head, the markings may not be 
applied only to the removable head.
    (c) Marking of reconditioned packagings. (1) If a packaging is 
reconditioned, it shall be marked by the reconditioner near the marks 
required in paragraphs (a)(1) through (6) of this section with the 
following additional information:
    (i) The name of the country in which the reconditioning was 
performed (in the United States, use the letters ``USA'');
    (ii) The name and address or symbol of the reconditioner. Symbols, 
if used, must be registered with the Associate Administrator;
    (iii) The last two digits of the year of reconditioning;
    (iv) The letter ``R''; and
    (v) For every packaging successfully passing a leakproofness test, 
the additional letter ``L''.
    (2) When, after reconditioning, the markings required by paragraph 
(a)(1) through (a)(5) of this section no longer appear on the top head 
or the side of the metal drum, the reconditioner must apply them in a 
durable form followed by the markings in paragraph (c)(1) of this 
section. These markings may identify a different performance capability 
than that for which the original design type had been tested and marked, 
but may not identify a greater performance capability. The markings 
applied in accordance with this paragraph may be different from those 
which are permanently marked on the bottom of a drum in accordance with 
paragraph (a)(10) of this section.
    (d) Marking of remanufactured packagings. For remanufactured metal 
drums, if there is no change to the packaging type and no replacement or 
removal of integral structural components, the required markings need 
not be permanent (e.g., embossed). Every other remanufactured drum must 
bear the marks required in paragraphs (a)(1) through (a)(6) of this 
section in a permanent form (e.g., embossed) on the top head or side. If 
the metal thickness marking required in paragraph (a)(9)(i) of this 
section does not appear on the bottom of the drum, or if it is no longer 
valid, the remanufacturer also must mark this information in permanent 
form.
    (e) The following are examples of symbols and required markings.
    (1)(i) The United Nations symbol is:
    [GRAPHIC] [TIFF OMITTED] TR05OC12.059
    

[[Page 197]]


    (ii) The circle that surrounds the letters ``u'' and ``n'' may have 
small breaks provided the following provisions are met:
    (A) The total gap space does not exceed 15 percent of the 
circumference of the circle;
    (B) There are no more than four gaps in the circle;
    C) The spacing between gaps is separated by no less than 20 percent 
of the circumference of the circle (72 degrees); and
    D) The letters ``u'' and ``n'' appear exactly as depicted in Sec.  
178.503(e)(1)(i) with no gaps.
    (2) Examples of markings for a new packaging are as follows:
    (i) For a fiberboard box designed to contain an inner packaging:
    [GRAPHIC] [TIFF OMITTED] TR05OC12.060
    

(as in Sec.  178.503 (a)(1) through (9) of this subpart).

    (ii) For a steel drum designed to contain liquids:
    [GRAPHIC] [TIFF OMITTED] TR05OC12.061
    

(as in Sec.  178.503 (a)(1) through (10) of this subpart).

    (iii) For a steel drum to transport solids or inner packagings:
    [GRAPHIC] [TIFF OMITTED] TR05OC12.062
    

[[Page 198]]



(as in Sec.  178.503 (a)(1) through (8) of this subpart).

    (3) Examples of markings for reconditioned packagings are as 
follows:
[GRAPHIC] [TIFF OMITTED] TR05OC12.063


(as in Sec.  178.503(c)(1)).
    (f) A manufacturer must mark every UN specification package 
represented as manufactured to meet the requirements of Sec.  178.609 
for packaging of infectious substances with the marks specified in this 
section. The markings must be durable, legible, and must be readily 
visible, as specified in Sec.  178.3(a). An infectious substance 
packaging that successfully passes the tests conforming to the UN 
standard must be marked as follows:
    (1) The United Nations symbol as illustrated in paragraph (e) of 
this section.
    (2) The code designating the type of packaging and material of 
construction according to the identification codes for packagings 
specified in Sec.  178.502.
    (3) The text ``CLASS 6.2''.
    (4) The last two digits of the year of manufacture of the packaging.
    (5) The country authorizing the allocation of the mark. The letters 
``USA'' indicate the packaging is manufactured and marked in the United 
States in compliance with the provisions of this subchapter.
    (6) The name and address or symbol of the manufacturer or the 
approval agency certifying compliance with subparts L and M of this 
part. Symbols, if used, must be registered with the Associate 
Administrator for Hazardous Materials Safety.
    (7) For packagings meeting the requirements of Sec.  178.609(i)(3), 
the letter ``U'' must be inserted immediately following the marking 
designating the type of packaging and material required in paragraph 
(f)(2) of this section.

[Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, as amended at 56 FR 66284, 
Dec. 20, 1991; Amdt. 178-102, 59 FR 28493, June 2, 1994; Amdt. 178-106, 
59 FR 67520, 67521, Dec. 29, 1994; Amdt. 178-107, 60 FR 26806, May 18, 
1995; 62 FR 51561, Oct. 1, 1997; 66 FR 45386, Aug. 28, 2001; 67 FR 
61016, Sept. 27, 2002; 67 FR 53143, Aug. 14, 2002; 68 FR 75757, Dec. 31, 
2003; 75 FR 5395, Feb. 2, 2010; 75 FR 60339, Sept. 30, 2010; 77 FR 
60943, Oct. 5, 2012; 78 FR 60755, Oct. 2, 2013]



Sec.  178.504  Standards for steel drums.

    (a) The following are identification codes for steel drums:
    (1) 1A1 for a non-removable head steel drum; and
    (2) 1A2 for a removable head steel drum.
    (b) Construction requirements for steel drums are as follows:
    (1) Body and heads must be constructed of steel sheet of suitable 
type and adequate thickness in relation to the capacity and intended use 
of the drum. Minimum thickness and marking requirements in Sec. Sec.  
173.28(b)(4) and 178.503(a)(9) of this subchapter apply to drums 
intended for reuse.
    (2) Body seams must be welded on drums designed to contain more than 
40 L (11 gallons) of liquids. Body seams must be mechanically seamed or 
welded on drums intended to contain only solids or 40 L (11 gallons) or 
less of liquids.
    (3) Chimes must be mechanically seamed or welded. Separate 
reinforcing rings may be applied.
    (4) The body of a drum of a capacity greater than 60 L (16 gallons) 
may have at least two expanded rolling hoops or two separate rolling 
hoops. If there are separate rolling hoops, they must be

[[Page 199]]

fitted tightly on the body and so secured that they cannot shift. 
Rolling hoops may not be spot-welded.
    (5) Openings for filling, emptying and venting in the bodies or 
heads of non-removable head (1A1) drums may not exceed 7.0 cm (3 inches) 
in diameter. Drums with larger openings are considered to be of the 
removable head type (1A2). Closures for openings in the bodies and heads 
of drums must be so designed and applied that they will remain secure 
and leakproof under normal conditions of transport. Closure flanges may 
be mechanically seamed or welded in place. Gaskets or other sealing 
elements must be used with closures unless the closure is inherently 
leakproof.
    (6) Closure devices for removable head drums must be so designed and 
applied that they will remain secure and drums will remain leakproof 
under normal conditions of transport. Gaskets or other sealing elements 
must be used with all removable heads.
    (7) If materials used for body, heads, closures, and fittings are 
not in themselves compatible with the contents to be transported, 
suitable internal protective coatings or treatments must be applied. 
These coatings or treatments must retain their protective properties 
under normal conditions of transport.
    (8) Maximum capacity of drum: 450 L (119 gallons).
    (9) Maximum net mass: 400 kg (882 pounds).

[Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, as amended at 56 FR 66284, 
Dec. 20, 1991; Amdt. 178-110, 60 FR 49111, Sept. 21, 1995]



Sec.  178.505  Standards for aluminum drums.

    (a) The following are the identification codes for aluminum drums:
    (1) 1B1 for a non-removable head aluminum drum; and
    (2) 1B2 for a removable head aluminum drum.
    (b) Construction requirements for aluminum drums are as follows:
    (1) Body and heads must be constructed of aluminum at least 99 
percent pure or an aluminum base alloy. Material must be of suitable 
type and adequate thickness in relation to the capacity and the intended 
use of the drum. Minimum thickness and marking requirements in 
Sec. Sec.  173.28(b)(4) and 178.503(a)(9) of this subchapter apply to 
drums intended for reuse.
    (2) All seams must be welded. Chime seams, if any, must be 
reinforced by the application of separate reinforcing rings.
    (3) The body of a drum of a capacity greater than 60 L (16 gallons) 
may have at least two expanded rolling hoops or two separate rolling 
hoops. If there are separate rolling hoops, the hoops must be fitted 
tightly on the body and so secured that they cannot shift. Rolling hoops 
may not be spot-welded.
    (4) Openings for filling, emptying, or venting in the bodies or 
heads of non-removable head (1B1) drums may not exceed 7.0 cm (3 inches) 
in diameter. Drums with larger openings are considered to be of the 
removable head type (1B2). Closures for openings in the bodies and heads 
of drums must be so designed and applied that they will remain secure 
and leakproof under normal conditions of transport. Closure flanges may 
be welded in place so that the weld provides a leakproof seam. Gaskets 
or other sealing elements must be used with closures unless the closure 
is inherently leakproof.
    (5) Closure devices for removable head drums must be so designed and 
applied that they remain secure and drums remain leakproof under normal 
conditions of transport. Gaskets or other sealing elements must be used 
with all removable heads.
    (6) If materials used for body, heads, closures, and fittings are 
not compatible with the contents to be transported, suitable internal 
protective coatings or treatments must be applied. These coatings or 
treatments must retain their protective properties under normal 
conditions of transport.
    (7) Maximum capacity of drum: 450 L (119 gallons).
    (8) Maximum net mass: 400 kg (882 pounds).

[Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, as amended at 56 FR 66284, 
Dec. 20, 1991; Amdt. 178-102, 59 FR 28494, June 2, 1994; 87 FR 45000, 
July 26, 2022]

[[Page 200]]



Sec.  178.506  Standards for metal drums other than steel or aluminum.

    (a) The following are the identification codes for metal drums other 
than steel or aluminum:
    (1) 1N1 for a non-removable head metal drum; and
    (2) 1N2 for a removable head metal drum.
    (b) Construction requirements for metal drums other than steel or 
aluminum are as follows:
    (1) Body and heads must be constructed of metal (other than steel or 
aluminum) of suitable type and adequate thickness in relation to the 
capacity and the intended use of the drum. Minimum thickness and marking 
requirements in Sec. Sec.  173.28(b)(4) and 178.503(a)(9) of this 
subchapter apply to drums intended for reuse.
    (2) All seams must be welded. Chime seams, if any, must be 
reinforced by the application of separate reinforcing rings.
    (3) The body of a drum of a capacity greater than 60 L (16 gallons) 
may have at least two expanded rolling hoops or two separate rolling 
hoops. If there are separate rolling hoops, the hoops must be fitted 
tightly on the body and so secured that they cannot shift. Rolling hoops 
may not be spot-welded.
    (4) Openings for filling, emptying, or venting in the bodies or 
heads of non-removable head (1N1) drums may not exceed 7.0 cm (3 inches) 
in diameter. Drums with larger openings are considered to be of the 
removable head type (1N2). Closures for openings in the bodies and heads 
of drums must be so designed and applied that they will remain secure 
and leakproof under normal conditions of transport. Closure flanges may 
be welded in place so that the weld provides a leakproof seam. Gaskets 
or other sealing elements must be used with closures unless the closure 
is inherently leakproof.
    (5) Closure devices for removable head drums must be so designed and 
applied that they remain secure and drums remain leakproof under normal 
conditions of transport. Gaskets or other sealing elements must be used 
with all removable heads.
    (6) If materials used for body, heads, closures, and fittings are 
not compatible with the contents to be transported, suitable internal 
protective coatings or treatments must be applied. These coatings or 
treatments must retain their protective properties under normal 
conditions of transport.
    (7) Maximum capacity of drum: 450 L (119 gallons).
    (8) Maximum net mass: 400 kg (882 pounds).

[Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, as amended at 56 FR 66285, 
Dec. 20, 1991; Amdt. 178-102, 59 FR 28494, June 2, 1994; 87 FR 45000, 
July 26, 2022]



Sec.  178.507  Standards for plywood drums.

    (a) The identification code for a plywood drum is 1D.
    (b) Construction requirements for plywood drums are as follows:
    (1) The wood used must be well-seasoned, commercially dry and free 
from any defect likely to lessen the effectiveness of the drum for the 
purpose intended. A material other than plywood, of at least equivalent 
strength and durability, may be used for the manufacture of the heads.
    (2) At least two-ply plywood must be used for the body and at least 
three-ply plywood for the heads; the plies must be firmly glued 
together, with their grains crosswise.
    (3) The body and heads of the drum and their joints must be of a 
design appropriate to the capacity of the drum and its intended use.
    (4) In order to prevent sifting of the contents, lids must be lined 
with kraft paper or some other equivalent material which must be 
securely fastened to the lid and extend to the outside along its full 
circumference.
    (5) Maximum capacity of drum: 250 L (66 gallons).
    (6) Maximum net mass: 400 kg (882 pounds).

[Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, as amended at 57 FR 45465, 
Oct. 1, 1992]



Sec.  178.508  Standards for fiber drums.

    (a) The identification code for a fiber drum is 1G.
    (b) Construction requirements for fiber drums are as follows:
    (1) The body of the drum must be constructed of multiple plies of 
heavy

[[Page 201]]

paper or fiberboard (without corrugations) firmly glued or laminated 
together and may include one or more protective layers of bitumen, waxed 
kraft paper, metal foil, plastic material, or similar materials.
    (2) Heads must be of natural wood, fiberboard, metal, plywood, 
plastics, or other suitable material and may include one or more 
protective layers of bitumen, waxed kraft paper, metal foil, plastic 
material, or similar material.
    (3) The body and heads of the drum and their joints must be of a 
design appropriate to the capacity and intended use of the drum.
    (4) The assembled packaging must be sufficiently water-resistant so 
as not to delaminate under normal conditions of transport.
    (5) Maximum capacity of drum: 450 L (119 gallons).
    (6) Maximum net mass: 400 kg (882 pounds).

[Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, as amended by Amdt. 178-106, 
59 FR 67521, Dec. 29, 1994]



Sec.  178.509  Standards for plastic drums and jerricans.

    (a) The following are identification codes for plastic drums and 
jerricans:
    (1) 1H1 for a non-removable head plastic drum;
    (2) 1H2 for a removable head plastic drum;
    (3) 3H1 for a non-removable head jerrican; and
    (4) 3H2 for a removable head jerrican.
    (b) Construction requirements for plastic drums and jerricans are as 
follows:
    (1) The packaging must be manufactured from suitable plastic 
material and be of adequate strength in relation to its capacity and 
intended use. No used material other than production residues or regrind 
from the same manufacturing process may be used unless approved by the 
Associate Administrator. The packaging must be adequately resistant to 
aging and to degradation caused either by the substance contained or by 
ultra-violet radiation. Any permeation of the substance contained may 
not constitute a danger under normal conditions of transport.
    (2) If protection against ultra-violet radiation is required, it 
must be provided by the addition of carbon black or other suitable 
pigments or inhibitors. These additives must be compatible with the 
contents and remain effective throughout the life of the packaging. 
Where use is made of carbon black, pigments or inhibitors other than 
those used in the manufacture of the design type, retesting may be 
omitted if the carbon black content does not exceed 2 percent by mass or 
if the pigment content does not exceed 3 percent by mass; the content of 
inhibitors of ultra-violet radiation is not limited.
    (3) Additives serving purposes other than protection against ultra-
violet radiation may be included in the composition of the plastic 
material provided they do not adversely affect the chemical and physical 
properties of the packaging material.
    (4) The wall thickness at every point of the packaging must be 
appropriate to its capacity and its intended use, taking into account 
the stresses to which each point is liable to be exposed. Minimum 
thickness and marking requirements in Sec. Sec.  173.28(b)(4) and 
178.503(a)(9) of this subchapter apply to drums intended for reuse.
    (5) Openings for filling, emptying and venting in the bodies or 
heads of non-removable head (1H1) drums and jerricans (3H1) may not 
exceed 7.0 cm (3 inches) in diameter. Drums and jerricans with larger 
openings are considered to be of the removable head type (1H2 and 3H2). 
Closures for openings in the bodies or heads of drums and jerricans must 
be so designed and applied that they remain secure and leakproof under 
normal conditions of transport. Gaskets or other sealing elements must 
be used with closures unless the closure is inherently leakproof.
    (6) Closure devices for removable head drums and jerricans must be 
so designed and applied that they remain secure and leakproof under 
normal conditions of transport. Gaskets must be used with all removable 
heads unless the drum or jerrican design is such that when the removable 
head is properly secured, the drum or jerrican is inherently leakproof.

[[Page 202]]

    (7) Maximum capacity of drums and jerricans: 1H1, 1H2: 450 L (119 
gallons); 3H1, 3H2: 60 L (16 gallons).
    (8) Maximum net mass: 1H1, 1H2: 400 kg (882 pounds); 3H1, 3H2: 120 
kg (265 pounds).

[Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, as amended by Amdt. 178-102, 
59 FR 28494, June 2, 1994; 64 FR 10782, Mar. 5, 1999; 66 FR 45386, Aug. 
28, 2001]



Sec.  178.510  Standards for wooden barrels.

    (a) The following are identification codes for wooden barrels:
    (1) 2C1 for a bung type wooden barrel; and
    (2) 2C2 for a slack type (removable head) wooden barrel.
    (b) Construction requirements for wooden barrels are as follows:
    (1) The wood used must be of good quality, straight-grained, well-
seasoned and free from knots, bark, rotten wood, sapwood or other 
defects likely to lessen the effectiveness of the barrel for the purpose 
intended.
    (2) The body and heads must be of a design appropriate to the 
capacity and intended use of the barrel.
    (3) Staves and heads must be sawn or cleft with the grain so that no 
annual ring extends over more than half the thickness of a stave or 
head.
    (4) Barrel hoops must be of steel or iron of good quality. The hoops 
of 2C2 barrels may be of a suitable hardwood.
    (5) For wooden barrels 2C1, the diameter of the bung-hole may not 
exceed half the width of the stave in which it is placed.
    (6) For wooden barrels 2C2, heads must fit tightly into crozes.
    (7) Maximum capacity of barrel: 250 L (66 gallons).
    (8) Maximum net mass: 400 kg (882 pounds).



Sec.  178.511  Standards for aluminum and steel jerricans.

    (a) The following are identification codes for aluminum and steel 
jerricans:
    (1) 3A1 for a non-removable head steel jerrican;
    (2) 3A2 for a removable head steel jerrican;
    (3) 3B1 for a non-removable head aluminum jerrican; and
    (4) 3B2 for a removable head aluminum jerrican.
    (b) Construction requirements for aluminum and steel jerricans are 
as follows:
    (1) For steel jerricans the body and heads must be constructed of 
steel sheet of suitable type and adequate thickness in relation to the 
capacity of the jerrican and its intended use. Minimum thickness and 
marking requirements in Sec. Sec.  173.28(b)(4) and 178.503(a)(9) of 
this subchapter apply to jerricans intended for reuse.
    (2) For aluminum jerricans the body and heads must be constructed of 
aluminum at least 99% pure or of an aluminum base alloy. Material must 
be of a type and of adequate thickness in relation to the capacity of 
the jerrican and to its intended use.
    (3) Chimes of all jerricans must be mechanically seamed or welded. 
Body seams of jerricans intended to carry more than 40 L (11 gallons) of 
liquid must be welded. Body seams of jerricans intended to carry 40 L 
(11 gallons) or less must be mechanically seamed or welded.
    (4) Openings in jerricans (3A1) may not exceed 7.0 cm (3 inches) in 
diameter. Jerricans with larger openings are considered to be of the 
removable head type. Closures must be so designed that they remain 
secure and leakproof under normal conditions of transport. Gaskets or 
other sealing elements must be used with closures, unless the closure is 
inherently leakproof.
    (5) If materials used for body, heads, closures and fittings are not 
in themselves compatible with the contents to be transported, suitable 
internal protective coatings or treatments must be applied. These 
coatings or treatments must retain their protective properties under 
normal conditions of transport.
    (6) Maximum capacity of jerrican: 60 L (16 gallons).
    (7) Maximum net mass: 120 kg (265 pounds).

[Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, as amended by Amdt. 178-102, 
59 FR 28494, June 2, 1994; Amdt. 178-119, 62 FR 24742, May 6, 1997]

[[Page 203]]



Sec.  178.512  Standards for steel, aluminum or other metal boxes.

    (a) The following are identification codes for steel, aluminum, or 
other metal boxes:
    (1) 4A for a steel box;
    (2) 4B for an aluminum box; and
    (3) 4N for an other metal box.
    (b) Construction requirements for steel, aluminum or other metal 
boxes are as follows:
    (1) The strength of the metal and the construction of the box must 
be appropriate to the capacity and intended use of the box.
    (2) Boxes must be lined with fiberboard or felt packing pieces or 
must have an inner liner or coating of suitable material in accordance 
with subpart C of part 173 of this subchapter. If a double seamed metal 
liner is used, steps must be taken to prevent the ingress of materials, 
particularly explosives, into the recesses of the seams.
    (3) Closures may be of any suitable type, and must remain secure 
under normal conditions of transport.
    (4) Maximum net mass: 400 kg (882 pounds).

[Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, as amended by Amdt. 178-106, 
59 FR 67521, Dec. 29, 1994; 78 FR 1096, Jan. 7, 2013]



Sec.  178.513  Standards for boxes of natural wood.

    (a) The following are the identification codes for boxes of natural 
wood:
    (1) 4C1 for an ordinary box; and
    (2) 4C2 for a box with sift-proof walls.
    (b) Construction requirements for boxes of natural wood are as 
follows:
    (1) The wood used must be well-seasoned, commercially dry and free 
from defects that would materially lessen the strength of any part of 
the box. The strength of the material used and the method of 
construction must be appropriate to the capacity and intended use of the 
box. The tops and bottoms may be made of water-resistant reconstituted 
wood such as hard board, particle board or other suitable type.
    (2) Fastenings must be resistant to vibration experienced under 
normal conditions of transportation. End grain nailing must be avoided 
whenever practicable. Joints which are likely to be highly stressed must 
be made using clenched or annular ring nails or equivalent fastenings.
    (3) Each part of the 4C2 box must be one piece or equivalent. Parts 
are considered equivalent to one piece when one of the following methods 
of glued assembly is used: Linderman joint, tongue and groove joint, 
ship lap or rabbet joint, or butt joint with at least two corrugated 
metal fasteners at each joint.
    (4) Maximum net mass: 400 kg (882 pounds).

[Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, as amended by Amdt. 178-106, 
59 FR 67521, Dec. 29, 1994]



Sec.  178.514  Standards for plywood boxes.

    (a) The identification code for a plywood box is 4D.
    (b) Construction requirements for plywood boxes are as follows:
    (1) Plywood used must be at least 3 ply. It shall be made from well-
seasoned rotary cut, sliced or sawn veneer, commercially dry and free 
from defects that would materially lessen the strength of the box. The 
strength of the material used and the method of construction must be 
appropriate to the capacity and intended use of the box. All adjacent 
plies must be glued with water-resistant adhesive. Other suitable 
materials may be used together with plywood in the construction of 
boxes. Boxes must be nailed or secured to corner posts or ends or 
assembled with other equally suitable devices.
    (2) Maximum net mass: 400 kg (882 pounds).



Sec.  178.515  Standards for reconstituted wood boxes.

    (a) The identification code for a reconstituted wood box is 4F.
    (b) Construction requirements for reconstituted wood boxes are as 
follows:
    (1) The walls of boxes must be made of water-resistant, 
reconstituted wood such as hardboard, particle board, or other suitable 
type. The strength of the material used and the method of construction 
must be appropriate to the capacity of the boxes and their intended use.
    (2) Other parts of the box may be made of other suitable materials.
    (3) Boxes must be securely assembled by means of suitable devices.

[[Page 204]]

    (4) Maximum net mass: 400 kg (882 pounds).



Sec.  178.516  Standards for fiberboard boxes.

    (a) The identification code for a fiberboard box is 4G.
    (b) Construction requirements for fiberboard boxes are as follows:
    (1) Strong, solid or double-faced corrugated fiberboard (single or 
multi-wall) must be used, appropriate to the capacity and intended use 
of the box. The water resistance of the outer surface must be such that 
the increase in mass, as determined in a test carried out over a period 
of 30 minutes by the Cobb method of determining water absorption, is not 
greater than 155 g per square meter (0.0316 pounds per square foot)--see 
ISO 535 (IBR, see Sec.  171.7 of this subchapter). Fiberboard must have 
proper bending qualities. Fiberboard must be cut, creased without 
cutting through any thickness of fiberboard, and slotted so as to permit 
assembly without cracking, surface breaks, or undue bending. The fluting 
of corrugated fiberboard must be firmly glued to the facings.
    (2) The ends of boxes may have a wooden frame or be entirely of wood 
or other suitable material. Reinforcements of wooden battens or other 
suitable material may be used.
    (3) Manufacturing joints. (i) Manufacturing joints in the bodies of 
boxes must be--
    (A) Taped;
    (B) Lapped and glued; or
    (C) Lapped and stitched with metal staples.
    (ii) Lapped joints must have an appropriate overlap.
    (4) Where closing is effected by gluing or taping, a water resistant 
adhesive must be used.
    (5) Boxes must be designed so as to provide a snug fit to the 
contents.
    (6) Maximum net mass: 400 kg (882 pounds).
    (7) Authorization to manufacture, mark, and sell UN4G combination 
packagings with outer fiberboard boxes and with inner fiberboard 
components that have individual containerboard or paper wall basis 
weights that vary by not more than plus or minus 10% from the nominal 
basis weight reported in the initial design qualification test report.

[Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, as amended by Amdt. 178-99, 
58 FR 51534, Oct. 1, 1993; Amdt. 178-106, 59 FR 67521, Dec. 29, 1994; 68 
FR 75758, Dec. 31, 2003; 79 FR 15046, Mar. 18, 2014; 83 FR 55810, Nov. 
7, 2018]



Sec.  178.517  Standards for plastic boxes.

    (a) The following are identification codes for plastic boxes:
    (1) 4H1 for an expanded plastic box; and
    (2) 4H2 for a solid plastic box.
    (b) Construction requirements for plastic boxes are as follows:
    (1) The box must be manufactured from suitable plastic material and 
be of adequate strength in relation to its capacity and intended use. 
The box must be adequately resistant to aging and to degradation caused 
either by the substance contained or by ultra-violet radiation.
    (2) An expanded plastic box must consist of two parts made of a 
molded expanded plastic material: a bottom section containing cavities 
for the inner receptacles, and a top section covering and interlocking 
with the bottom section. The top and bottom sections must be so designed 
that the inner receptacles fit snugly. The closure cap for any inner 
receptacle may not be in contact with the inside of the top section of 
the box.
    (3) For transportation, an expanded plastic box must be closed with 
a self-adhesive tape having sufficient tensile strength to prevent the 
box from opening. The adhesive tape must be weather-resistant and its 
adhesive compatible with the expanded plastic material of the box. Other 
closing devices at least equally effective may be used.
    (4) For solid plastic boxes, protection against ultra-violet 
radiation, if required, must be provided by the addition of carbon black 
or other suitable pigments or inhibitors. These additives must be 
compatible with the contents and remain effective throughout the life of 
the box. Where use is made of carbon black pigment or inhibitors other 
than those used in the manufacture of the tested design type, retesting 
may be waived if the carbon black content does not exceed 2 percent by 
mass or if the pigment content does

[[Page 205]]

not exceed 3 percent by mass; the content of inhibitors of ultra-violet 
radiation is not limited.
    (5) Additives serving purposes other than protection against ultra-
violet radiation may be included in the composition of the plastic 
material if they do not adversely affect the material of the box. 
Addition of these additives does not change the design type.
    (6) Solid plastic boxes must have closure devices made of a suitable 
material of adequate strength and so designed as to prevent the box from 
unintentionally opening.
    (7) Maximum net mass 4H1: 60 kg (132 pounds); 4H2: 400 kg (882 
pounds).



Sec.  178.518  Standards for woven plastic bags.

    (a) The following are identification codes for woven plastic bags:
    (1) 5H1 for an unlined or non-coated woven plastic bag;
    (2) 5H2 for a sift-proof woven plastic bag; and
    (3) 5H3 for a water-resistant woven plastic bag.
    (b) Construction requirements for woven plastic fabric bags are as 
follows:
    (1) Bags must be made from stretched tapes or monofilaments of a 
suitable plastic material. The strength of the material used and the 
construction of the bag must be appropriate to the capacity and intended 
use of the bag.
    (2) If the fabric is woven flat, the bags must be made by sewing or 
some other method ensuring closure of the bottom and one side. If the 
fabric is tubular, the bag must be closed by sewing, weaving, or some 
other equally strong method of closure.
    (3) Bags, sift-proof, 5H2 must be made sift-proof by appropriate 
means such as use of paper or a plastic film bonded to the inner surface 
of the bag or one or more separate inner liners made of paper or plastic 
material.
    (4) Bags, water-resistant, 5H3: To prevent the entry of moisture, 
the bag must be made waterproof by appropriate means, such as separate 
inner liners of water-resistant paper (e.g., waxed kraft paper, double-
tarred kraft paper or plastic-coated kraft paper), or plastic film 
bonded to the inner or outer surface of the bag, or one or more inner 
plastic liners.
    (5) Maximum net mass: 50 kg (110 pounds).

[Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, as amended by Amdt. 178-99, 
58 FR 51534, Oct. 1, 1993]



Sec.  178.519  Standards for plastic film bags.

    (a) The identification code for a plastic film bag is 5H4.
    (b) Construction requirements for plastic film bags are as follows:
    (1) Bags must be made of a suitable plastic material. The strength 
of the material used and the construction of the bag must be appropriate 
to the capacity and the intended use of the bag. Joints and closures 
must be capable of withstanding pressures and impacts liable to occur 
under normal conditions of transportation.
    (2) Maximum net mass: 50 kg (110 pounds).



Sec.  178.520  Standards for textile bags.

    (a) The following are identification codes for textile bags:
    (1) 5L1 for an unlined or non-coated textile bag;
    (2) 5L2 for a sift-proof textile bag; and
    (3) 5L3 for a water-resistant textile bag.
    (b) Construction requirements for textile bags are as follows:
    (1) The textiles used must be of good quality. The strength of the 
fabric and the construction of the bag must be appropriate to the 
capacity and intended use of the bag.
    (2) Bags, sift-proof, 5L2: The bag must be made sift-proof, by 
appropriate means, such as by the use of paper bonded to the inner 
surface of the bag by a water-resistant adhesive such as bitumen, 
plastic film bonded to the inner surface of the bag, or one or more 
inner liners made of paper or plastic material.
    (3) Bags, water-resistant, 5L3: To prevent entry of moisture, the 
bag must be made waterproof by appropriate means, such as by the use of 
separate inner liners of water-resistant paper (e.g., waxed kraft paper, 
tarred paper, or plastic-coated kraft paper), or plastic film bonded to 
the inner surface of

[[Page 206]]

the bag, or one or more inner liners made of plastic material or 
metalized film or foil.
    (4) Maximum net mass: 50 kg (110 pounds).

[Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, as amended at 56 FR 66285, 
Dec. 20, 1991]



Sec.  178.521  Standards for paper bags.

    (a) The following are identification codes for paper bags:
    (1) 5M1 for a multi-wall paper bag; and
    (2) 5M2 for a multi-wall water-resistant paper bag.
    (b) Construction requirements for paper bags are as follows:
    (1) Bags must be made of a suitable kraft paper, or of an equivalent 
paper with at least three plies. The strength of the paper and the 
construction of the bag must be appropriate to the capacity and intended 
use of the bag. Seams and closures must be sift-proof.
    (2) Paper bags 5M2: To prevent the entry of moisture, a bag of four 
plies or more must be made waterproof by the use of either a water-
resistant ply as one of the two outermost plies or a water-resistant 
barrier made of a suitable protective material between the two outermost 
plies. A 5M2 bag of three plies must be made waterproof by the use of a 
water-resistant ply as the outermost ply. When there is danger of the 
lading reacting with moisture, or when it is packed damp, a waterproof 
ply or barrier, such as double-tarred kraft paper, plastics-coated kraft 
paper, plastics film bonded to the inner surface of the bag, or one or 
more inner plastics liners, must also be placed next to the substance. 
Seams and closures must be waterproof.
    (3) Maximum net mass: 50 kg (110 pounds).
    (4) UN5M1 and UN5M2 multi-wall paper bags that have paper wall basis 
weights that vary by not more than plus or minus 10 percent from the 
nominal basis weight reported in the initial design qualification test 
report.

[Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, as amended at 56 FR 66285, 
Dec. 20, 1991; Amdt. 178-106, 59 FR 67521, Dec. 29, 1994; 79 FR 15046, 
Mar. 18, 2014; 85 FR 75716, Nov. 25, 2020]



Sec.  178.522  Standards for composite packagings with inner plastic 
receptacles. 

    (a) The following are the identification codes for composite 
packagings with inner plastic receptacles:
    (1) 6HA1 for a plastic receptacle within a protective steel drum;
    (2) 6HA2 for a plastic receptacle within a protective steel crate or 
box;
    (3) 6HB1 for a plastic receptacle within a protective aluminum drum.
    (4) 6HB2 for a plastic receptacle within a protective aluminum crate 
or box.
    (5) 6HC for a plastic receptacle within a protective wooden box.
    (6) 6HD1 for a plastic receptacle within a protective plywood drum;
    (7) 6HD2 for a plastic receptacle within a protective plywood box;
    (8) 6HG1 for a plastic receptacle within a protective fiber drum;
    (9) 6HG2 for a plastic receptacle within a protective fiberboard 
box;
    (10) 6HH1 for a plastic receptacle within a protective plastic drum; 
and
    (11) 6HH2 for a plastic receptacle within a protective plastic box.
    (b) Construction requirements for composite packagings with inner 
receptacles of plastic are as follows:
    (1) Inner receptacles must be constructed under the applicable 
construction requirements prescribed in Sec.  178.509(b) (1) through (7) 
of this subpart.
    (2) The inner plastic receptacle must fit snugly inside the outer 
packaging, which must be free of any projections which may abrade the 
plastic material.
    (3) Outer packagings must be constructed as follows:
    (i) 6HA1 or 6HB1: Protective packaging must conform to the 
requirements for steel drums in Sec.  178.504(b) of this subpart, or 
aluminum drums in Sec.  178.505(b) of this subpart.
    (ii) 6HA2 or 6HB2: Protective packagings with steel or aluminum 
crate must conform to the requirements for steel or aluminum boxes found 
in Sec.  178.512(b) of this subpart.
    (iii) 6HC protective packaging must conform to the requirements for 
wooden boxes in Sec.  178.513(b) of this subpart.
    (iv) 6HD1: Protective packaging must conform to the requirements for 
plywood drums, in Sec.  178.507(b) of this subpart.

[[Page 207]]

    (v) 6HD2: Protective packaging must conform to the requirements of 
plywood boxes, in Sec.  178.514(b) of this subpart.
    (vi) 6HG1: Protective packaging must conform to the requirements for 
fiber drums, in Sec.  178.508(b) of this subpart.
    (vii) 6HG2: protective packaging must conform to the requirements 
for fiberboard boxes, in Sec.  178.516(b) of this subpart.
    (viii) 6HH1: Protective packaging must conform to the requirements 
for plastic drums, in Sec.  178.509(b).
    (ix) 6HH2: Protective packaging must conform to the requirements for 
plastic boxes, in Sec.  178.517(b).
    (4) Maximum capacity of inner receptacles is as follows: 6HA1, 6HB1, 
6HD1, 6HG1, 6HH1--250 L (66 gallons); 6HA2, 6HB2, 6HC, 6HD2, 6HG2, 
6HH2--60 L (16 gallons).
    (5) Maximum net mass is as follows: 6HA1, 6HB1, 6HD1, 6HG1, 6HH1--
400kg (882 pounds); 6HB2, 6HC, 6HD2, 6HG2, 6HH2--75 kg (165 pounds).

[Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, as amended by Amdt. 178-106, 
59 FR 67521, Dec. 29, 1994]



Sec.  178.523  Standards for composite packagings with inner glass, 
porcelain, or stoneware receptacles. 

    (a) The following are identification codes for composite packagings 
with inner receptacles of glass, porcelain, or stoneware:
    (1) 6PA1 for glass, porcelain, or stoneware receptacles within a 
protective steel drum;
    (2) 6PA2 for glass, porcelain, or stoneware receptacles within a 
protective steel crate or box;
    (3) 6PB1 for glass, porcelain, or stoneware receptacles within a 
protective aluminum drum;
    (4) 6PB2 for glass, porcelain, or stoneware receptacles within a 
protective aluminum crate or box;
    (5) 6PC for glass, porcelain, or stoneware receptacles within a 
protective wooden box;
    (6) 6PD1 for glass, porcelain, or stoneware receptacles within a 
protective plywood drum;
    (7) 6PD2 for glass, porcelain, or stoneware receptacles within a 
protective wickerwork hamper;
    (8) 6PG1 for glass, porcelain, or stoneware receptacles within a 
protective fiber drum;
    (9) 6PG2 for glass, porcelain, or stoneware receptacles within a 
protective fiberboard box;
    (10) 6PH1 for glass, porcelain, or stoneware receptacles within a 
protective expanded plastic packaging; and
    (11) 6PH2 for glass, porcelain, or stoneware receptacles within a 
protective solid plastic packaging.
    (b) Construction requirements for composite packagings with inner 
receptacles of glass, porcelain, or stoneware are as follows:
    (1) Inner receptacles must conform to the following requirements:
    (i) Receptacles must be of suitable form (cylindrical or pear-
shaped), be made of good quality materials free from any defect that 
could impair their strength, and be firmly secured in the outer 
packaging.
    (ii) Any part of a closure likely to come into contact with the 
contents of the receptacle must be resistant to those contents. Closures 
must be fitted so as to be leakproof and secured to prevent any 
loosening during transportation. Vented closures must conform to Sec.  
173.24(f) of this subchapter.
    (2) Protective packagings must conform to the following 
requirements:
    (i) For receptacles with protective steel drum 6PAl, the drum must 
comply with Sec.  178.504(b) of this subpart. However, the removable lid 
required for this type of packaging may be in the form of a cap.
    (ii) For receptacles with protective packaging of steel crate or 
steel box 6PA2, the protective packaging must conform to the following:
    (A) Section 178.512(b) of this subpart.
    (B) In the case of cylindrical receptacles, the protective packaging 
must, when upright, rise above the receptacle and its closure; and
    (C) If the protective crate surrounds a pear-shaped receptacle and 
is of matching shape, the protective packaging must be fitted with a 
protective cover (cap).
    (iii) For receptacles with protective aluminum drum 6PB1, the 
requirements of Sec.  178.505(b) of this subpart apply to the protective 
packaging.

[[Page 208]]

    (iv) For receptacles with protective aluminum box or crate 6PB2, the 
requirements of Sec.  178.512(b) of this subpart apply to the protective 
packaging.
    (v) For receptacles with protective wooden box 6PC, the requirements 
of Sec.  178.513(b) of this subpart apply to the protective packaging.
    (vi) For receptacles with protective plywood drum 6PD1, the 
requirements of Sec.  178.507(b) of this subpart apply to the protective 
packaging.
    (vii) For receptacles with protective wickerwork hamper 6PD2, the 
wickerwork hamper must be properly made with material of good quality. 
The hamper must be fitted with a protective cover (cap) so as to prevent 
damage to the receptacle.
    (viii) For receptacles with protective fiber drum 6PG1, the drum 
must conform to the requirements of Sec.  178.508(b) of this subpart.
    (ix) For receptacles with protective fiberboard box 6PG2, the 
requirements of Sec.  178.516(b) of this subpart apply to the protective 
packaging.
    (x) For receptacles with protective solid plastic or expanded 
plastic packaging 6PH1 or 6PH2, the requirements of Sec.  178.517(b) of 
this subpart apply to the protective packaging. Solid protective plastic 
packaging must be manufactured from high-density polyethylene from some 
other comparable plastic material. The removable lid required for this 
type of packaging may be a cap.
    (3) Quantity limitations are as follows:
    (i) Maximum net capacity for packaging for liquids: 60 L (16 
gallons).
    (ii) Maximum net mass for packagings for solids: 75 kg (165 pounds).



          Subpart M_Testing of Non-bulk Packagings and Packages

    Source: Amdt. 178-97, 55 FR 52723, Dec. 21, 1990, unless otherwise 
noted.



Sec.  178.600  Purpose and scope.

    This subpart prescribes certain testing requirements for 
performance-oriented packagings identified in subpart L of this part.

[Amdt. 178-97, 55 FR 52717, Dec. 21, 1990, as amended by Amdt. 178-99, 
58 FR 51534, Oct. 1, 1993]



Sec.  178.601  General requirements.

    (a) General. The test procedures prescribed in this subpart are 
intended to ensure that packages containing hazardous materials can 
withstand normal conditions of transportation and are considered minimum 
requirements. Each packaging must be manufactured and assembled so as to 
be capable of successfully passing the prescribed tests and of 
conforming to the requirements of Sec.  173.24 of this subchapter at all 
times while in transportation.
    (b) Responsibility. It is the responsibility of the packaging 
manufacturer to assure that each package is capable of passing the 
prescribed tests. To the extent that a package assembly function, 
including final closure, is performed by the person who offers a 
hazardous material for transportation, that person is responsible for 
performing the function in accordance with Sec. Sec.  173.22 and 178.2 
of this subchapter.
    (c) Definitions. For the purpose of this subpart:
    (1) Design qualification testing is the performance of the tests 
prescribed in Sec.  178.603, Sec.  178.604, Sec.  178.605, Sec.  
178.606, Sec.  178.607, Sec.  178.608, or Sec.  178.609, as applicable, 
for each new or different packaging, at the start of production of that 
packaging.
    (2) Periodic retesting is the performance of the drop, 
leakproofness, hydrostatic pressure, and stacking tests, as applicable, 
as prescribed in Sec.  178.603, Sec.  178.604, Sec.  178.605, or Sec.  
178.606, respectively, at the frequency specified in paragraph (e) of 
this section. For infectious substances packagings required to meet the 
requirements of Sec.  178.609, periodic retesting is the performance of 
the tests specified in Sec.  178.609 at the frequency specified in 
paragraph (e) of this section.
    (3) Production testing is the performance of the leakproofness test 
prescribed in Sec.  178.604 of this subpart on each single or composite 
packaging intended to contain a liquid.

[[Page 209]]

    (4) A different packaging is one that differs (i.e., is not 
identical) from a previously produced packaging in structural design, 
size, material of construction, wall thickness or manner of construction 
but does not include:
    (i) A packaging which differs only in surface treatment;
    (ii) A combination packaging which differs only in that the outer 
packaging has been successfully tested with different inner packagings. 
A variety of such inner packagings may be assembled in this outer 
packaging without further testing;
    (iii) A plastic packaging which differs only with regard to 
additives which conform to Sec.  178.509(b)(3) or Sec.  178.517(b) (4) 
or (5) of this part;
    (iv) A combination packaging with inner packagings conforming to the 
provisions of paragraph (g) of this section;
    (v) Packagings which differ from the design type only in their 
lesser design height; or
    (vi) For a steel drum, variations in design elements which do not 
constitute a different design type under the provisions of paragraph 
(g)(8) of this section.
    (d) Design qualification testing. The packaging manufacturer shall 
achieve successful test results for the design qualification testing at 
the start of production of each new or different packaging.
    (e) Periodic retesting. The packaging manufacturer must achieve 
successful test results for the periodic retesting at intervals 
established by the manufacturer of sufficient frequency to ensure that 
each packaging produced by the manufacturer is capable of passing the 
design qualification tests. Changes in retest frequency are subject to 
the approval of the Associate Administrator for Hazardous Materials 
Safety. For single or composite packagings, the periodic retests must be 
conducted at least once every 12 months. For combination packagings, the 
periodic retests must be conducted at least once every 24 months. For 
infectious substances packagings, the periodic retests must be conducted 
at least once every 24 months.
    (f) Test samples. The manufacturer shall conduct the design 
qualification and periodic tests prescribed in this subpart using random 
samples of packagings, in the numbers specified in the appropriate test 
section. In addition, the leakproofness test, when required, shall be 
performed on each packaging produced by the manufacturer, and each 
packaging prior to reuse under Sec.  173.28 of this subchapter, by the 
reconditioner.
    (g) Selective testing. The selective testing of packagings that 
differ only in minor respects from a tested type is permitted as 
described in this section. For air transport, packagings must comply 
with Sec.  173.27(c)(1) and (c)(2) of this subchapter.
    (1) Selective testing of combination packagings. Variation 1. 
Variations are permitted in inner packagings of a tested combination 
package, without further testing of the package, provided an equivalent 
level of performance is maintained and, when a package is altered under 
Variation 1 after October 1, 2010, the methodology used to determine 
that the inner packaging, including closure, maintains an equivalent 
level of performance is documented in writing by the person certifying 
compliance with this paragraph and retained in accordance with paragraph 
(l) of this section. Permitted variations are as follows:
    (i) Inner packagings of equivalent or smaller size may be used 
provided--
    (A) The inner packagings are of similar design to the tested inner 
packagings (i.e., shape--round, rectangular, etc.);
    (B) The material of construction of the inner packagings (glass, 
plastic, metal, etc.) offers resistance to impact and stacking forces 
equal to or greater than that of the originally tested inner packaging;
    (C) The inner packagings have the same or smaller openings and the 
closure is of similar design (e.g., screw cap, friction lid, etc.);
    (D) Sufficient additional cushioning material is used to take up 
void spaces and to prevent significant moving of the inner packagings;
    (E) Inner packagings are oriented within the outer packaging in the 
same manner as in the tested package; and,
    (F) The gross mass of the package does not exceed that originally 
tested.

[[Page 210]]

    (ii) A lesser number of the tested inner packagings, or of the 
alternative types of inner packagings identified in paragraph (g)(1)(i) 
of this section, may be used provided sufficient cushioning is added to 
fill void space(s) and to prevent significant moving of the inner 
packagings.
    (2) Selective testing of combination packagings. Variation 2. 
Articles or inner packagings of any type, for solids or liquids, may be 
assembled and transported without testing in an outer packaging under 
the following conditions:
    (i) The outer packaging must have been successfully tested in 
accordance with Sec.  178.603 with fragile (e.g. glass) inner packagings 
containing liquids at the Packing Group I drop height;
    (ii) The total combined gross mass of inner packagings may not 
exceed one-half the gross mass of inner packagings used for the drop 
test;
    (iii) The thickness of cushioning material between inner packagings 
and between inner packagings and the outside of the packaging may not be 
reduced below the corresponding thickness in the originally tested 
packaging; and when a single inner packaging was used in the original 
test, the thickness of cushioning between inner packagings may not be 
less than the thickness of cushioning between the outside of the 
packaging and the inner packaging in the original test. When either 
fewer or smaller inner packagings are used (as compared to the inner 
packagings used in the drop test), sufficient additional cushioning 
material must be used to take up void spaces.
    (iv) The outer packaging must have successfully passed the stacking 
test set forth in Sec.  178.606 of this subpart when empty, i.e., 
without either inner packagings or cushioning materials. The total mass 
of identical packages must be based on the combined mass of inner 
packagings used for the drop test;
    (v) Inner packagings containing liquids must be completely 
surrounded with a sufficient quantity of absorbent material to absorb 
the entire liquid contents of the inner packagings;
    (vi) When the outer packaging is intended to contain inner 
packagings for liquids and is not leakproof or is intended to contain 
inner packagings for solids and is not siftproof, a means of containing 
any liquid or solid contents in the event of leakage must be provided in 
the form of a leakproof liner, plastic bag, or other equally efficient 
means of containment. For packagings containing liquids, the absorbent 
material required in paragraph (g)(2)(v) of this section must be placed 
inside as the means of containing liquid contents; and
    (vii) Packagings must be marked in accordance with Sec.  178.503 of 
this part as having been tested to Packing Group I performance for 
combination packagings. The marked maximum gross mass may not exceed the 
sum of the mass of the outer packaging plus one half the mass of the 
filled inner packagings of the tested combination packaging. In 
addition, the marking required by Sec.  178.503(a)(2) of this part must 
include the letter ``V''.
    (3) Variation 3. Packagings other than combination packagings which 
are produced with reductions in external dimensions (i.e., length, width 
or diameter) of up to 25 percent of the dimensions of a tested packaging 
may be used without further testing provided an equivalent level of 
performance is maintained. The packagings must, in all other respects 
(including wall thicknesses), be identical to the tested design-type. 
The marked gross mass (when required) must be reduced in proportion to 
the reduction in volume.
    (4) Variation 4. Variations are permitted in outer packagings of a 
tested design-type combination packaging, without further testing, 
provided an equivalent level of performance is maintained, as follows:
    (i) Each external dimension (length, width and height) is less than 
or equal to the corresponding dimension of the tested design-type;
    (ii) The structural design of the tested outer packaging (i.e., 
methods of construction, materials of construction, strength 
characteristics of materials of construction, method of closure and 
material thicknesses) is maintained;
    (iii) The inner packagings are identical to the inner packagings 
used in the tested design type except that their size and mass may be 
less; and they are

[[Page 211]]

oriented within the outer packaging in the same manner as in the tested 
packaging;
    (iv) The same type or design of absorbent materials, cushioning 
materials and any other components necessary to contain and protect 
inner packagings, as used in the tested design type, are maintained. The 
thickness of cushioning material between inner packagings and between 
inner packagings and the outside of the packaging may not be less than 
the thicknesses in the tested design type packaging; and
    (v) Sufficient additional cushioning material is used to take up 
void spaces and to prevent significant moving of the inner packagings.

An outer packaging qualifying for use in transport in accordance with 
all of the above conditions may also be used without testing to 
transport inner packagings substituted for the originally tested inner 
packagings in accordance with the conditions set out in Variation 1 in 
paragraph (g)(1) of this section.
    (5) Variation 5. Single packagings (i.e., non-bulk packagings other 
than combination packagings), that differ from a tested design type only 
to the extent that the closure device or gasketing differs from that 
used in the originally tested design type, may be used without further 
testing, provided an equivalent level of performance is maintained, 
subject to the following conditions (the qualifying tests):
    (i) A packaging with the replacement closure devices or gasketing 
must successfully pass the drop test specified in Sec.  178.603 in the 
orientation which most severely tests the integrity of the closure or 
gasket;
    (ii) When intended to contain liquids, a packaging with the 
replacement closure devices or gasketing must successfully pass the 
leakproofness test specified in Sec.  178.604, the hydrostatic pressure 
test specified in Sec.  178.605, and the stacking test specified in 
Sec.  178.606.

Replacement closures and gasketings qualified under the above test 
requirements are authorized without additional testing for packagings 
described in paragraph (g)(3) of this section. Replacement closures and 
gasketings qualified under the above test requirements also are 
authorized without additional testing for different tested design types 
packagings of the same type as the originally tested packaging, provided 
the original design type tests are more severe or comparable to tests 
which would otherwise be conducted on the packaging with the replacement 
closures or gasketings. (For example: The packaging used in the 
qualifying tests has a lesser packaging wall thickness than the 
packaging with replacement closure devices or gasketing; the gross mass 
of the packaging used in the qualifying drop test equals or exceeds the 
mass for which the packaging with replacement closure devices or 
gasketing was tested; the packaging used in the qualifying drop test was 
dropped from the same or greater height than the height from which the 
packaging with replacement closure devices or gasketing was dropped in 
design type tests; and the specific gravity of the substance used in the 
qualifying drop test was the same or greater than the specific gravity 
of the liquid used in the design type tests of the packaging with 
replacement closure devices or gasketing.)
    (6) The provisions in Variations 1, 2, and 4 in paragraphs (g)(1), 
(2) and (4) of this section for combination packagings may be applied to 
packagings containing articles, where the provisions for inner 
packagings are applied analogously to the articles. In this case, inner 
packagings need not comply with Sec.  173.27(c)(1) and (c)(2) of this 
subchapter.
    (7) Approval of selective testing. In addition to the provisions of 
Sec.  178.601(g)(1) through (g)(6) of this subpart, the Associate 
Administrator may approve the selective testing of packagings that 
differ only in minor respects from a tested type.
    (8) For a steel drum with a capacity greater than 12 L (3 gallons) 
manufactured from low carbon, cold-rolled sheet steel meeting ASTM 
designations A 366/A 366M or A 568/A 568M, variations in elements other 
than the following design elements are considered minor and do not 
constitute a different drum design type, or ``different packaging'' as 
defined in paragraph (c) of this section for which design qualification 
testing and periodic retesting are

[[Page 212]]

required. Minor variations authorized without further testing include 
changes in the identity of the supplier of component material made to 
the same specifications, or the original manufacturer of a DOT 
specification or UN standard drum to be remanufactured. A change in any 
one or more of the following design elements constitutes a different 
drum design type:
    (i) The packaging type and category of the original drum and the 
remanufactured drum, i.e., 1A1 or 1A2;
    (ii) The style, (i.e., straight-sided or tapered);
    (iii) Except as provided in paragraph (g)(3) of this section, the 
rated (marked) capacity and outside dimensions;
    (iv) The physical state for which the packaging was originally 
approved (e.g., tested for solids or liquids);
    (v) An increase in the marked level of performance of the original 
drum (i.e., to a higher packing group, hydrostatic test pressure, or 
specific gravity to which the packaging has been tested);
    (vi) Type of side seam welding;
    (vii) Type of steel;
    (viii) An increase greater than 10% or any decrease in the steel 
thickness of the head, body, or bottom;
    (ix) End seam type, (e.g., triple or double seam);
    (x) A reduction in the number of rolling hoops (beads) which equal 
or exceed the diameter over the chimes;
    (xi) The location, type or size, and material of closures (other 
than the cover of UN 1A2 drums);
    (xii) The location (e.g., from the head to the body), type (e.g., 
mechanically seamed or welded flange), and materials of closure (other 
than the cover of UN 1A2 drums); and
    (xiii) For UN 1A2 drums:
    (A) Gasket material (e.g., plastic), or properties affecting the 
performance of the gasket;
    (B) Configuration or dimensions of the gasket;
    (C) Closure ring style including bolt size (e.g., square or round 
back, 0.625 inches bolt); and
    (D) Closure ring thickness,
    (E) Width of lugs or extensions in crimp/lug cover.
    (h) Approval of equivalent packagings. A packaging having 
specifications different from those in Sec. Sec.  178.504-178.523 of 
this part, or which is tested using methods or test intervals, other 
than those specified in subpart M of this part, may be used if approved 
by the Associate Administrator. Such packagings must be shown to be 
equally effective, and testing methods used must be equivalent.
    (i) Proof of compliance. Notwithstanding the periodic retest 
intervals specified in paragraph (e) of this section, the Associate 
Administrator may at any time require demonstration of compliance by a 
manufacturer, through testing in accordance with this subpart, that 
packagings meet the requirements of this subpart. As required by the 
Associate Administrator, the manufacturer shall either--
    (1) Conduct performance tests, or have tests conducted by an 
independent testing facility, in accordance with this subpart; or
    (2) Supply packagings, in quantities sufficient to conduct tests in 
accordance with this subpart, to the Associate Administrator or a 
designated representative of the Associate Administrator.
    (j) Coatings. If an inner treatment or coating of a packaging is 
required for safety reasons, the manufacturer shall design the packaging 
so that the treatment or coating retains its protective properties even 
after withstanding the tests prescribed by this subpart.
    (k) Number of test samples. Except as provided in this section, one 
test sample must be used for each test performed under this subpart.
    (1) Stainless steel drums. Provided the validity of the test results 
is not affected, a person may perform the design qualification testing 
of stainless steel drums using three (3) samples rather than the 
specified eighteen (18) samples under the following provisions:
    (i) The packaging must be tested in accordance with this subpart by 
subjecting each of the three containers to the following sequence of 
tests:
    (A) The stacking test in Sec.  178.606,
    (B) The leakproofness test in Sec.  178.604,
    (C) The hydrostatic pressure test in Sec.  178.608, and
    (D) Diagonal top chime and flat on the side drop tests in Sec.  
178.603. Both

[[Page 213]]

drop tests may be conducted on the same sample.
    (ii) For periodic retesting of stainless steel drums, a reduced 
sample size of one container is authorized.
    (2) Packagings other than stainless steel drums. Provided the 
validity of the test results is not affected, several tests may be 
performed on one sample with the approval of the Associate 
Administrator.
    (l) Record retention. Following each design qualification test and 
each periodic retest on a packaging, a test report must be prepared.
    (1) The test report must be maintained at each location where the 
packaging is manufactured, certified, and a design qualification test or 
periodic retest is conducted as follows:

------------------------------------------------------------------------
           Responsible party                         Duration
------------------------------------------------------------------------
Person manufacturing the packaging.....  As long as manufactured and two
                                          years thereafter.
Person performing design testing.......  Design test maintained for a
                                          single or composite packaging
                                          for six years after the test
                                          is successfully performed and
                                          for a combination packaging or
                                          packaging intended for
                                          infectious substances for
                                          seven years after the test is
                                          successfully performed.
Person performing periodic retesting...  Performance test maintained for
                                          a single or composite
                                          packaging for one year after
                                          the test is successfully
                                          performed and for a
                                          combination packaging or
                                          packaging intended for
                                          infectious substances for two
                                          years after the test is
                                          successfully performed.
------------------------------------------------------------------------

    (2) The test report must be made available to a user of a packaging 
or a representative of the Department upon request. The test report, at 
a minimum, must contain the following information:
    (i) Name and address of test facility;
    (ii) Name and address of applicant (where appropriate);
    (iii) A unique test report identification;
    (iv) Date of the test report;
    (v) Manufacturer of the packaging;
    (vi) Description of the packaging design type (e.g., dimensions, 
materials, closures, thickness, etc.), including methods of manufacture 
(e.g., blow molding) and which may include drawing(s) and/or 
photograph(s);
    (vii) Maximum capacity;
    (viii) Characteristics of test contents, including for plastic 
packagings subject to the hydrostatic pressure test in Sec.  178.605 of 
this subpart, the temperature of the water used;
    (ix) Test descriptions and results; and
    (x) Signed with the name and title of signatory.

[Amdt. 178-97, 55 FR 52723, Dec. 21, 1990, as amended at 56 FR 66285, 
Dec. 20, 1991; 57 FR 45465, Oct. 1, 1992; Amdt. 178-102, 59 FR 28494, 
June 2, 1994; Amdt. 178-106, 59 FR 67521, 67522, Dec. 29, 1994; Amdt. 
178-117, 61 FR 50628, Sept. 26, 1996; 66 FR 45386, Aug. 28, 2001; 67 FR 
53143, Aug. 14, 2002; 68 FR 75758, Dec. 31, 2003; 68 FR 61942, Oct. 30, 
2003; 75 FR 5396, Feb. 2, 2010; 75 FR 60339, Sept. 30, 2010; 77 FR 
60944, Oct. 5, 2012; 78 FR 1118, Jan. 7, 2013; 78 FR 14715, Mar. 7, 
2013; 78 FR 65487, Oct. 31, 2013; 85 FR 27901, May 11, 2020; 87 FR 
79784, Dec. 27, 2022]



Sec.  178.602  Preparation of packagings and packages for testing.

    (a) Except as otherwise provided in this subchapter, each packaging 
and package must be closed in preparation for testing and tests must be 
carried out in the same manner as if prepared for transportation, 
including inner packagings in the case of combination packagings.
    (b) For the drop and stacking test, inner and single-unit 
receptacles other than bags must be filled to not less than 95% of 
maximum capacity (see Sec.  171.8 of this subchapter) in the case of 
solids and not less than 98% of maximum in the case of liquids. Bags 
containing solids shall be filled to the maximum mass at which they may 
be used. The material to be transported in the packagings may be 
replaced by a

[[Page 214]]

non-hazardous material, except for chemical compatibility testing or 
where this would invalidate the results of the tests.
    (c) If the material to be transported is replaced for test purposes 
by a non-hazardous material, the material used must be of the same or 
higher specific gravity as the material to be carried, and its other 
physical properties (grain, size, viscosity) which might influence the 
results of the required tests must correspond as closely as possible to 
those of the hazardous material to be transported. Water may also be 
used for the liquid drop test under the conditions specified in Sec.  
178.603(e) of this subpart. It is permissible to use additives, such as 
bags of lead shot, to achieve the requisite total package mass, so long 
as they are placed so that the test results are not affected.
    (d) Paper or fiberboard packagings must be conditioned for at least 
24 hours immediately prior to testing in an atmosphere maintained--
    (1) At 50 percent 2 percent relative humidity, 
and at a temperature of 23 [deg]C2 [deg]C (73 
[deg]F4 [deg]F). Average values should fall within 
these limits. Short-term fluctuations and measurement limitations may 
cause individual measurements to vary by up to 5 
percent relative humidity without significant impairment of test 
reproducibility;
    (2) At 65 percent 2 percent relative humidity, 
and at a temperature of 20 [deg]C2 [deg]C (68 
[deg]F4 [deg]F), or 27 [deg]C2 [deg]C (81 [deg]F4 [deg]F). 
Average values should fall within these limits. Short-term fluctuations 
and measurement limitations may cause individual measurements to vary by 
up to 5 percent relative humidity without 
significant impairment of test reproducibility; or
    (3) For testing at periodic intervals only (i.e., other than initial 
design qualification testing), at ambient conditions.
    (e) Except as otherwise provided, each packaging must be closed in 
preparation for testing in the same manner as if prepared for actual 
shipment. All closures must be installed using proper techniques and 
torques.
    (f) Bung-type barrels made of natural wood must be left filled with 
water for at least 24 hours before the tests.

[Amdt. 178-97, 55 FR 52723, Dec. 21, 1990, as amended at 56 FR 66286, 
Dec. 20, 1991; Amdt. 178-106, 59 FR 67522, Dec. 29, 1994; 69 FR 76186, 
Dec. 20, 2004; 71 FR 78635, Dec. 29, 2006]



Sec.  178.603  Drop test.

    (a) General. The drop test must be conducted for the qualification 
of all packaging design types and performed periodically as specified in 
Sec.  178.601(e). For other than flat drops, the center of gravity of 
the test packaging must be vertically over the point of impact. Where 
more than one orientation is possible for a given drop test, the 
orientation most likely to result in failure of the packaging must be 
used. The number of drops required and the packages' orientations are as 
follows:

------------------------------------------------------------------------
                                 No. of tests      Drop orientation of
          Packaging               (samples)              samples
------------------------------------------------------------------------
Steel drums, Aluminum drums,   Six--(three for  First drop (using three
 Metal drums (other than        each drop).      samples): The package
 steel or aluminum), Steel                       must strike the target
 Jerricans, Plywood drums,                       diagonally on the chime
 Wooden barrels, Fiber drums,                    or, if the packaging
 Plastic drums and Jerricans,                    has no chime, on a
 Composite packagings which                      circumferential seam or
 are in the shape of a drum.                     an edge. Second drop
                                                 (using the other three
                                                 samples): The package
                                                 must strike the target
                                                 on the weakest part not
                                                 tested by the first
                                                 drop, for example a
                                                 closure or, for some 7
                                                 cylindrical drums, the
                                                 welded longitudinal
                                                 seam of the drum body.
Boxes of natural wood,         Five--(one for   First drop: Flat on the
 Plywood boxes, Reconstituted   each drop).      bottom (using the first
 wood boxes, Fiberboard                          sample). Second drop:
 boxes, Plastic boxes, Steel,                    Flat on the top (using
 aluminum or other metal                         the second sample).
 boxes, Composite packagings                     Third drop: Flat on the
 that are in the shape of a                      long side (using the
 box.                                            third sample). Fourth
                                                 drop: Flat on the short
                                                 side (using the fourth
                                                 sample). Fifth drop: On
                                                 a corner (using the
                                                 fifth sample).
Bags--single-ply with a side   Three--(three    First drop: Flat on a
 seam.                          drops per bag).  wide face (using all
                                                 three samples). Second
                                                 drop: Flat on a narrow
                                                 face (using all three
                                                 samples). Third drop:
                                                 On an end of the bag
                                                 (using all three
                                                 samples).
Bags--single-ply without a     Three--(two      First drop: Flat on a
 side seam, or multi-ply.       drops per bag).  wide face (using all
                                                 three samples). Second
                                                 drop: On an end of the
                                                 bag (using all three
                                                 samples).
------------------------------------------------------------------------


[[Page 215]]

    (b) Exceptions. For testing of single or composite packagings 
constructed of stainless steel, nickel, or monel at periodic intervals 
only (i.e., other than design qualification testing), the drop test may 
be conducted with two samples, one sample each for the two drop 
orientations. These samples may have been previously used for the 
hydrostatic pressure or stacking test. Exceptions for the number of 
steel, aluminum and other metal packaging samples used for conducting 
the drop test are subject to the approval of the Associate 
Administrator.
    (c) Special preparation of test samples for the drop test. (1) 
Testing of plastic drums, plastic jerricans, plastic boxes other than 
expanded polystyrene boxes, composite packagings (plastic material), and 
combination packagings with plastic inner packagings other than plastic 
bags intended to contain solids or articles must be carried out when the 
temperature of the test sample and its contents has been reduced to -18 
[deg]C (0 [deg]F) or lower. Test liquids must be kept in the liquid 
state, if necessary, by the addition of anti-freeze. Water/anti-freeze 
solutions with a minimum specific gravity of 0.95 for testing at -18 
[deg]C (0 [deg]F) or lower are considered acceptable test liquids. Test 
samples prepared in this way are not required to be conditioned in 
accordance with Sec.  178.602(d).
    (d) Target. The target must be a rigid, non-resilient, flat and 
horizontal surface.
    (e) Drop height. Drop heights, measured as the vertical distance 
from the target to the lowest point on the package, must be equal to or 
greater than the drop height determined as follows:
    (1) For solids and liquids, if the test is performed with the solid 
or liquid to be transported or with a non-hazardous material having 
essentially the same physical characteristic, the drop height must be 
determined according to packing group, as follows:
    (i) Packing Group I: 1.8 m (5.9 feet).
    (ii) Packing Group II: 1.2 m (3.9 feet).
    (iii) Packing Group III: 0.8 m (2.6 feet).
    (2) For liquids in single packagings and for inner packagings of 
combination packagings, if the test is performed with water:
    (i) Where the materials to be carried have a specific gravity not 
exceeding 1.2, drop height must be determined according to packing 
group, as follows:
    (A) Packing Group I: 1.8 m (5.9 feet).
    (B) Packing Group II: 1.2 m (3.9 feet).
    (C) Packing Group III: 0.8 m (2.6 feet).
    (ii) Where the materials to be transported have a specific gravity 
exceeding 1.2, the drop height must be calculated on the basis of the 
specific gravity (SG) of the material to be carried, rounded up to the 
first decimal, as follows:
    (A) Packing Group I: SG x 1.5 m (4.9 feet).
    (B) Packing Group II: SG x 1.0 m (3.3 feet).
    (C) Packing Group III: SG x 0.67 m (2.2 feet).
    (f) Criteria for passing the test. A package is considered to 
successfully pass the drop tests if for each sample tested--
    (1) For packagings containing liquid, each packaging does not leak 
when equilibrium has been reached between the internal and external 
pressures, except for inner packagings of combination packagings when it 
is not necessary that the pressures be equalized;
    (2) For removable head drums for solids, the entire contents are 
retained by an inner packaging (e.g., a plastic bag) even if the closure 
on the top head of the drum is no longer sift-proof;
    (3) For a bag, neither the outermost ply nor an outer packaging 
exhibits any damage likely to adversely affect safety during transport;
    (4) The packaging or outer packaging of a composite or combination 
packaging must not exhibit any damage likely to affect safety during 
transport. Inner receptacles, inner packagings, or articles must remain 
completely within the outer packaging and there must be no leakage of 
the filling substance from the inner receptacles or inner packagings;
    (5) Any discharge from a closure is slight and ceases immediately 
after impact with no further leakage; and
    (6) No rupture is permitted in packagings for materials in Class 1 
which

[[Page 216]]

would permit spillage of loose explosive substances or articles from the 
outer packaging.

[Amdt. 178-97, 55 FR 52723, Dec. 21, 1990, as amended at 56 FR 66286, 
Dec. 20, 1991; 57 FR 45465, Oct. 1, 1992; Amdt. 178-99, 58 FR 51534, 
Oct. 1, 1993; Amdt. 178-106, 59 FR 67522, Dec. 29, 1994; 65 FR 50462, 
Aug. 18, 2000; 66 FR 45386, Aug. 28, 2001; 67 FR 61016, Sept. 27, 2002; 
69 FR 76186, Dec. 20, 2004; 76 FR 3389, Jan. 19, 2011; 78 FR 1097, Jan. 
7, 2013]



Sec.  178.604  Leakproofness test.

    (a) General. The leakproofness test must be performed with 
compressed air or other suitable gases on all packagings intended to 
contain liquids, except that:
    (1) The inner receptacle of a composite packaging may be tested 
without the outer packaging provided the test results are not affected; 
and
    (2) This test is not required for inner packagings of combination 
packagings.
    (b) Number of packagings to be tested--(1) Production testing. All 
packagings subject to the provisions of this section must be tested and 
must pass the leakproofness test:
    (i) Before they are first used in transportation; and
    (ii) Prior to reuse, when authorized for reuse by Sec.  173.28 of 
this subchapter.
    (2) Design qualification and periodic testing. Three samples of each 
different packaging must be tested and must pass the leakproofness test. 
Exceptions for the number of samples used in conducting the 
leakproofness test are subject to the approval of the Associate 
Administrator.
    (c) Special preparation--(1) For design qualification and periodic 
testing, packagings must be tested with closures in place. For 
production testing, packagings need not have their closures in place. 
Removable heads need not be installed during production testing.
    (2) For testing with closures in place, vented closures must either 
be replaced by similar non-vented closures or the vent must be sealed.
    (d) Test method. The packaging must be restrained under water while 
an internal air pressure is applied; the method of restraint must not 
affect the results of the test. The test must be conducted, for other 
than production testing, for a minimum time of five minutes. Other 
methods, at least equally effective, may be used in accordance with 
appendix B of this part.
    (e) Pressure applied. An internal air pressure (gauge) must be 
applied to the packaging as indicated for the following packing groups:
    (1) Packing Group I: Not less than 30 kPa (4 psi).
    (2) Packing Group II: Not less than 20 kPa (3 psi).
    (3) Packing Group III: Not less than 20 kPa (3 psi).
    (f) Criteria for passing the test. A packaging passes the test if 
there is no leakage of air from the packaging.

[Amdt. 178-97, 55 FR 52723, Dec. 21, 1990, as amended at 56 FR 66286, 
Dec. 20, 1991; Amdt. 178-106, 59 FR 67522, Dec. 29, 1994; 66 FR 45386, 
Aug. 28, 2001]



Sec.  178.605  Hydrostatic pressure test.

    (a) General. The hydrostatic pressure test must be conducted for the 
qualification of all metal, plastic, and composite packaging design 
types intended to contain liquids and be performed periodically as 
specified in Sec.  178.601(e). This test is not required for inner 
packagings of combination packagings. For internal pressure requirements 
for inner packagings of combination packagings intended for 
transportation by aircraft, see Sec.  173.27(c) of this subchapter.
    (b) Number of test samples. Three test samples are required for each 
different packaging. For packagings constructed of stainless steel, 
monel, or nickel, only one sample is required for periodic retesting of 
packagings. Exceptions for the number of aluminum and steel sample 
packagings used in conducting the hydrostatic pressure test are subject 
to the approval of the Associate Administrator.
    (c) Special preparation of receptacles for testings. Vented closures 
must either be replaced by similar non-vented closures or the vent must 
be sealed.
    (d) Test method and pressure to be applied. Metal packagings and 
composite packagings other than plastic (e.g., glass, porcelain or 
stoneware), including their closures, must be subjected to the test 
pressure for 5 minutes. Plastic packagings and composite packagings 
(plastic material), including their closures, must be subjected to the 
test

[[Page 217]]

pressure for 30 minutes. This pressure is the one to be marked as 
required in Sec.  178.503(a)(5). The receptacles must be supported in a 
manner that does not invalidate the test. The test pressure must be 
applied continuously and evenly, and it must be kept constant throughout 
the test period. In addition, packagings intended to contain hazardous 
materials of Packing Group I must be tested to a minimum test pressure 
of 250 kPa (36 psig). The hydraulic pressure (gauge) applied, taken at 
the top of the receptacle, and determined by any one of the following 
methods must be:
    (1) Not less than the total gauge pressure measured in the packaging 
(i.e., the vapor pressure of the filling material and the partial 
pressure of the air or other inert gas minus 100 kPa (15 psi)) at 55 
[deg]C (131 [deg]F), multiplied by a safety factor of 1.5. This total 
gauge pressure must be determined on the basis of a maximum degree of 
filling in accordance with Sec.  173.24a(d) of this subchapter and a 
filling temperature of 15 [deg]C (59 [deg]F);
    (2) Not less than 1.75 times the vapor pressure at 50 [deg]C (122 
[deg]F) of the material to be transported minus 100 kPa (15 psi), but 
with a minimum test pressure of 100 kPa (15 psig); or
    (3) Not less than 1.5 times the vapor pressure at 55 [deg]C (131 
[deg]F) of the material to be transported minus 100 kPa (15 psi), but 
with a minimum test pressure of 100 kPa (15 psig).

Packagings intended to contain hazardous materials of Packing Group I 
must be tested to a minimum test pressure of 250 kPa (36 psig).
    (e) Criteria for passing the test. A package passes the hydrostatic 
test if, for each test sample, there is no leakage of liquid from the 
package.

[Amdt. 178-97, 55 FR 52723, Dec. 21, 1990, as amended at 56 FR 66286, 
Dec. 20, 1991; Amdt. 178-99, 58 FR 51534, Oct. 1, 1993; Amdt. 178-102, 
59 FR 28494, June 2, 1994; 65 FR 50462, Aug. 18, 2000; 66 FR 45386, 
45390, Aug. 28, 2001; 73 FR 57007, Oct. 1, 2008; 78 FR 60755, Oct. 2, 
2013]



Sec.  178.606  Stacking test.

    (a) General. All packaging design types other than bags must be 
subjected to a stacking test.
    (b) Number of test samples. Three test samples are required for each 
different packaging. For periodic retesting of packagings constructed of 
stainless steel, monel, or nickel, only one test sample is required. 
Exceptions for the number of aluminum and steel sample packagings used 
in conducting the stacking test are subject to the approval of the 
Associate Administrator. Notwithstanding the provisions of Sec.  
178.602(a) of this subpart, combination packagings may be subjected to 
the stacking test without their inner packagings, except where this 
would invalidate the results of the test.
    (c) Test method--(1) Design qualification testing. The test sample 
must be subjected to a force applied to the top surface of the test 
sample equivalent to the total weight of identical packages which might 
be stacked on it during transport; where the contents of the test sample 
are non-hazardous liquids with specific gravities different from that of 
the liquid to be transported, the force must be calculated based on the 
specific gravity that will be marked on the packaging. The minimum 
height of the stack, including the test sample, must be 3.0 m (10 feet). 
The duration of the test must be 24 hours, except that plastic drums, 
jerricans, and composite packagings 6HH intended for liquids shall be 
subjected to the stacking test for a period of 28 days at a temperature 
of not less than 40 [deg]C (104 [deg]F). Alternative test methods which 
yield equivalent results may be used if approved by the Associate 
Administrator. In guided load tests, stacking stability must be assessed 
after completion of the test by placing two filled packagings of the 
same type on the test sample. The stacked packages must maintain their 
position for one hour. Plastic packagings must be cooled to ambient 
temperature before this stacking stability assessment.
    (2) Periodic retesting. The test sample must be tested in accordance 
with:
    (i) Section 178.606(c)(1) of this subpart; or
    (ii) The packaging may be tested using a dynamic compression testing 
machine. The test must be conducted at room temperature on an empty, 
unsealed packaging. The test sample must be centered on the bottom 
platen of the testing machine. The top platen

[[Page 218]]

must be lowered until it comes in contact with the test sample. 
Compression must be applied end to end. The speed of the compression 
tester must be one-half inch plus or minus one-fourth inch per minute. 
An initial preload of 50 pounds must be applied to ensure a definite 
contact between the test sample and the platens. The distance between 
the platens at this time must be recorded as zero deformation. The force 
A to then be applied must be calculated using the formula:

Liquids: A = (n-1) [w + (s x v x 8.3 x .98)] x 1.5;
Solids: A = (n-1) (m x 2.2 x 1.5)

Where:

A = applied load in pounds
m = the certified maximum gross mass for the container in kilograms.
n = minimum number of containers that, when stacked, reach a height of 3 
          meters.
s = specific gravity of lading.
w = maximum weight of one empty container in pounds.
v = actual capacity of container (rated capacity + outage) in gallons.

And:

8.3 corresponds to the weight in pounds of 1.0 gallon of water.
.98 corresponds to the minimum filling percentage of the maximum 
          capacity for liquids.
1.5 is a compensation factor that converts the static load of the 
          stacking test into a load suitable for dynamic compression 
          testing.
2.2 is the conversion factor for kilograms to pounds.
    (d) Criteria for passing the test. No test sample may leak. In 
composite packagings or combination packagings, there must be no leakage 
of the filling substance from the inner receptacle, or inner packaging. 
No test sample may show any deterioration which could adversely affect 
transportation safety or any distortion likely to reduce its strength, 
cause instability in stacks of packages, or cause damage to inner 
packagings likely to reduce safety in transportation. For the dynamic 
compression test, a container passes the test if, after application of 
the required load, there is no buckling of the sidewalls sufficient to 
cause damage to its expected contents; in no case may the maximum 
deflection exceed one inch.

[Amdt. 178-97, 55 FR 52723, Dec. 21, 1990, as amended at 56 FR 66286, 
Dec. 20, 1991; 57 FR 45465, Oct. 1, 1992; Amdt. 178-102, 59 FR 28494, 
June 2, 1994; Amdt. 178-106, 59 FR 67522, Dec. 29, 1994; 65 FR 58632, 
Sept. 29, 2000; 66 FR 45386, Aug. 28, 2001; 70 FR 34076, June 13, 2005; 
72 FR 55696, Oct. 1, 2007]



Sec.  178.607  Cooperage test for bung-type wooden barrels.

    (a) Number of samples. One barrel is required for each different 
packaging.
    (b) Method of testing. Remove all hoops above the bilge of an empty 
barrel at least two days old.
    (c) Criteria for passing the test. A packaging passes the cooperage 
test only if the diameter of the cross-section of the upper part of the 
barrel does not increase by more than 10 percent.



Sec.  178.608  Vibration standard.

    (a) Each packaging must be capable of withstanding, without rupture 
or leakage, the vibration test procedure outlined in this section.
    (b) Test method. (1) Three sample packagings, selected at random, 
must be filled and closed as for shipment.
    (2) The three samples must be placed on a vibrating platform that 
has a vertical or rotary double-amplitude (peak-to-peak displacement) of 
one inch. The packages should be constrained horizontally to prevent 
them from falling off the platform, but must be left free to move 
vertically, bounce and rotate.
    (3) The test must be performed for one hour at a frequency that 
causes the package to be raised from the vibrating platform to such a 
degree that a piece of material of approximately 1.6 mm (0.063 inch) 
thickness (such as steel strapping or paperboard) can be passed between 
the bottom of any package and the platform.
    (4) Immediately following the period of vibration, each package must 
be removed from the platform, turned on its side and observed for any 
evidence of leakage.
    (5) Other methods, at least equally effective, may be used, if 
approved by the Associate Administrator.
    (c) Criteria for passing the test. A packaging passes the vibration 
test if there

[[Page 219]]

is no rupture or leakage from any of the packages. No test sample should 
show any deterioration which could adversely affect transportation 
safety or any distortion liable to reduce packaging strength.

[Amdt. 178-97, 55 FR 52723, Dec. 21, 1990, as amended at 56 FR 66286, 
Dec. 20, 1991; 66 FR 45386, Aug. 28, 2001]



Sec.  178.609  Test requirements for packagings for infectious substances.

    (a) Samples of each packaging must be prepared for testing as 
described in paragraph (b) of this section and then subjected to the 
tests in paragraphs (d) through (i) of this section.
    (b) Samples of each packaging must be prepared as for transport 
except that a liquid or solid infectious substance should be replaced by 
water or, where conditioning at -18 [deg]C (0 [deg]F) is specified, by 
water/antifreeze. Each primary receptacle must be filled to 98 percent 
capacity. Packagings for live animals should be tested with the live 
animal being replaced by an appropriate dummy of similar mass.
    (c) Packagings prepared as for transport must be subjected to the 
tests in Table I of this paragraph (c), which, for test purposes, 
categorizes packagings according to their material characteristics. For 
outer packagings, the headings in Table I relate to fiberboard or 
similar materials whose performance may be rapidly affected by moisture; 
plastics that may embrittle at low temperature; and other materials, 
such as metal, for which performance is not significantly affected by 
moisture or temperature. Where a primary receptacle and a secondary 
packaging of an inner packaging are made of different materials, the 
material of the primary receptacle determines the appropriate test. In 
instances where a primary receptacle is made of more than one material, 
the material most likely to be damaged determines the appropriate test.

                                             Table I--Tests Required
----------------------------------------------------------------------------------------------------------------
                             Material of                                            Tests required
----------------------------------------------------------------------------------------------------------------
             Outer packaging                    Inner packaging             Refer to para. (d)
----------------------------------------------------------------------------------------------------   Refer to
 Fiberboard     Plastics        Other       Plastics        Other      (d)   (e)   (f)      (g)       para. (h)
----------------------------------------------------------------------------------------------------------------
X             ............  ............  X             ............  ....  X     X     When dry     X
                                                                                         ice is
                                                                                         used
X             ............  ............  ............  X             ....  X     ....  ...........  X
              X             ............  X             ............  ....  ....  X     ...........  X
              X             ............  ............  X             ....  ....  X     ...........  X
              ............  X             X             ............  ....  ....  X     ...........  X
              ............  X             ............  X             X     ....  ....  ...........  X
----------------------------------------------------------------------------------------------------------------

    (d) Samples must be subjected to free-fall drops onto a rigid, 
nonresilient, flat, horizontal surface from a height of 9 m (30 feet).
    The drops must be performed as follows:
    (1) Where the samples are in the shape of a box, five samples must 
be dropped, one in each of the following orientation:
    (i) Flat on the base;
    (ii) Flat on the top;
    (iii) Flat on the longest side;
    (iv) Flat on the shortest side; and
    (v) On a corner.
    (2) Where the samples are in the shape of a drum, three samples must 
be dropped, one in each of the following orientations:
    (i) Diagonally on the top chime, with the center of gravity directly 
above the point of impact;
    (ii) Diagonally on the base chime; and
    (iii) Flat on the side.
    (3) While the sample should be released in the required orientation, 
it is accepted that for aerodynamic reasons the impact may not take 
place in that orientation.
    (4) Following the appropriate drop sequence, there must be no 
leakage from the primary receptacle(s) which should remain protected by 
absorbent material in the secondary packaging.

[[Page 220]]

    (e) The samples must be subjected to a water spray to simulate 
exposure to rainfall of approximately 50 mm (2 inches) per hour for at 
least one hour. They must then be subjected to the test described in 
paragraph (d) of this section.
    (f) The sample must be conditioned in an atmosphere of -18 [deg]C (0 
[deg]F) or less for a period of at least 24 hours and within 15 minutes 
of removal from that atmosphere be subjected to the test described in 
paragraph (d) of this section. Where the sample contains dry ice, the 
conditioning period may be reduced to 4 hours.
    (g) Where packaging is intended to contain dry ice, an additional 
drop test to that specified in paragraph (d), and when appropriate, 
paragraph (e) or (f) of this section must be performed on one sample in 
one of the orientations described in paragraph (d)(1) or (2) of this 
section, as appropriate, which is most likely to result in failure of 
the packaging. The sample must be stored so that all the dry ice 
dissipates prior to being subjected to the drop test.
    (h) Packagings with a gross mass of 7 kg (15 pounds) or less should 
be subjected to the tests described in paragraph (h)(1) of this section 
and packagings with a gross mass exceeding 7 kg (15 pounds) to the tests 
in paragraph (h)(2) of this section.
    (1) Samples must be placed on a level, hard surface. A cylindrical 
steel rod with a mass of at least 7 kg (15 pounds), a diameter not 
exceeding 38 mm (1.5 inches), and, at the impact end edges, a radius not 
exceeding 6 mm (0.2 inches), must be dropped in a vertical free fall 
from a height of 1 m (3 feet), measured from the impact end of the 
sample's impact surface. One sample must be placed on its base. A second 
sample must be placed in an orientation perpendicular to that used for 
the first. In each instance, the steel rod must be aimed to impact the 
primary receptacle(s). For a successful test, there must be no leakage 
from the primary receptacle(s) following each impact.
    (2) Samples must be dropped onto the end of a cylindrical steel rod. 
The rod must be set vertically in a level, hard surface. It must have a 
diameter of 38 mm (1.5 inches) and a radius not exceeding 6 mm (0.2 
inches) at the edges of the upper end. The rod must protrude from the 
surface a distance at least equal to that between the primary 
receptacle(s) and the outer surface of the outer packaging with a 
minimum of 200 mm (7.9 inches). One sample must be dropped in a vertical 
free fall from a height of 1 m (3 feet), measured from the top of the 
steel rod. A second sample must be dropped from the same height in an 
orientation perpendicular to that used for the first. In each instance, 
the packaging must be oriented so the steel rod will impact the primary 
receptacle(s). For a successful test, there must be no leakage from the 
primary receptacle(s) following each impact.
    (i) Variations. The following variations in the primary receptacles 
placed within the secondary packaging are allowed without additional 
testing of the completed package. An equivalent level of performance 
must be maintained.
    (1) Variation 1. Primary receptacles of equivalent or smaller size 
as compared to the tested primary receptacles may be used provided they 
meet all of the following conditions:
    (i) The primary receptacles are of similar design to the tested 
primary receptacle (e.g., shape: round, rectangular, etc.).
    (ii) The material of construction of the primary receptacle (glass, 
plastics, metal, etc.) offers resistance to impact and a stacking force 
equal to or greater than that of the originally tested primary 
receptacle.
    (iii) The primary receptacles have the same or smaller openings and 
the closure is of similar design (e.g., screw cap, friction lid, etc.).
    (iv) Sufficient additional cushioning material is used to fill void 
spaces and to prevent significant movement of the primary receptacles.
    (v) Primary receptacles are oriented within the intermediate 
packaging in the same manner as in the tested package.
    (2) Variation 2. A lesser number of the tested primary receptacles, 
or of the alternative types of primary receptacles identified in 
paragraph (i)(1) of this section, may be used provided sufficient 
cushioning is added to fill the

[[Page 221]]

void space(s) and to prevent significant movement of the primary 
receptacles.
    (3) Variation 3. Primary receptacles of any type may be placed 
within a secondary packaging and shipped without testing in the outer 
packaging provided all of the following conditions are met:
    (i) The secondary and outer packaging combination must be 
successfully tested in accordance with paragraphs (a) through (h) of 
this section with fragile (e.g., glass) inner receptacles.
    (ii) The total combined gross weight of inner receptacles may not 
exceed one-half the gross weight of inner receptacles used for the drop 
test in paragraph (d) of this section.
    (iii) The thickness of cushioning material between inner receptacles 
and between inner receptacles and the outside of the secondary packaging 
may not be reduced below the corresponding thicknesses in the originally 
tested packaging. If a single inner receptacle was used in the original 
test, the thickness of cushioning between the inner receptacles must be 
no less than the thickness of cushioning between the outside of the 
secondary packaging and the inner receptacle in the original test. When 
either fewer or smaller inner receptacles are used (as compared to the 
inner receptacles used in the drop test), sufficient additional 
cushioning material must be used to fill the void.
    (iv) The outer packaging must pass the stacking test in Sec.  
178.606 while empty. The total weight of identical packages must be 
based on the combined mass of inner receptacles used in the drop test in 
paragraph (d) of this section.
    (v) For inner receptacles containing liquids, an adequate quantity 
of absorbent material must be present to absorb the entire liquid 
contents of the inner receptacles.
    (vi) If the outer packaging is intended to contain inner receptacles 
for liquids and is not leakproof, or is intended to contain inner 
receptacles for solids and is not sift proof, a means of containing any 
liquid or solid contents in the event of leakage must be provided. This 
can be a leakproof liner, plastic bag, or other equally effective means 
of containment.
    (vii) In addition, the marking required in Sec.  178.503(f) of this 
subchapter must be followed by the letter ``U''.

[Amdt. 178-97, 55 FR 52723, Dec. 21, 1990, as amended by Amdt. 178-111, 
60 FR 48787, Sept. 20, 1995; 67 FR 53143, Aug. 14, 2002; 69 FR 54046, 
Sept. 7, 2004; 87 FR 45000, July 26, 2022]



              Subpart N_IBC Performance-Oriented Standards



Sec.  178.700  Purpose, scope and definitions.

    (a) This subpart prescribes requirements applying to IBCs intended 
for the transportation of hazardous materials. Standards for these 
packagings are based on the UN Recommendations.
    (b) Terms used in this subpart are defined in Sec.  171.8 of this 
subchapter and in paragraph (c) of this section.
    (c) The following definitions pertain to the IBC standards in this 
subpart.
    (1) Body means the receptacle proper (including openings and their 
closures, but not including service equipment) that has a volumetric 
capacity of not more than 3 cubic meters (3,000 L, 793 gallons, or 106 
cubic feet).
    (2) Service equipment means filling and discharge, pressure relief, 
safety, heating and heat-insulating devices and measuring instruments.
    (3) Structural equipment means the reinforcing, fastening, handling, 
protective or stabilizing members of the body or stacking load bearing 
structural members (such as metal cages).
    (4) Maximum permissible gross mass means the mass of the body, its 
service equipment, structural equipment and the maximum net mass (see 
Sec.  171.8 of this subchapter).

[Amdt. 178-103, 59 FR 38068, July 26, 1994, as amended by Amdt. 178-108, 
60 FR 40038, Aug. 4, 1995; 66 FR 45386, 45387, Aug. 28, 2001; 73 FR 
57008, Oct. 1, 2008; 75 FR 5396, Feb. 2, 2010]



Sec.  178.702  IBC codes.

    (a) Intermediate bulk container code designations consist of: two 
numerals specified in paragraph (a)(1) of this section; followed by the 
capital letter(s) specified in paragraph (a)(2) of this section; 
followed, when specified in an individual section, by a numeral 
indicating the category of intermediate bulk container.

[[Page 222]]

    (1) IBC code number designations are as follows:

------------------------------------------------------------------------
                                    For solids, discharged
                                  --------------------------
                                                   Under
               Type                             pressure of  For liquids
                                    by gravity   more than
                                                   10 kPa
                                                (1.45 psig)
------------------------------------------------------------------------
Rigid............................           11           21           31
Flexible.........................           13
------------------------------------------------------------------------

    (2) Intermediate bulk container code letter designations are as 
follows:

``A'' means steel (all types and surface treatments).
``B'' means aluminum.
``C'' means natural wood.
``D'' means plywood.
``F'' means reconstituted wood.
``G'' means fiberboard.
``H'' means plastic.
``L'' means textile.
``M'' means paper, multiwall.
``N'' means metal (other than steel or aluminum).

    (b) For composite IBCs, two capital letters are used in sequence 
following the numeral indicating IBC design type. The first letter 
indicates the material of the IBC inner receptacle. The second letter 
indicates the material of the outer IBC. For example, 31HA1 is a 
composite IBC with a plastic inner receptacle and a steel outer 
packaging.

[Amdt. 178-103, 59 FR 38068, July 26, 1994, as amended at 66 FR 45386, 
Aug. 28, 2001]



Sec.  178.703  Marking of IBCs.

    (a) The manufacturer shall:
    (1) Mark every IBC in a durable and clearly visible manner. The 
marking may be applied in a single line or in multiple lines provided 
the correct sequence is followed with the information required by this 
section in letters, numerals and symbols of at least 12 mm in height. 
This minimum marking size applies only to IBCs manufactured after 
October 1, 2001). The following information is required in the sequence 
presented:
    (i) Except as provided in Sec.  178.503(e)(1)(ii), the United 
Nations symbol as illustrated in Sec.  178.503(e)(1)(i). For metal IBCs 
on which the marking is stamped or embossed, the capital letters ``UN'' 
may be applied instead of the symbol.
    (ii) The code number designating IBC design type according to Sec.  
178.702(a). The letter ``W'' must follow the IBC design type 
identification code on an IBC when the IBC differs from the requirements 
in subpart N of this part, or is tested using methods other than those 
specified in this subpart, and is approved by the Associate 
Administrator in accordance with the provisions in Sec.  178.801(i).
    (iii) A capital letter identifying the performance standard under 
which the design type has been successfully tested, as follows:
    (A) X--for IBCs meeting Packing Group I, II and III tests;
    (B) Y--for IBCs meeting Packing Group II and III tests; and
    (C) Z--for IBCs meeting only Packing Group III tests.
    (iv) The month (designated numerically) and year (last two digits) 
of manufacture.
    (v) The country authorizing the allocation of the mark. The letters 
`USA' indicate that the IBC is manufactured and marked in the United 
States in compliance with the provisions of this subchapter.
    (vi) The name and address or symbol of the manufacturer or the 
approval agency certifying compliance with subparts N and O of this 
part. Symbols, if used, must be registered with the Associate 
Administrator.
    (vii) The stacking test load in kilograms (kg). For IBCs not 
designed for stacking, the figure ``0'' must be shown.
    (viii) The maximum permissible gross mass in kg.
    (2) The following are examples of symbols and required markings:
    (i) For a metal IBC containing solids discharged by gravity made 
from steel:

[[Page 223]]

[GRAPHIC] [TIFF OMITTED] TR26JY94.000

    (ii) For a flexible IBC containing solids discharged by gravity and 
made from woven plastic with a liner:
[GRAPHIC] [TIFF OMITTED] TR26JY94.001

    (iii) For a rigid plastic IBC containing liquids, made from plastic 
with structural equipment withstanding the stack load and with a 
manufacturer's symbol in place of the manufacturer's name and address:
[GRAPHIC] [TIFF OMITTED] TR26JY94.002

    (iv) For a composite IBC containing liquids, with a rigid plastic 
inner receptacle and an outer steel body and with the symbol of a DOT 
approved third-party test laboratory:
[GRAPHIC] [TIFF OMITTED] TR26JY94.003

    (b) Additional marking. In addition to markings required in 
paragraph (a) of this section, each IBC must be marked as follows in a 
place near the markings required in paragraph (a) of this section that 
is readily accessible for inspection. Where units of measure are used, 
the metric unit indicated (e.g., 450 L) must also appear.
    (1) For each rigid plastic and composite IBC, the following markings 
must be included:
    (i) Rated capacity in L of water at 20 [deg]C (68 [deg]F);
    (ii) Tare mass in kilograms;

[[Page 224]]

    (iii) Gauge test pressure in kPa;
    (iv) Date of last leakproofness test, if applicable (month and 
year); and
    (v) Date of last inspection (month and year).
    (2) For each metal IBC, the following markings must be included on a 
metal corrosion-resistant plate:
    (i) Rated capacity in L of water at 20 [deg]C (68 [deg]F);
    (ii) Tare mass in kilograms;
    (iii) Date of last leakproofness test, if applicable (month and 
year);
    (iv) Date of last inspection (month and year);
    (v) Maximum loading/discharge pressure, in kPa, if applicable;
    (vi) Body material and its minimum thickness in mm; and
    (vii) Serial number assigned by the manufacturer.
    (3) Markings required by paragraph (b)(1) or (b)(2) of this section 
may be preceded by the narrative description of the marking, e.g. ``Tare 
Mass: * * *'' where the ``* * *'' are replaced with the tare mass in 
kilograms of the IBC.
    (4) For each fiberboard and wooden IBC, the tare mass in kg must be 
shown.
    (5) Each flexible IBC may be marked with a pictogram displaying 
recommended lifting methods.
    (6) For each composite IBC, the inner receptacle must be marked with 
at least the following information as required by paragraphs (b)(6)(i) 
and (ii) of this section. Additionally, the marking must be visible 
while inside of the outer receptacle. If the marking is not visible from 
the outer receptacle, the marking must be duplicated on the outer 
receptacle and include an indication that the marking applies to the 
inner receptacle.
    (i) The code number designating the IBC design type, the name and 
address or symbol of the manufacturer, the date of manufacture and the 
country authorizing the allocation of the mark as specified in paragraph 
(a) of this section. The date of manufacture of the inner receptacle may 
be different from the marked date of manufacture required by Sec.  
178.703(a)(1)(iv) or by Sec.  180.352(d)(1)(iv) of this subchapter; and
    (ii) When a composite IBC is designed in such a manner that the 
outer casing is intended to be dismantled for transport when empty (such 
as, for the return of the IBC for reuse to the original consignor), each 
of the parts intended to be detached when so dismantled must be marked 
with the month and year of manufacture and the name or symbol of the 
manufacturer.
    (7) The symbol applicable to an IBC designed for stacking or not 
designed for stacking, as appropriate, must be marked on all IBCs 
manufactured, repaired or remanufactured after January 1, 2011 as 
follows:
    (i)
    [GRAPHIC] [TIFF OMITTED] TR04JA10.097
    
    (ii) Display the symbol in a durable and visible manner.
    (iii) The symbol must be a square with each side being not less than 
100 mm (3.9 inches) by 100 mm (3.9 inches) as measured from the corner 
printer marks shown on the figures in paragraph (b)(7)(i) of this 
section. Where dimensions are not specified, all features must be in 
approximate proportion to those shown.
    (A) Transitional exception. A marking in conformance with the 
requirements of this paragraph in effect on December 31, 2014, may 
continue to be applied to all IBCs manufactured, repaired or 
remanufactured between January 1, 2011 and December 31, 2016.

[[Page 225]]

    (B) For domestic transportation, an IBC marked prior to January 1, 
2017 and in conformance with the requirements of this paragraph in 
effect on December 31, 2014, may continue in service until the end of 
its useful life.
    (iv) For IBCs designed for stacking, the maximum permitted stacking 
load applicable when the IBC is in transportation must be displayed with 
the symbol. The mass in kilograms (kg) marked above the symbol must not 
exceed the load imposed during the design test, as indicated by the 
marking in paragraph (a)(1)(vii) of this section, divided by 1.8. The 
letters and numbers indicating the mass must be at least 12 mm (0.48 
inches).

[Amdt. 178-103, 59 FR 38068, July 26, 1994, as amended by Amdt. 178-119, 
62 FR 24743, May 6, 1997; 64 FR 10782, Mar. 5, 1999; 65 FR 50462, Aug. 
18, 2000; 65 FR 58632, Sept. 29, 2000; 66 FR 33451, June 21, 2001; 66 FR 
45387, Aug. 28, 2001; 74 FR 2269, Jan. 14, 2009; 75 FR 74, Jan. 4, 2010; 
75 FR 5396, Feb. 2, 2010; 76 FR 3389, Jan. 19, 2011; 80 FR 1168, Jan. 8, 
2015; 83 FR 55810, Nov. 7, 2018; 87 FR 45000, July 26, 2022]



Sec.  178.704  General IBC standards.

    (a) Each IBC must be resistant to, or protected from, deterioration 
due to exposure to the external environment. IBCs intended for solid 
hazardous materials must be sift-proof and water-resistant.
    (b) All service equipment must be so positioned or protected as to 
minimize potential loss of contents resulting from damage during IBC 
handling and transportation.
    (c) Each IBC, including attachments, and service and structural 
equipment, must be designed to withstand, without loss of hazardous 
materials, the internal pressure of the contents and the stresses of 
normal handling and transport. An IBC intended for stacking must be 
designed for stacking. Any lifting or securing features of an IBC must 
be of sufficient strength to withstand the normal conditions of handling 
and transportation without gross distortion or failure and must be 
positioned so as to cause no undue stress in any part of the IBC.
    (d) An IBC consisting of a packaging within a framework must be so 
constructed that:
    (1) The body is not damaged by the framework;
    (2) The body is retained within the framework at all times; and
    (3) The service and structural equipment are fixed in such a way 
that they cannot be damaged if the connections between body and frame 
allow relative expansion or motion.
    (e) Bottom discharge valves must be secured in the closed position 
and the discharge system suitably protected from damage. Valves having 
lever closures must be secured against accidental opening. The open or 
closed position of each valve must be readily apparent. For each IBC 
containing a liquid, a secondary means of sealing the discharge aperture 
must also be provided, e.g., by a blank flange or equivalent device.
    (f) IBC design types must be constructed in such a way as to be 
bottom-lifted or top-lifted as specified in Sec. Sec.  178.811 and 
178.812.

[Amdt. 178-103, 59 FR 38068, July 26, 1994, as amended at 66 FR 45386, 
Aug. 28, 2001; 68 FR 61942, Oct. 30, 2003]



Sec.  178.705  Standards for metal IBCs.

    (a) The provisions in this section apply to metal IBCs intended to 
contain liquids and solids. Metal IBC types are designated:
    (1) 11A, 11B, 11N for solids that are loaded or discharged by 
gravity.
    (2) 21A, 21B, 21N for solids that are loaded or discharged at a 
gauge pressure greater than 10 kPa (1.45 psig).
    (3) 31A, 31B, 31N for liquids.
    (b) Definitions for metal IBCs:
    (1) Metal IBC means an IBC with a metal body, together with 
appropriate service and structural equipment.
    (2) Protected means providing the IBC body with additional external 
protection against impact and abrasion. For example, a multi-layer 
(sandwich) or double wall construction or a frame with a metal lattice-
work casing.
    (c) Construction requirements for metal IBCs are as follows:
    (1) Body. The body must be made of ductile metal materials. Welds 
must be made so as to maintain design type integrity of the receptacle 
under conditions normally incident to transportation.
    (i) The use of dissimilar metals must not result in deterioration 
that could affect the integrity of the body.

[[Page 226]]

    (ii) Aluminum IBCs intended to contain flammable liquids must have 
no movable parts, such as covers and closures, made of unprotected steel 
liable to rust, which might cause a dangerous reaction from friction or 
percussive contact with the aluminum.
    (iii) Metals used in fabricating the body of a metal IBC must meet 
the following requirements:
    (A) For steel, the percentage elongation at fracture must not be 
less than 10,000/Rm with a minimum of 20 percent; where Rm = minimum 
tensile strength of the steel to be used, in N/mm\2\; if U.S. Standard 
units of psi are used for tensile strength then the ratio becomes 10,000 
x (145/Rm).
    (B) For aluminum, the percentage elongation at fracture must not be 
less than 10,000/(6Rm) with an absolute minimum of eight percent; if 
U.S. Standard units of psi are used for tensile strength then the ratio 
becomes 10,000 x 145 / (6Rm).
    (C) Specimens used to determine the elongation at fracture must be 
taken transversely to the direction of rolling and be so secured that:

Lo = 5d


or

Lo = 5.65 [radic]A

where:

Lo = gauge length of the specimen before the test
d = diameter
A = cross-sectional area of test specimen.

    (iv) Minimum wall thickness. For metal IBCs with a capacity of more 
than 1500 liters, the minimum wall thickness must be determined as 
follows:
    (A) For a reference steel having a product of Rm x Ao = 10,000, 
where Ao is the minimum elongation (as a percentage) of the reference 
steel to be used on fracture under tensile stress (Rm x Ao = 10,000 x 
145; if tensile strength is in U.S. Standard units of pounds per square 
inch), the wall thickness must not be less than:

 Table 1 to Paragraph (c)(1)(iv)(A)--Wall Thickness (T) in mm, Capacity
                              (C) in Liters
------------------------------------------------------------------------
         Types 11A, 11B, 11N          Types 21A, 21B, 21N, 31A, 31B, 31N
------------------------------------------------------------------------
   Unprotected         Protected         Unprotected        Protected
------------------------------------------------------------------------
T = C/2000 + 1.5   T = C/2000 + 1.0   T = C/1000 + 1.0  T = C/2000 + 1.5
------------------------------------------------------------------------

    (B) For metals other than the reference steel described in paragraph 
(c)(1)(iii)(A) of this section, the minimum wall thickness is the 
greater of 1.5 mm (0.059 inches) or as determined by use of the 
following equivalence formula:
                        Formula for Metric Units
[GRAPHIC] [TIFF OMITTED] TP26JN96.000

                     Formula for U.S. Standard Units
[GRAPHIC] [TIFF OMITTED] TP26JN96.001

where:

e1 = required equivalent wall thickness of the metal to be 
used (in mm or if eo is in inches, use formula for U.S. 
Standard units).
eo = required minimum wall thickness for the reference steel 
(in mm or if eo is in inches, use formula for U.S. Standard 
units).
Rm1 = guaranteed minimum tensile strength of the metal to be 
used (in N/mm\2\ or for U.S. Standard units, use psi).
A1 = minimum elongation (as a percentage) of the metal to be 
used on fracture under tensile stress (see paragraph (c)(1) of this 
section).

    (C) For purposes of the calculation described in paragraph 
(c)(1)(iv)(B) of this section, the guaranteed minimum tensile strength 
of the metal to be used (Rm1) must be the minimum value 
according to material standards. However, for austenitic (stainless) 
steels, the specified minimum value for Rm, according to the material 
standards, may be increased by up to 15% when a greater value is 
provided in the material inspection certificate. When no

[[Page 227]]

material standard exists for the material in question, the value of Rm 
must be the minimum value indicated in the material inspection 
certificate.
    (2) Pressure relief. The following pressure relief requirements 
apply to IBCs intended for liquids:
    (i) IBCs must be capable of releasing a sufficient amount of vapor 
in the event of fire engulfment to ensure that no rupture of the body 
will occur due to pressure build-up. This can be achieved by spring-
loaded or non-reclosing pressure relief devices or by other means of 
construction.
    (ii) The start-to-discharge pressure may not be higher than 65 kPa 
(9 psig) and no lower than the vapor pressure of the hazardous material 
plus the partial pressure of the air or other inert gases, measured in 
the IBC at 55 [deg]C (131 [deg]F), determined on the basis of a maximum 
degree of filling as specified in Sec.  173.35(d) of this subchapter. 
This does not apply to fusible devices unless such devices are the only 
source of pressure relief for the IBC. Pressure relief devices must be 
fitted in the vapor space.
    (d) Metal IBCs may not have a volumetric capacity greater than 3,000 
L (793 gallons) or less than 450 L (119 gallons).

[Amdt. 178-103, 59 FR 38068, July 26, 1994, as amended by Amdt. 178-108, 
60 FR 40038, Aug. 4, 1995; Amdt. 178-117, 61 FR 50629, Sept. 26, 1996; 
66 FR 33452, June 21, 2001; 66 FR 45386, 45387, Aug. 28, 2001; 68 FR 
45041, July 31, 2003; 75 FR 5396, Feb. 2, 2010; 78 FR 1097, Jan. 7, 
2013; 87 FR 45000, July 26, 2022]



Sec.  178.706  Standards for rigid plastic IBCs.

    (a) The provisions in this section apply to rigid plastic IBCs 
intended to contain solids or liquids. Rigid plastic IBC types are 
designated:
    (1) 11H1 fitted with structural equipment designed to withstand the 
whole load when IBCs are stacked, for solids which are loaded or 
discharged by gravity.
    (2) 11H2 freestanding, for solids which are loaded or discharged by 
gravity.
    (3) 21H1 fitted with structural equipment designed to withstand the 
whole load when IBCs are stacked, for solids which are loaded or 
discharged under pressure.
    (4) 21H2 freestanding, for solids which are loaded or discharged 
under pressure.
    (5) 31H1 fitted with structural equipment designed to withstand the 
whole load when IBCs are stacked, for liquids.
    (6) 31H2 freestanding, for liquids.
    (b) Rigid plastic IBCs consist of a rigid plastic body, which may 
have structural equipment, together with appropriate service equipment.
    (c) Rigid plastic IBCs must be manufactured from plastic material of 
known specifications and be of a strength relative to its capacity and 
to the service it is required to perform. In addition to conformance to 
Sec.  173.24 of this subchapter, plastic materials must be resistant to 
aging and to degradation caused by ultraviolet radiation.
    (1) If protection against ultraviolet radiation is necessary, it 
must be provided by the addition of a pigment or inhibiter such as 
carbon black. These additives must be compatible with the contents and 
remain effective throughout the life of the IBC body. Where use is made 
of carbon black, pigments or inhibitors, other than those used in the 
manufacture of the tested design type, retesting may be omitted if 
changes in the carbon black content, the pigment content or the 
inhibitor content do not adversely affect the physical properties of the 
material of construction.
    (2) Additives may be included in the composition of the plastic 
material to improve the resistance to aging or to serve other purposes, 
provided they do not adversely affect the physical or chemical 
properties of the material of construction.
    (3) No used material other than production residues or regrind from 
the same manufacturing process may be used in the manufacture of rigid 
plastic IBCs.
    (4) Rigid plastic IBCs intended for the transportation of liquids 
must be capable of releasing a sufficient amount of vapor to prevent the 
body of the IBC from rupturing if it is subjected to an internal 
pressure in excess of that for which it was hydraulically tested. This 
may be achieved by spring-loaded or non-reclosing pressure relief 
devices or by other means of construction.
    (d) Rigid plastic IBCs may not have a volumetric capacity greater 
than 3,000

[[Page 228]]

L (793 gallons) or less than 450 L (119 gallons).

[Amdt. 178-103, 59 FR 38068, July 26, 1994, as amended at 66 FR 45386, 
45387, Aug. 28, 2001; 75 FR 5396, Feb. 2, 2010]



Sec.  178.707  Standards for composite IBCs.

    (a) The provisions in this section apply to composite IBCs intended 
to contain solids and liquids. To complete the marking codes listed 
below, the letter ``Z'' must be replaced by a capital letter in 
accordance with Sec.  178.702(a)(2) to indicate the material used for 
the outer packaging. Composite IBC types are designated:
    (1) 11HZ1 Composite IBCs with a rigid plastic inner receptacle for 
solids loaded or discharged by gravity.
    (2) 11HZ2 Composite IBCs with a flexible plastic inner receptacle 
for solids loaded or discharged by gravity.
    (3) 21HZ1 Composite IBCs with a rigid plastic inner receptacle for 
solids loaded or discharged under pressure.
    (4) 21HZ2 Composite IBCs with a flexible plastic inner receptacle 
for solids loaded or discharged under pressure.
    (5) 31HZ1 Composite IBCs with a rigid plastic inner receptacle for 
liquids.
    (6) 31HZ2 Composite IBCs with a flexible plastic inner receptacle 
for liquids.
    (b) Definitions for composite IBC types:
    (1) A composite IBC is an IBC which consists of a rigid outer 
packaging enclosing a plastic inner receptacle together with any service 
or other structural equipment. The outer packaging of a composite IBC is 
designed to bear the entire stacking load. The inner receptacle and 
outer packaging form an integral packaging and are filled, stored, 
transported, and emptied as a unit.
    (2) The term plastic means polymeric materials (i.e., plastic or 
rubber).
    (3) A ``rigid'' inner receptacle is an inner receptacle which 
retains its general shape when empty without closures in place and 
without benefit of the outer casing. Any inner receptacle that is not 
``rigid'' is considered to be ``flexible.''
    (c) Construction requirements for composite IBCs with plastic inner 
receptacles are as follows:
    (1) The outer packaging must consist of rigid material formed so as 
to protect the inner receptacle from physical damage during handling and 
transportation, but is not required to perform the secondary containment 
function. It includes the base pallet where appropriate. The inner 
receptacle is not intended to perform a containment function without the 
outer packaging.
    (2) A composite IBC with a fully enclosing outer packaging must be 
designed to permit assessment of the integrity of the inner container 
following the leakproofness and hydraulic tests. The outer packaging of 
31HZ2 composite IBCs must enclose the inner receptacles on all sides.
    (3) The inner receptacle must be manufactured from plastic material 
of known specifications and be of a strength relative to its capacity 
and to the service it is required to perform. In addition to conformance 
with the requirements of Sec.  173.24 of this subchapter, the material 
must be resistant to aging and to degradation caused by ultraviolet 
radiation. The inner receptacle of 31HZ2 composite IBCs must consist of 
at least three plies of film.
    (i) If necessary, protection against ultraviolet radiation must be 
provided by the addition of pigments or inhibitors such as carbon black. 
These additives must be compatible with the contents and remain 
effective throughout the life of the inner receptacle. Where use is made 
of carbon black, pigments, or inhibitors, other than those used in the 
manufacture of the tested design type, retesting may be omitted if the 
carbon black content, the pigment content, or the inhibitor content do 
not adversely affect the physical properties of the material of 
construction.
    (ii) Additives may be included in the composition of the plastic 
material of the inner receptacle to improve resistance to aging, 
provided they do not adversely affect the physical or chemical 
properties of the material.
    (iii) No used material other than production residues or regrind 
from the same manufacturing process may be used in the manufacture of 
inner receptacles.

[[Page 229]]

    (iv) Composite IBCs intended for the transportation of liquids must 
be capable of releasing a sufficient amount of vapor to prevent the body 
of the IBC from rupturing if it is subjected to an internal pressure in 
excess of that for which it was hydraulically tested. This may be 
achieved by spring-loaded or non-reclosing pressure relief devices or by 
other means of construction.
    (4) The strength of the construction material comprising the outer 
packaging and the manner of construction must be appropriate to the 
capacity of the composite IBC and its intended use. The outer packaging 
must be free of any projection that might damage the inner receptacle.
    (i) Outer packagings of natural wood must be constructed of well 
seasoned wood that is commercially dry and free from defects that would 
materially lessen the strength of any part of the outer packaging. The 
tops and bottoms may be made of water-resistant reconstituted wood such 
as hardboard or particle board. Materials other than natural wood may be 
used for construction of structural equipment of the outer packaging.
    (ii) Outer packagings of plywood must be made of well-seasoned, 
rotary cut, sliced, or sawn veneer, commercially dry and free from 
defects that would materially lessen the strength of the casing. All 
adjacent plies must be glued with water-resistant adhesive. Materials 
other than plywood may be used for construction of structural equipment 
of the outer packaging. Outer packagings must be firmly nailed or 
secured to corner posts or ends or be assembled by equally suitable 
devices.
    (iii) Outer packagings of reconstituted wood must be constructed of 
water-resistant reconstituted wood such as hardboard or particle board. 
Materials other than reconstituted wood may be used for the construction 
of structural equipment of reconstituted wood outer packaging.
    (iv) Fiberboard outer packagings must be constructed of strong, 
solid, or double-faced corrugated fiberboard (single or multiwall).
    (A) Water resistance of the outer surface must be such that the 
increase in mass, as determined in a test carried out over a period of 
30 minutes by the Cobb method of determining water absorption, is not 
greater than 155 grams per square meter (0.0316 pounds per square 
foot)--see ISO 535 (E) (IBR, see Sec.  171.7 of this subchapter). 
Fiberboard must have proper bending qualities. Fiberboard must be cut, 
creased without cutting through any thickness of fiberboard, and slotted 
so as to permit assembly without cracking, surface breaks, or undue 
bending. The fluting of corrugated fiberboard must be firmly glued to 
the facings.
    (B) The ends of fiberboard outer packagings may have a wooden frame 
or be constructed entirely of wood. Wooden battens may be used for 
reinforcements.
    (C) Manufacturers' joints in the bodies of outer packagings must be 
taped, lapped and glued, or lapped and stitched with metal staples.
    (D) Lapped joints must have an appropriate overlap.
    (E) Where closing is effected by gluing or taping, a water-resistant 
adhesive must be used.
    (F) All closures must be sift-proof.
    (v) Outer packagings of plastic materials must be constructed in 
accordance with the relevant provisions of paragraph (c)(3) of this 
section.
    (5) Any integral pallet base forming part of an IBC, or any 
detachable pallet, must be suitable for the mechanical handling of an 
IBC filled to its maximum permissible gross mass.
    (i) The pallet or integral base must be designed to avoid 
protrusions that may cause damage to the IBC in handling.
    (ii) The outer packaging must be secured to any detachable pallet to 
ensure stability in handling and transportation. Where a detachable 
pallet is used, its top surface must be free from sharp protrusions that 
might damage the IBC.
    (iii) Strengthening devices, such as timber supports to increase 
stacking performance, may be used but must be external to the inner 
receptacle.
    (iv) The load-bearing surfaces of IBCs intended for stacking must be 
designed to distribute loads in a stable manner. An IBC intended for 
stacking must be designed so that loads are not supported by the inner 
receptacle.

[[Page 230]]

    (6) Intermediate IBCs of type 31HZ2 must be limited to a capacity of 
not more than 1,250 L.
    (d) Composite IBCs may not have a volumetric capacity greater than 
3,000 L (793 gallons) or less than 450 L (119 gallons).

[Amdt. 178-103, 59 FR 38068, July 26, 1994, as amended by Amdt. 178-119, 
62 FR 24743, May 6, 1997; 66 FR 45387, Aug. 28, 2001; 67 FR 61016, Sept. 
27, 2002; 68 FR 75758, Dec. 31, 2003; 69 FR 54046, Sept. 7, 2004; 75 FR 
5396, Feb. 2, 2010]



Sec.  178.708  Standards for fiberboard IBCs.

    (a) The provisions of this section apply to fiberboard IBCs intended 
to contain solids that are loaded or discharged by gravity. Fiberboard 
IBCs are designated: 11G.
    (b) Definitions for fiberboard IBC types:
    (1) Fiberboard IBCs consist of a fiberboard body with or without 
separate top and bottom caps, appropriate service and structural 
equipment, and if necessary an inner liner (but no inner packaging).
    (2) Liner means a separate tube or bag, including the closures of 
its openings, inserted in the body but not forming an integral part of 
it.
    (c) Construction requirements for fiberboard IBCs are as follows:
    (1) Top lifting devices are prohibited in fiberboard IBCs.
    (2) Fiberboard IBCs must be constructed of strong, solid or double-
faced corrugated fiberboard (single or multiwall) that is appropriate to 
the capacity of the outer packaging and its intended use. Water 
resistance of the outer surface must be such that the increase in mass, 
as determined in a test carried out over a period of 30 minutes by the 
Cobb method of determining water absorption, is not greater than 155 
grams per square meter (0.0316 pounds per square foot)--see ISO 535 (E) 
(IBR, see Sec.  171.7 of this subchapter). Fiberboard must have proper 
bending qualities. Fiberboard must be cut, creased without cutting 
through any thickness of fiberboard, and slotted so as to permit 
assembly without cracking, surface breaks, or undue bending. The fluting 
of corrugated fiberboard must be firmly glued to the facings.
    (i) The walls, including top and bottom, must have a minimum 
puncture resistance of 15 Joules (11 foot-pounds of energy) measured 
according to ISO 3036 (IBR, see Sec.  171.7 of this subchapter).
    (ii) Manufacturers' joints in the bodies of IBCs must be made with 
an appropriate overlap and be taped, glued, stitched with metal staples 
or fastened by other means at least equally effective. Where joints are 
made by gluing or taping, a water-resistant adhesive must be used. Metal 
staples must pass completely through all pieces to be fastened and be 
formed or protected so that any inner liner cannot be abraded or 
punctured by them.
    (3) The strength of the material used and the construction of the 
liner must be appropriate to the capacity of the IBC and the intended 
use. Joints and closures must be sift-proof and capable of withstanding 
pressures and impacts liable to occur under normal conditions of 
handling and transport.
    (4) Any integral pallet base forming part of an IBC, or any 
detachable pallet, must be suitable for the mechanical handling of an 
IBC filled to its maximum permissible gross mass.
    (i) The pallet or integral base must be designed to avoid 
protrusions that may cause damage to the IBC in handling.
    (ii) The outer packaging must be secured to any detachable pallet to 
ensure stability in handling and transport. Where a detachable pallet is 
used, its top surface must be free from sharp protrusions that might 
damage the IBC.
    (iii) Strengthening devices, such as timber supports to increase 
stacking performance, may be used but must be external to the inner 
liner.
    (iv) The load-bearing surfaces of IBCs intended for stacking must be 
designed to distribute loads in a stable manner.
    (d) Fiberboard IBCs may not have a volumetric capacity greater than 
3,000 L (793 gallons) or less than 450 L (119 gallons).

[Amdt. 178-103, 59 FR 38068, July 26, 1994, as amended at 66 FR 45386, 
Aug. 28, 2001; 68 FR 75758, Dec. 31, 2003; 75 FR 5396, Feb. 2, 2010]

[[Page 231]]



Sec.  178.709  Standards for wooden IBCs.

    (a) The provisions in this section apply to wooden IBCs intended to 
contain solids that are loaded or discharged by gravity. Wooden IBC 
types are designated:
    (1) 11C Natural wood with inner liner.
    (2) 11D Plywood with inner liner.
    (3) 11F Reconstituted wood with inner liner.
    (b) Definitions for wooden IBCs:
    (1) Wooden IBCs consist of a rigid or collapsible wooden body 
together with an inner liner (but no inner packaging) and appropriate 
service and structural equipment.
    (2) Liner means a separate tube or bag, including the closures of 
its openings, inserted in the body but not forming an integral part of 
it.
    (c) Construction requirements for wooden IBCs are as follows:
    (1) Top lifting devices are prohibited in wooden IBCs.
    (2) The strength of the materials used and the method of 
construction must be appropriate to the capacity and intended use of the 
IBC.
    (i) Natural wood used in the construction of an IBC must be well-
seasoned, commercially dry, and free from defects that would materially 
lessen the strength of any part of the IBC. Each IBC part must consist 
of uncut wood or a piece equivalent in strength and integrity. IBC parts 
are equivalent to one piece when a suitable method of glued assembly is 
used (i.e., a Lindermann joint, tongue and groove joint, ship lap or 
rabbet joint, or butt joint with at least two corrugated metal fasteners 
at each joint, or when other methods at least equally effective are 
used). Materials other than natural wood may be used for the 
construction of structural equipment of the outer packaging.
    (ii) Plywood used in construction of bodies must be at least 3-ply. 
Plywood must be made of well-seasoned, rotary-cut, sliced or sawn 
veneer, commercially dry, and free from defects that would materially 
lessen the strength of the body. All adjacent plies must be glued with 
water-resistant adhesive. Materials other than plywood may be used for 
the construction of structural equipment of the outer packaging.
    (iii) Reconstituted wood used in construction of bodies must be 
water resistant reconstituted wood such as hardboard or particle board. 
Materials other than reconstituted wood may be used for the construction 
of structural equipment of the outer packaging.
    (iv) Wooden IBCs must be firmly nailed or secured to corner posts or 
ends or be assembled by similar devices.
    (3) The strength of the material used and the construction of the 
liner must be appropriate to the capacity of the IBC and its intended 
use. Joints and closures must be sift-proof and capable of withstanding 
pressures and impacts liable to occur under normal conditions of 
handling and transportation.
    (4) Any integral pallet base forming part of an IBC, or any 
detachable pallet, must be suitable for the mechanical handling of an 
IBC filled to its maximum permissible gross mass.
    (i) The pallet or integral base must be designed to avoid 
protrusions that may cause damage to the IBC in handling.
    (ii) The outer packaging must be secured to any detachable pallet to 
ensure stability in handling and transportation. Where a detachable 
pallet is used, its top surface must be free from sharp protrusions that 
might damage the IBC.
    (iii) Strengthening devices, such as timber supports to increase 
stacking performance, may be used but must be external to the inner 
liner.
    (iv) The load-bearing surfaces of IBCs intended for stacking must be 
designed to distribute loads in a stable manner.
    (d) Wooden IBCs may not have a volumetric capacity greater than 
3,000 L (793 gallons) or less than 450 L (119 gallons).

[Amdt. 178-103, 59 FR 38068, July 26, 1994, as amended at 66 FR 45386, 
Aug. 28, 2001; 75 FR 5397, Feb. 2, 2010]



Sec.  178.710  Standards for flexible IBCs.

    (a) The provisions of this section apply to flexible IBCs intended 
to contain solid hazardous materials. Flexible IBC types are designated:
    (1) 13H1 woven plastic without coating or liner.
    (2) 13H2 woven plastic, coated.
    (3) 13H3 woven plastic with liner.

[[Page 232]]

    (4) 13H4 woven plastic, coated and with liner.
    (5) 13H5 plastic film.
    (6) 13L1 textile without coating or liner.
    (7) 13L2 textile, coated.
    (8) 13L3 textile with liner.
    (9) 13L4 textile, coated and with liner.
    (10) 13M1 paper, multiwall.
    (11) 13M2 paper, multiwall, water resistant.
    (b) Definitions for flexible IBCs:
    (1) Flexible IBCs consist of a body constructed of film, woven 
plastic, woven fabric, paper, or combination thereof, together with any 
appropriate service equipment and handling devices, and if necessary, an 
inner coating or liner.
    (2) Woven plastic means a material made from stretched tapes or 
monofilaments.
    (3) Handling device means any sling, loop, eye, or frame attached to 
the body of the IBC or formed from a continuation of the IBC body 
material.
    (c) Construction requirements for flexible IBCs are as follows:
    (1) The strength of the material and the construction of the 
flexible IBC must be appropriate to its capacity and its intended use.
    (2) All materials used in the construction of flexible IBCs of types 
13M1 and 13M2 must, after complete immersion in water for not less than 
24 hours, retain at least 85 percent of the tensile strength as measured 
originally on the material conditioned to equilibrium at 67 percent 
relative humidity or less.
    (3) Seams must be stitched or formed by heat sealing, gluing or any 
equivalent method. All stitched seam-ends must be secured.
    (4) In addition to conformance with the requirements of Sec.  173.24 
of this subchapter, flexible IBCs must be resistant to aging and 
degradation caused by ultraviolet radiation.
    (5) For plastic flexible IBCs, if necessary, protection against 
ultraviolet radiation must be provided by the addition of pigments or 
inhibitors such as carbon black. These additives must be compatible with 
the contents and remain effective throughout the life of the container. 
Where use is made of carbon black, pigments, or inhibitors, other than 
those used in the manufacture of the tested design type, retesting may 
be omitted if the carbon black content, the pigment content or the 
inhibitor content does not adversely affect the physical properties of 
the material of construction. Additives may be included in the 
composition of the plastic material to improve resistance to aging, 
provided they do not adversely affect the physical or chemical 
properties of the material.
    (6) No used material other than production residues or regrind from 
the same manufacturing process may be used in the manufacture of plastic 
flexible IBCs. This does not preclude the re-use of component parts such 
as fittings and pallet bases, provided such components have not in any 
way been damaged in previous use.
    (7) When flexible IBCs are filled, the ratio of height to width may 
not be more than 2:1.
    (d) Flexible IBCs: (1) May not have a volumetric capacity greater 
than 3,000 L (793 gallons) or less than 56 L (15 gallons); and
    (2) Must be designed and tested to a capacity of no less than 50 kg 
(110 pounds).

[Amdt. 178-103, 59 FR 38068, July 26, 1994, as amended by Amdt. 178-108, 
60 FR 40038, Aug. 4, 1995; 66 FR 45386, Aug. 28, 2001; 75 FR 5397, Feb. 
2, 2010]



                        Subpart O_Testing of IBCs



Sec.  178.800  Purpose and scope.

    This subpart prescribes certain testing requirements for IBCs 
identified in subpart N of this part.

[Amdt. 178-103, 59 FR 38074, July 26, 1994, as amended by 66 FR 45386, 
Aug. 28, 2001]



Sec.  178.801  General requirements.

    (a) General. The test procedures prescribed in this subpart are 
intended to ensure that IBCs containing hazardous materials can 
withstand normal conditions of transportation and are considered minimum 
requirements. Each packaging must be manufactured and assembled so as to 
be capable of successfully passing the prescribed tests and of 
conforming to the requirements of Sec.  173.24 of this subchapter at all 
times while in transportation.

[[Page 233]]

    (b) Responsibility. It is the responsibility of the IBC manufacturer 
to assure that each IBC is capable of passing the prescribed tests. To 
the extent that an IBC assembly function, including final closure, is 
performed by the person who offers a hazardous material for 
transportation, that person is responsible for performing the function 
in accordance with Sec. Sec.  173.22 and 178.2 of this subchapter.
    (c) Definitions. For the purpose of this subpart:
    (1) IBC design type refers to an IBC that does not differ in 
structural design, size, material of construction, wall thickness, 
manner of construction and representative service equipment.
    (2) Design qualification testing is the performance of the drop, 
leakproofness, hydrostatic pressure, stacking, bottom-lift or top-lift, 
tear, topple, righting and vibration tests, as applicable, prescribed in 
this subpart, for each different IBC design type, at the start of 
production of that packaging.
    (3) Periodic design requalification test is the performance of the 
applicable tests specified in paragraph (c)(2) of this section on an IBC 
design type, in order to requalify the design for continued production 
at the frequency specified in paragraph (e) of this section.
    (4) Production inspection is the inspection that must initially be 
conducted on each newly manufactured IBC.
    (5) Production testing is the performance of the leakproofness test 
in accordance with paragraph (f) of this section on each IBC intended to 
contain solids discharged by pressure or intended to contain liquids.
    (6) Periodic retest and inspection is performance of the applicable 
test and inspections on each IBC at the frequency specified in Sec.  
180.352 of this subchapter.
    (7) Different IBC design type is one that differs from a previously 
qualified IBC design type in structural design, size, material of 
construction, wall thickness, or manner of construction, but does not 
include:
    (i) A packaging which differs in surface treatment;
    (ii) A rigid plastic IBC or composite IBC which differs with regard 
to additives used to comply with Sec. Sec.  178.706(c), 178.707(c) or 
178.710(c);
    (iii) A packaging which differs only in its lesser external 
dimensions (i.e., height, width, length) provided materials of 
construction and material thicknesses or fabric weight remain the same;
    (iv) A packaging which differs in service equipment.
    (d) Design qualification testing. The packaging manufacturer shall 
achieve successful test results for the design qualification testing at 
the start of production of each new or different IBC design type. The 
service equipment selected for this design qualification testing shall 
be representative of the type of service equipment that will be fitted 
to any finished IBC body under the design. Application of the 
certification mark by the manufacturer shall constitute certification 
that the IBC design type passed the prescribed tests in this subpart.
    (e) Periodic design requalification testing. (1) Periodic design 
requalification must be conducted on each qualified IBC design type if 
the manufacturer is to maintain authorization for continued production. 
The IBC manufacturer shall achieve successful test results for the 
periodic design requalification at sufficient frequency to ensure each 
packaging produced by the manufacturer is capable of passing the design 
qualification tests. Design requalification tests must be conducted at 
least once every 12 months.
    (2) Changes in the frequency of design requalification testing 
specified in paragraph (e)(1) of this section are authorized if approved 
by the Associate Administrator. These requests must be based on:
    (i) Detailed quality assurance programs that assure that proposed 
decreases in test frequency maintain the integrity of originally tested 
IBC design types; and
    (ii) Demonstrations that each IBC produced is capable of 
withstanding higher standards (e.g., increased drop height, hydrostatic 
pressure, wall thickness, fabric weight).
    (f) Production testing and inspection. (1) Production testing 
consists of the leakproofness test prescribed in Sec.  178.813 of this 
subpart and must be performed on each IBC intended to contain solids 
discharged by pressure or

[[Page 234]]

intended to contain liquids. For this test:
    (i) The IBC need not have its closures fitted, except that the IBC 
must be fitted with its primary bottom closure.
    (ii) The inner receptacle of a composite IBC may be tested without 
the outer IBC body, provided the test results are not affected.
    (2) Applicable inspection requirements in Sec.  180.352 of this 
subchapter must be performed on each IBC initially after production.
    (g) Test samples. The IBC manufacturer shall conduct the design 
qualification and periodic design requalification tests prescribed in 
this subpart using random samples of IBCs, according to the appropriate 
test section.
    (h) Selective testing of IBCs. Variation of a tested IBC design type 
is permitted without further testing, provided selective testing 
demonstrates an equivalent or greater level of safety than the design 
type tested and which has been approved by the Associate Administrator.
    (i) Approval of equivalent packagings. An IBC differing from the 
standards in subpart N of this part, or tested using methods other than 
those specified in this subpart, may be used if approved by the 
Associate Administrator. Such IBCs must be shown to be equally 
effective, and testing methods used must be equivalent.
    (j) Proof of compliance. Notwithstanding the periodic design 
requalification testing intervals specified in paragraph (e) of this 
section, the Associate Administrator, or a designated representative, 
may at any time require demonstration of compliance by a manufacturer, 
through testing in accordance with this subpart, that packagings meet 
the requirements of this subpart. As required by the Associate 
Administrator, or a designated representative, the manufacturer shall 
either:
    (1) Conduct performance tests or have tests conducted by an 
independent testing facility, in accordance with this subpart; or
    (2) Make a sample IBC available to the Associate Administrator, or a 
designated representative, for testing in accordance with this subpart.
    (k) Coatings. If an inner treatment or coating of an IBC is required 
for safety reasons, the manufacturer shall design the IBC so that the 
treatment or coating retains its protective properties even after 
withstanding the tests prescribed by this subpart.
    (l) Record retention. Following each design qualification test and 
each periodic retest on an IBC, a test report must be prepared.
    (1) The test report must be maintained at each location where the 
packaging is manufactured, certified, and a design qualification test or 
periodic retest is conducted as follows:

------------------------------------------------------------------------
           Responsible party                         Duration
------------------------------------------------------------------------
Person manufacturing the packaging.....  As long as manufactured and two
                                          years thereafter.
Person performing design testing.......  Design test maintained for a
                                          single or composite packaging
                                          for six years after the test
                                          is successfully performed and
                                          for a combination packaging or
                                          packaging intended for
                                          infectious substances for
                                          seven years after the test is
                                          successfully performed.
Person performing periodic retesting...  Performance test maintained for
                                          a single or composite
                                          packaging for one year after
                                          the test is successfully
                                          performed and for a
                                          combination packaging or
                                          packaging intended for
                                          infectious substances for two
                                          years after the test is
                                          successfully performed.
------------------------------------------------------------------------

    (2) The test report must be made available to a user of a packaging 
or a representative of the Department upon request. The test report, at 
a minimum, must contain the following information:
    (i) Name and address of test facility;
    (ii) Name and address of the person certifying the IBC;
    (iii) A unique test report identification;
    (iv) Date of test report;
    (v) Manufacturer of the IBC;

[[Page 235]]

    (vi) Description of the IBC design type (e.g., dimensions, 
materials, closures, thickness, representative service equipment, etc.);
    (vii) Maximum IBC capacity;
    (viii) Characteristics of test contents, including for rigid 
plastics and composite IBCs subject to the hydrostatic pressure test in 
Sec.  178.814 of this subpart, the temperature of the water used;
    (ix) Test descriptions and results (including drop heights, 
hydrostatic pressures, tear propagation length, etc.); and
    (x) The signature of the person conducting the test, and name of the 
person responsible for testing.

[Amdt. 178-103, 59 FR 38074, July 26, 1994, as amended by Amdt. 178-108, 
60 FR 40038, Aug. 4, 1995; 66 FR 45386, Aug. 28, 2001; 66 FR 33452, June 
21, 2001; 68 FR 75758, Dec. 31, 2003; 73 FR 57008, Oct. 1, 2008; 74 FR 
2269, Jan. 14, 2009; 75 FR 5397, Feb. 2, 2010; 78 FR 14715, Mar. 7, 
2013; 78 FR 65487, Oct. 31, 2013; 80 FR 72929, Nov. 23, 2015; 85 FR 
27901, May 11, 2020]



Sec.  178.802  Preparation of fiberboard IBCs for testing.

    (a) Fiberboard IBCs and composite IBCs with fiberboard outer 
packagings must be conditioned for at least 24 hours in an atmosphere 
maintained:
    (1) At 50 percent 2 percent relative humidity, 
and at a temperature of 23[deg] 2 [deg]C (73 
[deg]F 4 [deg]F); or
    (2) At 65 percent 2 percent relative humidity, 
and at a temperature of 20[deg] 2 [deg]C (68 
[deg]F 4 [deg]F), or 27 [deg]C 2 [deg]C (81 [deg]F 4 [deg]F).
    (b) Average values for temperature and humidity must fall within the 
limits in paragraph (a) of this section. Short-term fluctuations and 
measurement limitations may cause individual measurements to vary by up 
to 5 percent relative humidity without significant 
impairment of test reproducibility.
    (c) For purposes of periodic design requalification only, fiberboard 
IBCs or composite IBCs with fiberboard outer packagings may be at 
ambient conditions.

[Amdt. 178-103, 59 FR 38074, July 26, 1994, as amended at 66 FR 45386, 
Aug. 28, 2001]



Sec.  178.803  Testing and certification of IBCs.

    Tests required for the certification of each IBC design type are 
specified in the following table. The letter X indicates that one IBC 
(except where noted) of each design type must be subjected to the tests 
in the order presented:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                          IBC type
         Performance test         ----------------------------------------------------------------------------------------------------------------------
                                       Metal IBCs      Rigid plastic IBCs    Composite IBCs     Fiber-board IBCs       Wooden IBCs       Flexible IBCs
--------------------------------------------------------------------------------------------------------------------------------------------------------
Vibration........................  \6\ X               \6\ X               \6\ X               \6\ X               \6\ X               \1.5\ X
Bottom lift......................  \2\ X               X                   X                   X                   X                   .................
Top lift.........................  \2\ X               \2\ X               \2\ X               ..................  ..................  \2 5\ X
Stacking.........................  \7\ X               \7\ X               \7\ X               \7\ X               \7\ X               \5\ X
Leakproofness....................  \3\ X               \3\ X               \3\ X               ..................  ..................  .................
Hydrostatic......................  \3\ X               \3\ X               \3\ X               ..................  ..................  .................
Drop.............................  \4\ X               \4\ X               \4\ X               \4\ X               \4\ X               \5\ X
Topple...........................  ..................  ..................  ..................  ..................  ..................  \5\ X
Righting.........................  ..................  ..................  ..................  ..................  ..................  \2 5\ X
Tear.............................  ..................  ..................  ..................  ..................  ..................  \5\ X
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Flexible IBCs must be capable of withstanding the vibration test.
\2\ This test must be performed only if IBCs are designed to be handled this way. For metal IBCs, at least one of the bottom lift or top lift tests must
  be performed.
\3\ The leakproofness and hydrostatic pressure tests are required only for IBCs intended to contain liquids or intended to contain solids loaded or
  discharged under pressure.
\4\ Another IBC of the same design type may be used for the drop test set forth in Sec.   178.810 of this subchapter.
\5\ Another different flexible IBC of the same design type may be used for each test.
\6\ The vibration test may be performed in another order for IBCs manufactured and tested under provisions of an exemption before October 1, 1994 and
  for non-DOT specification portable tanks tested before October 1, 1994, intended for export.
\7\ This test must be performed only if the IBC is designed to be stacked.


[Amdt. 178-108, 60 FR 40039, Aug. 4, 1995, as amended at 64 FR 51919, 
Sept. 27, 1999; 66 FR 45386, 45390, Aug. 28, 2001]

[[Page 236]]



Sec.  178.810  Drop test.

    (a) General. The drop test must be conducted for the qualification 
of all IBC design types and performed periodically as specified in Sec.  
178.801(e) of this subpart.
    (b) Special preparation for the drop test. (1) Metal, rigid plastic, 
and composite IBCs intended to contain solids must be filled to not less 
than 95 percent of their maximum capacity, or if intended to contain 
liquids, to not less than 98 percent of their maximum capacity. Pressure 
relief devices must be removed and their apertures plugged or rendered 
inoperative.
    (2) Fiberboard and wooden IBCs must be filled with a solid material 
to not less than 95 percent of their maximum capacity; the contents must 
be evenly distributed.
    (3) Flexible IBCs must be filled to the maximum permissible gross 
mass; the contents must be evenly distributed.
    (4) Rigid plastic IBCs and composite IBCs with plastic inner 
receptacles must be conditioned for testing by reducing the temperature 
of the packaging and its contents to -18 [deg]C (0 [deg]F) or lower. 
Test liquids must be kept in the liquid state, if necessary, by the 
addition of anti-freeze. Water/anti-freeze solutions with a minimum 
specific gravity of 0.95 for testing at -18 [deg]C (0 [deg]F) or lower 
are considered acceptable test liquids, and may be considered equivalent 
to water for test purposes. IBCs conditioned in this way are not 
required to be conditioned in accordance with Sec.  178.802.
    (c) Test method. (1) Samples of all IBC design types must be dropped 
onto a rigid, non-resilient, smooth, flat and horizontal surface. The 
point of impact must be the most vulnerable part of the base of the IBC 
being tested. Following the drop, the IBC must be restored to the 
upright position for observation.
    (2) IBC design types with a capacity of 0.45 cubic meters (15.9 
cubic feet) or less must be subject to an additional drop test. The same 
IBC or a different IBC of the same design may be used for each drop.
    (d) Drop height. (1) For all IBCs, drop heights are specified as 
follows:
    (i) Packing Group I: 1.8 m (5.9 feet).
    (ii) Packing Group II: 1.2 m (3.9 feet).
    (iii) Packing Group III: 0.8 m (2.6 feet).
    (2) Drop tests are to be performed with the solid or liquid to be 
transported or with a non-hazardous material having essentially the same 
physical characteristics.
    (3) The specific gravity and viscosity of a substituted non-
hazardous material used in the drop test for liquids must be similar to 
the hazardous material intended for transportation. Water also may be 
used for the liquid drop test under the following conditions:
    (i) Where the substances to be carried have a specific gravity not 
exceeding 1.2, the drop heights must be those specified in paragraph 
(d)(1) of this section for each IBC design type; and
    (ii) Where the substances to be carried have a specific gravity 
exceeding 1.2, the drop heights must be as follows:
    (A) Packing Group I: SG x 1.5 m (4.9 feet).
    (B) Packing Group II: SG x 1.0 m (3.3 feet).
    (C) Packing Group III: SG x 0.67 m (2.2 feet).
    (e) Criteria for passing the test. For all IBC design types, there 
may be no damage which renders the IBC unsafe to be transported for 
salvage or for disposable, and no loss of contents. The IBC shall be 
capable of being lifted by an appropriate means until clear of the floor 
for five minutes. A slight discharge from a closure upon impact is not 
considered to be a failure of the IBC provided that no further leakage 
occurs. A slight discharge (e.g., from closures or stitch holes) upon 
impact is not considered a failure of the flexible IBC provided that no 
further leakage occurs after the IBC has been raised clear of the 
ground.

[Amdt. 178-103, 59 FR 38074, July 26, 1994, as amended at 66 FR 45386, 
Aug. 28, 2001; 69 FR 76186, Dec. 20, 2004; 71 FR 78635, Dec. 29, 2006; 
74 FR 2269, Jan. 14, 2009; 75 FR 5397, Feb. 2, 2010; 85 FR 27901, May 
11, 2020]



Sec.  178.811  Bottom lift test.

    (a) General. The bottom lift test must be conducted for the 
qualification of all IBC design types designed to be lifted from the 
base.
    (b) Special preparation for the bottom lift test. The IBC must be 
loaded to 1.25

[[Page 237]]

times its maximum permissible gross mass, the load being evenly 
distributed.
    (c) Test method. All IBC design types must be raised and lowered 
twice by a lift truck with the forks centrally positioned and spaced at 
three quarters of the dimension of the side of entry (unless the points 
of entry are fixed). The forks must penetrate to three quarters of the 
direction of entry. The test must be repeated from each possible 
direction of entry.
    (d) Criteria for passing the test. For all IBC design types designed 
to be lifted from the base, there may be no permanent deformation which 
renders the IBC unsafe for transportation and no loss of contents.

[Amdt. 178-103, 59 FR 38074, July 26, 1994, as amended at 66 FR 45386, 
Aug. 28, 2001]



Sec.  178.812  Top lift test.

    (a) General. The top lift test must be conducted for the 
qualification of all IBC design types designed to be lifted from the top 
or, for flexible IBCs, from the side.
    (b) Special preparation for the top lift test. (1) Metal, rigid 
plastic, and composite IBC design types must be loaded to twice the 
maximum permissible gross mass with the load being evenly distributed.
    (2) Flexible IBC design types must be filled to six times the 
maximum net mass, the load being evenly distributed.
    (c) Test method. (1) A metal or flexible IBC must be lifted in the 
manner for which it is designed until clear of the floor and maintained 
in that position for a period of five minutes.
    (2) Rigid plastic and composite IBC design types must be:
    (i) Lifted by each pair of diagonally opposite lifting devices, so 
that the hoisting forces are applied vertically, for a period of five 
minutes; and
    (ii) Lifted by each pair of diagonally opposite lifting devices, so 
that the hoisting forces are applied towards the center at 45[deg] to 
the vertical, for a period of five minutes.
    (3) If not tested as indicated in paragraph (c)(1) of this section, 
a flexible IBC design type must be tested as follows:
    (i) Fill the flexible IBC to 95% full with a material representative 
of the product to be shipped.
    (ii) Suspend the flexible IBC by its lifting devices.
    (iii) Apply a constant downward force through a specially designed 
platen. The platen will be a minimum of 60% and a maximum of 80% of the 
cross sectional surface area of the flexible IBC.
    (iv) The combination of the mass of the filled flexible IBC and the 
force applied through the platen must be a minimum of six times the 
maximum net mass of the flexible IBC. The test must be conducted for a 
period of five minutes.
    (v) Other equally effective methods of top lift testing and 
preparation may be used with approval of the Associate Administrator.
    (d) Criteria for passing the test. For all IBC design types designed 
to be lifted from the top, there may be no permanent deformation which 
renders the IBC, including the base pallets when applicable, unsafe for 
transportation, and no loss of contents.

[Amdt. 178-103, 59 FR 38074, July 26, 1994, as amended at 66 FR 33452, 
June 21, 2001; 66 FR 45386, Aug. 28, 2001; 68 FR 45042, July 31, 2003]



Sec.  178.813  Leakproofness test.

    (a) General. The leakproofness test must be conducted for the 
qualification of all IBC design types and on all production units 
intended to contain solids that are loaded or discharged under pressure 
or intended to contain liquids.
    (b) Special preparation for the leakproofness test. Vented closures 
must either be replaced by similar non-vented closures or the vent must 
be sealed. For metal IBC design types, the initial test must be carried 
out before the fitting of any thermal insulation equipment. The inner 
receptacle of a composite IBC may be tested without the outer packaging 
provided the test results are not affected.
    (c) Test method and pressure applied. The leakproofness test must be 
carried out for a suitable length of time using air at a gauge pressure 
of not less than 20 kPa (2.9 psig). Leakproofness of IBC design types 
must be determined by coating the seams and joints with a heavy oil, a 
soap solution and water, or other methods suitable for the purpose

[[Page 238]]

of detecting leaks. Other methods, if at least equally effective, may be 
used in accordance with appendix B of this part, or if approved by the 
Associate Administrator, as provided in Sec.  178.801(i)).
    (d) Criterion for passing the test. For all IBC design types 
intended to contain solids that are loaded or discharged under pressure 
or intended to contain liquids, there may be no leakage of air from the 
IBC.

[Amdt. 178-103, 59 FR 38074, July 26, 1994, as amended at 64 FR 10782, 
Mar. 5, 1999; 66 FR 45185, 45386, Aug. 28, 2001]



Sec.  178.814  Hydrostatic pressure test.

    (a) General. The hydrostatic pressure test must be conducted for the 
qualification of all metal, rigid plastic, and composite IBC design 
types intended to contain solids that are loaded or discharged under 
pressure or intended to contain liquids.
    (b) Special preparation for the hydrostatic pressure test. For metal 
IBCs, the test must be carried out before the fitting of any thermal 
insulation equipment. For all IBCs, pressure relief devices and vented 
closures must be removed and their apertures plugged or rendered 
inoperative.
    (c) Test method. Hydrostatic gauge pressure must be measured at the 
top of the IBC. The test must be carried out for a period of at least 10 
minutes applying a hydrostatic gauge pressure not less than that 
indicated in paragraph (d) of this section. The IBCs may not be 
mechanically restrained during the test.
    (d) Hydrostatic gauge pressure applied. (1) For metal IBC design 
types, 31A, 31B, 31N: 65 kPa gauge pressure (9.4 psig).
    (2) For metal IBC design types 21A, 21B, 21N, 31A, 31B, 31N: 200 kPa 
(29 psig). For metal IBC design types 31A, 31B and 31N, the tests in 
paragraphs (d)(1) and (d)(2) of this section must be conducted 
consecutively.
    (3) For metal IBCs design types 21A, 21B, and 21N, for Packing Group 
I solids: 250 kPa (36 psig) gauge pressure.
    (4) For rigid plastic IBC design types 21H1 and 21H2 and composite 
IBC design types 21HZ1 and 21HZ2: 75 kPa (11 psig).
    (5) For rigid plastic IBC design types 31H1 and 31H2 and composite 
IBC design types 31HZ1 and 31HZ2: whichever is the greater of:
    (i) The pressure determined by any one of the following methods:
    (A) The gauge pressure (pressure in the IBC above ambient 
atmospheric pressure) measured in the IBC at 55 [deg]C (131 [deg]F) 
multiplied by a safety factor of 1.5. This pressure must be determined 
on the basis of the IBC being filled and closed to no more than 98 
percent capacity at 15 [deg]C (60 [deg]F);
    (B) If absolute pressure (vapor pressure of the hazardous material 
plus atmospheric pressure) is used, 1.5 multiplied by the vapor pressure 
of the hazardous material at 55 [deg]C (131 [deg]F) minus 100 kPa (14.5 
psi). If this method is chosen, the hydrostatic test pressure applied 
must be at least 100 kPa gauge pressure (14.5 psig); or
    (C) If absolute pressure (vapor pressure of the hazardous material 
plus atmospheric pressure) is used, 1.75 multiplied by the vapor 
pressure of the hazardous material at 50 [deg]C (122 [deg]F) minus 100 
kPa (14.5 psi). If this method is chosen, the hydrostatic test pressure 
applied must be at least 100 kPa gauge pressure (14.5 psig); or
    (ii) Twice the greater of: (A) The static pressure of the hazardous 
material on the bottom of the IBC filled to 98 percent capacity; or
    (B) The static pressure of water on the bottom of the IBC filled to 
98 percent capacity.
    (e) Criteria for passing the test(s). (1) For metal IBCs, subjected 
to the 65 kPa (9.4 psig) test pressure specified in paragraph (d)(1) of 
this section, there may be no leakage or permanent deformation that 
would make the IBC unsafe for transportation.
    (2) For metal IBCs intended to contain liquids, when subjected to 
the 200 kPa (29 psig) and the 250 kPa (36 psig) test pressures specified 
in paragraphs (d)(2) and (d)(3) of this section, respectively, there may 
be no leakage.
    (3) For rigid plastic IBC types 21H1, 21H2, 31H1, and 31H2, and 
composite IBC types 21HZ1, 21HZ2, 31HZ1, and 31HZ2, there may be no 
leakage and no

[[Page 239]]

permanent deformation which renders the IBC unsafe for transportation.

[Amdt. 178-103, 59 FR 38074, July 26, 1994, as amended at 66 FR 45185, 
45386, Aug. 28, 2001]



Sec.  178.815  Stacking test.

    (a) General. The stacking test must be conducted for the 
qualification of all IBC design types intended to be stacked.
    (b) Special preparation for the stacking test. (1) All IBCs except 
flexible IBC design types must be loaded to their maximum permissible 
gross mass.
    (2) The flexible IBC must be filled to not less than 95 percent of 
its capacity and to its maximum net mass, with the load being evenly 
distributed.
    (c) Test method. (1) Design Qualification Testing. All IBCs must be 
placed on their base on level, hard ground and subjected to a uniformly 
distributed superimposed test load for a period of at least five minutes 
(see paragraph (c)(5) of this section).
    (2) Fiberboard, wooden and composite IBCs with outer packagings 
constructed of other than plastic materials must be subject to the test 
for 24 hours.
    (3) Rigid plastic IBC types and composite IBC types with plastic 
outer packagings (11HH1, 11HH2, 21HH1, 21HH2, 31HH1 and 31HH2) which 
bear the stacking load must be subjected to the test for 28 days at 40 
[deg]C (104 [deg]F).
    (4) For all IBCs, the load must be applied by one of the following 
methods:
    (i) One or more IBCs of the same type loaded to their maximum 
permissible gross mass and stacked on the test IBC;
    (ii) The calculated superimposed test load weight loaded on either a 
flat plate or a reproduction of the base of the IBC, which is stacked on 
the test IBC.
    (5) Calculation of superimposed test load. For all IBCs, the load to 
be placed on the IBC must be 1.8 times the combined maximum permissible 
gross mass of the number of similar IBCs that may be stacked on top of 
the IBC during transportation.
    (d) Periodic Retest. (1) The package must be tested in accordance 
with paragraph (c) of this section; or
    (2) The packaging may be tested using a dynamic compression testing 
machine. The test must be conducted at room temperature on an empty, 
unsealed packaging. The test sample must be centered on the bottom 
platen of the testing machine. The top platen must be lowered until it 
comes in contact with the test sample. Compression must be applied end 
to end. The speed of the compression tester must be one-half inch plus 
or minus one-fourth inch per minute. An initial preload of 50 pounds 
must be applied to ensure a definite contact between the test sample and 
the platens. The distance between the platens at this time must be 
recorded as zero deformation. The force ``A'' then to be applied must be 
calculated using the applicable formula:

Liquids: A = (1.8)(n - 1) [w + (s x v x 8.3 x .98)] x 1.5;

or

Solids: A = (1.8)(n - 1) [w + (s x v x 8.3 x .95)] x 1.5

Where:

A = applied load in pounds.
n = maximum number of IBCs being stacked during transportation.
w = maximum weight of one empty container in pounds.
s = specific gravity (liquids) or density (solids) of the lading.
v = actual capacity of container (rated capacity + outage) in gallons.
and:
8.3 corresponds to the weight in pounds of 1.0 gallon of water.
1.5 is a compensation factor converting the static load of the stacking 
test into a load suitable for dynamic compression testing.

    (e) Criteria for passing the test. (1) For metal, rigid plastic, and 
composite IBCs, there may be no permanent deformation, which renders the 
IBC unsafe for transportation, and no loss of contents.
    (2) For fiberboard and wooden IBCs, there may be no loss of contents 
and no permanent deformation, which renders the whole IBC, including the 
base pallet, unsafe for transportation.
    (3) For flexible IBCs, there may be no deterioration, which renders 
the IBC unsafe for transportation, and no loss of contents.
    (4) For the dynamic compression test, a container passes the test 
if, after application of the required load, there is no permanent 
deformation to the IBC, which renders the whole IBC,

[[Page 240]]

including the base pallet, unsafe for transportation; in no case may the 
maximum deflection exceed one inch.

[75 FR 5397, Feb. 2, 2010]



Sec.  178.816  Topple test.

    (a) General. The topple test must be conducted for the qualification 
of all flexible IBC design types.
    (b) Special preparation for the topple test. The flexible IBC must 
be filled to not less than 95 percent of its capacity and to its maximum 
net mass, with the load being evenly distributed.
    (c) Test method. A flexible IBC must be toppled onto any part of its 
top upon a rigid, non-resilient, smooth, flat, and horizontal surface.
    (d) Topple height. For all flexible IBCs, the topple height is 
specified as follows:
    (1) Packing Group I: 1.8 m (5.9 feet).
    (2) Packing Group II: 1.2 m (3.9 feet).
    (3) Packing Group III: 0.8 m (2.6 feet).
    (e) Criteria for passing the test. For all flexible IBCs, there may 
be no loss of contents. A slight discharge (e.g., from closures or 
stitch holes) upon impact is not considered to be a failure, provided no 
further leakage occurs.

[Amdt. 178-103, 59 FR 38074, July 26, 1994, as amended at 66 FR 45386, 
Aug. 28, 2001]



Sec.  178.817  Righting test.

    (a) General. The righting test must be conducted for the 
qualification of all flexible IBCs designed to be lifted from the top or 
side.
    (b) Special preparation for the righting test. The flexible IBC must 
be filled to not less than 95 percent of its capacity and to its maximum 
net mass, with the load being evenly distributed.
    (c) Test method. The flexible IBC, lying on its side, must be lifted 
at a speed of at least 0.1 m/second (0.33 ft/s) to an upright position, 
clear of the floor, by one lifting device, or by two lifting devices 
when four are provided.
    (d) Criterion for passing the test. For all flexible IBCs, there may 
be no damage to the IBC or its lifting devices which renders the IBC 
unsafe for transportation or handling.

[Amdt. 178-103, 59 FR 38074, July 26, 1994, as amended at 66 FR 45386, 
Aug. 28, 2001]



Sec.  178.818  Tear test.

    (a) General. The tear test must be conducted for the qualification 
of all flexible IBC design types.
    (b) Special preparation for the tear test. The flexible IBC must be 
filled to not less than 95 percent of its capacity and to its maximum 
net mass, the load being evenly distributed.
    (c) Test method. Once the IBC is placed on the ground, a 100-mm (4-
inch) knife score, completely penetrating the wall of a wide face, is 
made at a 45[deg] angle to the principal axis of the IBC, halfway 
between the bottom surface and the top level of the contents. The IBC 
must then be subjected to a uniformly distributed superimposed load 
equivalent to twice the maximum net mass. The load must be applied for 
at least five minutes. An IBC which is designed to be lifted from the 
top or the side must, after removal of the superimposed load, be lifted 
clear of the floor and maintained in that position for a period of five 
minutes.
    (d) Criterion for passing the test. The IBC passes the tear test if 
the cut does not propagate more than 25 percent of its original length.

[Amdt. 178-103, 59 FR 38074, July 26, 1994, as amended at 66 FR 45386, 
Aug. 28, 2001]



Sec.  178.819  Vibration test.

    (a) General. The vibration test must be conducted for the 
qualification of all rigid IBC design types. Flexible IBC design types 
must be capable of withstanding the vibration test.
    (b) Test method. (1) A sample IBC, selected at random, must be 
filled and closed as for shipment. IBCs intended for liquids may be 
tested using water as the filling material for the vibration test.
    (2) The sample IBC must be placed on a vibrating platform with a 
vertical or rotary double-amplitude (peak-to-peak displacement) of one 
inch. The IBC must be constrained horizontally to prevent it from 
falling off the platform, but must be left free to move vertically and 
bounce.
    (3) The test must be performed for one hour at a frequency that 
causes the package to be raised from the vibrating platform to such a 
degree that a piece of material of approximately 1.6-mm

[[Page 241]]

(0.063-inch) thickness (such as steel strapping or paperboard) can be 
passed between the bottom of the IBC and the platform. Other methods at 
least equally effective may be used (see Sec.  178.801(i)).
    (c) Criteria for passing the test. An IBC passes the vibration test 
if there is no rupture or leakage.

[Amdt. 178-103, 59 FR 38074, July 26, 1994, as amended by Amdt. 178-108, 
60 FR 40038, Aug. 4, 1995; Amdt. 178-110, 60 FR 49111, Sept. 21, 1995; 
66 FR 45386, Aug. 28, 2001; 75 FR 5397, Feb. 2, 2010]



                  Subpart P_Large Packagings Standards

    Source: 75 FR 5397, Feb. 2, 2010, unless otherwise noted.



Sec.  178.900  Purpose and scope.

    (a) This subpart prescribes requirements for Large Packaging 
intended for the transportation of hazardous materials. Standards for 
these packagings are based on the UN Recommendations.
    (b) Terms used in this subpart are defined in Sec.  171.8 of this 
subchapter.



Sec.  178.905  Large Packaging identification codes.

    Large packaging code designations consist of: two numerals specified 
in paragraph (a) of this section; followed by the capital letter(s) 
specified in paragraph (b) of this section.
    (a) Large packaging code number designations are as follows: 50 for 
rigid Large Packagings; or 51 for flexible Large Packagings.
    (b) Large Packagings code letter designations are as follows:
    (1) ``A'' means steel (all types and surface treatments).
    (2) ``B'' means aluminum.
    (3) ``C'' means natural wood.
    (4) ``D'' means plywood.
    (5) ``F'' means reconstituted wood.
    (6) ``G'' means fiberboard.
    (7) ``H'' means plastic.
    (8) ``M'' means paper, multiwall.
    (9) ``N'' means metal (other than steel or aluminum).



Sec.  178.910  Marking of Large Packagings.

    (a) The manufacturer must:
    (1) Mark every Large Packaging in a durable and clearly visible 
manner. The marking may be applied in a single line or in multiple lines 
provided the correct sequence is followed with the information required 
by this section, in letters, numerals, and symbols of at least 12 mm in 
height. This minimum marking size requirement applies only to large 
packages manufactured after January 1, 2014. The following information 
is required in the sequence presented:
    (i) Except as provided in Sec.  178.503(e)(1)(ii), the United 
Nations packaging symbol as illustrated in Sec.  178.503(e)(1)(i). For 
metal Large Packagings on which the marking is stamped or embossed, the 
capital letters ``UN'' may be applied instead of the symbol;
    (ii) The code number designating the Large Packaging design type 
according to Sec.  178.905. The letters ``T'' or ``W'' may follow the 
Large Packaging design type identification code on a Large Packaging. 
Large Salvage Packagings conforming to the requirements of subpart P of 
this part must be marked with the letter ``T''. Large Packagings must be 
marked with the letter ``W'' when the Large Packaging differs from the 
requirements in subpart P of this part, or is tested using methods other 
than those specified in this subpart, and is approved by the Associate 
Administrator in accordance with the provisions in Sec.  178.955;
    (iii) A capital letter identifying the performance standard under 
which the design type has been successfully tested, as follows:
    (A) X--for Large Packagings meeting Packing Groups I, II and III 
tests;
    (B) Y--for Large Packagings meeting Packing Groups II and III tests; 
and
    (C) Z--for Large Packagings meeting Packing Group III test.
    (iv) The month (designated numerically) and year (last two digits) 
of manufacture;
    (v) The country authorizing the allocation of the mark. The letters 
``USA'' indicate that the Large Packaging is manufactured and marked in 
the United States in compliance with the provisions of this subchapter.
    (vi) The name and address or symbol of the manufacturer or the 
approval

[[Page 242]]

agency certifying compliance with subpart P and subpart Q of this part. 
Symbols, if used, must be registered with the Associate Administrator.
    (vii) The stacking test load in kilograms (kg). For Large Packagings 
not designed for stacking the figure ``0'' must be shown.
    (viii) The maximum permissible gross mass or for flexible Large 
Packagings, the maximum net mass, in kg.
    (2) The following are examples of symbols and required markings:
    (i) For a steel Large Packaging suitable for stacking; stacking 
load: 2,500 kg; maximum gross mass: 1,000 kg.
[GRAPHIC] [TIFF OMITTED] TR02FE10.003

    (ii) For a plastic Large Packaging not suitable for stacking; 
maximum gross mass: 800 kg.
[GRAPHIC] [TIFF OMITTED] TR02FE10.004

    (iii) For a Flexible Large Packaging not suitable for stacking; 
maximum gross mass: 500 kg.
[GRAPHIC] [TIFF OMITTED] TR02FE10.005

    (iv) For a steel Large Salvage Packaging suitable for stacking; 
stacking load: 2,500 kg; maximum gross mass: 1,000 kg.
[GRAPHIC] [TIFF OMITTED] TR08JA15.003

    (b) All Large Packagings manufactured, repaired or remanufactured 
after January 1, 2015 must be marked with

[[Page 243]]

the symbol applicable to a Large Packaging designed for stacking or not 
designed for stacking, as appropriate. The symbol must be a square with 
each side being not less than 100 mm (3.9 inches) by 100 mm (3.9 inches) 
as measured from the corner printer marks shown on the following 
figures. Where dimensions are not specified, all features must be in 
approximate proportion to those shown.
[GRAPHIC] [TIFF OMITTED] TR07JA13.001

    (1) Transitional exception--A marking in conformance with the 
requirements of this paragraph in effect on December 31, 2014, may 
continue to be applied to all Large Packagings manufactured, repaired or 
remanufactured between January 1, 2015 and December 31, 2016.
    (2) For domestic transportation, a Large Packaging marked prior to 
January 1, 2017 and in conformance with the requirements of this 
paragraph in effect on December 31, 2014, may continue in service until 
the end of its useful life.

[75 FR 5397, Feb. 2, 2010, as amended at 75 FR 60339, Sept. 30, 2010; 78 
FR 1097, Jan. 7, 2013; 80 FR 1168, Jan. 8, 2015]



Sec.  178.915  General Large Packaging standards.

    (a) Each Large Packaging must be resistant to, or protected from, 
deterioration due to exposure to the external environment. Large 
Packagings intended for solid hazardous materials must be sift-proof and 
water-resistant.
    (b) All service equipment must be positioned or protected to 
minimize potential loss of contents resulting from damage during Large 
Packaging handling and transportation.
    (c) Each Large Packaging, including attachments and service and 
structural equipment, must be designed to withstand, without loss of 
hazardous materials, the internal pressure of the contents and the 
stresses of normal handling and transport. A Large Packaging intended 
for stacking must be designed for stacking. Any lifting or securing 
features of a Large Packaging must be sufficient strength to withstand 
the normal conditions of handling and transportation without gross 
distortion or failure and must be positioned so as to cause no undue 
stress in any part of the Large Packaging.
    (d) A Large Packaging consisting of packagings within a framework 
must be so constructed that the packaging is not damaged by the 
framework and is retained within the framework at all times.
    (e) Large Packaging design types must be constructed in such a way 
as to be bottom-lifted or top-lifted as specified in Sec. Sec.  178.970 
and 178.975.

[75 FR 5397, Feb. 2, 2010, as amended at 75 FR 60339, Sept. 30, 2010]



Sec.  178.920  Standards for metal Large Packagings.

    (a) The provisions in this section apply to metal Large Packagings 
intended to contain liquids and solids. Metal Large Packaging types are 
designated:
    (1) 50A steel
    (2) 50B aluminum
    (3) 50N metal (other than steel or aluminum)
    (b) Each Large Packaging must be made of suitable ductile metal 
materials. Welds must be made so as to

[[Page 244]]

maintain design type integrity of the receptacle under conditions 
normally incident to transportation. Low-temperature performance must be 
taken into account when appropriate.
    (c) The use of dissimilar metals must not result in deterioration 
that could affect the integrity of the Large Packaging.
    (d) Metal Large Packagings may not have a volumetric capacity 
greater than 3,000 L (793 gallons) and not less than 450 L (119 
gallons).



Sec.  178.925  Standards for rigid plastic Large Packagings.

    (a) The provisions in this section apply to rigid plastic Large 
Packagings intended to contain liquids and solids. Rigid plastic Large 
Packaging types are designated:
    (1) 50H rigid plastics.
    (2) [Reserved]
    (b) A rigid plastic Large Packaging must be manufactured from 
plastic material of known specifications and be of a strength relative 
to its capacity and to the service it is required to perform. In 
addition to conformance to Sec.  173.24 of this subchapter, plastic 
materials must be resistant to aging and to degradation caused by 
ultraviolet radiation.
    (1) If protection against ultraviolet radiation is necessary, it 
must be provided by the addition of a pigment or inhibiter such as 
carbon black to plastic materials. These additives must be compatible 
with the contents and remain effective throughout the life of the 
plastic Large Packaging body. Where use is made of carbon black, 
pigments or inhibitors, other than those used in the manufacture of the 
tested design type, retesting may be omitted if changes in the carbon 
black content, the pigment content or the inhibitor content do not 
adversely affect the physical properties of the material of 
construction.
    (2) Additives may be included in the composition of the plastic 
material to improve the resistance to aging or to serve other purposes, 
provided they do not adversely affect the physical or chemical 
properties of the material of construction.
    (3) No used material other than production residues or regrind from 
the same manufacturing process may be used in the manufacture of rigid 
plastic Large Packagings.
    (c) Rigid plastic Large Packagings:
    (1) May not have a volumetric capacity greater than 3,000 L (793 
gallons); and
    (2) May not have a volumetric capacity less than 450 L (119 
gallons).



Sec.  178.930  Standards for fiberboard Large Packagings.

    (a) The provisions in this section apply to fiberboard Large 
Packagings intended to contain solids. Rigid fiberboard Large Packaging 
types are designated:
    (1) 50G fiberboard
    (2) [Reserved]
    (b) Construction requirements for fiberboard Large Packagings. (1) 
Fiberboard Large Packagings must be constructed of strong, solid or 
double-faced corrugated fiberboard (single or multiwall) that is 
appropriate to the capacity of the Large Packagings and to their 
intended use. Water resistance of the outer surface must be such that 
the increase in mass, as determined in a test carried out over a period 
of 30 minutes by the Cobb method of determining water absorption, is not 
greater than 155 grams per square meter (0.0316 pounds per square 
foot)--see ISO 535 (E) (IBR, see Sec.  171.7 of this subchapter). 
Fiberboard must have proper bending qualities. Fiberboard must be cut, 
creased without cutting through any thickness of fiberboard, and slotted 
so as to permit assembly without cracking, surface breaks or undue 
bending. The fluting or corrugated fiberboard must be firmly glued to 
the facings.
    (i) The walls, including top and bottom, must have a minimum 
puncture resistance of 15 Joules (11 foot-pounds of energy) measured 
according to ISO 3036 (IBR, see Sec.  171.7 of this subchapter).
    (ii) Manufacturers' joints in the outer packaging of Large 
Packagings must be made with an appropriate overlap and be taped, glued, 
stitched with metal staples or fastened by other means at least equally 
effective. Where joints are made by gluing or taping, a water resistant 
adhesive must be used. Metal staples must pass completely through all 
pieces to be fastened and be formed or protected so that any inner

[[Page 245]]

liner cannot be abraded or punctured by them.
    (2) Integral and detachable pallets. (i) Any integral pallet base 
forming part of a Large Packaging or any detachable pallet must be 
suitable for mechanical handling with the Large Packaging filled to its 
maximum permissible gross mass.
    (ii) The pallet or integral base must be designed to avoid 
protrusions causing damage to the fiberboard Large Packagings in 
handling.
    (iii) The body must be secured to any detached pallet to ensure 
stability in handling and transport. Where a detachable pallet is used, 
its top surface must be free from protrusions that might damage the 
Large Packaging.
    (3) Strengthening devices, such as timber supports to increase 
stacking performance may be used but must be external to the liner.
    (4) The load-bearing surfaces of Large Packagings intended for 
stacking must be designed to distribute the load in a stable manner.
    (c) Fiberboard Large Packagings may not have a volumetric capacity 
greater than 3,000 L (793 gallons) and not less than 450 L (119 
gallons).

[75 FR 5397, Feb. 2, 2010, as amended at 75 FR 60339, Sept. 30, 2010]



Sec.  178.935  Standards for wooden Large Packagings.

    (a) The provisions in this section apply to wooden Large Packagings 
intended to contain solids. Wooden Large Packaging types are designated:
    (1) 50C natural wood.
    (2) 50D plywood.
    (3) 50F reconstituted wood.
    (b) Construction requirements for wooden Large Packagings are as 
follows:
    (1) The strength of the materials used and the method of 
construction must be appropriate to the capacity and intended use of the 
Large Packagings.
    (i) Natural wood used in the construction of Large Packagings must 
be well-seasoned, commercially dry and free from defects that would 
materially lessen the strength of any part of the Large Packagings. Each 
Large Packaging part must consist of uncut wood or a piece equivalent in 
strength and integrity. Large Packagings parts are equivalent to one 
piece when a suitable method of glued assembly is used (i.e., a 
Lindermann joint, tongue and groove joint, ship, lap or babbet joint; or 
butt joint with at least two corrugated metal fasteners at each joint, 
or when other methods at least equally effective are used).
    (ii) Plywood used in construction must be at least 3-ply. Plywood 
must be made of well-seasoned rotary cut, sliced or sawn veneer, 
commercially dry and free from defects that would materially lessen the 
strength of the Large Packagings. All adjacent piles must be glued with 
water resistant adhesive. Materials other than plywood may be used for 
the construction of the Large Packaging.
    (iii) Reconstituted wood used in the construction of Large 
Packagings must be water resistant reconstituted wood such as hardboard, 
particle board or other suitable type.
    (iv) Wooden Large Packagings must be firmly nailed or secured to 
corner posts or ends or be assembled by similar devices.
    (2) Integral and detachable pallets. (i) Any integral pallet base 
forming part of a Large Packaging, or any detachable pallet must be 
suitable for mechanical handling of a Large Packaging filled to its 
maximum permissible gross mass.
    (ii) The pallet or integral base must be designed to avoid 
protrusion that may cause damage to the Large Packaging in handling.
    (iii) The body must be secured to any detachable pallet to ensure 
stability in handling and transportation. Where a detachable pallet is 
used, its top surface must be free from protrusions that might damage 
the Large Packaging.
    (3) Strengthening devices, such as timber supports to increase 
stacking performance, may be used but must be external to the liner.
    (4) The load bearing surfaces of the Large Packaging must be 
designed to distribute loads in a stable manner.
    (c) Wooden Large Packagings:
    (1) May not have a volumetric capacity greater than 3,000 L (793 
gallons); and
    (2) May not have a volumetric capacity less than 450 L (119 
gallons).

[[Page 246]]



Sec.  178.940  Standards for flexible Large Packagings.

    (a) The provisions in this section apply to flexible Large 
Packagings intended to contain liquids and solids. Flexible Large 
Packagings types are designated:
    (1) 51H flexible plastics.
    (2) 51M flexible paper.
    (b) Construction requirements for flexible Large Packagings are as 
follows:
    (1) The strength of the material and the construction of the 
flexible Large Packagings must be appropriate to its capacity and its 
intended use.
    (2) All materials used in the construction of flexible Large 
Packagings of types 51M must, after complete immersion in water for not 
less than 24 hours, retain at least 85 percent of the tensile strength 
as measured originally on the material conditioned to equilibrium at 67 
percent relative humidity or less.
    (3) Seams must be stitched or formed by heat sealing, gluing or any 
equivalent method. All stitched seam-ends must be secured.
    (4) In addition to conformance with the requirements of Sec.  173.24 
of this subchapter, flexible Large Packaging must be resistant to aging 
and degradation caused by ultraviolet radiation.
    (5) For plastic flexible Large Packagings, if necessary, protection 
against ultraviolet radiation must be provided by the addition of 
pigments or inhibitors such as carbon black. These additives must be 
compatible with the contents and remain effective throughout the life of 
the Large Packaging. Where use is made of carbon black, pigments or 
inhibitors other than those used in the manufacture of the tested design 
type, retesting may be omitted if the carbon black content, the pigment 
content or the inhibitor content do not adversely affect the physical 
properties of the material of construction.
    (6) Additives may be included in the composition of the material of 
the Large Packaging to improve the resistance to aging, provided they do 
not adversely affect the physical or chemical properties of the 
material.
    (7) When flexible material Large Packagings are filled, the ratio of 
height to width must be no more than 2:1.
    (c) Flexible Large Packagings:
    (1) May not have a volumetric capacity greater than 3,000 L (793 
gallons);
    (2) May not have a volumetric capacity less than 56 L (15 gallons); 
and
    (3) Must be designed and tested to a capacity of not less than 50 kg 
(110 pounds).



                  Subpart Q_Testing of Large Packagings

    Source: 75 FR 5400, Feb. 2, 2010, unless otherwise noted.



Sec.  178.950  Purpose and scope.

    This subpart prescribes certain testing requirements for Large 
Packagings identified in subpart P of this part.



Sec.  178.955  General requirements.

    (a) General. The test procedures prescribed in this subpart are 
intended to ensure that Large Packagings containing hazardous materials 
can withstand normal conditions of transportation. These test procedures 
are considered minimum requirements. Each packaging must be manufactured 
and assembled so as to be capable of successfully passing the prescribed 
tests and to conform to the requirements of Sec.  173.24 of this 
subchapter while in transportation.
    (b) Responsibility. The Large Packaging manufacturer is responsible 
for ensuring each Large Packaging is capable of passing the prescribed 
tests. To the extent a Large Packaging's assembly function, including 
final closure, is performed by the person who offers a hazardous 
material for transportation, that person is responsible for performing 
the function in accordance with Sec. Sec.  173.22 and 178.2 of this 
subchapter.
    (c) Definitions. For the purpose of this subpart:
    (1) Large packaging design type refers to a Large Packaging which 
does not differ in structural design, size, material of construction and 
packing.
    (2) Design qualification testing is the performance of the drop, 
stacking, and bottom-lift or top-lift tests, as applicable, prescribed 
in this subpart, for each different Large Packaging design type,

[[Page 247]]

at the start of production of that packaging.
    (3) Periodic design requalification test is the performance of the 
applicable tests specified in paragraph (c)(2) of this section on a 
Large Packaging design type, to requalify the design for continued 
production at the frequency specified in paragraph (e) of this section.
    (4) Production inspection is the inspection, which must initially be 
conducted on each newly manufactured Large Packaging.
    (5) Different Large Packaging design type is one which differs from 
a previously qualified Large Packaging design type in structural design, 
size, material of construction, wall thickness, or manner of 
construction, but does not include:
    (i) A packaging which differs in surface treatment;
    (ii) A rigid plastic Large Packaging, which differs with regard to 
additives used to comply with Sec.  178.925(b) or Sec.  178.940(b);
    (iii) A packaging which differs only in its lesser external 
dimensions (i.e., height, width, length) provided materials of 
construction and material thickness or fabric weight remain the same;
    (6) Remanufactured Large Packaging is a metal or rigid Large 
Packaging that is produced as a UN type from a non-UN type or is 
converted from one UN design type to another UN design type. 
Remanufactured Large Packagings are subject to the same requirements of 
this subchapter that apply to new Large Packagings of the same type.
    (7) Reused Large Packaging is a Large Packaging intended to be 
refilled and has been examined and found free of defects affecting its 
ability to withstand the performance tests. See also Sec.  173.36(c) of 
this subchapter.
    (d) Design qualification testing. The packaging manufacturer must 
achieve successful test results for the design qualification testing at 
the start of production of each new or different Large Packaging design 
type. Application of the certification mark by the manufacturer 
constitutes certification that the Large Packaging design type passed 
the prescribed tests in this subpart.
    (e) Periodic design requalification testing. (1) Periodic design 
requalification must be conducted on each qualified Large Packaging 
design type if the manufacturer is to maintain authorization for 
continued production. The Large Packaging manufacturer must achieve 
successful test results for the periodic design requalification at 
sufficient frequency to ensure each packaging produced by the 
manufacturer is capable of passing the design qualification tests. 
Design requalification tests must be conducted at least once every 24 
months.
    (2) Changes in the frequency of design requalification testing 
specified in paragraph (e)(1) of this section are authorized if approved 
by the Associate Administrator.
    (f) Test samples. The manufacturer must conduct the design 
qualification and periodic tests prescribed in this subpart using random 
samples of packagings, in the numbers specified in the appropriate test 
section.
    (g) Selective testing. The selective testing of Large Packagings, 
which differ only in minor respects from a tested type is permitted as 
described in this section. For air transport, Large Packagings must 
comply with Sec.  173.27(c)(1) and (c)(2) of this subchapter. Variations 
are permitted in inner packagings of a tested Large Packaging, without 
further testing of the package, provided an equivalent level of 
performance is maintained and the methodology used to determine that the 
inner packaging, including closure, maintains an equivalent level of 
performance is documented in writing by the person certifying compliance 
with this paragraph and retained in accordance with paragraph (l) of 
this section. Permitted variations are as follows:
    (1) Inner packagings of equivalent or smaller size may be used 
provided--
    (i) The inner packagings are of similar design to the tested inner 
packagings (i.e., shape--round, rectangular, etc.);
    (ii) The material of construction of the inner packagings (glass, 
plastic, metal, etc.) offers resistance to impact and stacking forces 
equal to or greater than that of the originally tested inner packaging;

[[Page 248]]

    (iii) The inner packagings have the same or smaller openings and the 
closure is of similar design (e.g., screw cap, friction lid, etc.);
    (iv) Sufficient additional cushioning material is used to take up 
void spaces and to prevent significant movement of the inner packagings;
    (v) Inner packagings are oriented within the outer packaging in the 
same manner as in the tested package; and
    (vi) The gross mass of the package does not exceed that originally 
tested.
    (2) A lesser number of the tested inner packagings, or of the 
alternative types of inner packagings identified in paragraph (g)(1) of 
this section, may be used provided sufficient cushioning is added to 
fill void space(s) and to prevent significant movement of the inner 
packagings.
    (h) Approval of equivalent packagings. A Large Packaging differing 
from standards in subpart P of this part, or tested using methods other 
than those specified in this subpart, may be used if approved by the 
Associate Administrator. The Large Packagings and testing methods must 
be shown to have an equivalent level of safety.
    (i) Proof of compliance. In addition to the periodic design 
requalification testing intervals specified in paragraph (e) of this 
section, the Associate Administrator, or a designated representative, 
may at any time require demonstration of compliance by a manufacturer, 
through testing in accordance with this subpart, to ensure packagings 
meet the requirements of this subpart. As required by the Associate 
Administrator, or a designated representative, the manufacturer must 
either:
    (1) Conduct performance tests or have tests conducted by an 
independent testing facility, in accordance with this subpart; or
    (2) Make a sample Large Packaging available to the Associate 
Administrator, or a designated representative, for testing in accordance 
with this subpart.
    (j) Record retention. Following each design qualification test and 
each periodic retest on a Large Packaging, a test report must be 
prepared.
    (1) The test report must be maintained at each location where the 
packaging is manufactured, certified, and a design qualification test or 
periodic retest is conducted as follows:

------------------------------------------------------------------------
           Responsible party                         Duration
------------------------------------------------------------------------
Person manufacturing the packaging.....  As long as manufactured and two
                                          years thereafter.
Person performing design testing.......  Design test maintained for a
                                          single or composite packaging
                                          for six years after the test
                                          is successfully performed and
                                          for a combination packaging or
                                          packaging intended for
                                          infectious substances for
                                          seven years after the test is
                                          successfully performed.
Person performing periodic retesting...  Performance test maintained for
                                          a single or composite
                                          packaging for one year after
                                          the test is successfully
                                          performed and for a
                                          combination packaging or
                                          packaging intended for
                                          infectious substances for two
                                          years after the test is
                                          successfully performed.
------------------------------------------------------------------------

    (2) The test report must be made available to a user of a Large 
Packaging or a representative of the Department of Transportation upon 
request. The test report, at a minimum, must contain the following 
information:
    (i) Name and address of test facility;
    (ii) Name and address of applicant (where appropriate);
    (iii) A unique test report identification;
    (iv) Date of the test report;
    (v) Manufacturer of the packaging;
    (vi) Description of the packaging design type (e.g., dimensions, 
materials, closures, thickness, etc.), including methods of manufacture 
(e.g., blow molding) and which may include drawing(s) and/or 
photograph(s);
    (vii) Maximum capacity;
    (viii) Characteristics of test contents, e.g., viscosity and 
relative density for liquids and particle size for solids;
    (ix) Mathematical calculations performed to conduct and document 
testing (for example, drop height, test capacity, outage requirements, 
etc.);

[[Page 249]]

    (x) Test descriptions and results; and
    (xi) Signature with the name and title of signatory.

[75 FR 5400, Feb. 2, 2010, as amended at 75 FR 60339, Sept. 30, 2010; 76 
FR 3389, Jan. 19, 2011; 78 FR 14715, Mar. 7, 2013; 78 FR 65487, Oct. 31, 
2013; 81 FR 35545, June 2, 2016]



Sec.  178.960  Preparation of Large Packagings for testing.

    (a) Except as otherwise provided in this subchapter, each Large 
Packaging and package must be closed in preparation for testing and 
tests must be carried out in the same manner as if prepared for 
transportation, including inner packagings. All closures must be 
installed using proper techniques and torques.
    (b) For the drop and stacking test, inner receptacles must be filled 
to not less than 95 percent of maximum capacity (see Sec.  171.8 of this 
subchapter) in the case of solids and not less than 98 percent of 
maximum in the case of liquids. Bags must be filled to the maximum mass 
at which they may be used. For Large Packagings where the inner 
packagings are designed to carry liquids and solids, separate testing is 
required for both liquid and solid contents. The material to be 
transported in the packagings may be replaced by a non-hazardous 
material, except for chemical compatibility testing or where this would 
invalidate the results of the tests.
    (c) If the material to be transported is replaced for test purposes 
by a non-hazardous material, the material used must be of the same or 
higher specific gravity as the material to be carried, and its other 
physical properties (grain, size, viscosity) which might influence the 
results of the required tests must correspond as closely as possible to 
those of the hazardous material to be transported. It is permissible to 
use additives, such as bags of lead shot, to achieve the requisite total 
package mass, so long as they do not affect the test results.
    (d) Paper or fiberboard Large Packagings must be conditioned for at 
least 24 hours immediately prior to testing in an atmosphere 
maintained--
    (1) At 50 percent 2 percent relative humidity, 
and at a temperature of 23 [deg]C 2 [deg]C (73 
[deg]F 4 [deg]F). Average values should fall 
within these limits. Short-term fluctuations and measurement limitations 
may cause individual measurements to vary by up to 5 percent relative humidity without significant 
impairment of test reproducibility;
    (2) At 65 percent 2 percent relative humidity, 
and at a temperature of 20 [deg]C 2 [deg]C (68 
[deg]F 4 [deg]F), or 27 [deg]C 2 [deg]C (81 [deg]F 4 [deg]F). 
Average values should fall within these limits. Short-term fluctuations 
and measurement limitations may cause individual measurements to vary by 
up to 5 percent relative humidity without 
significant impairment of test reproducibility; or
    (3) For testing at periodic intervals only (i.e., other than initial 
design qualification testing), at ambient conditions.



Sec.  178.965  Drop test.

    (a) General. The drop test must be conducted for the qualification 
of all Large Packaging design types and performed periodically as 
specified in Sec.  178.955(e) of this subpart.
    (b) Special preparation for the drop test. Large Packagings must be 
filled in accordance with Sec.  178.960.
    (c) Conditioning. Rigid plastic Large Packagings and Large 
Packagings with plastic inner receptacles must be conditioned for 
testing by reducing the temperature of the packaging and its contents to 
-18 [deg]C (0 [deg]F) or lower. Test liquids must be kept in the liquid 
state, if necessary, by the addition of anti-freeze. Water/anti-freeze 
solutions with a minimum specific gravity of 0.95 for testing at -18 
[deg]C (0 [deg]F) or lower are considered acceptable test liquids, and 
may be considered equivalent to water for test purposes. Large 
Packagings conditioned in this way are not required to be conditioned in 
accordance with Sec.  178.960(d).
    (d) Test method. (1) Samples of all Large Packaging design types 
must be dropped onto a rigid, non-resilient, smooth, flat and horizontal 
surface. The point of impact must be the most vulnerable part of the 
base of the Large Packaging being tested. Following the drop, the Large 
Packaging must be restored to the upright position for observation.
    (2) Large Packaging design types with a capacity of 0.45 cubic 
meters

[[Page 250]]

(15.9 cubic feet) or less must be subject to an additional drop test.
    (e) Drop height. (1) For all Large Packagings, drop heights are 
specified as follows:
    (i) Packing group I: 1.8 m (5.9 feet)
    (ii) Packing group II: 1.2 m (3.9 feet)
    (iii) Packing group III: 0.8 m (2.6 feet)
    (2) Drop tests are to be performed with the solid or liquid to be 
transported or with a non-hazardous material having essentially the same 
physical characteristics.
    (3) The specific gravity and viscosity of a substituted non-
hazardous material used in the drop test for liquids must be similar to 
the hazardous material intended for transportation. Water also may be 
used for the liquid drop test under the following conditions:
    (i) Where the substances to be carried have a specific gravity not 
exceeding 1.2, the drop heights must be those specified in paragraph 
(e)(1) of this section for each Large Packaging design type; and
    (ii) Where the substances to be carried have a specific gravity 
exceeding 1.2, the drop heights must be as follows:
    (A) Packing Group I: SG x 1.5 m (4.9 feet).
    (B) Packing Group II: SG x 1.0 m (3.3 feet).
    (C) Packing Group III: SG x 0.67 m (2.2 feet).
    (f) Criteria for passing the test. For all Large Packaging design 
types there may be no loss of the filling substance from inner 
packaging(s) or article(s). Ruptures are not permitted in Large 
Packaging for articles of Class 1 which permit the spillage of loose 
explosive substances or articles from the Large Packaging. Where a Large 
Packaging undergoes a drop test, the sample passes the test if the 
entire contents are retained even if the closure is no longer sift-
proof.

[75 FR 5400, Feb. 2, 2010, as amended at 75 FR 60339, Sept. 30, 2010]



Sec.  178.970  Bottom lift test.

    (a) General. The bottom lift test must be conducted for the 
qualification of all Large Packagings design types designed to be lifted 
from the base.
    (b) Special preparation for the bottom lift test. The Large 
Packaging must be loaded to 1.25 times its maximum permissible gross 
mass, the load being evenly distributed.
    (c) Test method. All Large Packaging design types must be raised and 
lowered twice by a lift truck with the forks centrally positioned and 
spaced at three quarters of the dimension of the side of entry (unless 
the points of entry are fixed). The forks must penetrate to three 
quarters of the direction of entry.
    (d) Criteria for passing the test. For all Large Packagings design 
types designed to be lifted from the base, there may be no permanent 
deformation which renders the Large Packaging unsafe for transport and 
there must be no loss of contents.



Sec.  178.975  Top lift test.

    (a) General. The top lift test must be conducted for the 
qualification of all of Large Packagings design types to be lifted from 
the top or, for flexible Large Packagings, from the side.
    (b) Special preparation for the top lift test. (1) Metal and rigid 
plastic Large Packagings design types must be loaded to twice its 
maximum permissible gross mass.
    (2) Flexible Large Packaging design types must be filled to six 
times the maximum permissible gross mass, the load being evenly 
distributed.
    (c) Test method. (1) A Large Packaging must be lifted in the manner 
for which it is designed until clear of the floor and maintained in that 
position for a period of five minutes.
    (2) Rigid plastic Large Packaging design types must be:
    (i) Lifted by each pair of diagonally opposite lifting devices, so 
that the hoisting forces are applied vertically for a period of five 
minutes; and
    (ii) Lifted by each pair of diagonally opposite lifting devices so 
that the hoisting forces are applied towards the center at 45[deg] to 
the vertical, for a period of five minutes.
    (3) If not tested as indicated in paragraph (c)(1) of this section, 
a flexible Large Packaging design type must be tested as follows:
    (i) Fill the flexible Large Packaging to 95% full with a material 
representative of the product to be shipped.

[[Page 251]]

    (ii) Suspend the flexible Large Packaging by its lifting devices.
    (iii) Apply a constant downward force through a specially designed 
platen. The platen will be a minimum of 60 percent and a maximum of 80 
percent of the cross sectional surface area of the flexible Large 
Packaging.
    (iv) The combination of the mass of the filled flexible Large 
Packaging and the force applied through the platen must be a minimum of 
six times the maximum net mass of the flexible Large Packaging. The test 
must be conducted for a period of five minutes.
    (v) Other equally effective methods of top lift testing and 
preparation may be used with approval of the Associate Administrator.
    (d) Criterion for passing the test. For all Large Packagings design 
types designed to be lifted from the top, there may be no permanent 
deformation which renders the Large Packagings unsafe for transport and 
no loss of contents.



Sec.  178.980  Stacking test.

    (a) General. The stacking test must be conducted for the 
qualification of all Large Packagings design types intended to be 
stacked.
    (b) Special preparation for the stacking test. (1) All Large 
Packagings except flexible Large Packaging design types must be loaded 
to their maximum permissible gross mass.
    (2) Flexible Large Packagings must be filled to not less than 95 
percent of their capacity and to their maximum net mass, with the load 
being evenly distributed.
    (c) Test method. (1) All Large Packagings must be placed on their 
base on level, hard ground and subjected to a uniformly distributed 
superimposed test load for a period of at least five minutes (see 
paragraph (c)(5) of this section).
    (2) Fiberboard and wooden Large Packagings must be subjected to the 
test for 24 hours.
    (3) Rigid plastic Large Packagings which bear the stacking load must 
be subjected to the test for 28 days at 40 [deg]C (104 [deg]F).
    (4) For all Large Packagings, the load must be applied by one of the 
following methods:
    (i) One or more Large Packagings of the same type loaded to their 
maximum permissible gross mass and stacked on the test Large Packaging;
    (ii) The calculated superimposed test load weight loaded on either a 
flat plate or a reproduction of the base of the Large Packaging, which 
is stacked on the test Large Packaging; or
    (5) Calculation of superimposed test load. For all Large Packagings, 
the load to be placed on the Large Packaging must be 1.8 times the 
combined maximum permissible gross mass of the number of similar Large 
Packaging that may be stacked on top of the Large Packaging during 
transportation.
    (d) Periodic Retest. (1) The package must be tested in accordance 
with Sec.  178.980(c) of this subpart; or
    (2) The packaging may be tested using a dynamic compression testing 
machine. The test must be conducted at room temperature on an empty, 
unsealed packaging. The test sample must be centered on the bottom 
platen of the testing machine. The top platen must be lowered until it 
comes in contact with the test sample. Compression must be applied end 
to end. The speed of the compression tester must be one-half inch plus 
or minus one-fourth inch per minute. An initial preload of 50 pounds 
must be applied to ensure a definite contact between the test sample and 
the platens. The distance between the platens at this time must be 
recorded as zero deformation. The force ``A'' to then be applied must be 
calculated using the applicable formula:

Liquids: A = (1.8)(n-1) [w + (s x v x 8.3 x .98)] x 1.5;


or

Solids: A = (1.8)(n-1) [w + (s x v x 8.3 x .95)] x 1.5

Where:

A = applied load in pounds.
n = maximum number of Large Packagings that may be stacked during 
          transportation.
w = maximum weight of one empty container in pounds.
s = specific gravity (liquids) or density (solids) of the lading.
v = actual capacity of container (rated capacity + outage) in gallons.
and:

[[Page 252]]

8.3 corresponds to the weight in pounds of 1.0 gallon of water.
1.5 is a compensation factor that converts the static load of the 
          stacking test into a load suitable for dynamic compression 
          testing.

    (e) Criterion for passing the test. (1) For metal or rigid plastic 
Large Packagings, there may be no permanent deformation which renders 
the Large Packaging unsafe for transportation and no loss of contents.
    (2) For fiberboard or wooden Large Packagings, there may be no loss 
of contents and no permanent deformation that renders the whole Large 
Packaging, including the base pallet, unsafe for transportation.
    (3) For flexible Large Packagings, there may be no deterioration 
which renders the Large Packaging unsafe for transportation and no loss 
of contents.
    (4) For the dynamic compression test, a container passes the test 
if, after application of the required load, there is no permanent 
deformation to the Large Packaging which renders the whole Large 
Packaging; including the base pallet, unsafe for transportation; in no 
case may the maximum deflection exceed one inch.

[75 FR 5400, Feb. 2, 2010, as amended at 75 FR 60339, Sept. 30, 2010; 78 
FR 1097, Jan. 7, 2013]



Sec.  178.985  Vibration test.

    (a) General. All rigid Large Packaging and flexible Large Packaging 
design types must be capable of withstanding the vibration test.
    (b) Test method. (1) A sample Large Packaging, selected at random, 
must be filled and closed as for shipment. Large Packagings intended for 
liquids may be tested using water as the filling material for the 
vibration test.
    (2) The sample Large Packaging must be placed on a vibrating 
platform that has a vertical or rotary double-amplitude (peak-to-peak 
displacement) of one inch. The Large Packaging must be constrained 
horizontally to prevent it from falling off the platform, but must be 
left free to move vertically and bounce.
    (3) The sample Large Packaging must be placed on a vibrating 
platform that has a vertical double-amplitude (peak-to-peak 
displacement) of one inch. The Large Packaging must be constrained 
horizontally to prevent it from falling off the platform, but must be 
left free to move vertically and bounce.
    (4) The test must be performed for one hour at a frequency that 
causes the package to be raised from the vibrating platform to such a 
degree that a piece of material of approximately 1.6-mm (0.063-inch) in 
thickness (such as steel strapping or paperboard) can be passed between 
the bottom of the Large Packaging and the platform. Other methods at 
least equally effective may be used (see Sec.  178.801(i)).
    (c) Criterion for passing the test. A Large Packaging passes the 
vibration test if there is no rupture or leakage.

[75 FR 5400, Feb. 2, 2010, as amended at 75 FR 60339, Sept. 30, 2010]



               Subpart R_Flexible Bulk Container Standards

    Source: 78 FR 1097, Jan. 7, 2013, unless otherwise noted.



Sec.  178.1000  Purpose and scope.

    (a) This subpart prescribes requirements for Flexible Bulk 
Containers (FBCs) intended for the transportation of hazardous 
materials. FBC standards in this subpart are based on the UN Model 
Regulations.
    (b) Terms used in this subpart are defined in Sec.  171.8 of this 
subchapter.



Sec.  178.1005  Flexible Bulk Container identification code.

    The Flexible Bulk Container code designation is BK3.



Sec.  178.1010  Marking of Flexible Bulk Containers.

    (a) The manufacturer must:
    (1) Mark every Flexible Bulk Container in a durable and clearly 
visible manner. The marking may be applied in a single line or in 
multiple lines provided the correct sequence is followed with the 
information required by this section. The following information is 
required in the sequence presented:
    (i) Except as provided in Sec.  178.503(e)(1)(ii), the United 
Nations packaging symbol as illustrated in Sec.  178.503(e)(1)(i).
    (ii) The code number designating the Flexible Bulk Container design 
type

[[Page 253]]

according to Sec.  178.1005. The letter ``W'' must follow the Flexible 
Bulk Container design type identification code on a Flexible Bulk 
Container when the Flexible Bulk Container differs from the requirements 
in subpart R of this part, or is tested using methods other than those 
specified in this subpart, and is approved by the Associate 
Administrator in accordance with Sec.  178.1035;
    (iii) The capital letter Z identifying that the Flexible Bulk 
Container meets Packing Group III performance standard under which the 
design type has been successfully tested.
    (iv) The month (designated numerically) and year (last two digits) 
of manufacture;
    (v) The country authorizing the allocation of the mark. The letters 
``USA'' indicate that the Flexible Bulk Container is manufactured and 
marked in the United States in compliance with the provisions of this 
subchapter.
    (vi) The name and address or symbol of the manufacturer or the 
approval agency certifying compliance with subpart R and subpart S of 
this part. Symbols, if used, must be registered with the Associate 
Administrator.
    (vii) The stacking test load in kilograms (kg). For Flexible Bulk 
Containers not designed for stacking the figure ``0'' must be shown.
    (viii) The maximum permissible gross mass in kg.
    (2) The following is an example of symbols and required markings for 
a Flexible Bulk container suitable for stacking; stacking load: 1,000 
kg; maximum gross mass: 2,500 kg.
[GRAPHIC] [TIFF OMITTED] TR07JA13.002

    (b) [Reserved]



Sec.  178.1015  General Flexible Bulk Container standards.

    (a) Each Flexible Bulk Containers must be sift-proof and completely 
closed during transport to prevent the release of contents and 
waterproof.
    (b) Parts of the Flexible Bulk Container that are in direct contact 
with hazardous materials:
    (1) Must not be affected or significantly weakened by those 
hazardous materials.
    (2) Must not cause a dangerous effect with the dangerous goods 
(e.g., catalyzing a reaction or reacting with the hazardous materials).
    (3) Must not allow permeation of the hazardous materials that could 
constitute a danger under conditions normally incident to 
transportation.
    (c) Filling and discharge devices must be so constructed as to be 
protected against damage during transport and handling. The filling and 
discharge devices must be capable of being secured against unintended 
opening.
    (d) Slings of the Flexible Bulk Container, if fitted with such, must 
withstand pressure and dynamic forces which can be expected under 
conditions normally incident to transportation.
    (e) Handling devices must be strong enough to withstand repeated 
use.
    (f) A venting device must be fitted to Flexible Bulk Containers 
intended to transport hazardous materials that may develop dangerous 
accumulation of gases within the Flexible Bulk Container. Any venting 
device must be designed so that external foreign substances or the 
ingress of water are prevented from entering the Flexible Bulk Container 
through the venting device under conditions normally incident to 
transportation.

[78 FR 1097, Jan. 7, 2013, as amended at 82 FR 15896, Mar. 30, 2017]

[[Page 254]]



Sec.  178.1020  Period of use for transportation of hazardous materials in 
Flexible Bulk Containers.

    The use of Flexible Bulk Containers for the transport of hazardous 
materials is permitted for a period of time not to exceed two years from 
the date of manufacture of the Flexible Bulk Container.



              Subpart S_Testing of Flexible Bulk Containers

    Source: 78 FR 1098, Jan. 7, 2013, unless otherwise noted.



Sec.  178.1030  Purpose and scope.

    This subpart prescribes certain testing requirements for Flexible 
Bulk Containers identified in subpart R of this part.



Sec.  178.1035  General requirements.

    (a) General. The test procedures prescribed in this subpart are 
intended to ensure that Flexible Bulk Containers containing hazardous 
materials can withstand normal conditions of transportation. These test 
procedures are considered minimum requirements. Each packaging must be 
manufactured and assembled so as to be capable of successfully passing 
the prescribed tests and to conform to the requirements of Sec.  173.24 
of this subchapter while in transportation.
    (b) Responsibility. The Flexible Bulk Container manufacturer is 
responsible for ensuring each Flexible Bulk Containers is capable of 
passing the prescribed tests. To the extent a Flexible Bulk Container's 
assembly function, including final closure, is performed by the person 
who offers a hazardous material for transportation, that person is 
responsible for performing the function in accordance with Sec. Sec.  
173.22 and 178.2 of this subchapter.
    (c) Definitions. For the purpose of this subpart:
    (1) Flexible Bulk Container design type refers to a Flexible Bulk 
Container that does not differ in structural design, size, material of 
construction and packing.
    (2) Design qualification testing is the performance of the drop, 
topple, righting, tear, stacking, and top-lift tests prescribed in this 
subpart, for each different Flexible Bulk Container design type, at the 
start of production of that packaging.
    (3) Periodic design requalification test is the performance of the 
applicable tests specified in paragraph (c)(2) of this section on a 
Flexible Bulk Container design type, to requalify the design for 
continued production at the frequency specified in paragraph (e) of this 
section.
    (4) Production inspection is the inspection that must initially be 
conducted on each newly manufactured Flexible Bulk Container.
    (5) Different Flexible Bulk Container design type is one that 
differs from a previously qualified Flexible Bulk Container design type 
in structural design, size, material of construction, wall thickness, or 
manner of construction, but does not include:
    (i) A packaging that differs in surface treatment;
    (ii) A packaging that differs only in its lesser external dimensions 
(i.e., height, width, length) provided materials of construction and 
material thickness or fabric weight remain the same;
    (d) Design qualification testing. The packaging manufacturer must 
achieve successful test results for the design qualification testing at 
the start of production of each new or different Flexible Bulk Container 
design type. Application of the certification mark by the manufacturer 
constitutes certification that the Flexible Bulk Container design type 
passed the prescribed tests in this subpart.
    (e) Periodic design requalification testing. (1) Periodic design 
requalification must be conducted on each qualified Flexible Bulk 
Container design type if the manufacturer is to maintain authorization 
for continued production. The Flexible Bulk Container manufacturer must 
achieve successful test results for the periodic design requalification 
at sufficient frequency to ensure each packaging produced by the 
manufacturer is capable of passing the design qualification tests. 
Design requalification tests must be conducted at least once every 24 
months.
    (2) Changes in the frequency of design requalification testing 
specified in

[[Page 255]]

paragraph (e)(1) of this section are authorized if approved by the 
Associate Administrator.
    (f) Test samples. The manufacturer must conduct the design 
qualification and periodic tests prescribed in this subpart using random 
samples of packagings, in the numbers specified in the appropriate test 
section.
    (g) Proof of compliance. In addition to the periodic design 
requalification testing intervals specified in paragraph (e) of this 
section, the Associate Administrator, or a designated representative, 
may at any time require demonstration of compliance by a manufacturer, 
through testing in accordance with this subpart, to ensure packagings 
meet the requirements of this subpart. As required by the Associate 
Administrator, or a designated representative, the manufacturer must 
either:
    (1) Conduct performance tests or have tests conducted by an 
independent testing facility, in accordance with this subpart; or
    (2) Make a sample Flexible Bulk Container available to the Associate 
Administrator, or a designated representative, for testing in accordance 
with this subpart.
    (h) Record retention. Following each design qualification test and 
each periodic retest on a Flexible Bulk Container, a test report must be 
prepared. The test report must be maintained at each location where the 
Flexible Bulk Container is manufactured and each location where the 
design qualification tests are conducted, for as long as the Flexible 
Bulk Container is produced and for at least two years thereafter, and at 
each location where the periodic retests are conducted until such tests 
are successfully performed again and a new test report produced. In 
addition, a copy of the test report must be maintained by a person 
certifying compliance with this part. The test report must be made 
available to a user of a Flexible Bulk Container or a representative of 
the Department upon request. The test report, at a minimum, must contain 
the following information:
    (1) Name and address of test facility;
    (2) Name and address of applicant (where appropriate);
    (3) A unique test report identification;
    (4) Date of the test report;
    (5) Manufacturer of the packaging;
    (6) Description of the flexible bulk container design type (e.g., 
dimensions materials, closures, thickness, etc.), including methods of 
manufacture (e.g., blow molding) and which may include drawing(s) and/or 
photograph(s);
    (7) Maximum capacity;
    (8) Characteristics of test contents (e.g., particle size for 
solids);
    (9) Mathematical calculations performed to conduct and document 
testing (e.g., drop height, test capacity, outage requirements, etc.);
    (10) Test descriptions and results; and
    (11) Signature with the name and title of signatory.



Sec.  178.1040  Preparation of Flexible Bulk Containers for testing.

    (a) Except as otherwise provided in this subchapter, each Flexible 
Bulk Container must be closed in preparation for testing and tests must 
be carried out in the same manner as if prepared for transportation. All 
closures must be installed using proper techniques and torques.
    (b) If the material to be transported is replaced for test purposes 
by a non-hazardous material, the physical properties (grain, size, 
viscosity) of the replacement material used that might influence the 
results of the required tests must correspond as closely as possible to 
those of the hazardous material to be transported. It is permissible to 
use additives, such as bags of lead shot, to achieve the requisite total 
package mass, so long as they do not affect the test results.



Sec.  178.1045  Drop test.

    (a) General. The drop test must be conducted for the qualification 
of all Flexible Bulk Container design types and performed periodically 
as specified in Sec.  178.1035(e) of this subpart.
    (b) Special preparation for the drop test. Flexible Bulk Containers 
must be filled to their maximum permissible gross mass.
    (c) Test method. (1) A sample of all Flexible Bulk Container design 
types must be dropped onto a rigid, non-resilient, smooth, flat and 
horizontal surface. This test surface must be large enough to be 
immovable during testing

[[Page 256]]

and sufficiently large enough to ensure that the test Flexible Bulk 
Container falls entirely upon the surface. The test surface must be kept 
free from local defects capable of influencing the test results.
    (2) Following the drop, the Flexible Bulk Container must be restored 
to the upright position for observation.
    (d) Drop height. (1) For all Flexible Bulk Containers, drop heights 
are specified as follows: Packing group III: 0.8 m (2.6 feet)
    (2) Drop tests are to be performed with the solid to be transported 
or with a non-hazardous material having essentially the same physical 
characteristics.
    (e) Criteria for passing the test. For all Flexible Bulk Container 
design types there may be no loss of the filling substance. However a 
slight discharge (e.g., from closures or stitch holes) upon impact is 
not considered a failure of the Flexible Bulk Container provided that no 
further leakage occurs after the container has been restored to the 
upright position.



Sec.  178.1050  Top lift test.

    (a) General. The top lift test must be conducted for the 
qualification of all of Flexible Bulk Containers design types to be 
lifted from the top.
    (b) Special preparation for the top lift test. Flexible Bulk 
Container design types must be filled to six times the maximum 
permissible gross mass, the load being evenly distributed.
    (c) Test method. (1) A Flexible Bulk Container must be lifted in the 
manner for which it is designed until clear of the floor and maintained 
in that position for a period of five minutes.
    (2) If not tested as indicated in paragraph (c)(1) of this section, 
a Flexible Bulk Container design type must be tested as follows:
    (i) Fill the Flexible Bulk Container to 95% full with a material 
representative of the product to be shipped.
    (ii) Suspend the Flexible Bulk Container by its lifting devices.
    (iii) Apply a constant downward force through a specially designed 
platen. The platen will be a minimum of 60 percent and a maximum of 80 
percent of the cross sectional surface area of the Flexible Bulk 
Container.
    (iv) The combination of the mass of the filled Flexible Bulk 
Container and the force applied through the platen must be a minimum of 
six times the maximum net mass of the Flexible Bulk Container. The test 
must be conducted for a period of five minutes.
    (v) Other equally effective methods of top lift testing and 
preparation may be used with approval of the Associate Administrator.
    (d) Criteria for passing the test. For all Flexible Bulk Containers 
design types designed to be lifted from the top, there may be no damage 
to the Flexible Bulk Container or its lifting devices that renders the 
Flexible Bulk Container unsafe for transport, and no loss of contents.



Sec.  178.1055  Stacking test.

    (a) General. The stacking test must be conducted for the 
qualification of all Flexible Bulk Containers design types.
    (b) Special preparation for the stacking test. All Flexible Bulk 
Containers design types must be loaded to their maximum permissible 
gross mass.
    (c) Test method. (1) All Flexible Bulk Containers must be placed on 
their base on level, hard ground and subjected to a uniformly 
distributed superimposed test load that is four times the design type 
maximum gross weight for a period of at least twenty-four hours.
    (2) For all Flexible Bulk Containers, the load must be applied by 
one of the following methods:
    (i) Four Flexible Bulk Containers of the same type loaded to their 
maximum permissible gross mass and stacked on the test Flexible Bulk 
Container;
    (ii) The calculated superimposed test load weight loaded on either a 
flat plate or a reproduction of the base of the Flexible Bulk Container, 
which is stacked on the test Flexible Bulk Container.
    (d) Criteria for passing the test. There may be no deterioration 
that renders the Flexible Bulk Container unsafe for transportation and 
no loss of contents during the test or after removal of the test load.

[[Page 257]]



Sec.  178.1060  Topple test.

    (a) General. The topple test must be conducted for the qualification 
of all Flexible Bulk Containers design types.
    (b) Special preparation for the topple test. Flexible Bulk Container 
design types must be filled to their maximum permissible gross mass, the 
load being evenly distributed.
    (c) Test method. Samples of all Flexible Bulk Container design types 
must be toppled onto any part of its top by lifting the side furthest 
from the drop edge upon a rigid, non-resilient, smooth, flat and 
horizontal surface. This test surface must be large enough to be 
immovable during testing and sufficiently large enough to ensure that 
the test Flexible Bulk Container falls entirely upon the surface. The 
test surface must be kept free from local defects capable of influencing 
the test results.
    (d) Topple height. (1) For all Flexible Bulk Containers, topple 
heights are specified as follows: Packing group III: 0.8 m (2.6 feet).
    (e) Criterion for passing the test. For all Flexible Bulk Container 
design types there may be no loss of the filling substance. However a 
slight discharge (e.g., from closures or stitch holes) upon impact is 
not considered a failure of the Flexible Bulk Container.



Sec.  178.1065  Righting test.

    (a) General. The righting test must be conducted for the 
qualification of all Flexible Bulk Containers design types designed to 
be lifted from the top or side.
    (b) Special preparation for the righting test. Flexible Bulk 
Container design types must be filled to not less than 95% of their 
capacity and to their maximum permissible gross mass, the load being 
evenly distributed.
    (c) Test method. A sample Flexible Bulk Container design type must 
be tested; the Flexible Bulk Container should start lying on its side 
and then must be lifted at a speed of at least 0.1m/s (0.328 ft/s) to an 
upright position clear of the floor, by no more than half of the lifting 
devices.
    (d) Criterion for passing the test. For all Flexible Bulk Container 
design types there must be no damage that renders the Flexible Bulk 
Container unsafe for transport or handling.



Sec.  178.1070  Tear test.

    (a) General. The tear test must be conducted for the qualification 
of all of Flexible Bulk Containers design types.
    (b) Special preparation for the tear test. Flexible Bulk Container 
design types must be filled its maximum permissible gross mass, the load 
being evenly distributed.
    (c) Test method. (1) A Flexible Bulk Container design type must be 
placed on the ground and a 300 mm (11.9 in) cut shall be made. This 300 
mm (11.9 in) cut must:
    (i) Completely penetrate all layers of the Flexible Bulk Container 
on a wall with a wide face.
    (ii) Be made at a 45[deg] angle to the principal axis of the 
Flexible Bulk Container, halfway between the bottom surface and the top 
level of the contents.
    (2) The Flexible Bulk Container after being cut according to the 
provisions of Sec.  178.1070(c)(1), must be subjected to a uniformly 
distributed superimposed load equivalent to twice the maximum gross mass 
of the package. This load must be applied for at least fifteen minutes. 
Flexible Bulk Containers that are designed to be lifted from the top or 
the side must, after removal of the superimposed load, be lifted clear 
of the floor and maintained in that position for a period of fifteen 
minutes.
    (d) Criterion for passing the test. For all Flexible Bulk Container 
design types, the cut must not spread more than an additional 25% of its 
original length.



[[Page 258]]

            Appendix A to Part 178--Specifications for Steel

                                                     Table 1
 [Open-hearth, basic oxygen, or electric steel of uniform quality. The following chemical composition limits are
                                            based on ladle analysis:]
----------------------------------------------------------------------------------------------------------------
                                                      Chemical composition, percent-ladle analysis
             Designation              --------------------------------------------------------------------------
                                             Grade 1 \1\             Grade 2 \1 2\           Grade 3 \2 4 5\
----------------------------------------------------------------------------------------------------------------
Carbon...............................  0.10/0.20..............  0.24 maximum...........  0.22 maximum.
Manganese............................  1.10/1.60..............  0.50/1.00..............  1.25 maximum.
Phosphorus, maximum..................  0.04...................  0.04...................  0.045.\6\
Sulfur, maximum......................  0.05...................  0.05...................  0.05.
Silicon..............................  0.15/0.30..............  0.30 maximum...........  .......................
Copper, maximum......................  0.40...................  .......................  .......................
Columbium............................  .......................  0.01/0.04..............  .......................
Heat treatment authorized............  (\3\)..................  (\3\)..................  (\3\).
Maximum stress (p.s.i.)..............  35,000.................  35,000.................  35,000.
----------------------------------------------------------------------------------------------------------------
\1\ Addition of other elements to obtain alloying effect is not authorized.
\2\ Ferritic grain size 6 or finer according to ASTM E 112-96 (IBR, see Sec.   171.7 of this subchapter).
\3\ Any suitable heat treatment in excess of 1,100 [deg]F., except that liquid quenching is not permitted.
\4\ Other alloying elements may be added and shall be reported.
\5\ For compositions with a maximum carbon content of 0.15 percent of ladle analysis, the maximum limit for
  manganese on ladle analysis may be 1.40 percent.
\6\ Rephosphorized Grade 3 steels containing no more than 0.15 percent phosphorus are permitted if carbon
  content does not exceed 0.15 percent and manganese does not exceed 1 percent.


                                            Check Analysis Tolerances
     [A heat of steel made under any of the above grades, the ladle analysis of which is slightly out of the
            specified range is acceptable if the check analysis is within the following variations:]
----------------------------------------------------------------------------------------------------------------
                                                                                           Tolerance (percent)
                                                                                          over the maximum limit
                                                                                           or under the minimum
                                                                                                  limit
                    Element                       Limit or maximum specified (percent)  ------------------------
                                                                                            Under        Over
                                                                                           minimum      maximum
                                                                                            limit        limit
----------------------------------------------------------------------------------------------------------------
Carbon.........................................  To 0.15 inclusive.....................        0.02         0.03
                                                 Over 0.15 to 0.40 inclusive...........        0.03         0.04
Manganese......................................  To 0.60 inclusive.....................        0.03         0.03
                                                 Over 0.60 to 1.15 inclusive...........        0.04         0.04
                                                 Over 1.15 to 2.50 inclusive...........        0.05         0.05
Phosphorus \7\.................................  All ranges............................  ...........        0.01
Sulfur.........................................  All ranges............................  ...........        0.01
Silicon........................................  To 0.30 inclusive.....................        0.02         0.03
                                                 Over 0.30 to 1.00 inclusive...........        0.05         0.05
Copper.........................................  To 1.00 inclusive.....................        0.03         0.03
                                                 Over 1.00 to 2.00 inclusive...........        0.05         0.05
Nickel.........................................  To 1.00 inclusive.....................        0.03         0.03
                                                 Over 1.00 to 2.00 inclusive...........        0.05         0.05
Chromium.......................................  To 0.90 inclusive.....................        0.03         0.03
                                                 Over 0.90 to 2.10 inclusive...........        0.05         0.05
Molybdenum.....................................  To 0.20 inclusive.....................        0.01         0.01
                                                 Over 0.20 to 0.40 inclusive...........        0.02         0.02
Zirconium......................................  All ranges............................        0.01         0.05
Columbium......................................  To 0.04 inclusive.....................        0.005        0.01
Aluminum.......................................  Over 0.10 to 0.20 inclusive...........        0.04         0.04
                                                 Over 0.20 to 0.30 inclusive...........        0.05         0.05
----------------------------------------------------------------------------------------------------------------
\7\ Rephosphorized steels not subject to check analysis for phosphorus.


[Amdt. 178-3, 34 FR 12283, July 25, 1969; 34 FR 12593, Aug. 1, 1969, as 
amended by Amdt. 178-64, 45 FR 81573, Dec. 11, 1980; Amdt. 178-97, 55 FR 
52728, Dec. 21, 1990; 68 FR 75758, Dec. 31, 2003]



   Sec. Appendix B to Part 178--Alternative Leakproofness Test Methods

    In addition to the method prescribed in Sec.  178.604 of this 
subchapter, the following leakproofness test methods are authorized:
    (1) Helium test. The packaging must be filled with at least 1 L 
inert helium gas, air tight closed, and placed in a testing chamber. The 
testing chamber must be evacuated down to a pressure of 5 kPa which 
equals an over-pressure inside the packaging of 95 kPa.

[[Page 259]]

The air in the testing chamber must be analyzed for traces of helium gas 
by means of a mass spectrograph. The test must be conducted for a period 
of time sufficient to evacuate the chamber and to determine if there is 
leakage into or out of the packaging. If helium gas is detected, the 
leaking packaging must be automatically separated from non-leaking drums 
and the leaking area determined according to the method prescribed in 
Sec.  178.604(d) of this subchapter. A packaging passes the test if 
there is no leakage of helium.
    (2) Pressure differential test. The packaging shall be restrained 
while either pressure or a vacuum is applied internally. The packaging 
must be pressurized to the pressure required by Sec.  178.604(e) of this 
subchapter for the appropriate packing group. The method of restraint 
must not affect the results of the test. The test must be conducted for 
a period of time sufficient to appropriately pressurize or evacuate the 
interior of the packaging and to determine if there is leakage into or 
out of the packaging. A packaging passes the pressure differential test 
if there is no change in measured internal pressure.
    (3) Solution over seams. The packaging must be restrained while an 
internal air pressure is applied; the method of restraint may not affect 
the results of the test. The exterior surface of all seams and welds 
must be coated with a solution of soap suds or a water and oil mixture. 
The test must be conducted for a period of time sufficient to pressurize 
the interior of the packaging to the specified air pressure and to 
determine if there is leakage of air from the packaging. A packaging 
passes the test if there is no leakage of air from the packaging.
    (4) Solution over partial seams test. For other than design 
qualification testing, the following test may be used for metal drums: 
The packaging must be restrained while an internal air pressure of 48 
kPa (7.0 psig) is applied; the method of restraint may not affect the 
results of the test. The packaging must be coated with a soap solution 
over the entire side seam and a distance of not less than eight inches 
on each side of the side seam along the chime seam(s). The test must be 
conducted for a period of time sufficient to pressurize the interior of 
the packaging to the specified air pressure and to determine if there is 
leakage of air from the packaging. A packaging passes the test if there 
is no leakage of air from the packaging. Chime cuts must be made on the 
initial drum at the beginning of each production run and on the initial 
drum after any adjustment to the chime seamer. Chime cuts must be 
maintained on file in date order for not less than six months and be 
made available to a representative of the Department of Transportation 
on request.

[Amdt. 178-97, 55 FR 52728, Dec. 21, 1990, as amended at 56 FR 66287, 
Dec. 20, 1991; 57 FR 45466, Oct. 1, 1992]



 Sec. Appendix C to Part 178--Nominal and Minimum Thicknesses of Steel 
                           Drums and Jerricans

    For each listed packaging capacity, the following table compares the 
ISO 3574 (IBR, see Sec.  171.7 of this subchapter) nominal thickness 
with the corresponding ISO 3574 minimum thickness.

------------------------------------------------------------------------
                                                   ISO     Corresponding
             Maximum capacity (L)                nominal    ISO minimum
                                                  (mm)          (mm)
------------------------------------------------------------------------
20...........................................         0.7          0.63
30...........................................         0.8          0.73
40...........................................         0.8          0.73
60...........................................         1.0          0.92
120..........................................         1.0          0.92
220..........................................         1.0          0.92
450..........................................         1.9          1.77
------------------------------------------------------------------------


[Amdt. 178-106, 59 FR 67522, Dec. 29, 1994, as amended at 68 FR 75758, 
Dec. 31, 2003]



          Sec. Appendix D to Part 178--Thermal Resistance Test

    1. Scope. This test method evaluates the thermal resistance 
capabilities of a compressed oxygen generator and the outer packaging 
for a cylinder of compressed oxygen or other oxidizing gas and an oxygen 
generator. When exposed to a temperature of 205 [deg]C (400 [deg]F) for 
a period of not less than three hours, the outer surface of the cylinder 
may not exceed a temperature of 93 [deg]C (199 [deg]F) and the oxygen 
generator must not actuate.
    2. Apparatus.
    2.1 Test Oven. The oven must be large enough in size to fully house 
the test outer package without clearance problems. The test oven must be 
capable of maintaining a minimum steady state temperature of 205 [deg]C 
(400 [deg]F).
    2.2 Thermocouples. At least three thermocouples must be used to 
monitor the temperature inside the oven and an additional three 
thermocouples must be used to monitor the temperature of the cylinder. 
The thermocouples must be \1/16\ inch, ceramic packed, metal sheathed, 
type K (Chromel-Alumel), grounded junction with a nominal 30 American 
wire gauge (AWG) size conductor. The thermocouples measuring the 
temperature inside the oven must be placed at varying heights to ensure 
even temperature and proper heat-soak conditions. For

[[Page 260]]

the thermocouples measuring the temperature of the cylinder: (1) Two of 
them must be placed on the outer cylinder side wall at approximately 2 
inches (5 cm) from the top and bottom shoulders of the cylinder; and (2) 
one must be placed on the cylinder valve body near the pressure relief 
device. Alternatively, the thermocouples may be replaced with other 
devices such as a remote temperature sensor, metal fuse on the valve, or 
coated wax, provided the device is tested and the test report is 
retained for verification. Under this alternative, it is permissible to 
record the highest temperature to which the cylinder is subjected 
instead of temperature measurements in intervals of not more than five 
(5) minutes.
    2.3 Instrumentation. A calibrated recording device or a computerized 
data acquisition system with an appropriate range should be provided to 
measure and record the outputs of the thermocouples.
    3. Test Specimen.
    3.1 Specimen Configuration. Each outer package material type and 
design must be tested, including any features such as handles, latches, 
fastening systems, etc., that may compromise the ability of the outer 
package to provide thermal protection.
    3.2 Test Specimen Mounting. The tested outer package must be 
supported at the four corners using fire brick or other suitable means. 
The bottom surface of the outer package must be exposed to allow 
exposure to heat.
    4. Preparation for Testing.
    4.1 It is recommended that the cylinder be closed at ambient 
temperature and configured as when filled with a valve and pressure 
relief device. The oxygen generator must be filled with an oxidizing 
agent and may be tested with or without packaging.
    4.2 Place the package or generator onto supporting bricks or a stand 
inside the test oven in such a manner to ensure even temperature flow.
    5. Test Procedure.
    5.1 Close oven door and check for proper reading on thermocouples.
    5.2 Raise the temperature of the oven to a minimum temperature of 
205 [deg]C 2 [deg]C (400 [deg]F 5 [deg]F). Maintain a minimum oven temperature of 205 
[deg]C 2 [deg]C (400 [deg]F 5 [deg]F) for at least three hours. Exposure time begins 
when the oven steady state temperature reaches a minimum of 205 [deg]C 
2 [deg]C (400 [deg]F 5 
[deg]F).
    5.3 At the conclusion of the three-hour period, the outer package 
may be removed from the oven and allowed to cool naturally.
    6. Recordkeeping.
    6.1 Record a complete description of the material being tested, 
including the manufacturer, size of cylinder, etc.
    6.2 Record any observations regarding the behavior of the test 
specimen during exposure, such as smoke production, delamination, resin 
ignition, and time of occurrence of each event.
    6.3 Record the temperature and time history of the cylinder 
temperature during the entire test for each thermocouple location. 
Temperature measurements must be recorded at intervals of not more than 
five (5) minutes. Record the maximum temperatures achieved at all three 
thermocouple locations and the corresponding time.
    7. Requirements.
    7.1 For a cylinder, the outer package must provide adequate 
protection such that the outer surface of the cylinder and valve does 
not exceed a temperature of 93 [deg]C (199 [deg]F) at any of the three 
points where the thermocouples are located.
    7.2 For an oxygen generator, the generator must not actuate.

[72 FR 4457, Jan. 31, 2008, as amended at 72 FR 55099, Sept. 28, 2007]



     Sec. Appendix E to Part 178--Flame Penetration Resistance Test

    (a) Criteria for Acceptance. (1) At least three specimens of the 
outer packaging materials must be tested;
    (2) Each test must be conducted on a flat 16 inch x 24 inch test 
specimen mounted in the horizontal ceiling position of the test 
apparatus to represent the outer packaging design;
    (3) Testing must be conducted on all design features (latches, 
seams, hinges, etc.) affecting the ability of the outer packaging to 
safely prevent the passage of fire in the horizontal ceiling position; 
and
    (4) There must be no flame penetration of any specimen within 5 
minutes after application of the flame source and the maximum allowable 
temperature at a point 4 inches above the test specimen, centered over 
the burner cone, must not exceed 205 [deg]C (400 [deg]F).
    (b) Summary of Method. This method provides a laboratory test 
procedure for measuring the capability of cargo compartment lining 
materials to resist flame penetration with a 2 gallon per hour (GPH) 2 
Grade kerosene or equivalent burner fire source. Ceiling and sidewall 
liner panels may be tested individually provided a baffle is used to 
simulate the missing panel. Any specimen that passes the test as a 
ceiling liner panel may be used as a sidewall liner panel.
    (c) Test Specimens. (1) The specimen to be tested must measure 16 
\1/8\ inches (406 3 mm) by 
24 + \1/8\ inches (610 3 mm).
    (2) The specimens must be conditioned at 70 [deg]F. 5 [deg]F. (21 [deg]C. 2 [deg]C.) 
and 55% 5% humidity for at least 24 hours before 
testing.
    (d) Test Apparatus. The arrangement of the test apparatus must 
include the components described in this section. Minor details of the 
apparatus may vary, depending on the model of the burner used.

[[Page 261]]

    (1) Specimen Mounting Stand. The mounting stand for the test 
specimens consists of steel angles.
    (2) Test Burner. The burner to be used in tesing must--
    (i) Be a modified gun type.
    (ii) Use a suitable nozzle and maintain fuel pressure to yield a 2 
GPH fuel flow. For example: An 80 degree nozzle nominally rated at 2.25 
GPH and operated at 85 pounds per square inch (PSI) gauge to deliver 
2.03 GPH.
    (iii) Have a 12 inch (305 mm) burner extension installed at the end 
of the draft tube with an opening 6 inches (152 mm) high and 11 inches 
(280 mm) wide.
    (iv) Have a burner fuel pressure regulator that is adjusted to 
deliver a nominal 2.0 GPH of 2 Grade kerosene or equivalent.
    Burner models which have been used successfully in testing are the 
Lenox Model OB-32, Carlin Model 200 CRD and Park Model DPL.
    (3) Calorimeter. (i) The calorimeter to be used in testing must be a 
total heat flux Foil Type Gardon Gage of an appropriate range 
(approximately 0 to 15.0 British thermal unit (BTU) per ft.\2\ sec., 0-
17.0 watts/cm\2\). The calorimeter must be mounted in a 6 inch by 12 
inch (152 by 305 mm) by \3/4\ inch (19 mm) thick insulating block which 
is attached to a steel angle bracket for placement in the test stand 
during burner calibration as shown in Figure 2 of this part of this 
appendix.
    (ii) The insulating block must be monitored for deterioration and 
the mounting shimmed as necessary to ensure that the calorimeter face is 
parallel to the exit plane of the test burner cone.
    (4) Thermocouples. The seven thermocouples to be used for testing 
must be \1/16\ inch ceramic sheathed, type K, grounded thermocouples 
with a nominal 30 American wire gage (AWG) size conductor. The seven 
thermocouples must be attached to a steel angle bracket to form a 
thermocouple rake for placement in the test stand during burner 
calibration.
    (5) Apparatus Arrangement. The test burner must be mounted on a 
suitable stand to position the exit of the burner cone a distance of 8 
inches from the ceiling liner panel and 2 inches from the sidewall liner 
panel. The burner stand should have the capability of allowing the 
burner to be swung away from the test specimen during warm-up periods.
    (6) Instrumentation. A recording potentiometer or other suitable 
instrument with an appropriate range must be used to measure and record 
the outputs of the calorimeter and the thermocouples.
    (7) Timing Device. A stopwatch or other device must be used to 
measure the time of flame application and the time of flame penetration, 
if it occurs.
    (e) Preparation of Apparatus. Before calibration, all equipment must 
be turned on and allowed to stabilize, and the burner fuel flow must be 
adjusted as specified in paragraph (d)(2).
    (f) Calibration. To ensure the proper thermal output of the burner 
the following test must be made:
    (1) Remove the burner extension from the end of the draft tube. Turn 
on the blower portion of the burner without turning the fuel or igniters 
on. Measure the air velocity using a hot wire anemometer in the center 
of the draft tube across the face of the opening. Adjust the damper such 
that the air velocity is in the range of 1550 to 1800 ft./min. If tabs 
are being used at the exit of the draft tube, they must be removed prior 
to this measurement. Reinstall the draft tube extension cone.
    (2) Place the calorimeter on the test stand as shown in Figure 2 at 
a distance of 8 inches (203 mm) from the exit of the burner cone to 
simulate the position of the horizontal test specimen.
    (3) Turn on the burner, allow it to run for 2 minutes for warm-up, 
and adjust the damper to produce a calorimeter reading of 8.0 0.5 BTU per ft.\2\ sec. (9.1 0.6 
Watts/cm\2\).
    (4) Replace the calorimeter with the thermocouple rake.
    (5) Turn on the burner and ensure that each of the seven 
thermocouples reads 1700 [deg]F. 100 [deg]F. (927 
[deg]C. 38 [deg]C.) to ensure steady state 
conditions have been achieved. If the temperature is out of this range, 
repeat steps 2 through 5 until proper readings are obtained.
    (6) Turn off the burner and remove the thermocouple rake.
    (7) Repeat (1) to ensure that the burner is in the correct range.
    (g) Test Procedure. (1) Mount a thermocouple of the same type as 
that used for calibration at a distance of 4 inches (102 mm) above the 
horizontal (ceiling) test specimen. The thermocouple should be centered 
over the burner cone.
    (2) Mount the test specimen on the test stand shown in Figure 1 in 
either the horizontal or vertical position. Mount the insulating 
material in the other position.
    (3) Position the burner so that flames will not impinge on the 
specimen, turn the burner on, and allow it to run for 2 minutes. Rotate 
the burner to apply the flame to the specimen and simultaneously start 
the timing device.
    (4) Expose the test specimen to the flame for 5 minutes and then 
turn off the burner. The test may be terminated earlier if flame 
penetration is observed.
    (5) When testing ceiling liner panels, record the peak temperature 
measured 4 inches above the sample.
    (6) Record the time at which flame penetration occurs if applicable.
    (h) Test Report. The test report must include the following:

[[Page 262]]

    (1) A complete description of the materials tested including type, 
manufacturer, thickness, and other appropriate data.
    (2) Observations of the behavior of the test specimens during flame 
exposure such as delamination, resin ignition, smoke, etc., including 
the time of such occurrence.
    (3) The time at which flame penetration occurs, if applicable, for 
each of the three specimens tested.
[GRAPHIC] [TIFF OMITTED] TR11MR13.013


[[Page 263]]


[GRAPHIC] [TIFF OMITTED] TR11MR13.014


[[Page 264]]



[72 FR 55099, Sept. 28, 2007, as amended at 78 FR 15328, Mar. 11, 2013]



PART 179_SPECIFICATIONS FOR TANK CARS--Table of Contents



              Subpart A_Introduction, Approvals and Reports

Sec.
179.1 General.
179.2 Definitions and abbreviations.
179.3 Procedure for securing approval.
179.4 Changes in specifications for tank cars.
179.5 Certificate of construction.
179.6 Repairs and alterations.
179.7 Quality assurance program.
179.8 Limitation on actions by states, local governments, and Indian 
          tribes.

                  Subpart B_General Design Requirements

179.10 Tank mounting.
179.11 Welding certification.
179.12 Interior heater systems.
179.13 Tank car capacity and gross weight limitation.
179.14 Coupler vertical restraint system.
179.15 Pressure relief devices.
179.16 Tank-head puncture-resistance systems.
179.18 Thermal protection systems.
179.20 Service equipment; protection systems.
179.22 Marking.
179.24 Stamping.

 Subpart C_Specifications for Pressure Tank Car Tanks (Classes DOT-105, 
                         109, 112, 114, and 120)

179.100 General specifications applicable to pressure tank car tanks.
179.100-1 Tanks built under these specifications shall comply with the 
          requirements of Sec. Sec.  179.100, 179.101 and when 
          applicable, Sec. Sec.  179.102 and 179.103.
179.100-3 Type.
179.100-4 Insulation.
179.100-6 Thickness of plates.
179.100-7 Materials.
179.100-8 Tank heads.
179.100-9 Welding.
179.100-10 Postweld heat treatment.
179.100-12 Manway nozzle, cover and protective housing.
179.100-13 Venting, loading and unloading valves, measuring and sampling 
          devices.
179.100-14 Bottom outlets.
179.100-16 Attachments.
179.100-17 Closures for openings.
179.100-18 Tests of tanks.
179.100-19 Tests of safety relief valves.
179.100-20 Stamping.
179.101 Individual specification requirements applicable to pressure 
          tank car tanks.
179.101-1 Individual specification requirements.
179.102 Special commodity requirements for pressure tank car tanks.
179.102-1 Carbon dioxide, refrigerated liquid.
179.102-2 Chlorine.
179.102-3 Materials poisonous by inhalation.
179.102-4 Vinyl fluoride, stabilized.
179.102-17 Hydrogen chloride, refrigerated liquid.
179.103 Special requirements for class 114A * * * tank car tanks.
179.103-1 Type.
179.103-2 Manway cover.
179.103-3 Venting, loading and unloading valves, measuring and sampling 
          devices.
179.103-4 Safety relief devices and pressure regulators.
179.103-5 Bottom outlets.

 Subpart D_Specifications for Non-Pressure Tank Car Tanks (Classes DOT-
                        111AW, 115AW, and 117AW)

179.200 General specifications applicable to non-pressure tank car tanks 
          (Class DOT-111, DOT-117).
179.200-1 Tank built under these specifications must meet the applicable 
          requirements in this part.
179.200-3 Type.
179.200-4 Insulation.
179.200-6 Thickness of plates.
179.200-7 Materials.
179.200-8 Tank heads.
179.200-9 Compartment tanks.
179.200-10 Welding.
179.200-11 Postweld heat treatment.
179.200-13 Manway ring or flange, pressure relief device flange, bottom 
          outlet nozzle flange, bottom washout nozzle flange and other 
          attachments and openings.
179.200-14 Expansion capacity.
179.200-15 Closures for manways.
179.200-16 Gauging devices, top loading and unloading devices, venting 
          and air inlet devices.
179.200-17 Bottom outlets.
179.200-19 Reinforcements, when used, and appurtenances not otherwise 
          specified.
179.200-21 Closures for openings.
179.200-22 Test of tanks.
179.200-23 Tests of pressure relief valves.
179.200-24 Stamping.
179.201 Individual specification requirements applicable to non-pressure 
          tank car tanks.
179.201-1 Individual specification requirements.
179.201-2 [Reserved]
179.201-3 Lined tanks.
179.201-4 Material.
179.201-5 Postweld heat treatment and corrosion resistance.

[[Page 265]]

179.201-6 Manways and manway closures.
179.201-8 Sampling device and thermometer well.
179.201-9 Gauging device.
179.201-10 Water capacity marking.
179.201-11 Insulation.
179.202 Individual specification requirements applicable to DOT-117 tank 
          car tanks.
179.202-1 Applicability.
179.202-2 [Reserved]
179.202-3 Approval to operate at 286,000 gross rail load (GRL).
179.202-4 Thickness of plates.
179.202-5 Tank head puncture resistance system.
179.202-6 Thermal protection system.
179.202-7 Jackets.
179.202-8 Bottom outlets.
179.202-9 Top fittings protection.
179.202-11 Individual specification requirements.
179.202-12 Performance standard requirements (DOT-117P).
179.202-13 Retrofit standard requirements (DOT-117R).
179.203--179.202-22 [Reserved]
179.220 General specifications applicable to nonpressure tank car tanks 
          consisting of an inner container supported within an outer 
          shell (class DOT-115).
179.220-1 Tanks built under these specifications must meet the 
          requirements of Sec. Sec.  179.220 and 179.221.
179.220-3 Type.
179.220-4 Insulation.
179.220-6 Thickness of plates.
179.220-7 Materials.
179.220-8 Tank heads.
179.220-9 Compartment tanks.
179.220-10 Welding.
179.220-11 Postweld heat treatment.
179.220-13 Inner container manway nozzle and cover.
179.220-14 Openings in the tanks.
179.220-15 Support system for inner container.
179.220-16 Expansion capacity.
179.220-17 Gauging devices, top loading and unloading devices, venting 
          and air inlet devices.
179.220-18 Bottom outlets.
179.220-20 Reinforcements, when used, and appurtenances not otherwise 
          specified.
179.220-22 Closure for openings.
179.220-23 Test of tanks.
179.220-24 Tests of pressure relief valves.
179.220-25 Stamping.
179.220-26 Stenciling.
179.221 Individual specification requirements applicable to tank car 
          tanks consisting of an inner container supported within an 
          outer shell.
179.221-1 Individual specification requirements.

Subpart E_Specifications for Multi-Unit Tank Car Tanks (Classes DOT-106A 
                               and 110AW)

179.300 General specifications applicable to multi-unit tank car tanks 
          designed to be removed from car structure for filling and 
          emptying (Classes DOT-106A and 110AW).
179.300-1 Tanks built under these specifications shall meet the 
          requirements of Sec. Sec.  179.300 and 179.301.
179.300-3 Type and general requirements.
179.300-4 Insulation.
179.300-6 Thickness of plates.
179.300-7 Materials.
179.300-8 Tank heads.
179.300-9 Welding.
179.300-10 Postweld heat treatment.
179.300-12 Protection of fittings.
179.300-13 Venting, loading and unloading valves.
179.300-14 Attachments not otherwise specified.
179.300-15 Pressure relief devices.
179.300-16 Tests of tanks.
179.300-17 Tests of pressure relief devices.
179.300-18 Stamping.
179.300-19 Inspection.
179.300-20 Reports.
179.301 Individual specification requirements for multi-unit tank car 
          tanks.
179.302 [Reserved]

Subpart F_Specification for Cryogenic Liquid Tank Car Tanks and Seamless 
                 Steel Tanks (Classes DOT-113 and 107A)

179.400 General specification applicable to cryogenic liquid tank car 
          tanks.
179.400-1 General.
179.400-3 Type.
179.400-4 Insulation system and performance standard.
179.400-5 Materials.
179.400-6 Bursting and buckling pressure.
179.400-7 Tank heads.
179.400-8 Thickness of plates.
179.400-9 Stiffening rings.
179.400-10 Sump or siphon bowl.
179.400-11 Welding.
179.400-12 Postweld heat treatment.
179.400-13 Support system for inner tank.
179.400-14 Cleaning of inner tank.
179.400-15 Radioscopy.
179.400-16 Access to inner tank.
179.400-17 Inner tank piping.
179.400-18 Test of inner tank.
179.400-19 Valves and gages.
179.400-20 Pressure relief devices.
179.400-21 Test of pressure relief valves.
179.400-22 Protective housings.
179.400-23 Operating instructions.
179.400-24 Stamping.

[[Page 266]]

179.400-25 Stenciling.
179.401 Individual specification requirements applicable to inner tanks 
          for cryogenic liquid tank car tanks.
179.401-1 Individual specification requirements.
179.500 Specification DOT-107A * * * *, seamless steel tank car tanks.
179.500-1 Tanks built under these specifications shall meet the 
          requirements of Sec.  179.500.
179.500-3 Type and general requirements.
179.500-4 Thickness of wall.
179.500-5 Material.
179.500-6 Heat treatment.
179.500-7 Physical tests.
179.500-8 Openings in tanks.
179.500-10 Protective housing.
179.500-11 Loading and unloading valves.
179.500-12 Pressure relief devices.
179.500-13 Fixtures.
179.500-14 Test of tanks.
179.500-15 Handling of tanks failing in tests.
179.500-16 Tests of pressure relief devices.
179.500-17 Marking.
179.500-18 Inspection and reports.

Appendix A to Part 179--Procedures for Tank-Head Puncture-Resistance 
          Test
Appendix B to Part 179--Procedures for Simulated Pool and Torch-Fire 
          Testing

    Authority: 49 U.S.C. 5101-5128; 49 CFR 1.81 and 1.97.

    Source: 29 FR 18995, Dec. 29, 1964, unless otherwise noted. 
Redesignated at 32 FR 5606, Apr. 5, 1967.



              Subpart A_Introduction, Approvals and Reports



Sec.  179.1  General.

    (a) This part prescribes the specifications for tanks that are to be 
mounted on or form part of a tank car and which are to be marked with a 
DOT specification.
    (b) Except as provided in paragraph (c) of this section, tanks to 
which this part is applicable, must be built to the specifications 
prescribed in this part.
    (c) Tanks built to specifications predating those in this part may 
continue in use as provided in Sec.  180.507 of this subchapter.
    (d) Any person who performs a function prescribed in this part, 
shall perform that function in accordance with this part.
    (e) When this part requires a tank to be marked with a DOT 
specification (for example, DOT-105A100W), compliance with that 
requirement is the responsibility of the tank builder. Marking the tank 
with the DOT specification shall be understood to certify compliance by 
the builder that the functions performed by the builder, as prescribed 
in this part, have been performed in compliance with this part.
    (f) The tank builder should inform each person to whom that tank is 
transferred of any specification requirements which have not been met at 
time of transfer.

[Amdt. 179-17, 41 FR 38183, Sept. 9, 1976, as amended by Amdt. 179-50, 
60 FR 49076, Sept. 21, 1995; 68 FR 48571, Aug. 14, 2003]



Sec.  179.2  Definitions and abbreviations.

    (a) The following apply in part 179:
    (1) AAR means Association of American Railroads.
    (2) Approved means approval by the AAR Tank Car Committee.
    (3) ASTM means American Society for Testing and Materials.
    (4) [Reserved]
    (5) Definitions in part 173 of this chapter also apply.
    (6) F means degrees Fahrenheit.
    (7) NGT means National Gas Taper Threads.
    (8) NPT means an American Standard Taper Pipe Thread conforming to 
the requirements of NBS Handbook H-28 (IBR, see Sec.  171.7 of this 
subchapter).
    (9) [Reserved]
    (10) Tank car facility means an entity that manufactures, repairs, 
inspects, tests, qualifies, or maintains a tank car to ensure that the 
tank car conforms to this part and subpart F of part 180 of this 
subchapter, that alters the certificate of construction of the tank car, 
that ensures the continuing qualification of a tank car by performing a 
function prescribed in parts 179 or 180 of this subchapter, or that 
makes any representation indicating compliance with one or more of the 
requirements of parts 179 or 180 of this subchapter.
    (11) Tanks means tank car tanks.
    (b) [Reserved]

[29 FR 18995, Dec. 20, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21344, Nov. 6, 1971; Amdt. 179-50, 60 
FR 49076, Sept. 21, 1995; Amdt. 179-50, 61 FR 33255, June 26, 1996; 63 
FR 52850, Oct. 1, 1998; 66 FR 45186, 45390, Aug. 28, 2001; 68 fR 75759, 
Dec. 31, 2003]

[[Page 267]]



Sec.  179.3  Procedure for securing approval.

    (a) Application for approval of designs, materials and construction, 
conversion or alteration of tank car tanks under these specifications, 
complete with detailed prints, must be submitted in prescribed form to 
the Executive Director--Tank Car Safety, AAR, for consideration by its 
Tank Car Committee and other appropriate committees. Approval or 
rejections of applications based on appropriate committee action will be 
issued by the executive director.
    (b) When, in the opinion of the Committee, such tanks or equipment 
are in compliance with the requirements of this subchapter, the 
application will be approved.
    (c) When such tanks or equipment are not in compliance with the 
requirements of this subchapter, the Committee may recommend service 
trials to determine the merits of a change in specifications. Such 
service trials may be conducted only if the builder or shipper applies 
for and obtains a special permit.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967 
and amended by Amdt. 179-41, 52 FR 36672, Sept. 30, 1987; 63 FR 52850, 
Oct. 1, 1998; 68 FR 48571, Aug. 14, 2003; 70 FR 73166, Dec. 9, 2005]



Sec.  179.4  Changes in specifications for tank cars.

    (a) Proposed changes in or additions to specifications for tanks 
must be submitted to the Executive Director--Tank Car Safety, AAR, for 
consideration by its Tank Car Committee. An application for construction 
of tanks to any new specification may be submitted with proposed 
specification. Construction should not be started until the 
specification has been approved or a special permit has been issued. 
When proposing a new specification, the applicant shall furnish 
information to justify a new specification. This data should include the 
properties of the lading and the method of loading and unloading.
    (b) The Tank Car Committee will review the proposed specifications 
at its earliest convenience and report its recommendations through the 
Executive Director--Tank Car Safety to the Department. The 
recommendation will be considered by the Department in determining 
appropriate action.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967 
and amended by Amdt. 179-41, 52 FR 36672, Sept. 30, 1987; 63 FR 52850, 
Oct. 1, 1998; 70 FR 73166, Dec. 9, 2005]



Sec.  179.5  Certificate of construction.

    (a) Before a tank car is placed in service, the party assembling the 
completed car shall furnish a Certificate of Construction, Form AAR 4-2 
to the owner and the Executive Director--Tank Car Safety, AAR, 
certifying that the tank, equipment, and car fully conforms to all 
requirements of the specification.
    (b) When cars or tanks are covered in one application and are 
identical in all details are built in series, one certificate will 
suffice for each series when submitted to the Executive Director--Tank 
Car Safety, AAR.
    (c) If the owner elects to furnish service equipment, the owner 
shall furnish the Executive Director--Tank Car Safety, AAR, a report in 
prescribed form, certifying that the service equipment complies with all 
the requirements of the specifications.
    (d) When cars or tanks which are covered on one application and are 
identical in all details are built in series, one certificate shall 
suffice for each series when submitted to the Executive Director--Tank 
Car Safety, AAR. One copy of the Certificate of Construction must be 
furnished to the Executive Director--Tank Car Safety, AAR for each car 
number of consecutively numbered group or groups covered by the original 
application.

[Amdt. 179-10, 36 FR 21344, Nov. 6, 1971, as amended at 63 FR 52850, 
Oct. 1, 1998; 68 FR 48571, Aug. 14, 2003]



Sec.  179.6  Repairs and alterations.

    For procedure to be followed in making repairs or alterations, see 
appendix R of the AAR Specifications for Tank Cars (IBR, see Sec.  171.7 
of this subchapter).

[68 FR 75759, Dec. 31, 2003]

[[Page 268]]



Sec.  179.7  Quality assurance program.

    (a) At a minimum, each tank car facility shall have a quality 
assurance program, approved by AAR, that--
    (1) Ensures the finished product conforms to the requirements of the 
applicable specification and regulations of this subchapter;
    (2) Has the means to detect any nonconformity in the manufacturing, 
repair, inspection, testing, and qualification or maintenance program of 
the tank car; and
    (3) Prevents non-conformities from recurring.
    (b) At a minimum, the quality assurance program must have the 
following elements
    (1) Statement of authority and responsibility for those persons in 
charge of the quality assurance program.
    (2) An organizational chart showing the interrelationship between 
managers, engineers, purchasing, construction, inspection, testing, and 
quality control personnel.
    (3) Procedures to ensure that the latest applicable drawings, design 
calculations, specifications, and instructions are used in manufacture, 
inspection, testing, and repair.
    (4) Procedures to ensure that the fabrication and construction 
materials received are properly identified and documented.
    (5) A description of the manufacturing, repair, inspection, testing, 
and qualification or maintenance program, including the acceptance 
criteria, so that an inspector can identify the characteristics of the 
tank car and the elements to inspect, examine, and test at each point.
    (6) Monitoring and control of processes and product characteristics 
during production.
    (7) Procedures for correction of nonconformities.
    (8) Provisions indicating that the requirements of the AAR 
Specifications for Tank Cars (IBR, see Sec.  171.7 of this subchapter), 
apply.
    (9) Qualification requirements of personnel performing non-
destructive inspections and tests.
    (10) Procedures for evaluating the inspection and test technique 
employed, including the accessibility of the area and the sensitivity 
and reliability of the inspection and test technique and minimum 
detectable crack length.
    (11) Procedures for the periodic calibration and measurement of 
inspection and test equipment.
    (12) A system for the maintenance of records, inspections, tests, 
and the interpretation of inspection and test results.
    (c) Each tank car facility shall ensure that only personnel 
qualified for each non-destructive inspection and test perform that 
particular operation.
    (d) Each tank car facility shall provide written procedures to its 
employees to ensure that the work on the tank car conforms to the 
specification, AAR approval, and owner's acceptance criteria.
    (e) Each tank car facility shall train its employees in accordance 
with subpart H of part 172 of this subchapter on the program and 
procedures specified in paragraph (b) of this section to ensure quality.
    (f) No tank car facility may manufacture, repair, inspect, test, 
qualify or maintain tank cars subject to requirements of this 
subchapter, unless it is operating in conformance with a quality 
assurance program and written procedures required by paragraphs (a) and 
(b) of this section.

[Amdt. 179-50, 60 FR 49076, Sept. 21, 1995, as amended by Amdt. 179-50, 
61 FR 33255, June 26, 1996; 68 FR 48571, Aug. 14, 2003; 68 FR 75759, 
Dec. 31, 2003]



Sec.  179.8  Limitation on actions by states, local governments, and 
Indian tribes.

    Sections 5125 and 20106 of Title 49, United States Code, limit the 
authority of states, political subdivisions of states, and Indian tribes 
to impose requirements on the transportation of hazardous materials in 
commerce. A state, local, or Indian tribe requirement on the 
transportation of hazardous materials by rail may be preempted under 
either 49 U.S.C. 5125 or 20106, or both.
    (a) Section 171.1(f) of this subchapter describes the circumstances 
under which 49 U.S.C. 5125 preempts a requirement of a state, political 
subdivision of a state, or Indian tribe.
    (b) Under the Federal Railroad Safety Act (49 U.S.C. 20106), 
administered

[[Page 269]]

by the Federal Railroad Administration (see 49 CFR parts 200-244), laws, 
regulations and orders related to railroad safety, including security, 
shall be nationally uniform to the extent practicable. A state may 
adopt, or continue in force, a law, regulation, or order covering the 
same subject matter as a DOT regulation or order applicable to railroad 
safety and security (including the requirements in this subpart) only 
when an additional or more stringent state law, regulation, or order is 
necessary to eliminate or reduce an essentially local safety or security 
hazard; is not incompatible with a law, regulation, or order of the 
United States Government; and does not unreasonably burden interstate 
commerce.

[74 FR 1801, Jan. 13, 2009]



                  Subpart B_General Design Requirements



Sec.  179.10  Tank mounting.

    (a) The manner in which tanks are attached to the car structure 
shall be approved. The use of rivets to secure anchors to tanks 
prohibited.
    (b) [Reserved]



Sec.  179.11  Welding certification.

    (a) Welding procedures, welders and fabricators shall be approved.
    (b) [Reserved]



Sec.  179.12  Interior heater systems.

    (a) Interior heater systems shall be of approved design and 
materials. If a tank is divided into compartments, a separate system 
shall be provided for each compartment.
    (b) Each interior heater system shall be hydrostatically tested at 
not less than 13.79 bar (200 psig) and shall hold the pressure for 10 
minutes without leakage or evidence of distress.

[Amdt. 179-52, 61 FR 28678, June 5, 1996, as amended by 66 FR 45390, 
Aug. 28, 2001]



Sec.  179.13  Tank car capacity and gross weight limitation.

    Except as provided in this section, tank cars, built after November 
30, 1970, or any existing tank cars that are converted, may not exceed 
34,500 gallons (130,597 L) capacity or 263,000 pounds (119,295 kg) gross 
weight on rail.
    (a) For other than tank cars containing poisonous-by-inhalation 
material, a tank car may be loaded to a gross weight on rail of up to 
286,000 pounds (129,727 kg) upon approval by the Associate Administrator 
for Safety, Federal Railroad Administration (FRA). Tank cars must 
conform to the conditions of the approval and must be operated only 
under controlled interchange conditions agreed to by participating 
railroads.
    (b) Tank cars containing poisonous-by-inhalation material meeting 
the applicable authorized tank car specifications listed in Sec.  
173.244(a)(2) or (3) or Sec.  173.314(c) or (d) of this subchapter may 
have a gross weight on rail of up to 286,000 pounds (129,727 kg). Tank 
cars containing poisonous-by-inhalation material not meeting the 
specifications listed in Sec.  173.244(a)(2) or (3) or Sec.  173.314(c) 
or (d) may be loaded to a gross weight on rail of up to 286,000 pounds 
(129,727 kg) only upon approval of the Associate Administrator for 
Safety, Federal Railroad Administration (FRA). Any increase in weight 
above 263,000 pounds may not be used to increase thequantity of the 
contents of the tank car.

[74 FR 1802, Jan. 13, 2009, as amended at 75 FR 27216, May 14, 2010; 77 
FR 37985, June 25, 2012; 81 FR 35545, June 2, 2016]



Sec.  179.14  Coupler vertical restraint system.

    (a) Performance standard. Each tank car shall be equipped with 
couplers capable of sustaining, without disengagement or material 
failure, vertical loads of at least 200,000 pounds (90,718.5 kg) applied 
in upward and downward directions in combination with buff loads of 
2,000 pounds (907.2 kg), when coupled to cars which may or may not be 
equipped with couplers having this vertical restraint capability.
    (b) Test verification. Except as provided in paragraph (d) of this 
section, compliance with the requirements of paragraph (a) of this 
section shall be achieved by verification testing of the coupler 
vertical restraint system in accordance with paragraph (c) of this 
section.
    (c) Coupler vertical restraint tests. A coupler vertical restraint 
system shall

[[Page 270]]

be tested under the following conditions:
    (1) The test coupler shall be tested with a mating coupler (or 
simulated coupler) having only frictional vertical force resistance at 
the mating interface; or a mating coupler (or simulated coupler) having 
the capabilities described in paragraph (a) of this section;
    (2) The testing apparatus shall simulate the vertical coupler 
performance at the mating interface and may not interfere with coupler 
failure or otherwise inhibit failure due to force applications and 
reactions; and
    (3) The test shall be conducted as follows:
    (i) A minimum of 200,000 pounds (90,718.5 kg) vertical downward load 
shall be applied continuously for at least 5 minutes to the test coupler 
head simultaneously with the application of a nominal 2,000 pounds 
(907.2 kg) buff load;
    (ii) The procedures prescribed in paragraph (c)(3)(i) of this 
section, shall be repeated with a minimum vertical upward load of 
200,000 pounds (90,718.5 kg); and
    (iii) A minimum of three consecutive successful tests shall be 
performed for each load combination prescribed in paragraphs (c)(3) (i) 
and (ii) of this section. A test is successful when a vertical 
disengagement or material failure does not occur during the application 
of any of the loads prescribed in this paragraph.
    (d) Authorized couplers. As an alternative to the test verifications 
in paragraph (c) of this section, the following couplers are authorized:
    (1) E double shelf couplers designated by the Association of 
American Railroads' Catalog Nos., SE60CHT, SE60CC, SE60CHTE, SE60CE, 
SE60DC, SE60DE, SE67CC, SE67CE, SE67BHT, SE67BC, SE67BHTE, SE67BE, 
SE68BHT, SE68BC, SE68BHTE, SE68BE, SE69AHTE, and SE69AE.
    (2) F double shelf couplers designated by the Association of 
American Railroads' Catalog Nos., SF70CHT, SF70CC, SF70CHTE, SF70CE, 
SF73AC, SF73AE, SF73AHT, SF73AHTE, SF79CHT, SF79CC, SF79CHTE, and 
SF79CE.

[Amdt. 179-42, 54 FR 38797, Sept. 20, 1989]



Sec.  179.15  Pressure relief devices.

    Except for DOT Class 106, 107, 110, and 113 tank cars, tanks must 
have a pressure relief device, made of material compatible with the 
lading, that conforms to the following requirements:
    (a) Performance standard. Each tank must have a pressure relief 
device, made of materials compatible with the lading, having sufficient 
flow capacity to prevent pressure build-up in the tank to no more than 
the flow rating pressure of the pressure relief device in fire 
conditions as defined in appendix A of the AAR Specifications for Tank 
Cars (IBR, see Sec.  171.7 of this subchapter).
    (b) Settings for reclosing pressure relief devices. (1) Except as 
provided in paragraph (b)(2) of this section, a reclosing pressure 
relief valve must have a minimum start-to-discharge pressure equal to 
the sum of the static head and gas padding pressure and the lading vapor 
pressure at the following reference temperatures:
    (i) 46 [deg]C (115 [deg]F) for noninsulated tanks;
    (ii) 43 [deg]C (110 [deg]F) for tanks having a thermal protection 
system incorporating a metal jacket that provides an overall thermal 
conductance at 15.5 [deg]C (60 [deg]F) of no more than 10.22 kilojoules 
per hour per square meter per degree Celsius (0.5 Btu per hour/per 
square foot/per degree F) temperature differential; and
    (iii) 41 [deg]C (105 [deg]F) for insulated tanks.
    (2)(i) The start-to-discharge pressure of a pressure relief device 
may not be lower than 5.17 Bar (75 psig) or exceed 33 percent of the 
minimum tank burst pressure.
    (ii) Tanks built prior to October 1, 1997 having a minimum tank 
burst pressure of 34.47 Bar (500 psig) or less may be equipped with a 
reclosing pressure relief valve having a start-to-discharge pressure of 
not less than 14.5 percent of the minimum tank burst pressure but no 
more than 33 percent of the minimum tank burst pressure.
    (3) The vapor tight pressure of a reclosing pressure relief valve 
must be at least 80 percent of the start-to-discharge pressure.
    (4) The flow rating pressure must be 110 percent of the start-to-
discharge pressure for tanks having a minimum

[[Page 271]]

tank burst pressure greater than 34.47 Bar (500 psig) and from 110 
percent to 130 percent for tanks having a minimum tank burst pressure 
less than or equal to 34.47 Bar (500 psig).
    (5) The tolerance for a reclosing pressure relief valve is 3 psi for valves with a start-to-discharge pressure of 
6.89 Bar (100 psig) or less and 3 percent for 
valves with a start-to-discharge pressure greater than 6.89 Bar (100 
psig).
    (c) Flow capacity of pressure relief devices. The total flow 
capacity of each reclosing and nonreclosing pressure relief device must 
conform to appendix A of the AAR Specifications for Tank Cars.
    (d) Flow capacity tests. The manufacturer of any reclosing or 
nonreclosing pressure relief device must design and test the device in 
accordance with appendix A of the AAR Specifications for Tank Cars.
    (e) Combination pressure relief systems. A non-reclosing pressure 
relief device may be used in series with a reclosing pressure relief 
valve. The pressure relief valve must be located outboard of the non-
reclosing pressure relief device.
    (1) When a breaking pin device is used in combination with a 
reclosing pressure relief valve, the breaking pin must be designed to 
fail at the start-to-discharge pressure specified in paragraph (b) of 
this section, and the reclosing pressure relief valve must be designed 
to discharge at not greater than 95 percent of the start-to-discharge 
pressure.
    (2) When a rupture disc is used in combination with a reclosing 
pressure relief valve, the rupture disc must be designed to burst at the 
pressure specified in paragraph (b) of this section, and the reclosing 
pressure relief valve must be designed to discharge at not greater than 
95 percent of the pressure. A device must be installed to detect any 
accumulation of pressure between the rupture disc and the reclosing 
pressure relief valve. The detection device must be a needle valve, 
trycock, or tell-tale indicator. The detection device must be closed 
during transportation.
    (3) The vapor tight pressure and the start-to-discharge tolerance is 
based on the discharge setting of the reclosing pressure relief device.
    (f) Nonreclosing pressure relief device. In addition to paragraphs 
(a), (b)(4), (c), and (d) of this section, a nonreclosing pressure 
relief device must conform to the following requirements:
    (1) A non-reclosing pressure relief device must incorporate a 
rupture disc designed to burst at a pressure equal to the greater of 
100% of the tank test pressure, or 33% of the tank burst pressure.
    (2) The approach channel and the discharge channel may not reduce 
the required minimum flow capacity of the pressure relief device.
    (3) The non-reclosing pressure relief device must be designed to 
prevent interchange with other fittings installed on the tank car, must 
have a structure that encloses and clamps the rupture disc in position 
(preventing any distortion or damage to the rupture disc when properly 
applied), and must have a cover, with suitable means of preventing 
misplacement, designed to direct any discharge of the lading downward.
    (4) The non-reclosing pressure relief device must be closed with a 
rupture disc that is compatible with the lading and manufactured in 
accordance with Appendix A of the AAR Specifications for Tank Cars. The 
tolerance for a rupture disc is + 0 to -15 percent of the burst pressure 
marked on the disc.
    (g) Location of relief devices. Each pressure relief device must 
communicate with the vapor space above the lading as near as practicable 
on the longitudinal center line and center of the tank.
    (h) Marking of pressure relief devices. Each pressure relief device 
and rupture disc must be permanently marked in accordance with the 
appendix A of the AAR Specifications for Tank Cars.

[Amdt. 179-52, 61 FR 28678, June 5, 1996, as amended by Amdt. 179-52, 61 
FR 50255, Sept. 25, 1996; 62 FR 51561, Oct. 1, 1997; 64 FR 51919, Sept. 
27, 1999; 66 FR 45390, Aug. 28, 2001; 68 FR 75759, Dec. 31, 2003]



Sec.  179.16  Tank-head puncture-resistance systems.

    (a) Performance standard. When the regulations in this subchapter 
require

[[Page 272]]

a tank-head puncture-resistance system, the system shall be capable of 
sustaining, without any loss of lading, coupler-to-tank-head impacts at 
relative car speeds of 29 km/hour (18 mph) when:
    (1) The weight of the impact car is at least 119,295 kg (263,000 
pounds);
    (2) The impacted tank car is coupled to one or more backup cars that 
have a total weight of at least 217,724 kg (480,000 pounds) and the hand 
brake is applied on the last ``backup'' car; and
    (3) The impacted tank car is pressurized to at least 6.9 Bar (100 
psig).
    (b) Verification by testing. Compliance with the requirements of 
paragraph (a) of this section shall be verified by full-scale testing 
according to appendix A of this part.
    (c) Alternative compliance by other than testing. As an alternative 
to requirements prescribed in paragraph (b) of this section, compliance 
with the requirements of paragraph (a) of this section may be met by 
installing full-head protection (shields) or full tank-head jackets on 
each end of the tank car conforming to the following:
    (1) The full-head protection (shields) or full tank-head jackets 
must be at least 1.27 cm (0.5 inch) thick, shaped to the contour of the 
tank head and made from steel having a tensile strength greater than 
379.21 N/mm\2\ (55,000 psi).
    (2) The design and test requirements of the full-head protection 
(shields) or full tank-head jackets must meet the impact test 
requirements in Section 5.3 of the AAR Specifications for Tank Cars 
(IBR, see Sec.  171.7 of this subchapter).
    (3) The workmanship must meet the requirements in Section C, Part 
II, Chapter 5, of the AAR Specifications for Design, Fabrication, and 
Construction of Freight Cars (IBR, see Sec.  171.7 of this subchapter).

[Amdt. 179-50, 60 FR 49077, Sept. 21, 1995, as amended by Amdt. 179-50, 
61 FR 33255, June 26, 1996; 66 FR 45390, Aug. 28, 2001; 68 FR 75759, 
Dec. 31, 2003]



Sec.  179.18  Thermal protection systems.

    (a) Performance standard. When the regulations in this subchapter 
require thermal protection on a tank car, the tank car must have 
sufficient thermal resistance so that there will be no release of any 
lading within the tank car, except release through the pressure release 
device, when subjected to:
    (1) A pool fire for 100 minutes; and
    (2) A torch fire for 30 minutes.
    (b) Thermal analysis. (1) Compliance with the requirements of 
paragraph (a) of this section shall be verified by analyzing the fire 
effects on the entire surface of the tank car. The analysis must 
consider the fire effects on and heat flux through tank discontinuities, 
protective housings, underframes, metal jackets, insulation, and thermal 
protection. A complete record of each analysis shall be made, retained, 
and upon request, made available for inspection and copying by an 
authorized representative of the Department. The procedures outlined in 
``Temperatures, Pressures, and Liquid Levels of Tank Cars Engulfed in 
Fires,'' DOT/FRA/OR&D-84/08.11, (1984), Federal Railroad Administration, 
Washington, DC (available from the National Technical Information 
Service, Springfield, VA) shall be deemed acceptable for analyzing the 
fire effects on the entire surface of the tank car.
    (2) When the analysis shows the thermal resistance of the tank car 
does not conform to paragraph (a) of this section, the thermal 
resistance of the tank car must be increased by using a system listed by 
the Department under paragraph (c) of this section or by testing a new 
or untried system and verifying it according to appendix B of this part.
    (c) Systems that no longer require test verification. The Department 
maintains a list of thermal protection systems that comply with the 
requirements of appendix B of this part and that no longer require test 
verification. Information necessary to equip tank cars with one of these 
systems is available in the PHMSA Records Center, Pipeline and Hazardous 
Materials Safety Administration, East Building, 1200 New Jersey Avenue, 
SE., Washington, DC 20590-0001.

[Amdt. 179-50, 60 FR 49077, Sept. 21, 1995, as amended by Amdt. 179-50, 
61 FR 33256, June 26, 1996; 66 FR 45390, Aug. 28, 2001; 70 FR 56099, 
Sept. 23, 2005; 72 FR 55696, Oct. 1, 2007]

[[Page 273]]



Sec.  179.20  Service equipment; protection systems.

    If an applicable tank car specification authorizes location of 
filling or discharge connections in the bottom shell, the connections 
must be designed, constructed, and protected according to paragraphs 
E9.00 and E10.00 of the AAR Specifications for Tank Cars (IBR, see Sec.  
171.7 of this subchapter).

[68 FR 75759, Dec. 31, 2003]



Sec.  179.22  Marking.

    In addition to any other marking requirement in this subchapter, the 
following marking requirements apply:
    (a) Each tank car must be marked according to the requirements in 
appendix C of the AAR Specifications for Tank Cars (IBR, see Sec.  171.7 
of this subchapter).
    (b) Each tank car that requires a tank-head puncture-resistance 
system must have the letter ``S'' substituted for the letter ``A'' in 
the specification marking.
    (c) Each tank car that requires a tank-head puncture-resistance 
system, a thermal protection system, and a metal jacket must have the 
letter ``J'' substituted for the letter ``A'' or ``S'' in the 
specification marking.
    (d) Each tank car that requires a tank-head puncture-resistance 
system, a thermal protection system, and no metal jacket must have the 
letter ``T'' substituted for the letter ``A'' or ``S'' in the 
specification marking.
    (e) Each tank car manufactured after March 16, 2009, and before 
December 28, 2020, to meet the requirements of Sec. Sec.  173.244(a)(2) 
or (3) or 173.314(c) or (d) that is marked with the letter ``I'' in the 
specification marking, following the test pressure, shall be re-marked 
with the letter ``W'' with a delimeter of letter ``H'' at the tank car's 
next qualification. (Example: DOT 105J600I would be re-marked as 
105H600W.) Each new tank car manufactured after December 28, 2020 shall 
be marked with the letter ``W'' following the test pressure and with a 
delimiter of ``H''. (Example: 105H600W).

[Amdt. 179-50, 60 FR 49077, Sept. 21, 1995, as amended by Amdt. 179-50, 
61 FR 33256, June 26, 1996; 68 FR 75759, Dec. 31, 2003; 74 FR 1802, Jan. 
13, 2009; 85 FR 75716, Nov. 25, 2020]



Sec.  179.24  Stamping.

    (a)(1) After July 25, 2012, to certify compliance with federal 
requirements, the tank manufacturer must install two identical permanent 
identification plates, one located on both inboard surfaces of the body 
bolsters of the tank car. One identification plate must be installed on 
the right side (AR) of the tank car, and the other must be installed on 
the back end left side (BL) body bolster webs so that each plate is 
readily accessible for inspection. The plates must be at least \3/32\ 
inch thick and manufactured from corrosion resistant metal. When the 
tank jacket (flashing) covers the body bolster web and identification 
plates, additional identical plates must be installed on the AR and BL 
corners of the tank in a visible location. Tank cars built before July 
25, 2012, may have the plate instead of or in addition to the stamping.
    (2) Each plate must be stamped, embossed, or otherwise marked by an 
equally durable method in letters 3/16 inch high with the following 
information (parenthetical abbreviations may be used, and the AAR form 
reference is to the applicable provisions of the AAR Specifications for 
Tank Cars (IBR, see Sec.  171.7 of this subchapter):
    (i) Tank Manufacturer (Tank MFG): Full name of the car builder as 
shown on the certificate of construction (AAR form 4-2).
    (ii) Tank Manufacturer's Serial Number (SERIAL NO): For the specific 
car.
    (iii) AAR Number (AAR NO): The AAR number from line 3 of AAR Form 4-
2.
    (iv) Tank Specification (SPECIFICATION): The specification to which 
the tank was built from line 7 of AAR form 4-2.
    (v) Tank Shell Material/Head Material (SHELL MATL/HEAD MATL): ASTM 
or AAR specification of the material used in the construction of the 
tank shell and heads from lines 15 and 16 of AAR Form 4-2. For Class 
DOT-113W, DOT-115W, AAR-204W, and AAR-206W, the

[[Page 274]]

materials used in the construction of the outer tank shell and heads 
must be listed. Only list the alloy (e.g., 5154) for aluminum tanks and 
the type (e.g., 304L or 316L) for stainless steel tanks.
    (vi) Insulation Material (INSULATION MATL): Generic names of the 
first and second layer of any thermal protection/insulation material 
applied.
    (vii) Insulation Thickness (INSULATION THICKNESS): In inches.
    (viii) Underframe/Stub Sill Type (UF/SS DESIGN): The design from 
Line 32 of AAR Form 4-2.
    (ix) Date of Manufacture (DATE OF MFR): The month and year of tank 
manufacture. If the underframe has a different built date than the tank, 
show both dates.
    (3) When a modification to the tank changes any of the information 
shown in paragraph (a)(2) of this section, the car owner or the tank car 
facility making the modification must install an additional variable 
identification plate on the tank in accordance with paragraph (a)(1) of 
this section showing the following information:
    (i) AAR Number (AAR NO): The AAR number from line 3 of AAR Form 4-2 
for the alteration or conversion.
    (ii) All items of paragraph (a)(2) of this section that were 
modified, followed by the month and year of modification.
    (b) [Reserved].

[77 FR 37985, June 25, 2012, as amended at 81 FR 35545, June 2, 2016]



 Subpart C_Specifications for Pressure Tank Car Tanks (Classes DOT-105, 
                         109, 112, 114 and 120)



Sec.  179.100  General specifications applicable to pressure tank car tanks.



Sec.  179.100-1  Tanks built under these specifications shall comply with 
the requirements of Sec. Sec.  179.100, 179.101 and when applicable,  
Sec. Sec.  179.102 and 179.103. 



Sec.  179.100-3  Type.

    (a) Tanks built under this specification shall be fusion-welded with 
heads designed convex outward. Except as provided in Sec.  179.103 they 
shall be circular in cross section, shall be provided with a manway 
nozzle on top of the tank of sufficient size to permit access to the 
interior, a manway cover to provide for the mounting of all valves, 
measuring and sampling devices, and a protective housing. Other openings 
in the tank are prohibited, except as provided in part 173 of this 
chapter, Sec. Sec.  179.100-14, 179.101-1, 179.102 or Sec.  179.103.
    (b) Head shields and shells of tanks built under this specification 
must be normalized. Tank car heads must be normalized after forming 
unless specific approval is granted for a facility's equipment and 
controls.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21344, Nov. 6, 1971; 65 FR 58632, 
Sept. 29, 2000; 74 FR 1802, Jan. 13, 2009]



Sec.  179.100-4  Insulation.

    (a) If insulation is applied, the tank shell and manway nozzle must 
be insulated with an approved material. The entire insulation must be 
covered with a metal jacket of a thickness not less than 11 gauge 
(0.1196 inch) nominal (Manufacturers' Standard Gauge) and flashed around 
all openings so as to be weather-tight. The exterior surface of a carbon 
steel tank, and the inside surface of a carbon steel jacket must be 
given a protective coating.
    (b) If insulation is a specification requirement, it shall be of 
sufficient thickness so that the thermal conductance at 60 [deg]F is not 
more than 0.075 Btu per hour, per square foot, per degree F temperature 
differential. If exterior heaters are attached to tank, the thickness of 
the insulation over each heater element may be reduced to one-half that 
required for the shell.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21344, Nov. 6, 1971; Amdt. 179-50, 60 
FR 49077, Sept. 21, 1995]



Sec.  179.100-6  Thickness of plates.

    (a) The wall thickness after forming of the tank shell and heads 
must not be less than that specified in Sec.  179.101, nor that 
calculated by the following formula:

t = Pd / 2SE

Where:

d = Inside diameter in inches;

[[Page 275]]

E = 1.0 welded joint efficiency; except for heads with seams = 0.9;
P = Minimum required bursting pressure in p.s.i.;
S = Minimum tensile strength of plate material in p.s.i., as prescribed 
          in Sec.  179.100-7;
t = Minimum thickness of plate in inches after forming.

    (b) If plates are clad with material having tensile strength 
properties at least equal to the base plate, the cladding may be 
considered a part of the base plate when determining thickness. If 
cladding material does not have tensile strength at least equal to the 
base plate, the base plate alone shall meet the thickness requirement.
    (c) When aluminum plate is used, the minimum width of bottom sheet 
of tank shall be 60 inches, measured on the arc, but in all cases the 
width shall be sufficient to bring the entire width of the longitudinal 
welded joint, including welds, above the bolster.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21344, Nov. 6, 1971]



Sec.  179.100-7  Materials.

    (a) Steel plate: Steel plate materials used to fabricate tank shell 
and manway nozzle must comply with one of the following specifications 
with the indicated minimum tensile strength and elongation in the welded 
condition. The maximum allowable carbon content must be 0.31 percent 
when the individual specification allows carbon greater than this 
amount. The plates may be clad with other approved materials.

------------------------------------------------------------------------
                                                             Minimum
                                                         elongation in 2
                                        Minimum tensile       inches
            Specifications                  strength        (percent)
                                        (p.s.i.) welded       welded
                                          condition\1\      condition
                                                          (longitudinal)
------------------------------------------------------------------------
AAR TC 128, Gr. B.....................           81,000               19
ASTM A 302 \2\, Gr. B.................           80,000               20
ASTM A 516 \2\........................           70,000               20
ASTM A 537 \2\, Class 1...............           70,000              23
------------------------------------------------------------------------
\1\ Maximum stresses to be used in calculations.
\2\ These specifications are incorporated by reference (IBR, see Sec.
  171.7 of this subchapter).

    (b) Aluminum alloy plate: Aluminum alloy plate material used to 
fabricate tank shell and manway nozzle must be suitable for fusion 
welding and must comply with one of the following specifications (IBR, 
see Sec.  171.7 of this subchapter) with its indicated minimum tensile 
strength and elongation in the welded condition. * * *

------------------------------------------------------------------------
                                              Minimum         Minimum
                                              tensile      elongation in
                                             strength        2 inches
             Specifications                 (p.s.i.) 0      (percent) 0
                                          temper, welded  temper, welded
                                           condition \3      condition
                                                4\        (longitudinal)
------------------------------------------------------------------------
ASTM B 209, Alloy 5052 \1\..............          25,000              18
ASTM B 209, Alloy 5083 \2\..............          38,000              16
ASTM B 209, Alloy 5086 \1\..............          35,000              14
ASTM B 209, Alloy 5154 \1\..............          30,000              18
ASTM B 209, Alloy 5254 \1\..............          30,000              18
ASTM B 209, Alloy 5454 \1\..............          31,000              18
ASTM B 209, Alloy 5652 \1\..............          25,000              18
------------------------------------------------------------------------
\1\ For fabrication, the parent plate material may be 0, H112, or H32
  temper, but design calculations must be based on minimum tensile
  strength shown.
\2\ 0 temper only.
\3\ Weld filler metal 5556 must not be used.
\4\ Maximum stress to be used in calculations.

    (c) High alloy steel plate. (1) High alloy steel plate must conform 
to the following specifications:

------------------------------------------------------------------------
                                                             Minimum
                                        Minimum tensile  elongation in 2
                                            strength          inches
            Specifications              (p.s.i.) welded   (percent) weld
                                          condition\1\        metal
                                                          (longitudinal)
------------------------------------------------------------------------
ASTM A 240/A 240M (incorporated by               70,000               30
 reference; see Sec.   171.7 of this
 subchapter), Type 304L...............
ASTM A 240/A 240M (incorporated by               70,000               30
 reference; see Sec.   171.7 of this
 subchapter), Type 316L...............
------------------------------------------------------------------------
\1\ Maximum stresses to be used in calculations.

    (2)(i) High alloy steels used to fabricate tank must be tested in 
accordance with the following procedures in ASTM A 262, ``Standard 
Practices for Detecting Susceptibility to Intergranular Attack in 
Austenitic Stainless Steel'' (IBR, see Sec.  171.7 of this subchapter), 
and must exhibit corrosion rates not exceeding the following: * * *

------------------------------------------------------------------------
                                                              Corrosion
          Test procedures                   Material         rate i.p.m.
------------------------------------------------------------------------
Practice B.........................  Types 304L and 316L...       0.0040
Practice C.........................  Type 304L.............       0.0020
------------------------------------------------------------------------

    (ii) Type 304L and 316L test specimens must be given a sensitizing 
treatment prior to testing.
    (d) All attachments welded to tank shell must be of approved 
material

[[Page 276]]

which is suitable for welding to the tank.

[Amdt. 179-10, 36 FR 21344, Nov. 6, 1971, as amended by Amdt. 179-32, 48 
FR 27707, June 16, 1983; Amdt. 179-47, 58 FR 50237, Sept. 24, 1993; 
Amdt. 179-52, 61 FR 28679, June 5, 1996; Amdt. 179-52, 61 FR 50255, 
Sept. 25, 1996; 66 FR 45186, Aug. 28, 2001; 67 FR 51660, Aug. 8, 2002; 
68 FR 75759, Dec. 31, 2003]



Sec.  179.100-8  Tank heads.

    (a) The tank head shape shall be an ellipsoid of revolution in which 
the major axis shall equal the diameter of the shell adjacent to the 
head and the minor axis shall be one-half the major axis.
    (b) Each tank head made from steel which is required to be ``fine 
grain'' by the material specification, which is hot formed at a 
temperature exceeding 1700 [deg]F., must be normalized after forming by 
heating to a temperature between 1550[deg] and 1700 [deg]F., by holding 
at that temperature for at least 1 hour per inch of thickness (30-minute 
minimum), and then by cooling in air. If the material specification 
requires quenching and tempering, the treatment specified in that 
specification must be used instead of the one specified above.

[29 FR 18995, Dec. 29, 1964. Redesignated, 32 FR 5606, Apr. 5, 1967 and 
amended by Amdt. 179-12, 39 FR 15038, Apr. 30, 1974]



Sec.  179.100-9  Welding.

    (a) All joints shall be fusion-welded in compliance with the 
requirements of AAR Specifications for Tank Cars, appendix W (IBR, see 
Sec.  171.7 of this subchapter). Welding procedures, welders and 
fabricators shall be approved.
    (b) [Reserved]

[29 FR 18995, Dec. 29, 1964, as amended at 65 FR 58632, Sept. 29, 2000; 
68 FR 75759, Dec. 31, 2003]



Sec.  179.100-10  Postweld heat treatment.

    (a) After welding is complete, steel tanks and all attachments 
welded thereto must be postweld heat treated as a unit in compliance 
with the requirements of AAR Specifications for Tank Cars, appendix W 
(IBR, see Sec.  171.7 of this subchapter).
    (b) For aluminum tanks, postweld heat treatment is prohibited.
    (c) Tank and welded attachments, fabricated from ASTM A 240/A 240M 
(IBR, see Sec.  171.7 of this subchapter), Type 304L or Type 316L 
materials do not require postweld heat treatment, but these materials do 
require a corrosion resistance test as specified in Sec.  179.100-
7(c)(2).

[Amdt. 179-10, 36 FR 21345, Nov. 6, 1971, as amended by Amdt. 179-47, 58 
FR 50238, Sept. 24, 1993; Amdt. 179-52, 61 FR 28679, June 5, 1996; 67 FR 
51660, Aug. 8, 2002; 68 FR 75758, 75759, Dec. 31, 2003]



Sec.  179.100-12  Manway nozzle, cover and protective housing.

    (a) Manway nozzles must be of approved design of forged or rolled 
steel for steel tanks or of fabricated aluminum alloy for aluminum 
tanks, with an access opening of at least 18 inches inside diameter, or 
at least 14 inches by 18 inches around or oval. Each nozzle must be 
welded to the tank and the opening reinforced in an approved manner in 
compliance with the requirements of AAR Specifications for Tank Cars, 
appendix E, Figure E10 (IBR, see Sec.  171.7 of this subchapter).
    (b) Manway cover shall be machined to approved dimensions and be of 
forged or rolled carbon or alloy steel, rolled aluminum alloy or nickel 
when required by the lading. Minimum thickness is listed in Sec.  
179.101. Manway cover shall be attached to manway nozzle by through or 
stud bolts not entering tank, except as provided in Sec.  179.103-2(a).
    (c) Except as provided in Sec.  179.103, protective housing of cast, 
forged or fabricated approved materials must be bolted to manway cover 
with not less than twenty \3/4\-inch studs. The shearing value of the 
bolts attaching protective housing to manway cover must not exceed 70 
percent of the shearing value of bolts attaching manway cover to manway 
nozzle. Housing must have steel sidewalls not less than three-fourths 
inch in thickness and must be equipped with a metal cover not less than 
one-fourth inch in thickness that can be securely closed. Housing cover 
must have suitable stop to prevent cover striking loading and unloading 
connections and be hinged on one side only with approved riveted pin or 
rod with nuts and cotters. Openings in wall

[[Page 277]]

of housing must be equipped with screw plugs or other closures.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21345, Nov. 6, 1971; 68 FR 75760, 
Dec. 31, 2003]



Sec.  179.100-13  Venting, loading and unloading valves, measuring and 
sampling devices.

    (a) Venting, loading and unloading valves must be of approved 
design, made of metal not subject to rapid deterioration by the lading, 
and must withstand the tank test pressure without leakage. The valves 
shall be bolted to seatings on the manway cover, except as provided in 
Sec.  179.103. Valve outlets shall be closed with approved screw plugs 
or other closures fastened to prevent misplacement.
    (b) The interior pipes of the loading and unloading valves shall be 
anchored and, except as prescribed in Sec. Sec.  173.314(j), 179.102 or 
179.103, may be equipped with excess flow valves of approved design.
    (c) Gauging device, sampling valve and thermometer well are not 
specification requirements. When used, they shall be of approved design, 
made of metal not subject to rapid deterioration by the lading, and 
shall withstand the tank test pressure without leakage. Interior pipes 
of the gauging device and sampling valve, except as prescribed in 
Sec. Sec.  173.314(j), 179.102 or 179.103, may be equipped with excess 
flow valves of approved design. Interior pipe of the thermometer well 
shall be anchored in an approved manner to prevent breakage due to 
vibration. The thermometer well shall be closed by an approved valve 
attached close to the manway cover, or other approved location, and 
closed by a screw plug. Other approved arrangements that permit testing 
thermometer well for leaks without complete removal of the closure may 
be used.
    (d) An excess flow valve as referred to in this specification, is a 
device which closes automatically against the outward flow of the 
contents of the tank in case the external closure valve is broken off or 
removed during transit. Excess flow valves may be designed with a by-
pass to allow the equalization of pressures.
    (e) Bottom of tank shell may be equipped with a sump or siphon bowl, 
or both, welded or pressed into the shell. Such sumps or siphon bowls, 
if applied, are not limited in size and must be made of cast, forged or 
fabricated metal. Each sump or siphon bowl must be of good welding 
quality in conjunction with the metal of the tank shell. When the sump 
or siphon bowl is pressed in the bottom of the tank shell, the wall 
thickness of the pressed section must not be less than that specified 
for the shell. The section of a circular cross section tank to which a 
sump or siphon bowl is attached need not comply with the out-of-
roundness requirement specified in AAR Specifications for Tank Cars, 
appendix W, W14.06 (IBR, see Sec.  171.7 of this subchapter). Any 
portion of a sump or siphon bowl not forming a part of cylinder of 
revolution must have walls of such thickness and be so reinforced that 
the stresses in the walls caused by a given internal pressure are no 
greater than the circumferential stress that would exist under the same 
internal pressure in the wall of a tank of circular cross section 
designed in accordance with Sec.  179.100-6(a), but in no case shall the 
wall thickness be less than that specified in Sec.  179.101-1.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21345, Nov. 6, 1971; Amdt. 179-40, 52 
FR 13046, Apr. 20, 1987; Amdt. 179-42, 54 FR 38798, Sept. 20, 1989; 65 
FR 58632, Sept. 29, 2000; 68 FR 48571, Aug. 14, 2003; 68 FR 75760, Dec. 
31, 2003]



Sec.  179.100-14  Bottom outlets.

    (a) Bottom outlets for discharge of lading is prohibited, except as 
provided in Sec.  179.103-3. If indicated in Sec.  179.101, tank may be 
equipped with a bottom washout of approved construction. If applied, 
bottom washout shall be in accordance with the following requirements;
    (1) The extreme projection of the bottom washout equipment may not 
be more than that allowed by appendix E of the AAR Specifications for 
Tank Cars (IBR, see Sec.  171.7 of this subchapter).
    (2) Bottom washout shall be of cast, forged or fabricated metal and 
shall be fusion-welded to the tank. It shall be of

[[Page 278]]

good weldable quality in conjunction with metal of tank.
    (3) If the bottom washout nozzle extends 6 inches or more from shell 
of tank, a V-shaped breakage groove shall be cut (not cast) in the upper 
part of the outlet nozzle at a point immediately below the lowest part 
of the inside closure seat or plug. In no case may the nozzle wall 
thickness at the root of the ``V'' be more than \1/4\-inch. Where the 
nozzle is not a single piece, provision shall be made for the equivalent 
of the breakage groove. The nozzle must be of a thickness to insure that 
accidental breakage will occur at or below the ``V'' groove or its 
equivalent. On cars without continuous center sills, the breakage groove 
or its equivalent may not be more than 15 inches below the tank shell. 
On cars with continuous center sills, the breakage groove or its 
equivalent must be above the bottom of the center sill construction.
    (4) The closure plug and seat shall be readily accessible or 
removable for repairs.
    (5) The closure of the washout nozzle must be equipped with a \3/4\-
inch solid screw plug. Plug must be attached by at least a \1/4\-inch 
chain.
    (6) Joints between closures and their seats may be gasketed with 
suitable material.
    (b) [Reserved]

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21345, Nov. 6, 1971; Amdt. 179-40, 52 
FR 13046, Apr. 20, 1987; 66 FR 45186, Aug. 28, 2001; 68 FR 75760, Dec. 
31, 2003]



Sec.  179.100-16  Attachments.

    (a) Reinforcing pads must be used between external brackets and 
shells if the attachment welds exceed 6 linear inches of \1/4\-inch 
fillet or equivalent weld per bracket or bracket leg. When reinforcing 
pads are used, they must not be less than one-fourth inch in thickness, 
have each corner rounded to a 1-inch minimum radius, and be attached to 
the tank by continuous fillet welds except for venting provisions. The 
ultimate shear strength of the bracket-to-reinforcing pad weld must not 
exceed 85 percent of the ultimate shear strength of the reinforcing pad-
to-tank weld.
    (b) Attachments not otherwise specified shall be applied by approved 
means.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21346, Nov. 6, 1971]



Sec.  179.100-17  Closures for openings.

    (a) Closures shall be of approved design and made of metal not 
subject to rapid deterioration by the lading. Plugs, if used, shall be 
solid, with NPT threads, and shall be of a length which will screw at 
least six threads inside the face of fitting or tank.
    (b) [Reserved]



Sec.  179.100-18  Tests of tanks.

    (a) Each tank shall be tested by completely filling tank and manway 
nozzle with water or other liquid having similar viscosity, at a 
temperature which shall not exceed 100 [deg]F during the test; and 
applying the pressure prescribed in Sec.  179.101. The tank shall hold 
the prescribed pressure for at least 10 minutes without leakage or 
evidence of distress.
    (b) Insulated tanks shall be tested before insulation is applied.
    (c) Caulking of welded joints to stop leaks developed during the 
foregoing test is prohibited. Repairs in welded joints shall be made as 
prescribed in AAR Specifications for Tank Cars, appendix W (IBR, see 
Sec.  171.7 of this subchapter).
    (d) Testing of exterior heaters is not a specification requirement.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967; 
66 FR 45186, Aug. 28, 2001; 68 FR 75760, Dec. 31, 2003]



Sec.  179.100-19  Tests of safety relief valves.

    (a) Each valve shall be tested by air or gas for compliance with 
Sec.  179.15 before being put into service.
    (b) [Reserved]

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
as amended at 62 FR 51561, Oct. 1, 1997]



Sec.  179.100-20  Stamping.

    (a) To certify that the tank complies with all specification 
requirements, each tank shall be plainly and permanently stamped in 
letters and figures at least \3/8\ inch high into the metal

[[Page 279]]

near the center of both outside heads as follows:

------------------------------------------------------------------------
                                            Example of required stamping
------------------------------------------------------------------------
Specification.............................  DOT-105A100W
Material..................................  ASTM A 516
Cladding material (if any)................  ASTM A240-304
Tank builder's initials...................  Clad
Date of original test.....................  ABC
Car assembler (if other than tanker         00-0000
 builder).                                  DEF
------------------------------------------------------------------------

    (b) After July 25, 2012, newly constructed DOT tank cars must have 
their DOT specification and other required information stamped plainly 
and permanently on stainless steel identification plates in conformance 
with the applicable requirements prescribed in Sec.  179.24(a). Tank 
cars built before July 25, 2012, may have the identification plates 
instead of or in addition to the head stamping.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21346, Nov. 6, 1971; Amdt. 179-52, 61 
FR 28679, June 5, 1996; 65 FR 50463, Aug. 18, 2000; 77 FR 37985, June 
25, 2012]



Sec.  179.101  Individual specification requirements applicable to pressure 
tank car tanks.

    Editorial Note: At 66 FR 45186, Aug. 28, 2001, an amendment 
published amending a table in Sec.  179.101. No text or table appears in 
Sec.  179.101.



Sec.  179.101-1  Individual specification requirements.

    In addition to Sec.  179.100, the individual specification 
requirements are as follows:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                 Minimum
                                                      Bursting    plate       Test      Manway
        DOT specification             Insulation      pressure  thickness   pressure    cover      Bottom outlet    Bottom washout   Reference (179.***)
                                                       (psig)    (inches)    (psig)   thickness
--------------------------------------------------------------------------------------------------------------------------------------------------------
105A100ALW.......................  Yes.............        500        5/8        100  \2\ 2 1/2  No..............  No.............
105A200ALW.......................  Yes.............        500        5/8        200  \2\ 2 1/2  No..............  No.............
105A300ALW.......................  Yes.............        750        5/8        300  \2\ 2 5/8  No..............  No.............
105A100W.........................  Yes.............        500   \3\ 9/16        100      2 1/4  No..............  No.............
105A200W.........................  Yes.............        500   \3\ 9/16        200      2 1/4  No..............  No.............
105A300W.........................  Yes.............        750  \1\ 11/16        300  \7\ 2 1/4  No..............  No.............
105A400W.........................  Yes.............      1,000  \1\ 11/16        400  \7\ 2 1/4  No..............  No.............
105A500W.........................  Yes.............      1,250  \1\ 11/16        500      2 1/4  No..............  No.............  102-1, 102-2
105A600W.........................  Yes.............      1,500  \1\ 11/16        600      2 1/4  No..............  No.............  102-4, 102-17
109A100ALW.......................  Optional........        500        5/8        100  \2\ 2 1/2  No..............  Optional.......
109A200ALW.......................  Optional........        500        5/8        200  \2\ 2 1/2  No..............  Optional.......
109A300ALW.......................  Optional........        750        5/8        300  \2\ 2 5/8  No..............  Optional.......
109A300W.........................  Optional........        500  \1\ 11/16        300      2 1/4  No..............  Optional.......
112A200W.........................  Optional \4\....        500   \3 5\ 9/        200      2 1/4  No..............  No.............
                                                                       16
112A340W.........................  Optional \4\....        850  \1\ 11/16        340      2 1/4  No..............  No.............
112A400W.........................  Optional \4\....      1,000  \1\ 11/16        400      2 1/4  No..............  No.............
112A500W.........................  Optional \4\....      1,250  \1\ 11/16        500      2 1/4  No..............  No.............
114A340W.........................  Optional \4\....        850  \1\ 11/16        340        \6\  Optional........  Optional.......  103
114A400W.........................  Optional \4\....      1,000  \1\ 11/16        400        \6\  Optional........  Optional.......  103
120A200ALW.......................  Yes.............        500        5/8        200  \2\ 2 1/2  Optional........  Optional.......  103
120A100W.........................  Yes.............        500   \3\ 9/16        100      2 1/4  Optional........  Optional.......  103
120A200W.........................  Yes.............        500   \3\ 9/16        200      2 1/4  Optional........  Optional.......  103
120A300W.........................  Yes.............        750  \1\ 11/16        300      2 1/4  Optional........  Optional.......  103
120A400W.........................  Yes.............      1,000  \1\ 11/16        400      2 1/4  Optional........  Optional.......  103
120A500W.........................  Yes.............      1,250  \1\ 11/16        500      2 1/4  Optional........  Optional.......  103
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ When steel of 65,000 to 81,000 p.s.i. minimum tensile strength is used, the thickness of plates shall be not less than \5/8\ inch, and when steel of
  81,000 p.s.i. minimum tensile strength is used, the minimum thickness of plate shall be not less than \9/16\ inch.
\2\ When approved material other than aluminum alloys are used, the thickness shall be not less than 2\1/4\ inches.
\3\ When steel of 65,000 p.s.i. minimum tensile strength is used, minimum thickness of plates shall be not less than \1/2\ inch.
\4\ Tank cars not equipped with a thermal protection or an insulation system used for the transportation of a Class 2 (compressed gas) material must
  have at least the upper two-thirds of the exterior of the tank, including manway nozzle and all appurtenances in contact with this area, finished with
  a reflective coat of white paint.
\5\ For inside diameter of 87 inches or less, the thickness of plates shall be not less than \1/2\ inch.
\6\ See AAR Specifications for Tank Cars, appendix E, E4.01 (IBR, see Sec.   171.7 of this subchapter), and Sec.   179.103-2.
\7\ When the use of nickel is required by the lading, the thickness shall not be less than two inches.


[Amdt. 179-52, 61 FR 28679, June 5, 1996, as amended at 66 FR 45390, 
Aug. 28, 2001; 68 FR 75760, Dec. 31, 2003]

[[Page 280]]



Sec.  179.102  Special commodity requirements for pressure tank car tanks.

    (a) In addition to Sec. Sec.  179.100 and 179.101 the following 
requirements are applicable:
    (b) [Reserved]



Sec.  179.102-1  Carbon dioxide, refrigerated liquid.

    (a) Tank cars used to transport carbon dioxide, refrigerated liquid 
must comply with the following special requirements:
    (1) All plates for tank, manway nozzle and anchorage of tanks must 
be made of carbon steel conforming to ASTM A 516/A 516M (IBR, see Sec.  
171.7 of this subchapter), Grades 55, 60, 65, or 70, or AAR 
Specification TC 128-78, Grade B. The ASTM A 516/A 516M plate must also 
meet the Charpy V-Notch test requirements of ASTM A 20/A 20M (see table 
16) (IBR, see Sec.  171.7 of this subchapter) in the longitudinal 
direction of rolling. The TC 128 plate must also meet the Charpy V-Notch 
energy absorption requirements of 15 ft.-lb. minimum average for 3 
specimens, and 10 ft.-lb. minimum for one specimen, at minus 50 [deg]F 
in the longitudinal direction of rolling in accord with ASTM A 370 (IBR, 
see Sec.  171.7 of this subchapter). Production-welded test plates 
prepared as required by W4.00 of AAR Specifications for Tank Cars, 
appendix W (IBR, see Sec.  171.7 of this subchapter), must include 
impact test specimens of weld metal and heat-affected zone. As an 
alternate, anchor legs may be fabricated of stainless steel, ASTM A 240/
A 240M Types 304, 304L, 316 or 316L, for which impact tests are not 
required.
    (2)-(6) [Reserved]
    (b) [Reserved]

[29 FR 18995, Dec. 29, 1964]

    Editorial Note: For Federal Register citations affecting Sec.  
179.102-1, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.govinfo.gov.



Sec.  179.102-2  Chlorine.

    (a) Each tank car used to transport chlorine must comply with all of 
the following:
    (1) Tanks must be fabricated from carbon steel complying with ASTM 
Specification A 516 (IBR, see Sec.  171.7 of this subchapter), Grade 70, 
or AAR Specification TC 128, Grade A or B.
    (2)-(3) [Reserved]
    (b) [Reserved]

[Amdt. 179-7, 36 FR 14697, Aug. 10, 1971; Amdt. 179-10, 36 FR 21346, 
Nov. 6, 1971, as amended by Amdt. 179-25, 44 FR 20433, Apr. 5, 1979; 
Amdt. 179-40, 52 FR 13046, Apr. 20, 1987; Amdt. 179-45, 55 FR 52728, 
Dec. 21, 1990; Amdt. 179-52, 61 FR 28680, June 5, 1996; 68 FR 75760, 
Dec. 31, 2003]



Sec.  179.102-3  Materials poisonous by inhalation.

    (a) Each tank car built after March 16, 2009 for the transportation 
of a material poisonous by inhalation must, in addition to the 
requirements prescribed in Sec.  179.100-12(c), enclose the service 
equipment within a protective housing and cover.
    (1) Tank cars must be equipped with a top fitting protection system 
and nozzle capable of sustaining, without failure, a rollover accident 
at a speed of 9 miles per hour, in which the rolling protective housing 
strikes a stationary surface assumed to be flat, level and rigid and the 
speed is determined as a linear velocity, measured at the geometric 
center of the loaded tank car as a transverse vector. Failure is deemed 
to occur when the deformed protective housing contacts any of the 
service equipment or when the tank retention capability is compromised.
    (2) As an alternative to the tank car top fitting protection system 
requirements in paragraph (a)(1) of this section, the tank car may be 
equipped with a system that prevents the release of product from any top 
fitting in the case of an accident where any top fitting would be 
sheared off. The tank nozzle must meet the performance standard in 
paragraph (a)(1) of this section and only mechanically operated excess 
flow devices are authorized.
    (b) An application for approval of a tank car built in accordance 
with Sec.  173.244(a)(3) or Sec.  173.314(d) must include a 
demonstration, through engineering analysis, that the tank jacket and 
support structure system, including any anchors and support devices, is 
capable of withstanding a 6 mile per hour coupling without jacket shift 
such that results in damage to the nozzle.

[74 FR 1802, Jan. 13, 2009]

[[Page 281]]



Sec.  179.102-4  Vinyl fluoride, stabilized.

    Each tank used to transport vinyl fluoride, stabilized, must comply 
with the following special requirements:
    (a) All plates for the tank must be fabricated of material listed in 
paragraph (a)(2) of this section, and appurtenances must be fabricated 
of material listed in paragraph (a)(1) or (a)(2) of this section.
    (1) Stainless steel, ASTM A 240/A 240M (IBR, see Sec.  171.7 of this 
subchapter), Type 304, 304L, 316 or 316L, in which case impact tests are 
not required; or
    (2) Steel complying with ASTM Specification A 516 (IBR, see Sec.  
171.7 of this subchapter); Grade 70; ASTM Specification A 537 (IBR, see 
Sec.  171.7 of this subchapter), Class 1; or AAR Specification TC 128, 
Grade B, in which case impact tests must be performed as follows:
    (i) ASTM A 516/A 516M and A 537/A 537M material must meet the Charpy 
V-Notch test requirements, in longitudinal direction of rolling, of ASTM 
A 20/A 20M (IBR, see Sec.  171.7 of this subchapter).
    (ii) AAR Specification TC 128 material must meet the Charpy V-Notch 
test requirements, in longitudinal direction of rolling, of 15 ft.-lb. 
minimum average for 3 specimens, with a 10 ft.-lb. minimum for any one 
specimen, at minus 50 [deg]F or colder, in accordance with ASTM A 370 
(IBR, see Sec.  171.7 of this subchapter).
    (iii) Production welded test plates must--
    (A) Be prepared in accordance with AAR Specifications for Tank Cars, 
appendix W, W4.00 (IBR, see Sec.  171.7 of this subchapter);
    (B) Include impact specimens of weld metal and heat affected zone 
prepared and tested in accordance with AAR Specifications for Tank Cars, 
appendix W, W9.00; and
    (C) Meet the same impact requirements as the plate material.
    (b) Insulation must be of approved material.
    (c) Excess flow valves must be installed under all liquid and vapor 
valves, except safety relief valves.
    (d) A thermometer well may be installed.
    (e) Only an approved gaging device may be installed.
    (f) A pressure gage may be installed.
    (g) Aluminum, copper, silver, zinc, or an alloy containing any of 
these metals may not be used in the tank construction, or in fittings in 
contact with the lading.
    (h) The jacket must be stenciled, adjacent to the water capacity 
stencil,

MINIMUM OPERATING TEMPERATURE __ [deg]F.

    (i) The tank car and insulation must be designed to prevent the 
vapor pressure of the lading from increasing from the pressure at the 
maximum allowable filling density to the start-to-discharge pressure of 
the reclosing pressure relief valve within 30 days, at an ambient 
temperature of 90 [deg]F.

[Amdt. 179-32, 48 FR 27707, June 16, 1983, as amended at 49 FR 24317, 
June 12, 1984; 49 FR 42736, Oct. 24, 1984; Amdt. 179-45, 55 FR 52728, 
Dec. 21, 1990; Amdt. 179-52, 61 FR 28680, June 5, 1996; 65 FR 58632, 
Sept. 29, 2000; 66 FR 33452, June 21, 2001; 66 FR 45186, 45390, Aug. 28, 
2001; 67 FR 51660, Aug. 8, 2002; 68 FR 75758, 75760 Dec. 31, 2003]



Sec.  179.102-17  Hydrogen chloride, refrigerated liquid.

    Each tank car used to transport hydrogen chloride, refrigerated 
liquid must comply with the following special requirements:
    (a) The tank car must comply with Specification DOT-105J600W and be 
designed for loading at minus 50 [deg]F. or colder.
    (b) All plates for the tank must be fabricated of material listed in 
paragraph (b)(2) of this section, and appurtenances must be fabricated 
of material listed in paragraph (b)(1) or (b)(2) of this section.
    (1) Stainless steel, ASTM A 240/A 240M (IBR, see Sec.  171.7 of this 
subchapter), Type 304, 304L, 316, or 316L, in which case impact tests 
are not required; or
    (2) Steel conforming to ASTM A 516/A 516M (IBR, see Sec.  171.7 of 
this subchapter), Grade 70; ASTM A 537/A 537M, (IBR, see Sec.  171.7 of 
this subchapter) Class 1; or AAR Specification TC 128, Grade B in which 
case impact tests must be performed as follows:
    (i) ASTM A 516/A 516M and A 537/A 537M material must meet the Charpy 
V-notch test requirements, in longitudinal direction of rolling, of ASTM 
A

[[Page 282]]

20/A 20M (IBR, see Sec.  171.7 of this subchapter).
    (ii) AAR Specification TC 128 material must meet the Charpy V-notch 
test requirements, in longitudinal direction of rolling of 15 ft.-lb. 
minimum average for 3 specimens, with a 10 ft.-lb. minimum for any one 
specimen, at minus 50 [deg]F or colder, in accordance with ASTM A 370 
(IBR, see Sec.  171.7 of this subchapter).
    (iii) Production welded test plates must--
    (A) Be prepared in accordance with AAR Specifications for Tank Cars, 
appendix W, W4.00 (IBR, see Sec.  171.7 of this subchapter);
    (B) include impact test specimens of weld metal and heat affected 
zone prepared and tested in accordance with AAR Specifications for Tank 
Cars, appendix W, W9.00; and
    (C) meet the same impact requirements as the plate material.
    (c) Insulation must be of approved material.
    (d) Pressure relief valves must be trimmed with monel or other 
approved material and equipped with a rupture disc of silver, 
polytetrafluoroethylene coated monel, or tantalum. Each pressure relief 
device shall have the space between the rupture disc and the valve 
vented with a suitable auxiliary valve. The discharge from each pressure 
relief valve must be directed outside the protective housing.
    (e) Loading and unloading valves must be trimmed with Hastelloy B or 
C, monel, or other approved material, and identified as ``Vapor'' or 
``Liquid''. Excess flow valves must be installed under all liquid and 
vapor valves, except safety relief valves.
    (f) A thermometer well may be installed.
    (g) Only an approved gaging device may be installed.
    (h) A sump must be installed in the bottom of the tank under the 
liquid pipes.
    (i) All gaskets must be made of, or coated with, 
polytetrafluoroethylene or other approved material.
    (j) The tank car tank may be equipped with exterior cooling coils on 
top of the tank car shell.
    (k) The jacket must be stenciled, adjacent to the water capacity 
stencil,

MINIMUM OPERATING TEMPERATURE __ [deg]F.

    (l) The tank car and insulation must be designed to prevent the 
pressure of the lading from increasing from the pressure at the maximum 
allowable filling density to the start-to-discharge pressure of the 
pressure relief valve within 30 days, at an ambient temperature of 
90[deg] F.
    (m) Except as provided in Sec.  173.314(d), tank cars built on or 
after March 16, 2009 used for the transportation of hydrogen chloride, 
refrigerated liquid, must meet the applicable authorized tank car 
specification listed in Sec.  173.314(c).

[Amdt. 179-32, 48 FR 27708, June 16, 1983, as amended at 48 FR 50441, 
Nov. 1, 1983; 49 FR 24317, June 12, 1984; 49 FR 42736, Oct. 24, 1984; 
Amdt. 179-45, 55 FR 52728, Dec. 21, 1990; 66 FR 45390, Aug. 28, 2001; 67 
FR 51660, Aug. 8, 2002; 68 FR 75758, 75760, Dec. 31, 2003; 74 FR 1802, 
Jan. 13, 2009]



Sec.  179.103  Special requirements for class 114A * * * tank car tanks.

    (a) In addition to the applicable requirements of Sec. Sec.  179.100 
and 179.101 the following requirements shall be complied with:
    (b) [Reserved]



Sec.  179.103-1  Type.

    (a) Tanks built under this section may be of any approved cross 
section.
    (b) Any portion of the tank shell not circular in cross section 
shall have walls of such thickness and be so reinforced that the 
stresses in the walls caused by a given internal pressure are no greater 
than the circumferential stresses which would exist under the same 
internal pressure in the wall of a tank of circular cross section 
designed in accordance with paragraphs Sec.  179.100-6 (a) and (b), but 
in no case shall the wall thickness be less than that specified in Sec.  
179.101.
    (c) [Reserved]
    (d) Valves and fittings need not be mounted on the manway cover.
    (e) One opening may be provided in each head for use in purging the 
tank interior.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-50, 60 FR 49077, Sept. 21, 1995]

[[Page 283]]



Sec.  179.103-2  Manway cover.

    (a) The manway cover must be an approved design.
    (b) If no valves or measuring and sampling devices are mounted on 
manway cover, no protective housing is required.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-50, 60 FR 49077, Sept. 21, 1995]



Sec.  179.103-3  Venting, loading and unloading valves, measuring and 
sampling devices.

    (a) Venting, loading and unloading valves, measuring and sampling 
devices, when used, shall be attached to a nozzle or nozzles on the tank 
shell or heads.
    (b) These valves and appurtenances must be grouped in one location 
and, except as provided in Sec.  179.103-5, must be equipped with a 
protective housing with cover, or may be recessed into tank shell with 
cover. An additional set grouped in another location may be provided. 
Protective housing with cover, when used, must have steel sidewalls not 
less than three-fourths inch in thickness and a metal cover not less 
than one-fourth inch in thickness that can be securely closed. 
Underframe sills are an acceptable alternate to the protective housing 
cover, provided the arrangement is of approved design. For fittings 
recessed into tank shell, protective cover must be metal and not less 
than one-fourth inch in thickness.
    (c) When tank car is used to transport liquefied flammable gases, 
the interior pipes of the loading, unloading, and sampling valves must 
be equipped with excess flow valves of approved design except when quick 
closing internal valves of approved design are used. When the interior 
pipe of the gaging device provides a means for the passage of lading 
from the interior to the exterior of the tank, it must be equipped with 
an excess flow valve of approved design or with an orifice not exceeding 
0.060 inch.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21348, Nov. 6, 1971]



Sec.  179.103-4  Safety relief devices and pressure regulators.

    (a) Safety relief devices and pressure regulators must be located on 
top of the tank near the center of the car on a nozzle, mounting plate 
or recess in the shell. Through or stud bolts, if used, must not enter 
the tank.
    (b) Metal guard of approved design must be provided to protect 
safety relief devices and pressure regulators from damage.

[Amdt. 179-10, 36 FR 21348, Nov. 6, 1971]



Sec.  179.103-5  Bottom outlets.

    (a) In addition to or in place of the venting, loading and unloading 
valves, measuring and sampling devices as prescribed in Sec.  179.103-3, 
tanks may be equipped with approved bottom outlet valves. If applied, 
bottom outlet valves must meet the following requirements:
    (1) On cars with center sills, a ball valve may be welded to the 
outside bottom of the tank or mounted on a pad or nozzle with a tongue 
and groove or male and female flange attachment, but in no case shall 
the breakage groove or equivalent extend below the bottom flange of the 
center sill. On cars without continuous center sills, a ball valve may 
be welded to the outside bottom of the tank or mounted with a tongue and 
groove or male and female flange attachment on a pad attached to the 
outside bottom of the tank. The mounting pad must have a maximum 
thickness of 2\1/2\ inches measured on the longitudinal centerline of 
the tank. The valve operating mechanism must be provided with a suitable 
locking arrangement to insure positive closure during transit.
    (2) When internal bottom outlet valve is used in liquefied flammable 
gas service, the outlet of the valve must be equipped with an excess 
flow valve of approved design, except when a quick-closing internal 
valve of approved design is used. Protective housing is not required.
    (3) Bottom outlet must be equipped with a liquid tight closure at 
its lower end.
    (b) Bottom outlet equipment must be of approved design and must meet 
the following requirements:

[[Page 284]]

    (1) The extreme projection of the bottom outlet equipment may not be 
more than allowed by appendix E of the AAR Specifications for Tank Cars 
(IBR, see Sec.  171.7 of this subchapter). All bottom outlet reducers 
and closures and their attachments shall be secured to the car by at 
least \3/8\ inch chain, or its equivalent, except that bottom outlet 
closure plugs may be attached by \1/4\ inch chain. When the bottom 
outlet closure is of the combination cap and valve type, the pipe 
connection to the valve shall be closed by a plug, cap, or approved 
quick coupling device. The bottom outlet equipment should include only 
the valve, reducers and closures that are necessary for the attachment 
of unloading fixtures. The permanent attachment of supplementary 
exterior fittings must be approved by the AAR Committee on Tank Cars.
    (2) To provide for the attachment of unloading connections, the 
discharge end of the bottom outlet nozzle or reducer, the valve body of 
the exterior valve, or some fixed attachment thereto, shall be provided 
with one of the following arrangements or an approved modification 
thereof. (See appendix E. Fig. E17 of the AAR Specifications for Tank 
Cars for illustrations of some of the possible arrangements.)
    (i) A bolted flange closure arrangement including a minimum 1-inch 
NPT pipe plug (see Fig. E17.1) or including an auxiliary valve with a 
threaded closure.
    (ii) A threaded cap closure arrangement including a minimum 1-inch 
NPT pipe plug (see Fig. E17.2) or including an auxiliary valve with a 
threaded closure.
    (iii) A quick-coupling device using a threaded plug closure of at 
least 1-inch NPT or having a threaded cap closure with a minimum 1-inch 
NPT pipe plug (see Fig. E17.3 through E17.5). A minimum 1-inch auxiliary 
test valve with a threaded closure may be substituted for the 1-inch 
pipe plug (see Fig E17.6). If the threaded cap closure does not have a 
pipe plug or integral auxiliary test valve, a minimum 1-inch NPT pipe 
plug shall be installed in the outlet nozzle above the closure (see Fig. 
E17.7).
    (iv) A two-piece quick-coupling device using a clamped dust cap must 
include an in-line auxiliary valve, either integral with the quick-
coupling device or located between the primary bottom outlet valve and 
the quick-coupling device. The quick-coupling device closure dust cap or 
outlet nozzle shall be fitted with a minimum 1-inch NPT closure (see 
Fig. E17.8 and E17.9).
    (3) The valve operating mechanism must be provided with a suitable 
locking arrangement to insure positive closure during transit.
    (4) If the outlet nozzle extends 6 inches or more from shell of 
tank, a V-shaped breakage groove shall be cut (not cast) in the upper 
part to the outlet nozzle at a point immediately below the lowest part 
of value closest to the tank. In no case may the nozzle wall thickness 
at the roof of the ``V'' be more than \1/4\-inch. On cars without 
continuous center sills, the breakage groove or its equivalent may not 
be more than 15 inches below the tank shell. On cars with continuous 
center sills, the breakage groove or its equivalent must be above the 
bottom of the center sill construction.
    (5) The valve body must be of a thickness which will insure that 
accidental breakage of the outlet nozzle will occur at or below the 
``V'' groove, or its equivalent, and will not cause distortion of the 
valve seat or valve.

[Amdt. 179-10, 36 FR 21348, Nov. 6, 1971, as amended by Amdt. 179-40, 52 
FR 13046, Apr. 20, 1987; Amdt. 179-41, 52 FR 36672, Sept. 30, 1987; 
Amdt. 179-50, 60 FR 49077, Sept. 21, 1995; Amdt. 179-52, 61 FR 28680, 
June 5, 1996; Amdt. 179-53, 61 FR 51342, Oct. 1, 1996; 66 FR 45186, Aug. 
28, 2001; 68 FR 75761, Dec. 31, 2003]



 Subpart D_Specifications for Non-Pressure Tank Car Tanks (Classes DOT-
                        111AW, 115AW, and 117AW)



Sec.  179.200  General specifications applicable to non-pressure tank car  
tanks (Class DOT-111, DOT-117).



Sec.  179.200-1  Tank built under these specifications must meet the 
applicable requirements in this part. 



Sec.  179.200-3  Type.

    Tank built under these specifications must be circular in cross 
section, with formed heads designed convex outward. When specified in 
Sec.  179.201-1, the tank

[[Page 285]]

must have at least one manway or one expansion dome with manway, and 
such other external projections as are prescribed herein. When the tank 
is divided into compartments, each compartment must be treated as a 
separate tank.

[Amdt. 179-10, 36 FR 21348, Nov. 6, 1971]



Sec.  179.200-4  Insulation.

    (a) If insulation is applied, the tank shell and expansion dome when 
used must be insulated with an approved material. The entire insulation 
must be covered with a metal jacket of a thickness not less than 11 
gauge (0.1196 inch) nominal (Manufacturer's Standard Gauge) and flashed 
around all openings so as to be weather tight. The exterior surface of a 
carbon steel tank and the inside surface of a carbon steel jacket must 
be given a protection coating.
    (b) If insulation is a specification requirement, it shall be of 
sufficient thickness so that the thermal conductance at 60 [deg]F is not 
more than 0.225 Btu per hour, per square foot, per degree F temperature 
differential, unless otherwise provided in Sec.  179.201-1. If exterior 
heaters are attached to tank, the thickness of the insulation over each 
heater element may be reduced to one-half that required for the shell.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21349, Nov. 6, 1971; Amdt. 179-50, 60 
FR 49078, Sept. 21, 1995]



Sec.  179.200-6  Thickness of plates.

    (a) The wall thickness after forming of the tank shell, dome shell, 
and of 2:1 ellipsoidal heads must be not less than specified in Sec.  
179.201-1, nor that calculated by the following formula:
[GRAPHIC] [TIFF OMITTED] TC13NO91.032

Where:

d = Inside diameter in inches;
E = 0.9 Welded joint efficiency; except E = 1.0 for seamless heads;
P = Minimum required bursting pressure in psig;
S = Minimum tensile strength of plate material in p.s.i. as prescribed 
          in Sec.  179.200-7;
t = Minimum thickness of plate in inches after forming.

    (b) The wall thickness after forming of 3:1 ellipsoidal heads must 
be not less than specified in Sec.  179.201-1, nor that calculated by 
the following formula:
[GRAPHIC] [TIFF OMITTED] TC13NO91.033

Where:

d = Inside diameter in inches;
E = 0.9 Welded joint efficiency; except E = 1.0 for seamless heads;
P = Minimum required bursting pressure in psig;
S = Minimum tensile strength of plate material in p.s.i. as prescribed 
          in Sec.  179.200-7;
t = Minimum thickness of plate in inches after forming.

    (c) The wall thickness after forming of a flanged and dished head 
must be not less than specified in Sec.  179.201-1, nor that calculated 
by the following formula:
[GRAPHIC] [TIFF OMITTED] TC13NO91.034

Where:

E = 0.9 Welded joint efficiency; except E = 1.0 for seamless heads;
L = Main inside radius to which head is dished, measured on concave side 
          in inches;
P = Minimum required bursting pressure in psig;
S = Minimum tensile strength of plate material in p.s.i. as prescribed 
          in Sec.  179.200-7;
t = Minimum thickness of plate in inches after forming.

    (d) If plates are clad with material having tensile strength 
properties at least equal to the base plate, the cladding may be 
considered a part of the base plate when determining thickness. If 
cladding material does not have tensile strength at least equal to the 
base plate, the base plate alone must meet the thickness requirements.
    (e) For a tank constructed of longitudinal sections, the minimum 
width of bottom sheet of the tank must be 60 inches measured on the arc, 
but in all cases the width must be sufficient to bring the entire width 
of the longitudinal welded joint, including welds, above the bolster.
    (f) For a tank built of one piece cylindrical sections, the 
thickness specified for bottom sheet must apply to the entire 
cylindrical section.

[[Page 286]]

    (g) See Sec.  179.200-9 for thickness requirements for a 
compartmented tank.

[Amdt. 179-10, 36 FR 21349, Nov. 6, 1971, as amended at 66 FR 45390, 
Aug. 28, 2001]



Sec.  179.200-7  Materials.

    (a) Plate material used to fabricate the tank and, when used, 
expansion dome or manway nozzle material, must meet one of the following 
specifications with the indicated minimum tensile strength and 
elongation in the welded condition.
    (b) Carbon steel plate: The maximum allowable carbon content must be 
0.31 percent when the individual specification allows carbon content 
greater than this amount. The plates may be clad with other approved 
materials:

------------------------------------------------------------------------
                                              Minimum         Minimum
                                              tensile      elongation in
                                             strength        2 inches
             Specifications                  (p.s.i.)     (percent) weld
                                              welded           metal
                                           condition \1\  (longitudinal)
------------------------------------------------------------------------
AAR TC 128, Gr. B.......................          81,000              19
ASTM A 516 \2\..........................          70,000             20
------------------------------------------------------------------------
\1\ Minimum stresses to be used in calculations.
\2\ This specification is incorporated by reference (IBR, see Sec.
  171.7 of this subchapter).

    (c) Aluminum alloy plate: Aluminum alloy plate must be suitable for 
welding and comply with one of the following specifications (IBR, see 
Sec.  171.7 of this subchapter):

------------------------------------------------------------------------
                                               Minimum        Minimum
                                               tensile     elongation in
                                              strength       2 inches
              Specifications                  (p.s.i.)      (percent) 0
                                               welded       temper weld
                                            condition \3       metal
                                                 4\       (longitudinal)
------------------------------------------------------------------------
ASTM B 209, Alloy 5052 \1\................        25,000             18
ASTM B 209, Alloy 5083 \2\................        38,000             16
ASTM B 209, Alloy 5086 \1\................        35,000             14
ASTM B 209, Alloy 5154 \1\................        30,000             18
ASTM B 209, Alloy 5254 \1\................        30,000             18
ASTM B 209, Alloy 5454 \1\................        31,000             18
ASTM B 209, Alloy 5652 \1\................        25,000             18
------------------------------------------------------------------------
\1\ For fabrication, the parent plate material may be 0, H112, or H32
  temper, but design calculations must be based on minimum tensile
  strength shown.
\2\ 0 temper only.
\3\ Weld filler metal 5556 must not be used.
\4\ Maximum stresses to be used in calculations.

    (d) High alloy steel plate: High alloy steel plate must comply with 
one of the following specifications:

------------------------------------------------------------------------
                                               Minimum
                                               tensile        Minimum
                                              strength     elongation in
              Specifications                  (p.s.i.)       2 inches
                                               welded     (percent) weld
                                              condition        metal
                                                 \1\      (longitudinal)
------------------------------------------------------------------------
ASTM A 240/A 240M (incorporated by                75,000             30
 reference; see Sec.   171.7 of this
 subchapter), Type 304....................
ASTM A 240/A 240M (incorporated by                70,000             30
 reference; see Sec.   171.7 of this
 subchapter), Type 304L...................
ASTM A 240/A 240M (incorporated by                75,000             30
 reference; see Sec.   171.7 of this
 subchapter), Type 316....................
ASTM A 240/A 240M (incorporated by                70,000             30
 reference; see Sec.   171.7 of this
 subchapter), Type 316L...................
------------------------------------------------------------------------
\1\ Maximum stresses to be used in calculations.
\2\ High alloy steel materials used to fabricate tank and expansion
  dome, when used, must be tested in accordance with Practice A of ASTM
  Specification A 262 titled, ``Standard Practices for Detecting
  Susceptibility to Intergranular Attack in Austenitic Stainless
  Steels'' (IBR; see Sec.   171.7 of this subchapter). If the specimen
  does not pass Practice A, Practice B or C must be used and the
  corrosion rates may not exceed the following:


------------------------------------------------------------------------
                                                               Corrosion
           Test procedure                    Material            rate
                                                                i.p.m.
------------------------------------------------------------------------
Practice B..........................  Types 304, 304L, 316,       0.0040
                                       and 316L.
Practice C..........................  Type 304L.............       .0020
------------------------------------------------------------------------
Type 304L and Type 316L test specimens must be given a sensitizing
  treatment prior to testing. (A typical sensitizing treatment is 1 hour
  at 1250 F.)

    (e) Nickel plate: Nickel plate must comply with the following 
specification (IBR, see Sec.  171.7 of this subchapter):

------------------------------------------------------------------------
                                                Minimum
                                                tensile       Minimum
                                               strength    elongation in
               Specifications                    (psi)       2 inches
                                                welded    (percent) weld
                                               condition       metal
                                                  \1\     (longitudinal)
------------------------------------------------------------------------
ASTM B 162 \2\..............................      40,000            20
------------------------------------------------------------------------

    (f) Manganese-molybdenum steel plate: Manganese-molybdenum steel 
plate must be suitable for fusion welding and comply with the following 
specification (IBR, see Sec.  171.7 of this subchapter):

------------------------------------------------------------------------
                                                Minimum
                                                tensile       Minimum
                                               strength    elongation in
               Specifications                  (p.s.i.)      2 inches
                                                welded    (percent) weld
                                               condition       metal
                                                  \1\     (longitudinal)
------------------------------------------------------------------------
ASTM A 302, Gr. B...........................      80,000            20
------------------------------------------------------------------------
\1\ Maximum stresses to be used in calculations.


[[Page 287]]

    (g) All parts and items of construction in contact with the lading 
must be made of material compatible with plate material and not subject 
to rapid deterioration by the lading, or be coated or lined with 
suitable corrosion resistant material.
    (h) All external projections that may be in contact with the lading 
and all castings, forgings, or fabrications used for fittings or 
attachments to tank and expansion dome, when used, in contact with 
lading must be made of material to an approved specification. See AAR 
Specifications for Tank Cars, appendix M, M4.05 (IBR, see Sec.  171.7 of 
this subchapter) for approved material specifications for castings for 
fittings.

[Amdt. 179-10, 36 FR 21349, Nov. 9, 1971; 36 FR 21893, Nov. 17, 1971, as 
amended by Amdt.179-28, 46 FR 49906, Oct. 8, 1981; Amdt. 179-40, 52 FR 
13046, Apr. 20, 1987; Amdt. 179-52, 61 FR 28680, June 5, 1996; 66 FR 
45186, Aug. 28, 2001; 67 FR 51660, Aug. 8, 2002; 68 FR 75761, Dec. 31, 
2003; 70 FR 34076, June 13, 2005]



Sec.  179.200-8  Tank heads.

    (a) All external tank heads must be an ellipsoid of revolution in 
which the major axis must equal the diameter of the shell and the minor 
axis must be one-half the major axis.
    (b) Internal compartment tank heads may be 2:1 ellipsoidal, 3:1 
ellipsoidal, or flanged and dished to thicknesses as specified in Sec.  
179.200-6. Flanged and dished heads must have main inside radius not 
exceeding 10 feet, and inside knuckle radius must not be less than 3\3/
4\ inches for steel, alloy steel, or nickel tanks, and not less than 5 
inches for aluminum alloy tanks.

[Amdt. 179-10, 36 FR 21350, Nov. 6, 1971]



Sec.  179.200-9  Compartment tanks.

    (a) When a tank is divided into compartments, by inserting interior 
heads, interior heads must be inserted in accordance with AAR 
Specifications for Tank Cars, appendix E, E7.00 (IBR, see Sec.  171.7 of 
this subchapter), and must comply with the requirements specified in 
Sec.  179.201-1. Voids between compartment heads must be provided with 
at least one tapped drain hole at their lowest point, and a tapped hole 
at the top of the tank. The top hole must be closed, and the bottom hole 
may be closed, with not less than three-fourths inch and not more than 
1\1/2\-inch solid pipe plugs having NPT threads.
    (b) When the tank is divided into compartments by constructing each 
compartment as a separate tank, these tanks shall be joined together by 
a cylinder made of plate, having a thickness not less than that required 
for the tank shell and applied to the outside surface of tank head 
flanges. The cylinder shall fit the straight flange portion of the 
compartment tank head tightly. The cylinder shall contact the head 
flange for a distance of at least two times the plate thickness, or a 
minimum of 1 inch, whichever is greater. The cylinder shall be joined to 
the head flange by a full fillet weld. Distance from head seam to 
cylinder shall not be less than 1\1/2\ inches or three times the plate 
thickness, whichever is greater. Voids created by the space between 
heads of tanks joined together to form a compartment tank shall be 
provided with a tapped drain hole at their lowest point and a tapped 
hole at top of tank. The top hole shall be closed and the bottom hole 
may be closed with solid pipe plugs not less than \3/4\ inch nor more 
than 1\1/2\ inches having NPT threads.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21350, Nov. 6, 1971; 66 FR 45186, 
Aug. 28, 2001; 68 FR 75761, Dec. 31, 2003]



Sec.  179.200-10  Welding.

    (a) All joints shall be fusion-welded in compliance with the 
requirements of AAR Specifications for Tank Cars, appendix W (IBR, see 
Sec.  171.7 of this subchapter). Welding procedures, welders and 
fabricators shall be approved.
    (b) Welding is not permitted on or to ductile iron or malleable iron 
fittings.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21350, Nov. 6, 1971; 68 FR 75761, 
Dec. 31, 2003]



Sec.  179.200-11  Postweld heat treatment.

    When specified in Sec.  179.201-1, after welding is complete, 
postweld heat treatment must be in compliance with the requirements of 
AAR Specifications for Tank Cars, appendix W (IBR, see Sec.  171.7 of 
this subchapter).

[68 FR 75761, Dec. 31, 2003]

[[Page 288]]



Sec.  179.200-13  Manway ring or flange, pressure relief device flange, 
bottom outlet nozzle flange, bottom washout nozzle flange and other 
attachments and openings. 

    (a) These attachments shall be fusion welded to the tank and 
reinforced in an approved manner in compliance with the requirements of 
appendix E, figure 10, of the AAR Specifications for Tank Cars (IBR, see 
Sec.  171.7 of this subchapter).
    (b) The opening in the manway ring must be at least 16 inches in 
diameter except that acid resistant lined manways must be at least 18 
inches in diameter before lining.
    (c) The manway ring or flange, shall be made of cast, forged or 
fabricated metal. The metal of the dome, tank, or nozzle must be 
compatible with the manway ring or flange, so that they may be welded 
together.
    (d) The openings for the manway or other fittings shall be 
reinforced in an approved manner.

[Amdt. 179-40, 52 FR 13047, Apr. 20, 1987, as amended at 68 FR 75761, 
Dec. 31, 2003]



Sec.  179.200-14  Expansion capacity.

    (a) Tanks shall have expansion capacity as prescribed in this 
subchapter. This capacity shall be provided in the tank for Class DOT-
111A cars, or in a dome for Class DOT-103 and 104 type cars.
    (b) For tank cars having an expansion dome, the expansion capacity 
is the total capacity of the tank and dome combined. The capacity of the 
dome shall be measured from the inside top of shell of tank to the 
inside top of dome or bottom of any vent pipe projecting inside of dome, 
except that when a pressure relief device is applied to side of dome, 
the effective capacity of the dome shall be measured from top of the 
pressure relief device opening inside of dome to inside top of shell of 
tank.
    (c) The opening in the tank shell within the dome shall be at least 
29 inches in diameter. When the opening in the tank shell exceeds 30 
inches in diameter, the opening shall be reinforced in an approved 
manner. This additional reinforcement may be accomplished by the use of 
a dome opening of the flued-type as shown in appendix E, Figure E 10C of 
the AAR Specifications for Tank Cars or by the use of reinforcing as 
outlined in Appendix E, E3.04 and Figures E10K and E10L. When the 
opening in the tank shell is less than the inside diameter of the dome, 
and the dome pocket is not closed off in an approved manner, dome pocket 
drain holes shall be provided in the tank shell with nipples projecting 
inside the tank at least 1 inch.
    (d) The dome head shall be of approved contour and shall be designed 
for pressure on concave side.
    (e) Aluminum alloy domes: (1) The dome shell thickness shall be 
calculated by the formula in Sec.  179.200-6(a).
    (2) The dome head may be an ellipsoid of revolution in which the 
major axis shall be equal to the diameter of the dome shell and the 
minor axis shall be one-half the major axis. The thickness in this case 
shall be determined by using formula in Sec.  179.200-6(a).
    (3) The dome head, if dished, must be dished to a radius not 
exceeding 96 inches. Thickness of dished dome head must be calculated by 
the formula in Sec.  179.200-6(c).
    (4) Tank shell shall be reinforced by the addition of a plate equal 
to or greater than shell in thickness and the cross sectional area shall 
exceed metal removed for dome opening, or tank shell shall be reinforced 
by a seamless saddle plate equal to or greater than shell in thickness 
and butt welded to tank shell. The reinforcing saddle plate shall be 
provided with a fluid opening having a vertical flange of the diameter 
of the dome for butt welding shell of dome to the flange. The 
reinforcing saddle plate shall extend about the dome a distance measured 
along shell of tank at least equal to the extension at top of tank. 
Other approved designs may be used.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21350, Nov. 6, 1971; Amdt. 179-28, 46 
FR 49906, Oct. 8, 1981; Amdt. 179-52, 61 FR 28680, June 5, 1996; 66 FR 
45186, 45390, Aug. 28, 2001; 68 FR 48571, Aug. 14, 2003]



Sec.  179.200-15  Closures for manways.

    (a) Manway covers must be of approved type.

[[Page 289]]

    (b) Manway covers shall be designed to provide a secure closure of 
the manway.
    (c) Manway covers must be of approved cast, forged, or fabricated 
metals. Malleable iron, if used, must comply with ASTM A 47 (IBR, see 
Sec.  171.7 of this subchapter), Grade 35018. Cast iron manway covers 
must not be used.
    (d) All joints between manway covers and their seats shall be made 
tight against leakage of vapor and liquid by use of gaskets of suitable 
material.
    (e) For other manway cover requirements see Sec.  179.201-1.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21350, Nov. 6, 1971; Amdt. 179-37, 50 
FR 11066, Mar. 19, 1985; 68 FR 75762, Dec. 31, 2003]



Sec.  179.200-16  Gauging devices, top loading and unloading devices, 
venting and air inlet devices.

    (a) When installed, these devices shall be of an approved design 
which will prevent interchange with any other fixture, and be tightly 
closed. Unloading pipes shall be securely anchored within the tank. Each 
tank or compartment may be equipped with one separate air connection.
    (b) When the characteristics of the commodity for which the car is 
authorized are such that these devices must be equipped with valves or 
fittings to permit the loading and unloading of the contents, these 
devices, including valves, shall be of an approved design, and be 
provided with a protective housing except when plug or ball type valves 
with operating handles removed are used. Provision shall be made for 
closing pipe connections of valves.
    (c) A tank may be equipped with a vacuum relief valve of an approved 
design. Protective housing is not required.
    (d) When using a visual gauging device on a car with a hinged manway 
cover, an outage scale visible through the manway opening shall be 
provided. If loading devices are applied to permit tank loading with 
cover closed, a telltale pipe may be provided. Telltale pipe shall be 
capable of determining that required outage is provided. Pipe shall be 
equipped with \1/4\ inch minimum NPT control valve mounted outside tank 
and enclosed within a housing. Other approved devices may be used in 
lieu of outage scale or telltale pipe.
    (e) Bottom of tank shell may be equipped with a sump or siphon bowl, 
or both, welded or pressed into the shell. Such sumps or siphon bowls, 
if applied are not limited in size and must be made of cast, forged, or 
fabricated metal. Each sump or siphon bowl must be of good welding 
quality in conjunction with the metal of the tank shell. When sump or 
siphon bowl is pressed in the bottom of the tank shell, the wall 
thickness of the pressed section must not be less than that specified 
for the shell. The section of a circular cross section tank to which a 
sump or siphon bowl is attached need not comply with the out-of-
roundness requirement specified in appendix W, W14.06, of the AAR 
Specifications for Tank Cars. Any portion of a sump or siphon bowl not 
forming a part of a cylinder of revolution must have walls of such 
thickness and be so reinforced that the stresses in the walls caused by 
a given internal pressure are not greater than the circumferential 
stress which would exist under the same internal pressure in the wall of 
a tank of circular cross section designed in accordance with Sec.  
179.200-6 (a) and (d). In no case shall the wall thickness be less than 
that specified in Sec.  179.201-1.
    (f) When top loading and discharge devices, or venting and air inlet 
devices are installed with exposed piping to a removed location, shutoff 
valves must be applied directly to reinforcing pads or nozzles at their 
communication through the tank shell, and must be enclosed in a 
protective housing with provision for a seal. The piping must include 
breakage grooves, and suitable bracing. Relief valves must be applied to 
liquid lines for protection in case lading is trapped. Provision must be 
made to insure closure of the valves while the car is in transit.
    (g) Protective housing, when required, must be fabricated of 
approved material and have cover and sidewalls not less than 0.119 inch 
in thickness.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21350, Nov. 6, 1971; Amdt. 179-52, 61 
FR 28680, June 5, 1996; 69 FR 54047, Sept. 7, 2004]

[[Page 290]]



Sec.  179.200-17  Bottom outlets.

    (a) If indicated in Sec.  179.201-1, tank may be equipped with 
bottom outlet. Bottom outlet, if applied, must comply with the following 
requirements:
    (1) The extreme projection of the bottom outlet equipment may not be 
more than that allowed by appendix E of the AAR Specifications for Tank 
Cars (IBR, see Sec.  171.7 of this subchapter). All bottom outlet 
reducers and closures and their attachments shall be secured to the car 
by at least \3/8\-inch chain, or its equivalent, except that the bottom 
outlet closure plugs may be attached by \1/4\-inch chain. When the 
bottom outlet closure is of the combination cap and valve type, the pipe 
connection to the valve shall be closed by a plug, cap, or approved 
quick coupling device. The bottom outlet equipment should include only 
the valve, reducers and closures that are necessary for the attachment 
of unloading fixtures. The permanent attachment of supplementary 
exterior fittings shall be approved by the AAR Committee on Tank Cars.
    (2) Bottom outlet must be of approved construction, and be provided 
with a liquid-tight closure at its lower end.
    (3) On cars with center sills, a ball valve may be welded to the 
outside bottom of the tank or mounted on a pad or nozzle with a tongue 
and groove or male and female flange attachment. In no case shall the 
breakage groove or equivalent extend below the bottom flange of the 
center sill. On cars without continuous center sills, a ball valve may 
be welded to the outside bottom of the tank or mounted with a tongue and 
groove or male and female flange attachment on a pad attached to the 
outside bottom of the tank. The mounting pad must have a maximum 
thickness of 2\1/2\ inches measured on the longitudinal centerline of 
the tank. The valve operating mechanism must be provided with a suitable 
locking arrangement to insure positive closure during transit.
    (4) The valve operating mechanism for valves applied to the interior 
of the tank, and outlet nozzle construction, must insure against the 
unseating of the valve due to stresses or shocks incident to 
transportation.
    (5) Bottom outlet nozzle of interior valves and the valve body of 
exterior valves, must be of cast, fabricated, or forged metal. If welded 
to tank, they must be of good weldable quality in conjunction with metal 
of tank.
    (6) To provide for the attachment of unloading connections, the 
discharge end of the bottom outlet nozzle or reducer, the valve body of 
the exterior valve, or some fixed attachment thereto, shall be provided 
with one of the following arrangements or an approved modification 
thereof. (See appendix E. Fig. E17 of the AAR Specifications for Tank 
Cars for illustrations of some of the possible arrangements.)
    (i) A bolted flange closure arrangement including a minimum 1-inch 
NPT pipe plug (see Fig. E17.1) or including an auxiliary valve with a 
threaded closure.
    (ii) A threaded cap closure arrangement including a minimum 1-inch 
NPT pipe plug (see Fig. E17.2) or including an auxiliary valve with a 
threaded closure.
    (iii) A quick-coupling device using a threaded plug closure of at 
least 1-inch NPT or having a threaded cap closure with a minimum 1-inch 
NPT pipe plug (see Fig. E17.3 through E17.5). A minimum 1-inch auxiliary 
test valve with a threaded closure may be substituted for the 1-inch 
pipe plug (see Fig. E17.6). If the threaded cap closure does not have a 
pipe plug or integral auxiliary test valve, a minimum 1-inch NPT pipe 
plug shall be installed in the outlet nozzle above the closure (see Fig. 
E17.7).
    (iv) A two-piece quick-coupling device using a clamped dust cap must 
include an in-line auxiliary valve, either integral with the quick-
coupling device or located between the primary bottom outlet valve and 
the quick-coupling device. The quick-coupling device closure dust cap or 
outlet nozzle shall be fitted with a minimum 1-inch NPT closure (see 
Fig. E17.8 and E17.9).
    (7) If the outlet nozzle extends 6 inches or more from the shell of 
the tank, a V-shaped breakage groove shall be cut (not cast) in the 
upper part of the outlet nozzle at a point immediately below the lowest 
part of valve closest to the tank. In no case may the nozzle wall 
thickness at the root of the ``V'' be more than \1/4\ inch. The outlet 
nozzle on interior valves or the valve

[[Page 291]]

body on exterior valves may be steam jacketed, in which case the 
breakage groove or its equivalent must be below the steam chamber but 
above the bottom of center sill construction. If the outlet nozzle is 
not a single piece, or if exterior valves are applied, provisions shall 
be made for the equivalent of the breakage groove. On cars without 
continuous center sills, the breakage groove or its equivalent must be 
no more than 15 inches below the tank shell. On cars with continuous 
center sills, the breakage groove or its equivalent must be above the 
bottom of the center sill construction.
    (8) The flange on the outlet nozzle or the valve body of exterior 
valves must be of a thickness which will prevent distortion of the valve 
seat or valve by any change in contour of the shell resulting from 
expansion of lading, or other causes, and which will insure that 
accidental breakage of the outlet nozzle will occur at or below the 
``V'' groove, or its equivalent.
    (9) The valve must have no wings or stem projecting below the ``V'' 
groove or its equivalent. The valve and seat must be readily accessible 
or removable for repairs, including grinding.
    (10) The valve operating mechanism on interior valves must have 
means for compensating for variation in the vertical diameter of the 
tank produced by expansion, weight of the liquid contents, or other 
causes, and may operate from the interior of the tank, but in the event 
the rod is carried through the dome, or tank shell, leakage must be 
prevented by packing in stuffing box or other suitable seals and a cap.
    (b) If indicated in Sec.  179.201-1, tank may be equipped with 
bottom washout of approved construction. If applied, bottom washout 
shall be in accordance with the following requirements:
    (1) The extreme projection of the bottom washout equipment may not 
be more than that allowed by appendix E of the AAR Specifications for 
Tank Cars.
    (2) Bottom washout shall be of cast, forged or fabricated metal. If 
welded to tank, they shall be of good weldable quality in conjunction 
with metal of tank.
    (3) If the washout nozzle extends 6 inches or more from the shell of 
the tank, a V-shaped breakage groove shall be cut (not cast) in the 
upper part of the nozzle at a point immediately below the lowest part of 
the inside closure seat or plug. In no case may the nozzle wall 
thickness at the root of the ``V'' be more than \1/4\ inch. Where the 
nozzle is not a single piece, provisions shall be made for the 
equivalent of the breakage groove. The nozzle must be of a thickness to 
insure that accidental breakage will occur at or below the ``V'' groove 
or its equivalent. On cars without continuous center sills, the breakage 
groove or its equivalent may not be more than 15 inches below the outer 
shell. On cars with continuous center sills, the breakage groove or its 
equivalent must be above the bottom of the center sill construction.
    (4) The closure plug and seat must be readily accessible or 
removable for repairs, including grinding.
    (5) The closure of the washout nozzle must be equipped with a \3/4\-
inch solid screw plug. Plug must be attached by at least a \1/4\-inch 
chain.
    (6) Joints between closures and their seats may be gasketed with 
suitable material.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21351, Nov. 6, 1971; Amdt. 179-40, 52 
FR 13047, Apr. 20, 1987; 68 FR 75762, Dec. 31, 2003]



Sec.  179.200-19  Reinforcements, when used, and appurtenances not 
otherwise specified.

    (a) All attachments to tank and dome shall be applied by approved 
means. Rivets if used shall be caulked inside and outside.
    (b) Reinforcing pads must be used between external brackets and 
shells if the attachment welds exceed 6 lineal inches of \1/4\-inch 
fillet or equivalent weld per bracket or bracket leg. When reinforcing 
pads are used, they must not be less than one-fourth inch in thickness, 
have each corner rounded to a 1 inch minimum radius, and be attached to 
the tank by continuous fillet welds except for venting provisions. The 
ultimate shear strength of the bracket to reinforcing pad weld must not 
exceed 85 percent of the ultimate

[[Page 292]]

shear strength of the reinforcing pad to tank weld.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21351, Nov. 6, 1971]



Sec.  179.200-21  Closures for openings.

    (a) All plugs shall be solid, with NPT threads, and shall be of a 
length which will screw at least 6 threads inside the face of fitting or 
tank. Plugs, when inserted from the outside of tank heads, shall have 
the letter ``S'' at least \3/8\ inch in size stamped with steel stamp or 
cast on the outside surface to indicate the plug is solid.
    (b) [Reserved]



Sec.  179.200-22  Test of tanks.

    (a) Each tank shall be tested by completely filling the tank and 
dome or nozzles with water, or other liquid having similar viscosity, of 
a temperature which shall not exceed 100 [deg]F. during the test; and 
applying the pressure prescribed in Sec.  179.201-1. Tank shall hold the 
prescribed pressure for at least 10 minutes without leakage or evidence 
of distress. All rivets and closures, except safety relief valves or 
safety vents, shall be in place when test is made.
    (b) Insulated tanks shall be tested before insulation is applied.
    (c) Rubber-lined tanks shall be tested before rubber lining is 
applied.
    (d) Caulking of welded joints to stop leaks developed during the 
foregoing tests is prohibited. Repairs in welded joints shall be made as 
prescribed in AAR Specifications for Tank Cars, appendix W (IBR, see 
Sec.  171.7 of this subchapter).

[29 FR 18995, Dec. 29, 1964, as amended at 68 FR 75762, Dec. 31, 2003]



Sec.  179.200-23  Tests of pressure relief valves.

    (a) Each valve shall be tested by air or gas for compliance with 
Sec.  179.15 before being put into service.
    (b) [Reserved]

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
as amended at 62 FR 51561, Oct. 1, 1997]



Sec.  179.200-24  Stamping.

    (a) To certify that the tank complies with all specification 
requirements, each tank shall be plainly and permanently stamped in 
letters and figures at least \3/8\ inch high into the metal near the 
center of both outside heads as follows:

------------------------------------------------------------------------
                                            Example of required stamping
------------------------------------------------------------------------
Specification.............................  DOT-111A
Material..................................  ASTM A 516-GR 70
Cladding material (if any)................  ASTM A240-304 Clad
Tank builder's initials...................  ABC
Date of original test.....................  00-0000
Car assembler (if other than tank builder)  DEF
------------------------------------------------------------------------

    (b) On Class DOT-111 tank cars, the last numeral of the 
specification number may be omitted from the stamping; for example, DOT-
111A100W.
    (c) After July 25, 2012, newly constructed DOT tank cars must have 
their DOT specification and other required information stamped plainly 
and permanently on stainless steel identification plates in conformance 
with the applicable requirements prescribed in Sec.  179.24(a). Tank 
cars built before July 25, 2012, may have the identification plates 
instead of or in addition to the head stamping.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21351, Nov. 6, 1971; Amdt. 179-52, 61 
FR 28680, June 5, 1996; 68 FR 48571, Aug. 14, 2003; 77 FR 37985, June 
25, 2012]



Sec.  179.201  Individual specification requirements applicable to   
non-pressure tank car tanks.



Sec.  179.201-1  Individual specification requirements.

    In addition to Sec.  179.200, the individual specification 
requirements are as follows:

[[Page 293]]



--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                    Minimum
                                                        Bursting     plate      Test                                               References (179.201 -
      DOT Specification \1\             Insulation      pressure   thickness  pressure     Bottom outlet        Bottom washout             ***)
                                                         (psig)    (inches)    (psig)
--------------------------------------------------------------------------------------------------------------------------------------------------------
111A60ALW1.......................  Optional...........       240       \1/2\        60  Optional...........  Optional...........  6(a).
111A60ALW2.......................  Optional...........       240       \1/2\        60  No.................  Optional.
111A60W1.........................  Optional...........       240      \7/16\        60  Optional...........  Optional...........  6(a).
111A60W2.........................  Optional...........       240      \7/16\        60  No.................  Optional.
111A60W5.........................  Optional...........       240      \7/16\        60  No.................  No.................  3, 6(b).
111A60W6.........................  Optional...........       240      \7/16\        60  Optional...........  Optional...........  4, 5, 6(a), 6(c).
111A60W7.........................  Optional...........       240      \7/16\        60  No.................  No.................  4, 5, 6(a).
111A100ALW1......................  Optional...........       500       \5/8\       100  Optional...........  Optional...........  6(a).
111A100ALW2......................  Optional...........       500       \5/8\       100  No.................  Optional.
111A100W1........................  Optional...........       500      \7/16\       100  Optional...........  Optional...........  6(a).
111A100W2........................  Optional...........       500      \7/16\       100  No.................  Optional.
111A100W3........................  Yes................       500      \7/16\       100  Optional...........  Optional...........  6(a).
111A100W4........................  Yes (see 179.201-         500      \7/16\       100  No.................  No.................  6(a), 8, 10.
                                    11).
111A100W5........................  Optional...........       500      \7/16\       100  No.................  No.................  3.
111A100W6........................  Optional...........       500      \7/16\       100  Optional...........  Optional...........  4, 5, 6(a) and 6(c).
111A100W7........................  Optional...........       500      \7/16\       100  No.................  No.................  4, 5, 6(c).
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Tanks marked ``ALW'' are constructed from aluminum alloy plate; ``AN'' nickel plate; ``CW,'' ``DW,'' ``EW,'' ``W6,'' and ``W7'' high alloy steel or
  manganese-molybdenum steel plate; and those marked ``BW'' or ``W5'' must have an interior lining that conforms to Sec.   179.201-3.


[Amdt. 179-52, 61 FR 28680, June 5, 1996, as amended by 66 FR 45390, 
Aug. 28, 2001; 68 FR 48571, Aug. 14, 2003]



Sec.  179.201-2  [Reserved]



Sec.  179.201-3  Lined tanks.

    (a) Rubber-lined tanks. (1) Each tank or each compartment thereof 
must be lined with acid-resistant rubber or other approved rubber 
compound vulcanized or bonded directly to the metal tank, to provide a 
nonporous laminated lining, at least \5/32\-inch thick, except overall 
rivets and seams formed by riveted attachments in the lining must be 
double thickness. The rubber lining must overlap at least 1\1/2\ inches 
at all edges which must be straight and be beveled to an angle of 
approximately 45[deg], or butted edges of lining must be sealed with a 
3-inch minimum strip of lining having 45[deg] beveled edges.
    (2) As an alternate method, the lining may be joined with a skived 
butt seam then capped with a separate strip of lining 3 inches wide 
having 45[deg] beveled edges. An additional rubber reinforcing pad at 
least 4\1/2\ feet square and at least \1/2\-inch thick must be applied 
by vulcanizing to the lining on bottom of tank directly under the manway 
opening. The edges of the rubber pad must be beveled to an angle of 
approximately 45[deg]. An opening in this pad for sump is permitted. No 
lining must be under tension when applied except due to conformation 
over rivet heads. Interior of tank must be free from scale, oxidation, 
moisture, and all foreign matter during the lining operation.
    (3) Other approved lining materials may be used provided the 
material is resistant to the corrosive or solvent action of the lading 
in the liquid or gas phase and is suitable for the service temperatures.
    (b) Before a tank car tank is lined with rubber, or other rubber 
compound, a report certifying that the tank and its equipment have been 
brought into compliance with spec. DOT-111A60W5 or 111A100W5 must be 
furnished by car owner to the party who is to apply the lining. A copy 
of this report in approved form, certifying that tank has been lined in 
compliance with all requirements of one of the above specifications, 
must be furnished by party lining tank to car owner. Reports of the 
latest lining application must be retained by the car owner until the 
next relining has been accomplished and recorded.
    (c) All rivet heads on inside of tank must be buttonhead, or similar 
shape, and of uniform size. The under surface of heads must be driven 
tight against the plate. All plates, castings and rivet heads on the 
inside of the tank must be calked. All projecting edges of plates, 
castings and rivet heads on the inside of the tank must be rounded and 
free

[[Page 294]]

from fins and other irregular projections. Castings must be free from 
porosity.
    (d) All surfaces of attachments or fittings and their closures 
exposed to the lading must be covered with at least \1/8\-inch acid 
resistant material. Attachments made of metal not affected by the lading 
need not be covered with rubber or other acid resistant material.
    (e) Hard rubber or polyvinyl chloride may be used for pressure 
retaining parts of safety vents provided the material is resistant to 
the corrosive or solvent action of the lading in the liquid or gas phase 
and is suitable for the service temperatures.
    (f) Polyvinyl chloride lined tanks. Tank car tanks or each 
compartment thereof may be lined with elastomeric polyvinyl chloride 
having a minimum lining thickness of three thirty-seconds inch.
    (g) Polyurethane lined tanks. Tank car tanks or each compartment 
thereof may be lined with elastomeric polyurethane having a minimum 
lining thickness of one-sixteenth inch.

[Amdt. 179-10, 36 FR 21352, Nov. 6, 1971, as amended at 66 FR 45186, 
Aug. 28, 2001; 68 FR 48571, Aug. 14, 2003]



Sec.  179.201-4  Material.

    All fittings, tubes, and castings and all projections and their 
closures, except for protective housing, must also meet the requirements 
specified in ASTM A 262 (IBR, see Sec.  171.7 of this subchapter), 
except that when preparing the specimen for testing the carburized 
surface may be finished by grinding or machining.

[68 FR 75762, Dec. 31, 2003]



Sec.  179.201-5  Postweld heat treatment and corrosion resistance.

    (a) Tanks and attachments welded directly thereto must be postweld 
heat treated as a unit at the proper temperature except as indicated 
below. Tanks and attachments welded directly thereto fabricated from 
ASTM A 240/A 240M (IBR, see Sec.  171.7 of this subchapter) Type 430A, 
Type 304 and Type 316 materials must be postweld heat treated as a unit 
and must be tested to demonstrate that they possess the corrosion 
resistance specified in Sec.  179.200-7(d), Footnote 2. Tanks and 
attachments welded directly thereto, fabricated from ASTM A 240/A 240M 
Type 304L or Type 316L materials are not required to be postweld heat 
treated.
    (b) Tanks and attachments welded directly thereto, fabricated from 
ASTM A 240/A 240M Type 304L and Type 316 materials must be tested to 
demonstrate that they possess the corrosion resistance specified in 
Sec.  179.200-7(d), Footnote 2.

[68 FR 75762, Dec. 31, 2003]



Sec.  179.201-6  Manways and manway closures.

    (a) The manway cover for spec. DOT 104W, 111A60ALW1, 111A60W1, 
111A100ALW1, 111A100W1, 111A100W3, or 111A100W6 must be designed to make 
it impossible to remove the cover while the interior of the tank is 
subjected to pressure.
    (b) The manway cover for spec. DOT 111A60W5, or 111A100W5 must be 
made of a suitable metal. The top, bottom and edge of manway cover must 
be acid resistant material covered as prescribed in Sec.  179.201-3. 
Through-bolt holes must be lined with acid resistant material at least 
one-eighth inch in thickness. A manway cover made of metal not affected 
by the lading need not be acid resistant material covered.
    (c) The manway ring and cover for specifications DOT-103CW, 103DW, 
103EW, 111A60W7, or 111A100W6 must be made of the metal and have the 
same inspection procedures specified in AAR Specifications for Tank 
Cars, appendix M, M3.03 (IBR, see Sec.  171.7 of this subchapter).

[85 FR 83403, Dec. 21, 2020]



Sec.  179.201-8  Sampling device and thermometer well.

    (a) Sampling valve and thermometer well are not specification 
requirements. When used, they must be of approved design, made of metal 
not subject to rapid deterioration by lading, and must withstand a 
pressure of 100 psig without leakage. Interior pipes of the sampling 
valve must be equipped with excess flow valves of an approved design. 
Interior pipe of thermometer well must be closed by an approved valve 
attached close to fitting where it

[[Page 295]]

passes through the tank and closed by a screw plug. Other approved 
arrangements that permit testing thermometer well for leaks without 
complete removal of the closure may be used.
    (b) [Reserved]

[Amdt. 179-10, 36 FR 21348, Nov. 6, 1971, as amended at 66 FR 45390, 
Aug. 28, 2001]



Sec.  179.201-9  Gauging device.

    A gauging device of an approved design must be applied to permit 
determining the liquid level of the lading. The gauging device must be 
made of materials not subject to rapid deterioration by the lading. When 
the interior pipe of the gauging device provides a means for passage of 
the lading from the interior to the exterior of the tank, it must be 
equipped with an excess flow valve of an approved design. If the opening 
for passage of lading through the gauging device is not more than 0.060 
inch diameter an excess flow valve is not required. The gauging device 
must be provided with a protective housing.

[Amdt. 179-10, 36 FR 21353, Nov. 6, 1971]



Sec.  179.201-10  Water capacity marking.

    (a) Water capacity of the tank in pounds stamped plainly and 
permanently in letters and figures at least \3/8\ inch high into the 
metal of the tank immediately below the stamped marks specified in Sec.  
179.200-24(a). This mark shall also be stenciled on the jacket 
immediately below the dome platform and directly behind or within 3 feet 
of the right or left side of the ladder, or ladders, if there is a 
ladder on each side of the tank, in letters and figures at least 1\1/2\ 
inches high as follows:

                             water capacity

                              000000 Pounds

    (b) After July 25, 2012, authorized DOT non-pressure tank cars that 
comply with this section and are equipped with stainless steel 
identification plates may have the water capacity of the tank in pounds 
prescribed in the first sentence of paragraph (a) of this section 
stamped plainly and permanently on their identification plate in 
conformance with the applicable marking requirements prescribed in Sec.  
179.24(a) instead of into the metal of the tank or immediately below the 
stamped marks specified in Sec.  179.200-24(a).

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967. 
Amended at 77 FR 37985, June 25, 2012]



Sec.  179.201-11  Insulation.

    (a) Insulation shall be of sufficient thickness so that the thermal 
conductance at 60 [deg]F. is not more than 0.075 Btu per hour, per 
square foot, per degree F. temperature differential.
    (b) [Reserved]



Sec.  179.202  Individual specification requirements applicable to DOT-117 
tank car tanks.



Sec.  179.202-1  Applicability.

    Each tank built under these specifications must conform to the 
general requirements of Sec.  179.200 and the prescriptive standards in 
Sec. Sec.  179.202-1 through 179.202-11, or the performance standard 
requirements of Sec.  179.202-12.

[80 FR 26749, May 8, 2015]



Sec.  179.202-2  [Reserved]



Sec.  179.202-3  Approval to operate at 286,000 gross rail load (GRL).

    A tank car may be loaded to a gross weight on rail of up to 286,000 
pounds (129,727 kg) upon approval by the Associate Administrator for 
Safety, Federal Railroad Administration (FRA). See Sec.  179.13.

[80 FR 26749, May 8, 2015]



Sec.  179.202-4  Thickness of plates.

    The wall thickness after the forming of the tank shell and heads 
must be, at a minimum, 9/16 of an inch AAR TC-128 Grade B, normalized 
steel, in accordance with Sec.  179.200-7(b).

[80 FR 26749, May 8, 2015]



Sec.  179.202-5  Tank head puncture resistance system.

    The DOT-117 specification tank car must have a tank head puncture 
resistance system in conformance with Sec.  179.16(c). The full height 
head shields must have a minimum thickness of \1/2\ inch.

[80 FR 26749, May 8, 2015]

[[Page 296]]



Sec.  179.202-6  Thermal protection system.

    The DOT Specification 117 tank car must have a thermal protection 
system. The thermal protection system must:
    (a) Conform to Sec.  179.18 of this part;
    (b) Be equipped with a thermal protection blanket with at least \1/
2\-inch-thick material that meets Sec.  179.18(c) of this part; and
    (c) Include a reclosing pressure relief device in accordance with 
Sec.  173.31 of this subchapter.

[81 FR 53957, Aug. 15, 2016]



Sec.  179.202-7  Jackets.

    The entire thermal protection system must be covered with a metal 
jacket of a thickness not less than 11 gauge A1011 steel or equivalent; 
and flashed around all openings so as to be weather tight. A protective 
coating must be applied to the exterior surface of a carbon steel tank 
and the inside surface of a carbon steel jacket.

[80 FR 26749, May 8, 2015]



Sec.  179.202-8  Bottom outlets.

    If the tank car is equipped with a bottom outlet, the handle must be 
removed prior to train movement or be designed with protection safety 
system(s) to prevent unintended actuation during train accident 
scenarios.

[80 FR 26749, May 8, 2015]



Sec.  179.202-9  Top fittings protection.

    The tank car tank must be equipped with top fittings protection 
conforming to AAR Specifications for Tank Cars, appendix E paragraph 
10.2.1 (IBR, see Sec.  171.7 of this subchapter).

[80 FR 26749, May 8, 2015]



Sec.  179.202-11  Individual specification requirements.

    In addition to Sec.  179.200, the individual specification 
requirements are as follows:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                           Minimum plate
            DOT specification                       Insulation               Bursting        thickness      Test pressure           Bottom outlet
                                                                         pressure (psig)      (Inches)          (psig)
--------------------------------------------------------------------------------------------------------------------------------------------------------
117A100W.................................  Optional....................             500             9/16              100   Optional.
--------------------------------------------------------------------------------------------------------------------------------------------------------


[80 FR 26749, May 8, 2015]



Sec.  179.202-12  Performance standard requirements (DOT-117P).

    (a) Approval. Design, testing, and modeling results must be reviewed 
and approved by the Associate Administrator for Railroad Safety/Chief 
Safety Officer, Federal Railroad Administration (FRA), 1200 New Jersey 
Ave. SE., Washington, DC 20590.
    (b) Approval to operate at 286,000 gross rail load (GRL). In 
addition to the requirements of paragraph (a) of this section, a tank 
car may be loaded to a gross weight on rail of up to 286,000 pounds 
(129,727 kg) upon approval by the Associate Administrator for Safety, 
Federal Railroad Administration (FRA). See Sec.  179.13.
    (c) Puncture resistance. (1) Minimum side impact speed: 12 mph when 
impacted at the longitudinal and vertical center of the shell by a rigid 
12-inch by 12-inch indenter with a weight of 286,000 pounds.
    (2) Minimum head impact speed: 18 mph when impacted at the center of 
the head by a rigid 12-inch by 12-inch indenter with a weight of 286,000 
pounds.
    (d) Thermal protection systems. The tank car must be equipped with a 
thermal protection system. The thermal protection system must be 
equivalent to the performance standard prescribed in Sec.  179.18 and 
include a reclosing pressure relief device in accordance with Sec.  
173.31 of this subchapter.
    (e) Bottom outlet. If the tank car is equipped with a bottom outlet, 
the handle must be removed prior to train movement or be designed with 
protection safety system(s) to prevent unintended actuation during train 
accident scenarios.
    (f) Top fittings protection. The tank car tank must be equipped with 
top fittings protection conforming to AAR

[[Page 297]]

Specifications for Tank Cars, appendix E paragraph 10.2.1 (IBR, see 
Sec.  171.7 of this subchapter).

[80 FR 26749, May 8, 2015, as amended at 81 FR 53957, Aug. 15, 2016; 83 
FR 48401, Sept. 25, 2018]



Sec.  179.202-13  Retrofit standard requirements (DOT-117R).

    (a) Applicability. Each tank retrofit under these specifications 
must conform to the general requirements of Sec.  179.200 and the 
prescriptive standards in Sec.  179.202-13, or the performance standard 
requirements of Sec.  179.202-12.
    (b) Approval to operate at 286,000 gross rail load (GRL). A tank car 
may be loaded to a gross weight on rail of up to 286,000 pounds (129,727 
kg) upon approval by the Associate Administrator for Safety, Federal 
Railroad Administration (FRA). See Sec.  179.13.
    (c) Thickness of plates. The wall thickness after forming of the 
tank shell and heads must be, at a minimum, 7/16 of an inch, and 
constructed with steel authorized by the HMR at the time of 
construction.
    (d) Tank head puncture resistance system. The DOT-117R specification 
tank car must have a tank head puncture resistance system in conformance 
with Sec.  179.16(c). The full height head shields must have a minimum 
thickness of \1/2\ inch.
    (e) Thermal protection system. (1) The DOT Specification 117R tank 
car must have a thermal protection system. The thermal protection system 
must conform to Sec.  179.18 of this part and include a reclosing 
pressure relief device in accordance with Sec.  173.31 of this 
subchapter.
    (2) A non-jacketed tank car modified to the DOT Specification 117R 
must be equipped with a thermal protection blanket with at least \1/2\-
inch-thick material that meets Sec.  179.18(c) of this part.
    (f) Jackets. The entire thermal protection system must be covered 
with a metal jacket of a thickness not less than 11 gauge A1011 steel or 
equivalent; and flashed around all openings so as to be weather tight. 
The exterior surface of a carbon steel tank and the inside surface of a 
carbon steel jacket must be given a protective coating.
    (g) Bottom outlets. If the tank car is equipped with a bottom 
outlet, the handle must be removed prior to train movement or be 
designed with protection safety system(s) to prevent unintended 
actuation during train accident scenarios.
    (h) Top fittings protection--(1) Protective housing. Except as 
provided in Sec. Sec.  179.202-13(h)(2) and (3) of this paragraph, top 
fittings on DOT Specification 117R tank cars must be located inside a 
protective housing not less than 1/2-inch in thickness and constructed 
of a material having a tensile strength not less than 65 kpsi and must 
conform to all of the following conditions:
    (i) The protective housing must have a height exceeding the tallest 
valve or fitting which requires protection and the height of a valve or 
fitting within the protective housing must be kept to the minimum size 
compatible to allow for proper operation.
    (ii) The protective housing or cover may not reduce the flow 
capacity of a pressure relief device below the minimum required.
    (iii) The protective housing must provide a means of drainage with a 
minimum flow area equivalent to six (6) 1-inch diameter weep holes.
    (iv) When connected to the nozzle or fitting cover plate, and 
subject to a horizontal force applied perpendicular to and uniformly 
over the projected plane of the protective housing, the tensile 
connection strength of the protective housing must be designed to be--
    (A) no greater than 70 percent of the nozzle to tank tensile 
connection strength;
    (B) no greater than 70 percent of the cover plate to nozzle 
connection strength; and
    (C) no less than either 40 percent of the nozzle to tank tensile 
connection strength or the shear strength of twenty (20) 12-inch bolts.
    (2) Pressure relief devices. (i) The pressure relief device(s) must 
be located inside the protective housing, unless space does not allow 
for placement within a housing. If multiple pressure relief devices are 
installed, no more than one (1) may be located outside of a protective 
housing.
    (ii) The height of a pressure relief device located outside of a 
protective housing in accordance with paragraph

[[Page 298]]

(h)(2)(i) of this section may not exceed the tank car jacket by more 
than 12 inches.
    (iii) The highest point of a closure of any unused pressure relief 
device nozzle may not exceed the tank car jacket by more than six (6) 
inches.
    (3) Alternative. As an alternative to the protective housing 
requirements in paragraph (h)(1) of this section, the tank car may be 
equipped with a system that prevents the release of contents from any 
top fitting under accident conditions where any top fitting may be 
sheared off.

[80 FR 26749, May 8, 2015, as amended at 81 FR 53957, Aug. 15, 2016; 83 
FR 48401, Sept. 25, 2018; 85 FR 83403, Dec. 21, 2020]



Sec. Sec.  179.203--179.202-22  [Reserved]



Sec.  179.220  General specifications applicable to nonpressure tank car 
tanks consisting of an inner container supported within an outer shell 
(class DOT-115).



Sec.  179.220-1  Tanks built under these specifications must meet the 
requirements of Sec. Sec.  179.220 and 179.221.



Sec.  179.220-3  Type.

    (a) Tanks built under these specifications must consist of an inner 
container, a support system for the inner container, and an outer shell.
    (b) The inner container must be a fusion welded tank of circular 
cross section with formed heads designed convex outward and must have a 
manway on top of the tank as prescribed herein. When the inner container 
is divided into compartments, each compartment must be considered a 
separate container.
    (c) The outer shell must be a fusion welded tank with formed heads 
designed convex outward.

[Amdt. 179-9, 36 FR 21340, Nov. 6, 1971]



Sec.  179.220-4  Insulation.

    The annular space between the inner container and the outer shell 
must contain an approved insulation material.

[Amdt. 179-9, 36 FR 21340, Nov. 6, 1971]



Sec.  179.220-6  Thickness of plates.

    (a) The wall thickness, after forming of the inner container shell 
and 2:1 ellipsoidal heads must be not less than specified in Sec.  
179.221-1, or not less than that calculated by the following formula:
[GRAPHIC] [TIFF OMITTED] TC13NO91.035

Where:

d = Inside diameter in inches;
E = 0.9 welded joint efficiency; except E = 1.0 for seamless heads;
P = Minimum required bursting pressure in psig;
S = Minimum tensile strength of plate material in p.s.i. as prescribed 
          in AAR Specifications for Tank Cars, appendix M, Table M1;
t = Minimum thickness of plate in inches after forming.

    (b) The wall thickness after forming of the inner container heads, 
if flanged and dished, must be not less than specified in Sec.  179.221-
1, or not less than that calculated by the following formula:
[GRAPHIC] [TIFF OMITTED] TC13NO91.036

Where:

E = 0.9 welded joint efficiency; except E = 1.0 for seamless heads;
L = Main inside radius to which head is dished, measured on concave side 
          in inches;
P = Minimum required bursting pressure in psig;
S = Minimum tensile strength of plate material in psi as prescribed in 
          AAR Specifications for Tank Cars, appendix M, Table M1 (IBR, 
          see Sec.  171.7 of this subchapter);
t = Minimum thickness of plate in inches after forming.

    (c) The wall thickness after forming of the cylindrical section and 
heads of the outer shell must be not less than seven-sixteenths of an 
inch.
    (d) See Sec.  179.220-9 for plate thickness requirements for inner 
container when divided into compartments.

[Amdt. 179-9, 36 FR 21340, Nov. 6, 1971, as amended at 66 FR 45390, Aug. 
28, 2001; 68 FR 75762, Dec. 31, 2003]

[[Page 299]]



Sec.  179.220-7  Materials.

    (a) The plate material used to fabricate the inner container and 
nozzles must meet one of the following specifications and with the 
indicated minimum tensile strength and elongation in the welded 
condition.
    (b) Carbon steel plate: The maximum allowable carbon content must be 
0.31 percent when the individual specification allows carbon content 
greater than this amount. The plates may be clad with other approved 
materials.

------------------------------------------------------------------------
                                                Minimum
                                                tensile       Minimum
                                               strength    elongation in
               Specifications                  (p.s.i.)      2 inches
                                                welded    (percent) weld
                                               condition       metal
                                                  \1\     (longitudinal)
------------------------------------------------------------------------
AAR TC 128, Gr. B...........................      81,000            19
ASTM A 516 \2\, Gr. 70......................      70,000           20
------------------------------------------------------------------------
\1\ Maximum stresses to be used in calculations.
\2\ This specification is incorporated by reference (IBR, see Sec.
  171.7 of this subchapter).

    (c) Aluminum alloy plate: Aluminum alloy plate must be suitable for 
welding and comply with one of the following specifications (IBR, see 
Sec.  171.7 of this subchapter): * * *

------------------------------------------------------------------------
                                               Minimum
                                               tensile        Minimum
                                               strength    elongation in
               Specifications                  (p.s.i.)      2 inches
                                                welded    (percent) weld
                                             condition\3       metal
                                                  4\      (longitudinal)
------------------------------------------------------------------------
ASTM B 209, Alloy 5052 \1\.................       25,000            18
ASTM B 209, Alloy 5083 \2\.................       38,000            16
ASTM B 209, Alloy 5086 \1\.................       35,000            14
ASTM B 209, Alloy 5154 \1\.................       30,000            18
ASTM B 209, Alloy 5254 \1\.................       30,000            18
ASTM B 209, Alloy 5454 \1\.................       31,000            18
ASTM B 209, Alloy 5652 \1\.................       25,000            18
------------------------------------------------------------------------
\1\ For fabrication, the parent plate material may be 0 H112, or H32
  temper, but design calculations must be based on the minimum tensile
  strength shown.
\2\ 0 temper only.
\3\ Weld filler metal 5556 must not be used.
\4\ Maximum stresses to be used in calculations.

    (d) High alloy steel plate: High alloy steel plate must comply with 
one of the following specifications (IBR, see Sec.  171.7 of this 
subchapter):

------------------------------------------------------------------------
                                               Minimum        Minimum
                                               tensile     elongation in
                                              strength       2 inches
              Specifications                  (p.s.i.)    (percent) weld
                                               welded          metal
                                            condition\1\  (longitudinal)
------------------------------------------------------------------------
ASTM A 240/A 240M (incorporated by               75,000             30
 reference; see Sec.   171.7 of this
 subchapter), Type 304....................
ASTM A 240/A 240M (incorporated by               70,000             30
 reference; see Sec.   171.7 of this
 subchapter), Type 304L...................
ASTM A 240/A 240M (incorporated by               74,000             30
 reference; see Sec.   171.7 of this
 subchapter), Type 316....................
ASTM A 240/A 240M (incorporated by               70,000             30
 reference; see Sec.   171.7 of this
 subchapter), Type 316L...................
------------------------------------------------------------------------
\1\ Maximum stresses to be used in calculations.

    (e) Manganese-molybdenum steel plate: Manganese-molybdenum steel 
plate must be suitable for fusion welding and must comply with the 
following specification (IBR, see Sec.  171.7 of this subchapter):

------------------------------------------------------------------------
                                                Minimum
                                                tensile       Minimum
                                               strength    elongation in
               Specifications                  (p.s.i.)      2 inches
                                                welded    (percent) weld
                                               condition       metal
                                                  \1\     (longitudinal)
------------------------------------------------------------------------
ASTM A 302, Gr. B...........................      80,000            20
------------------------------------------------------------------------
\1\ Maximum stresses to be used in calculations.

    (f) Plate materials used to fabricate the outer shell and heads must 
be those listed in paragraphs (b), (c), (d), or (e) of this section. The 
maximum allowable carbon content must be 0.31 percent when the 
individual specification allows carbon content greater than this amount. 
The plates may be clad with other approved materials.
    (g) All appurtenances on the inner container in contact with the 
lading must be made of approved material compatible with the plate 
material of the inner container. These appurtenances must not be subject 
to rapid deterioration by the lading, or must be coated or lined with 
suitable corrosion resistant material. See AAR Specifications for Tank 
Cars, appendix M, M4.05 for approved material specifications for 
castings for fittings.

[Amdt. 179-9, 36 FR 21340, Nov. 6, 1971, as amended by Amdt. 179-28, 46 
FR 49906, Oct. 8, 1981; Amdt. 179-40, 52 FR 13048, Apr. 20, 1987; Amdt. 
179-52, 61 FR 28681, June 5, 1996; 66 FR 45186, Aug. 28, 2001; 67 FR 
51660, Aug. 8, 2002; 68 FR 75762, Dec. 31, 2003]

[[Page 300]]



Sec.  179.220-8  Tank heads.

    (a) Tank heads of the inner container, inner container compartments 
and outer shell must be of approved contour, and may be flanged and 
dished or ellipsoidal for pressure on concave side.
    (b) Flanged and dished heads must have main inside radius not 
exceeding 10 feet and inside knuckle radius must be not less than 3\3/4\ 
inches for steel and alloy steel tanks nor less than 5 inches for 
aluminum alloy tanks.
    (c) Ellipsoidal heads must be an ellipsoid of revolution in which 
the major axis must equal the diameter of the shell and the minor axis 
must be one-half the major axis.

[Amdt. 179-9, 36 FR 21341, Nov. 6, 1971]



Sec.  179.220-9  Compartment tanks.

    (a) The inner container may be divided into compartments by 
inserting interior heads, or by fabricating each compartment as a 
separate container and joining with a cylinder, or by fabricating each 
compartment as a separate tank without a joining cylinder. Each 
compartment must be capable of withstanding, without evidence of 
yielding or leakage, the required test pressure applied in each 
compartment separately, or in any combination of compartments.
    (b) When the inner container is divided into compartments by 
fabricating each compartment as a separate container and joining with a 
cylinder, the cylinder must have a plate thickness not less than that 
required for the inner container shell and must be applied to the 
outside surface of the straight flange portion of the container head. 
The cylinder must fit the straight flange tightly for a distance of at 
least two times the plate thickness, or 1 inch, whichever is greater and 
must be joined to the straight flange by a full fillet weld. Distance 
from fillet weld seam to container head seam must be not less than 1\1/
2\ inches or three times the plate thickness, whichever is greater.

[Amdt. 179-9, 36 FR 21341, Nov. 6, 1971]



Sec.  179.220-10  Welding.

    (a) All joints must be fusion welded in compliance with AAR 
Specifications for Tank Cars, appendix W (IBR, see Sec.  171.7 of this 
subchapter). Welding procedures, welders, and fabricators shall be 
approved.
    (b) Radioscopy of the outer shell is not a specification 
requirement.
    (c) Welding is not permitted on or to ductile iron or malleable iron 
fittings.

[Amdt. 179-9, 36 FR 21341, Nov. 6, 1971, as amended at 68 FR 75762, Dec. 
31, 2003]



Sec.  179.220-11  Postweld heat treatment.

    (a) Postweld heat treatment of the inner container is not a 
specification requirement.
    (b) Postweld heat treatment of the cylindrical portions of the outer 
shell to which the anchorage or draft sills are attached must comply 
with AAR Specifications for Tank Cars, appendix W (IBR, see Sec.  171.7 
of this subchapter).
    (c) When cold formed heads are used on the outer shell they must be 
heat treated before welding to shell if postweld heat treatment is not 
practicable due to assembly procedures.

[Amdt. 179-9, 36 FR 21341, Nov. 6, 1971, as amended at 68 FR 75762, Dec. 
31, 2003]



Sec.  179.220-13  Inner container manway nozzle and cover.

    (a) Inner container manway nozzle must be of approved design with 
access opening at least 18 inches inside diameter, or at least 14 inches 
by 18 inches obround or oval.
    (b) Manway covers must be of approved type. Design must provide a 
secure closure of the manway and must make it impossible to remove the 
cover while the tank interior is under pressure.
    (c) All joints between manway covers and their seats must be made 
tight against leakage of vapor and liquid by use of suitable gaskets.
    (d) Manway covers must be cast, forged, or fabricated metal 
complying with subsection Sec.  179.220-7(g) of this section.
    (e) A seal must be provided between the inner container manway 
nozzle and the opening in the outer shell.

[Amdt. 179-9, 36 FR 21341, Nov. 6, 1971]



Sec.  179.220-14  Openings in the tanks.

    Openings in the inner container and the outer shell must be 
reinforced in

[[Page 301]]

compliance with AAR Specifications for Tank Cars, appendix E (IBR, see 
Sec.  171.7 of this subchapter). In determining the required 
reinforcement area for openings in the outer shell, t shall be one-
fourth inch.

[68 FR 75763, Dec. 31, 2003]



Sec.  179.220-15  Support system for inner container.

    (a) The inner container must be supported within the outer shell by 
a support system of adequate strength and ductility at its operating 
temperature to support the inner container when filled with liquid 
lading to any level. The support system must be designed to support, 
without yielding, impact loads producing accelerations of the following 
magnitudes and directions when the inner container is loaded so that the 
car is at its rail load limit, and the car is equipped with a 
conventional AAR Specification M-901 draft gear.
Longitudinal..........................................................7G
Transverse............................................................3G
Vertical..............................................................3G
    (b) The longitudinal acceleration may be reduced to 3G where a 
cushioning device of approved design, which has been tested to 
demonstrate its ability to limit body forces to 400,000 pounds maximum 
at a 10 miles per hour impact, is used between the coupler and the tank 
structure. The support system must be of approved design and the inner 
container must be thermally isolated from the outer shell to the best 
practical extent. The inner container and outer shell must be 
permanently bonded to each other electrically either by the support 
system used, piping, or by a separate electrical connection of approved 
design.

[Amdt. 179-9, 36 FR 21341, Nov. 6, 1971, as amended by Amdt. 179-28, 46 
FR 49906, Oct. 8, 1981]



Sec.  179.220-16  Expansion capacity.

    Expansion capacity must be provided in the shell of the inner 
container as prescribed in Sec.  179.221-1.

[Amdt. 179-9, 36 FR 21341, Nov. 6, 1971]



Sec.  179.220-17  Gauging devices, top loading and unloading devices, 
venting and air inlet devices.

    (a) When installed, each device must be of approved design which 
will prevent interchange with any other fixture and must be tightly 
closed. Each unloading pipe must be securely anchored within the inner 
container. Each inner container or compartment thereof may be equipped 
with one separate air connection.
    (b) When the characteristics of the commodity for which the car is 
authorized require these devices to be equipped with valves or fittings 
to permit the loading and unloading of the contents, these devices 
including valves, shall be provided with a protective housing except 
when plug or ball-type valves with operating handles removed are used. 
Provision must be made for closing pipe connections of valves.
    (c) Inner container may be equipped with a vacuum relief valve of 
approved design. Protective housing is not required.
    (d) When a gauging device is required in Sec.  179.221-1, an outage 
scale visible through the manway opening must be provided. If loading 
devices are applied to permit tank loading with cover closed, a telltale 
pipe may be provided. The telltail pipe must be capable of determining 
that required outage is provided. The pipe must be equipped with \1/4\-
inch maximum, NPT control valve mounted outside tank and enclosed within 
a protective housing. Other approved devices may be used in place of an 
outage scale or a telltale pipe.
    (e) The bottom of the tank shell may be equipped with a sump or 
siphon bowl, or both, welded or pressed into the shell. These sumps or 
siphon bowls, if applied, are not limited in size and must be made of 
cast, forged, or fabricated metal. Each sump or siphon bowl must be of 
good welding quality in conjunction with the metal of the tank shell. 
When the sump or siphon bowl is pressed in the bottom of the tank shell, 
the wall thickness of the pressed section must not be less than that 
specified for the shell. The section of a circular cross section tank to 
which a sump or siphon bowl is attached need not comply with the out-

[[Page 302]]

of-roundness requirement specified in appendix W, W14.06 of the AAR 
Specifications for Tank Cars. Any portion of a sump or siphon bowl not 
forming a part of a cylinder of revolution must have walls of such 
thickness and must be so reinforced that the stresses in the walls 
caused by a given internal pressure are not greater than the 
circumferential stress which would exist under the same internal 
pressure in the wall of a tank of circular cross section designed in 
accordance with Sec. Sec.  179.220-6(a) and 179.220-9. In no case shall 
the wall thickness be less than that specified in Sec.  179.221-1.
    (f) Protective housing, when required, must be of approved material 
and must have cover and sidewalls not less than 0.119 inch in thickness.

[Amdt. 179-9, 36 FR 21341, Nov. 6, 1971, as amended at 69 FR 54047, 
Sept. 7, 2004]



Sec.  179.220-18  Bottom outlets.

    (a) The inner container may be equipped with a bottom outlet of 
approved design and an opening provided in the outer shell of its 
access. If applied, the bottom outlet must comply with the following 
requirements:
    (1) The extreme projection of the bottom outlet equipment may not be 
more than that allowed by appendix E of the AAR Specifications for Tank 
Cars (IBR, see Sec.  171.7 of this subchapter). All bottom outlet 
reducers and closures and their attachments shall be secured to car by 
at at least \3/8\-inch chain, or its equivalent, except that bottom 
outlet closure plugs may be attached by \1/4\-inch chain. When the 
bottom outlet closure is of the combination cap and valve type, the pipe 
connection to the valve shall be closed by a plug, or cap. The bottom 
outlet equipment should include only the valve, reducers and closures 
that are necessary for the attachment of unloading fixtures. The 
permanent attachment of supplementary exterior fittings shall be 
approved by the AAR Committee on Tank Cars.
    (2) Each bottom outlet must be provided with a liquid tight closure 
at its lower end.
    (3) The valve and its operating mechanism must be applied to the 
outside bottom of the inner container. The valve operating mechanism 
must be provided with a suitable locking arrangement to insure positive 
closure during transportation.
    (4) Valve outlet nozzle and valve body must be of cast, fabricated 
or forged metal. If welded to inner container, they must be of good 
weldable quality in conjunction with metal of tank.
    (5) To provide for the attachment of unloading connections, the 
bottom of the main portion of the outlet nozzle or valve body, or some 
fixed attachment thereto, must be provided with threaded cap closure 
arrangement or bolted flange closure arrangement having minimum 1-inch 
threaded pipe plug.
    (6) If outlet nozzle and its closure extends below the bottom of the 
outer shell, a V-shaped breakage groove shall be cut (not cast) in the 
upper part of the outlet nozzle at a point immediately below the lowest 
part of the valve closest to the tank. In no case may the nozzle wall 
thickness at the root of the ``V'' be more than \1/4\-inch. The outlet 
nozzle or the valve body may be steam jacketed, in which case the 
breakage groove or its equivalent must be below the steam chamber but 
above the bottom of the center sill construction. If the outlet nozzle 
is not a single piece or its exterior valves are applied, provision 
shall be made for the equivalent of the breakage groove. On cars without 
continuous center sills, the breakage groove or its equivalent may not 
be more than 15 inches below the outer shell. On cars with continuous 
center sills, the breakage groove or its equivalent must be above the 
bottom of the center sill construction.
    (7) The valve body must be of a thickness which will prevent 
distortion of the valve seat or valve by any change in contour of the 
shell resulting from expansion of lading, or other causes, and which 
will insure that accidental breakage of the outlet nozzle will occur at 
or below the ``V'' groove, or its equivalent.
    (8) The valve must have no wings or stem projection below the ``V'' 
groove or its equivalent. The valve and seat must be readily accessible 
or removable for repairs, including grinding.
    (b) Inner container may be equipped with bottom washout of approved 
design. If applied, bottom washout must

[[Page 303]]

comply with the following requirements:
    (1) The extreme projection of the bottom washout equipment may not 
be more than that allowed by appendix E of the AAR Specifications for 
Tank Cars.
    (2) Bottom washout must be of cast, forged or fabricated metals. If 
it is welded to the inner container, it must be of good weldable quality 
in conjunction with metal of tank.
    (3) If washout nozzle extends below the bottom of the outer shell, a 
V-shaped breakage groove shall be cut (not cast) in the upper part of 
the nozzle at a point immediately below the lowest part of the inside 
closure seat or plug. In no case may the nozzle wall thickness at the 
root of the ``V'' be more than \1/4\-inch. Where the nozzle is not a 
single piece, provisions shall be made for the equivalent of the 
breakage groove. The nozzle must be of a thickness to insure that 
accidental breakage will occur at or below the ``V'' groove or its 
equivalent. On cars without a continuous center sill, the breakage 
groove or its equivalent may not be more than 15 inches below the outer 
shell. On cars with continuous center sills, the breakage groove or its 
equivalent must be above the bottom of the center sill construction.
    (4) The closure plug and seat must be readily accessible or 
removable for repairs.
    (5) The closure of the washout nozzle must be equipped with a \3/4\-
inch solid screw plug. Plug must be attached by at least a \1/4\-inch 
chain.
    (6) Joints between closures and their seats may be gasketed with 
suitable material.

[Amdt. 179-9, 36 FR 21342, Nov. 6, 1971, as amended by Amdt. 179-40, 52 
FR 13048, Apr. 20, 1987; 68 FR 75763, Dec. 31, 2003]



Sec.  179.220-20  Reinforcements, when used, and appurtenances not otherwise  
specified.

    All attachments to inner container and outer shell must be applied 
by approved means.

[Amdt. 179-9, 36 FR 21342, Nov. 6, 1971]



Sec.  179.220-22  Closure for openings.

    (a) All plugs must be solid, with NPT threads, and must be of a 
length which will screw at least six threads inside the face of fitting 
or tank. Plugs, when inserted from the outside of the outer shell tank 
heads, must have the letter ``S'' at least three-eighths inch in size 
stamped with steel stamp or cast on the outside surface to indicate the 
plug is solid.
    (b) Openings in the outer shell used during construction for 
installation must be closed in an approved manner.

[Amdt. 179-9, 36 FR 21343, Nov. 6, 1971]



Sec.  179.220-23  Test of tanks.

    (a) Each inner container or compartment must be tested 
hydrostatically to the pressure specified in Sec.  179.221-1. The 
temperature of the pressurizing medium must not exceed 100 [deg]F. 
during the test. The container must hold the prescribed pressure for at 
least 10 minutes without leakage or evidence of distress. Safety relief 
devices must not be in place when the test is made.
    (b) The inner container must be pressure tested before installation 
within the outer shell. Items which, because of assembly sequence, must 
be welded to inner container after its installation within outer shell 
must have their attachment welds thoroughly inspected by a 
nondestructive dye penetrant method or its equivalent.
    (c) Pressure testing of outer shell is not a specification 
requirement.

[Amdt. 179-9, 36 FR 21343, Nov. 6, 1971]



Sec.  179.220-24  Tests of pressure relief valves.

    Each safety relief valve must be tested by air or gas for compliance 
with Sec.  179.15 before being put into service.

[Amdt. 179-9, 36 FR 21343, Nov. 6, 1971, as amended at 62 FR 51561, Oct. 
1, 1997]



Sec.  179.220-25  Stamping.

    (a) To certify that the tank complies with all specification 
requirements, each outer shell must be plainly and permanently stamped 
in letters and figures at least \3/8\-inch high into the metal near the 
center of both outside heads as follows:

------------------------------------------------------------------------
                                                Examples of required
                                                      stamping
------------------------------------------------------------------------
Specifications............................  DOT-115A60W6.
Inner container:
  Material................................  ASTM A240-316L.

[[Page 304]]

 
  Shell thickness.........................  Shell 0.167 in.
  Head thickness..........................  Head 0.150 in.
  Tank builders initials..................  ABC.
  Date of original test...................  00-0000.
Outer shell:
  Material................................  ASTM A285-C.
  Tank builders initials..................  WYZ.
Car assembler (if other than inner          DEF.
 container or outer shell builders).
------------------------------------------------------------------------

    (b) After July 25, 2012, newly constructed DOT tank cars must have 
their DOT specification and other required information stamped plainly 
and permanently on stainless steel identification plates in conformance 
with the applicable requirements prescribed in Sec.  179.24(a). Tank 
cars built before July 25, 2012, may have the identification plates 
instead of or in addition to the head stamping.

[Amdt. 179-9, 36 FR 21343, Nov. 6, 1971, as amended at 77 FR 37986, June 
25, 2012]



Sec.  179.220-26  Stenciling.

    (a) The outer shell, or the jacket if the outer shell is insulated, 
must be stenciled in compliance with AAR Specifications for Tank Cars, 
appendix C (IBR, see Sec.  171.7 of this subchapter).
    (b) Stenciling must be applied on both sides of the outer shell or 
jacket near the center in letters and figures at least 1\1/2\ inches 
high to indicate the safe upper temperature limit, if applicable, for 
the inner tank, insulation, and the support system.

[Amdt. 179-9, 36 FR 21343, Nov. 6, 1971, as amended at 68 FR 75763, Dec. 
31, 2003]



Sec.  179.221  Individual specification requirements applicable to tank 
car tanks consisting of an inner container supported within an outer shell.



Sec.  179.221-1  Individual specification requirements.

    In addition to Sec.  179.220, the individual specification 
requirements are as follows:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                     Minimum
                                                         Bursting     plate      Test                                                Reference (179.221-
        DOT specification               Insulation       pressure   thickness  pressure      Bottom outlet        Bottom washout             ***)
                                                          (psig)    (inches)    (psig)
--------------------------------------------------------------------------------------------------------------------------------------------------------
115A60ALW........................  Yes.................       240      \3/16\        60  Optional.             Optional............
115A60W1.........................  Yes.................       240       \1/8\        60  Optional............  Optional............  1
115A60W6.........................  Yes.................       240       \1/8\        60  Optional............  Optional............  1
--------------------------------------------------------------------------------------------------------------------------------------------------------


[Amdt. 170-52, 61 FR 28681, June 5, 1996, as amended at 62 FR 51561, 
Oct. 1, 1997; 66 FR 45390, Aug. 28, 2001]

[[Page 305]]



Subpart E_Specifications for Multi-Unit Tank Car Tanks (Classes DOT-106A 
                               and 110AW)



Sec.  179.300  General specifications applicable to multi-unit tank car 
tanks designed to be removed from car structure for filling and emptying 
(Classes DOT-106A and 110AW). 



Sec.  179.300-1  Tanks built under these specifications shall meet the 
requirements of Sec. Sec.  179.300 and 179.301.



Sec.  179.300-3  Type and general requirements.

    (a) Tanks built under this specification shall be cylindrical, 
circular in cross section, and shall have heads of approved design. All 
openings shall be located in the heads.
    (b) Each tank shall have a water capacity of at least 1500 pounds 
and not more than 2600 pounds.
    (c) For tanks made in foreign countries, a chemical analysis of 
materials and all tests as specified shall be carried out within the 
limits of the United States under the supervision of a competent and 
impartial inspector.



Sec.  179.300-4  Insulation.

    (a) Tanks shall not be insulated.
    (b) [Reserved]



Sec.  179.300-6  Thickness of plates.

    (a) For class DOT-110A tanks, the wall thickness after forming of 
the cylindrical portion of the tank must not be less than that specified 
in Sec.  179.301 nor that calculated by the following formula:
[GRAPHIC] [TIFF OMITTED] TC13NO91.037

Where:

d = inside diameter in inches;
E = 1.0 welded joint efficiency;
P = minimum required bursting pressure in psig;
S = minimum tensile strength of plate material in p.s.i. as prescribed 
          in Sec.  179.300-7;
t = minimum thickness of plate material in inches after forming.

    (b) For class DOT-106A tanks, the wall thickness of the cylindrical 
portion of the tank shall not be less than that specified in Sec.  
179.301 and shall be such that at the tank test pressure the maximum 
fiber stress in the wall of the tank will not exceed 15,750 p.s.i. as 
calculated by the following formula:

s=[p(1.3D\2\ + 0.4d\2\] / (D\2\-d\2\)

where:

d = inside diameter in inches;
D = outside diameter in inches;
p = tank test pressure in psig;
s = wall stress in psig

    (c) If plates are clad with material having tensile strength at 
least equal to the base plate, the cladding may be considered a part of 
the base plate when determining the thickness. If cladding material does 
not have tensile strength at least equal to the base plate, the base 
plate alone shall meet the thickness requirements.

[29 FR 18995, Dec. 29, 1964, as amended by Order 71, 31 FR 9083, July 1, 
1966. Redesignated at 32 FR 5606, Apr. 5, 1967; 66 FR 45186, 45390, Aug. 
28, 2001]



Sec.  179.300-7  Materials.

    (a) Steel plate material used to fabricate tanks must conform with 
the following specifications with the indicated minimum tensile strength 
and elongation in the welded condition. However, the maximum allowable 
carbon content for carbon steel must not exceed 0.31 percent, although 
the individual ASTM specification may allow for a greater amount of 
carbon. The plates may be clad with other approved materials:

------------------------------------------------------------------------
                                               Tensile     Elongation in
                                               strength      2 inches
                                                (psi)        (percent)
             Specifications \2\                 welded        welded
                                              condition    condition \1\
                                                 \1\      (longitudinal)
                                              (minimum)      (minimum)
------------------------------------------------------------------------
ASTM A 240/A 240M type 304.................       75,000             25
ASTM A 240/A 240M type 304L................       70,000             25
ASTM A 240/A 240M type 316.................       75,000             25
ASTM A 240/A 240M type 316L................       70,000             25
ASTM A 240/A 240M type 321.................       75,000             25
ASTM A 285 Gr. A...........................       45,000             29
ASTM A 285 Gr. B...........................       50,000             20
ASTM A 285 Gr. C...........................       55,000             20
ASTM A 515/A 515M Gr. 65...................       65,000             20
ASTM A 515/A 515M Gr. 70...................       70,000             20
ASTM A 516/A 516M Gr. 70...................       70,000             20
------------------------------------------------------------------------
\1\ Maximum stresses to be used in calculations.
\2\ These specifications are incorporated by reference (IBR, see Sec.
  171.7 of this subchapter.)

    (b) [Reserved]

[[Page 306]]

    (c) All plates must have their heat number and the name or brand of 
the manufacturer legibly stamped on them at the rolling mill.

[Amdt. 179-10, 36 FR 21355, Nov. 6, 1971, as amended by Amdt. 179-42, 54 
FR 38798, Sept. 20, 1989; Amdt. 179-43, 55 FR 27642, July 5, 1990; Amdt. 
179-52, 61 FR 28682, June 5, 1996; Amdt. 179-52, 61 FR 50255, Sept. 25, 
1996; Amdt. 179-53, 61 FR 51342, Oct. 1, 1996; 68 FR 75763, Dec. 31, 
2003]



Sec.  179.300-8  Tank heads.

    (a) Class DOT-110A tanks shall have fusion-welded heads formed 
concave to pressure. Heads for fusion welding shall be an ellipsoid of 
revolution 2:1 ratio of major to minor axis. They shall be one piece, 
hot formed in one heat so as to provide a straight flange at least 1\1/
2\ inches long. The thickness shall not be less than that calculated by 
the following formula:
[GRAPHIC] [TIFF OMITTED] TC13NO91.038

where symbols are as defined in Sec.  179.300-6(a).

    (b) Class DOT-106A tanks must have forged-welded heads, formed 
convex to pressure. Heads for forge welding must be torispherical with 
an inside radius not greater than the inside diameter of the shell. They 
must be one piece, hot formed in one heat so as to provide a straight 
flange at least 4 inches long. They must have snug drive fit into the 
shell for forge welding. The wall thickness after forming must be 
sufficient to meet the test requirements of Sec.  179.300-16 and to 
provide for adequate threading of openings.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21355, Nov. 6, 1971]



Sec.  179.300-9  Welding.

    (a) Longitudinal joints must be fusion welded. Head-to-shell joints 
must be forge welded on class DOT-106A tanks and fusion welded on class 
DOT-110A tanks. Welding procedures, welders and fabricators must be 
approved in accordance with AAR Specifications for Tank Cars, appendix W 
(IBR, see Sec.  171.7 of this subchapter).
    (b) Fusion-welded joints must be in compliance with the requirements 
of AAR Specifications for Tank Cars, appendix W, except that 
circumferential welds in tanks less than 36 inches inside diameter need 
not be radiotaped.
    (c) Forge-welded joints shall be thoroughly hammered or rolled to 
insure sound welds. The flanges of the heads shall be forge lapwelded to 
the shell and then crimped inwardly toward the center line at least one 
inch on the radius. Welding and crimping must be accomplished in one 
heat.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
as amended by Amdt. 179-10, 36 FR 21355, Nov. 6, 1971; 68 FR 75763, Dec. 
31, 2003]



Sec.  179.300-10  Postweld heat treatment.

    After welding is complete, steel tanks and all attachments welded 
thereto, must be postweld heat treated as a unit in compliance with the 
requirements of AAR Specifications for Tank Cars, appendix W (IBR, see 
Sec.  171.7 of this subchapter).

[68 FR 75763, Dec. 31, 2003]



Sec.  179.300-12  Protection of fittings.

    (a) Tanks shall be of such design as will afford maximum protection 
to any fittings or attachment to the head including the housing referred 
to in Sec.  179.300-12(b). Tank ends shall slope or curve inward toward 
the axis so that the diameter at each end is at least 2 inches less than 
the maximum diameter.
    (b) Loading and unloading valves shall be protected by a detachable 
protective housing of approved design which shall not project beyond the 
end of the tank and shall be securely fastened to the tank head. 
Pressure relief devices shall not be covered by the housing.

[29 FR 18995, Dec. 29, 1964, as amended at 68 FR 57634, Oct. 6, 2003]



Sec.  179.300-13  Venting, loading and unloading valves.

    (a) Valves shall be of approved type, made of metal not subject to 
rapid deterioration by lading, and shall withstand tank test pressure 
without leakage. The valves shall be screwed directly into or attached 
by other approved methods to one tank head. Provision shall be made for 
closing outlet connections of the valves.

[[Page 307]]

    (b) Threads for openings must be National Gas Taper Threads (NGT) 
tapped to gauge, clean cut, even and without checks. Taper threads must 
comply with Sec.  178.61(h)(3)(i) and (h)(3)(ii). Threads for the clean-
out/inspection ports of DOT Specification 110A multi-unit tank car tanks 
may be straight threads instead of taper threads. The straight threads 
must meet the requirements of Sec.  178.61(h)(3)(i) and (h)(3)(iii). Hex 
plugs may be secured to threaded boss ports using stainless steel safety 
wire that must not fail during its intended use.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967. 
Amended at 77 FR 37986, June 25, 2012]



Sec.  179.300-14  Attachments not otherwise specified.

    Siphon pipes and their couplings on the inside of the tank head and 
lugs on the outside of the tank head for attaching the valve protective 
housing must be fusion-welded in place prior to postweld heat treatment. 
All other fixtures and appurtenances, except as specifically provided 
for, are prohibited.

[Amdt. 179-10, 36 FR 21355, Nov. 6, 1971]



Sec.  179.300-15  Pressure relief devices.

    (a) Unless prohibited in part 173 of this subchapter, tanks shall be 
equipped with one or more relief devices of approved type, made of metal 
not subject to rapid deterioration by the lading and screwed directly 
into tank heads or attached to tank heads by other approved methods. The 
total discharge capacity shall be sufficient to prevent building up 
pressure in tank in excess of 82.5 percent of the tank test pressure. 
When relief devices of the fusible plug type are used, the required 
discharge capacity shall be available in each head. See AAR 
Specifications for Tank Cars, appendix A (IBR, see Sec.  171.7 of this 
subchapter), for the formula for calculating discharge capacity.
    (b) Threads for openings shall be National Gas Taper Threads (NGT) 
tapped to gage, clean cut, even and without checks.
    (c) Pressure relief devices shall be set for start-to-discharge and 
rupture discs shall burst at a pressure not exceeding that specified in 
Sec.  179.301.
    (d) Fusible plugs shall function at a temperature not exceeding 175 
[deg]F. and shall be vapor-tight at a temperature of not less than 130 
[deg]F.

[29 FR 18995, Dec. 29, 1964, as amended at 64 FR 51920, Sept. 27, 1999; 
66 FR 45390, Aug. 28, 2001; 68 FR 75763, Dec. 31, 2003]



Sec.  179.300-16  Tests of tanks.

    (a) After postweld heat treatment, tanks shall be subjected to 
hydrostatic expansion test in a water jacket, or by other approved 
methods. No tank shall have been subjected previously to internal 
pressure within 100 pounds of the test pressure. Each tank shall be 
tested to the pressure prescribed in Sec.  179.301. Pressure shall be 
maintained for 30 seconds and sufficiently longer to insure complete 
expansion of tank. Pressure gage shall permit reading to accuracy of one 
percent. Expansion gage shall permit reading of total expansion to 
accuracy of one percent. Expansion shall be recorded in cubic cm.
    (1) No leaks shall appear and permanent volumetric expansion shall 
not exceed 10 percent of total volumetric expansion at test pressure.
    (2) [Reserved]
    (b) After all fittings have been installed, each tank shall be 
subjected to interior air pressure test of at least 100 psig under 
conditions favorable to detection of any leakage. No leaks shall appear.
    (c) Repairs of leaks detected in manufacture or in foregoing tests 
shall be made by the same process as employed in manufacture of tank. 
Caulking, soldering, or similar repairing is prohibited.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21355, Nov. 6, 1971; 66 FR 45390, 
Aug. 28, 2001]



Sec.  179.300-17  Tests of pressure relief devices.

    (a) Each valve shall be tested by air or gas before being put into 
service. The valve shall open and be vapor-tight at the pressure 
prescribed in Sec.  179.301.
    (b) Rupture disks of non-reclosing pressure relief devices must be 
tested and qualified as prescribed in appendix A, Paragraph 5, of the 
AAR Manual of

[[Page 308]]

Standards and Recommended Practices, Section C--Part III, AAR 
Specifications for Tank Cars (IBR, see Sec.  171.7 of this subchapter).
    (c) For pressure relief devices of the fusible plug type, a sample 
of the plug used shall function at the temperatures prescribed in Sec.  
179.300-15.
    (d) The start-to-discharge and vapor-tight pressures shall not be 
affected by any auxiliary closure or other combination.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21355, Nov. 6, 1971; 66 FR 45390, 
Aug. 28, 2001; 68 FR 48572, Aug. 14, 2003; 68 FR 75763, Dec. 31, 2003]



Sec.  179.300-18  Stamping.

    (a) To certify that the tank complies with all specification 
requirements, each tank shall be plainly and permanently stamped in 
letters and figures \3/8\ inch high into the metal of valve end chime as 
follows:
    (1) DOT Specification number.
    (2) Material and cladding material if any (immediately below the 
specification number).
    (3) Owner's or builder's identifying symbol and serial number 
(immediately below the material identification). The symbol shall be 
registered with the Bureau of Explosives, duplications are not 
authorized.
    (4) Inspector's official mark (immediately below the owner's or 
builder's symbol).
    (5) Date of original tank test (month and year, such as 1-64 for 
January 1964). This should be so placed that dates of subsequent tests 
may easily be added thereto.
    (6) Water capacity--0000 pounds.
    (b) A copy of the above stamping in letters and figures of the 
prescribed size stamped on a brass plate secured to one of the tank 
heads is authorized.



Sec.  179.300-19  Inspection.

    (a) Tank shall be inspected within the United States and Canada by a 
competent and impartial inspector as approved by the Associate 
Administrator of Safety, FRA. For tanks made outside the United States 
or Canada, the specified inspection shall be made within the United 
States.
    (b) The inspector shall carefully inspect all plates from which 
tanks are to be made and secure records certifying that plates comply 
with the specification. Plates which do not comply with Sec.  179.300-7 
shall be rejected.
    (c) The inspector shall make such inspection as may be necessary to 
see that all the requirements of this specification, including markings, 
are fully complied with; shall see that the finished tanks are properly 
stress relieved and tested.
    (d) The inspector shall stamp his official mark on each accepted 
tank as required in Sec.  179.300-18, and render the report required in 
Sec.  179.300-20.

[29 FR 18995, Dec. 29, 1964, as amended at 72 FR 55696, Oct. 1, 2007]



Sec.  179.300-20  Reports.

    (a) Before a tank is placed in service, the inspector shall furnish 
to the builder, tank owner, Bureau of Explosives and the Secretary, 
Mechanical Division, Association of American Railroads, a report in 
approved form certifying that the tank and its equipment comply with all 
the requirements of this specification.
    (b) For builder's Certificate of Construction, see Sec.  179.5 (b), 
(c), and (d).

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21355, Nov. 5, 1971]



Sec.  179.301  Individual specification requirements for multi-unit tank 
car tanks.

    (a) In addition to Sec.  179.300 the individual specification 
requirements are as follows:

----------------------------------------------------------------------------------------------------------------
       DOT specification          106A500-X    106A800-X    110A500-W    110A600-W    110A800-W     110A1000-W
----------------------------------------------------------------------------------------------------------------
Minimum required bursting              (\1\)        (\1\)         1250         1500         2000            2500
 pressure, psig................
Minimum thickness shell, inches      \13/32\      \11/16\      \11/32\        \3/8\      \15/32\         \19/32\
Test pressure, psig (see Sec.            500          800          500          600          800            1000
 179.300-16)...................

[[Page 309]]

 
Safety relief devices, psig      ...........  ...........  ...........  ...........  ...........  ..............
 (see Sec.   179.300-15).......
Start-to-discharge, or burst             375          600          375          450          600             700
 maximum, p.s.i................
Vapor-tight, minimum psig......          300          480          300          360          480             650
----------------------------------------------------------------------------------------------------------------
\1\ None specified.

    (b) [Reserved]

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-10, 36 FR 21355, Nov. 6, 1971; Amdt. 179-40, 52 
FR 13049, Apr. 20, 1987; 65 FR 58632, Sept. 29, 2000; 66 FR 45390, Aug. 
28, 2001]



Sec.  179.302  [Reserved]



Subpart F_Specification for Cryogenic Liquid Tank Car Tanks and Seamless 
                 Steel Tanks (Classes DOT-113 and 107A)

    Source: Amdt. 179-32, 48 FR 27708, June 16, 1983, unless otherwise 
noted.



Sec.  179.400  General specification applicable to cryogenic liquid tank 
car tanks.



Sec.  179.400-1  General.

    A tank built to this specification must comply with Sec. Sec.  
179.400 and 179.401.



Sec.  179.400-3  Type.

    (a) A tank built to this specification must--
    (1) Consist of an inner tank of circular cross section supported 
essentially concentric within an outer jacket of circular cross section, 
with the out of roundness of both the inner tank and outer jacket 
limited in accordance with Paragraph UG-80 in Section VIII of the ASME 
Code (IBR, see Sec.  171.7 of this subchapter);
    (2) Have the annular space evacuated after filling the annular space 
with an approved insulating material;
    (3) Have the inner tank heads designed concave to pressure; and
    (4) Have the outer jacket heads designed convex to pressure.
    (b) The tank must be equipped with piping systems for vapor venting 
and transfer of lading, and with pressure relief devices, controls, 
gages and valves, as prescribed herein.

[Amdt. 179-32, 48 FR 27708, June 16, 1983, as amended at 68 FR 75763, 
Dec. 31, 2003]



Sec.  179.400-4  Insulation system and performance standard.

    (a) For the purposes of this specification--
    (1) Standard Heat Transfer Rate (SHTR), expressed in Btu/day/lb of 
water capacity, means the rate of heat transfer used for determining the 
satisfactory performance of the insulation system of a cryogenic tank 
car tank in cryogenic liquid service (see Sec.  179.401-1 table).
    (2) Test cryogenic liquid means the cryogenic liquid, which may be 
different from the lading intended to be shipped in the tank, being used 
during the performance tests of the insulation system.
    (3) Normal evaporation rate (NER), expressed in lbs. (of the 
cryogenic liquid)/day, means the rate of evaporation, determined by test 
of a test cryogenic liquid in a tank maintained at a pressure of 
approximately one atmosphere, absolute. This determination of the NER is 
the NER test.
    (4) Stabilization period means the elapsed time after a tank car 
tank is filled with the test cryogenic liquid until the NER has 
stabilized, or 24 hours has passed, whichever is greater.
    (5) Calculated heat transfer rate. The calculated heat transfer rate 
(CHTR) is determined by the use of test data obtained during the NER 
test in the formula:

q = [N([Delta] h)(90-tl)] / [V(8.32828)(ts-
tf)]


[[Page 310]]


Where:

q = CHTR, in Btu/day/lb., of water capacity;
N = NER, determined by NER test, in lbs./day;
[Delta]h = latent heat of vaporization of the test cryogenic liquid at 
          the NER test pressure of approximately one atmosphere, 
          absolute, in Btu/lb.;
90 = ambient temperature at 90 [deg]F.;
V = gross water volume at 60 [deg]F. of the inner tank, in gallons;
tl = equilibrium temperature of intended lading at maximum 
          shipping pressure, in [deg]F.;
8.32828 = constant for converting gallons of water at 60 [deg]F. to lbs. 
          of water at 60 [deg]F., in lbs./gallon;
ts = average temperature of outer jacket, determined by 
          averaging jacket temperatures at various locations on the 
          jacket at regular intervals during the NER test, in [deg]F.;
tf = equilibrium temperature of the test cryogenic liquid at 
          the NER test pressure of approximately, one atmosphere, 
          absolute, in [deg]F.

    (b) DOT-113A60W tank cars must--
    (1) Be filled with hydrogen, cryogenic liquid to the maximum 
permitted fill density specified in Sec.  173.319(d)(2) table of this 
subchapter prior to performing the NER test; and
    (2) Have a CHTR equal to or less than the SHTR specified in Sec.  
179.401-1 table for a DOT-113A60W tank car.
    (c) DOT-113C120W tank cars must--
    (1) Be filled with ethylene, cryogenic liquid to the maximum 
permitted fill density specified in Sec.  173.319(d)(2) table of this 
subchapter prior to performing the NER test, or be filled with nitrogen, 
cryogenic liquid to 90 percent of the volumetric capacity of the inner 
tank prior to performing the NER test; and
    (2) Have a CHTR equal to or less than 75 percent of the SHTR 
specified in Sec.  179.401-1 table for a DOT-113C120W tank car.
    (d) Insulating materials must be approved.
    (e) If the insulation consists of a powder having a tendency to 
settle, the entire top of the cylindrical portion of the inner tank must 
be insulated with a layer of glass fiber insulation at least one-inch 
nominal thickness, or equivalent, suitably held in position and covering 
an area extending 25 degrees to each side of the top center line of the 
inner tank.
    (f) The outer jacket must be provided with fittings to permit 
effective evacuation of the annular space between the outer jacket and 
the inner tank.
    (g) A device to measure the absolute pressure in the annular space 
must be provided. The device must be portable with an easily accessible 
connection or permanently positioned where it is readily visible to the 
operator.

[Amdt. 179-32, 48 FR 27708, June 16, 1983, as amended at 49 FR 24318, 
June 12, 1984; 66 FR 45186, Aug. 28, 2001]



Sec.  179.400-5  Materials.

    (a) Stainless steel of ASTM A 240/A 240M (IBR, see Sec.  171.7 of 
this subchapter), Type 304 or 304L must be used for the inner tank and 
its appurtenances, as specified in AAR Specifications for Tank Cars, 
appendix M (IBR, see Sec.  171.7 of this subchapter), and must be--
    (1) In the annealed condition prior to fabrication, forming and 
fusion welding;
    (2) Suitable for use at the temperature of the lading; and
    (3) Compatible with the lading.
    (b)(1) Any steel casting, steel forging, steel structural shape or 
carbon steel plate used to fabricate the outer jacket or heads must be 
as specified in AAR Specifications for Tank Cars, appendix M.
    (2) For DOT-113C120W9 tank cars, the outer jacket shell and outer 
jacket heads must be made of AAR TC-128, Grade B normalized steel plate 
as specified in Sec.  179.100-7(a).
    (c) Impact tests must be--
    (1) Conducted in accordance with AAR Specifications for Tank Cars, 
appendix W, W9.01;
    (2) Performed on longitudinal specimens of the material;
    (3) Conducted at the tank design service temperature or colder; and
    (4) Performed on test plate welds and materials used for inner tanks 
and appurtenances and which will be subjected to cryogenic temperatures.
    (d) Impact test values must be equal to or greater than those 
specified in AAR Specifications for Tank Cars, appendix W. The report of 
impact tests

[[Page 311]]

must include the test values and lateral expansion data.

[Amdt. 179-32, 48 FR 27708, June 16, 1983, as amended at 67 FR 51660, 
Aug. 8, 2002; 68 FR 75763, Dec. 31, 2003; 85 FR 45030, July 24, 2020]



Sec.  179.400-6  Bursting and buckling pressure.

    (a) [Reserved]
    (b) The outer jacket of the required evacuated insulation system 
must be designed in accordance with Sec.  179.400-8(d) and in addition 
must comply with the design loads specified in Section 6.2 of the AAR 
Specifications for Tank Cars (IBR, see Sec.  171.7 of this subchapter). 
The designs and calculations must provide for the loadings transferred 
to the outer jacket through the support system.

[Amdt. 179-32, 48 FR 27708, June 16, 1983, as amended by Amdt. 179-51, 
61 FR 18934, Apr. 29, 1996; 65 FR 58632, Sept. 29, 2000; 68 FR 75763, 
Dec. 31, 2003]



Sec.  179.400-7  Tank heads.

    (a) Tank heads of the inner tank and outer jacket must be flanged 
and dished, or ellipsoidal.
    (b) Flanged and dished heads must have--
    (1) A main inside dish radius not greater than the outside diameter 
of the straight flange;
    (2) An inside knuckle radius of not less than 6 percent of the 
outside diameter of the straight flange; and
    (3) An inside knuckle radius of at least three times the head 
thickness.



Sec.  179.400-8  Thickness of plates.

    (a) The minimum wall thickness, after forming, of the inner shell 
and any 2:1 ellipsoidal head for the inner tank must be that specified 
in Sec.  179.401-1, or that calculated by the following formula, 
whichever is greater:

t = Pd / 2SE

Where:

t = minimum thickness of plate, after forming, in inches;
P = minimum required bursting pressure in psig;
d = inside diameter, in inches;
S = minimum tensile strength of the plate material, as prescribed in AAR 
          Specifications for Tank Cars, appendix M, Table M1 (IBR, see 
          Sec.  171.7 of this subchapter), in psi;
E = 0.9, a factor representing the efficiency of welded joints, except 
          that for seamless heads, E = 1.0.

    (b) The minimum wall thickness, after forming, of any 3:1 
ellipsoidal head for the inner tank must be that specified in Sec.  
179.401-1, or that calculated by the following formula, whichever is 
greater:

t = 1.83 Pd / 2SE

Where:

t = minimum thickness of plate, after forming, in inches;
P = minimum required bursting pressure in psig;
d = inside diameter, in inches;
S = minimum tensile strength of the plate material, as prescribed in AAR 
          Specifications for Tank Cars, Appendix M, Table M1, in psi;
E = 0.9, a factor representing the efficiency of welded joints, except 
          that for seamless heads, E = 1.0.

    (c) The minimum wall thickness, after forming, of a flanged and 
dished head for the inner tank must be that specified in Sec.  179.401-
1, or that calculated by the following formula, whichever is greater:

t = [PL(3 + [radic](L/r))] / (8SE)

Where:

t = minimum thickness of plate, after forming, in inches;
P = minimum required bursting pressure in psig;
L = main inside radius of dished head, in inches;
r = inside knuckle radius, in inches;
S = minimum tensile strength of plate material, as prescribed in AAR 
          Specifications for Tank Cars, appendix M, table M1, in psi;
E = 0.9, a factor representing the efficiency of welded joints, except 
          that for seamless heads, E = 1.0.

    (d)(1) The minimum wall thickness, after forming, of the outer 
jacket shell may not be less than \7/16\ inch. The minimum wall 
thickness, after forming, of the outer jacket heads may not be less than 
\1/2\ inch and they must be made from steel specified in Sec.  
179.16(c).
    (2) For DOT 113C120W9 tank cars, the minimum wall thickness of the 
outer jacket shell and the outer jacket heads must be no less than \9/
16\ inch after forming, and must be made of AAR TC-128, Grade B 
normalized steel plate.

[[Page 312]]

    (3) The annular space is to be evacuated, and the cylindrical 
portion of the outer jacket between heads, or between stiffening rings 
if used, must be designed to withstand an external pressure of 37.5 psig 
(critical collapsing pressure), as determined by the following formula:

Pc = [2.6E(t/D)\2.5\]/[(L/D) - 0.45(t/D)\0.5\]

Where:

Pc = Critical collapsing pressure (37.5 psig minimum) in 
          psig;
E = modulus of elasticity of jacket material, in psi;
t = minimum thickness of jacket material, after forming, in inches;
D = outside diameter of jacket, in inches;
L = distance between stiffening ring centers in inches. (The heads may 
          be considered as stiffening rings located \1/3\ of the head 
          depth from the head tangent line.)

[Amdt. 179-32, 48 FR 27708, June 16, 1983; 49 FR 42736, Oct. 24, 1984; 
64 FR 51920, Sept. 27, 1999, as amended at 66 FR 45390, Aug. 28, 2001; 
68 FR 75763, Dec. 31, 2003; 85 FR 45030, July 24, 2020]



Sec.  179.400-9  Stiffening rings.

    (a) If stiffening rings are used in designing the cylindrical 
portion of the outer jacket for external pressure, they must be attached 
to the jacket by means of fillet welds. Outside stiffening ring 
attachment welds must be continuous on each side of the ring. Inside 
stiffening ring attachment welds may be intermittent welds on each side 
of the ring with the total length of weld on each side not less than 
one-third of the circumference of the tank. The maximum space between 
welds may not exceed eight times the outer jacket wall thickness.
    (b) A portion of the outer jacket may be included when calculating 
the moment of inertia of the ring. The effective width of jacket plate 
on each side of the attachment of the stiffening ring is given by the 
following formula:

W = 0.78(Rt)\0.5\

Where:

W = width of jacket effective on each side of the stiffening ring, in 
          inches;
R = outside radius of the outer jacket, in inches;
t = plate thickness of the outer jacket, after forming, in inches.

    (c) Where a stiffening ring is used that consists of a closed 
section having two webs attached to the outer jacket, the jacket plate 
between the webs may be included up to the limit of twice the value of 
``W'', as defined in paragraph (b) of this section. The outer flange of 
the closed section, if not a steel structural shape, is subject to the 
same limitations with ``W'' based on the ``R'' and ``t'' values of the 
flange. Where two separate members such as two angles, are located less 
than ``2W'' apart they may be treated as a single stiffening ring 
member. (The maximum length of plate which may be considered effective 
is 4W.) The closed section between an external ring and the outer jacket 
must be provided with a drain opening.
    (d) The stiffening ring must have a moment of inertia large enough 
to support the critical collapsing pressure, as determined by either of 
the following formulas:

I = [0.035D\3\ LPc] / E,


or

I' = [0.046D\3\ LPc] / E

Where:

I = required moment of inertia of stiffening ring about the centroidal 
          axis parallel to the vessel axis, in inches to the fourth 
          power;
I' = required moment of inertia of combined section of stiffening ring 
          and effective width of jacket plate about the centroidal axis 
          parallel to the vessel axis, in inches to the fourth power;
D = outside diameter of the outer jacket, in inches;
L = one-half of the distance from the centerline of the stiffening ring 
          to the next line of support on one side, plus one-half of the 
          distance from the centerline to the next line of support on 
          the other side of stiffening ring. Both distances are measured 
          parallel to the axis of the vessel, in inches. (A line of 
          support is:

(1) A stiffening ring which meets the requirements of this paragraph, or
(2) A circumferential line of a head at one-third the depth of the head 
from the tangent line);

Pc = critical collapsing pressure (37.5 psig minimum) in 
          psig;
E = modulus of elasticity of stiffening ring material, in psi.

    (e) Where loads are applied to the outer jacket or to stiffening 
rings from the system used to support the inner tank within the outer 
jacket, additional stiffening rings, or an increased

[[Page 313]]

moment of inertia of the stiffening rings designed for the external 
pressure, must be provided to carry the support loads.

[Amdt. 179-32, 48 FR 27708, June 16, 1983, as amended at 66 FR 45391, 
Aug. 28, 2001]



Sec.  179.400-10  Sump or siphon bowl.

A sump or siphon bowl may be in the bottom of the inner tank shell if--
    (a) It is formed directly into the inner tank shell, or is formed 
and welded to the inner tank shell and is of weldable quality metal that 
is compatible with the inner tank shell;
    (b) The stress in any orientation under any condition does not 
exceed the circumferential stress in the inner tank shell; and
    (c) The wall thickness is not less than that specified in Sec.  
179.401-1.



Sec.  179.400-11  Welding.

    (a) Except for closure of openings and a maximum of two 
circumferential closing joints in the cylindrical portion of the outer 
jacket, each joint of an inner tank and the outer jacket must be a 
fusion double welded butt joint.
    (b) The closure for openings and the circumferential closing joints 
in the cylindrical portion of the outer jacket, including head to shell 
joints, may be a single welded butt joint using a backing strip on the 
inside of the joint.
    (c) Each joint must be welded in accordance with the requirements of 
AAR Specifications for Tank Cars, appendix W (IBR, see Sec.  171.7 of 
this subchapter).
    (d) Each welding procedure, welder, and fabricator must be approved.

[Amdt. 179-32, 48 FR 27708, June 16, 1983, as amended at 68 FR 75763, 
Dec. 31, 2003]



Sec.  179.400-12  Postweld heat treatment.

    (a) Postweld heat treatment of the inner tank is not required.
    (b) The cylindrical portion of the outer jacket, with the exception 
of the circumferential closing seams, must be postweld heat treated as 
prescribed in AAR Specifications for Tank Cars, appendix W (IBR, see 
Sec.  171.7 of this subchapter). Any item to be welded to this portion 
of the outer jacket must be attached before postweld heat treatment. 
Welds securing the following need not be postweld heat treated when it 
is not practical due to final assembly procedures:
    (1) the inner tank support system to the outer jacket,
    (2) connections at piping penetrations,
    (3) closures for access openings, and
    (4) circumferential closing joints of head to shell joints.
    (c) When cold formed heads are used on the outer jacket they must be 
heat treated before welding to the jacket shell if postweld heat 
treatment is not practical due to assembly procedures.

[Amdt. 179-32, 48 FR 27708, June 16, 1983, as amended at 68 FR 75763, 
Dec. 31, 2003]



Sec.  179.400-13  Support system for inner tank.

    (a) The inner tank must be supported within the outer jacket by a 
support system of approved design. The system and its areas of 
attachment to the outer jacket must have adequate strength and ductility 
at operating temperatures to support the inner tank when filled with the 
lading to any level incident to transportation.
    (b) The support system must be designed to support, without 
yielding, impact loads producing accelerations of the following 
magnitudes and directions when the inner tank is fully loaded and the 
car is equipped with a conventional draft gear:
Longitudinal......................................................7``g''
Transverse........................................................3``g''
Vertical..........................................................3``g''

The longitudinal acceleration may be reduced to 3``g'' where a 
cushioning device of approved design, which has been tested to 
demonstrate its ability to limit body forces to 400,000 pounds maximum 
at 10 miles per hour, is used between the coupler and the tank 
structure.
    (c) The inner tank and outer jacket must be permanently bonded to 
each other electrically, by either the support system, piping, or a 
separate electrical connection of approved design.



Sec.  179.400-14  Cleaning of inner tank.

    The interior of the inner tank and all connecting lines must be 
thoroughly cleaned and dried prior to use. Proper precautions must be 
taken to avoid

[[Page 314]]

contamination of the system after cleaning.



Sec.  179.400-15  Radioscopy.

    Each longitudinal and circumferential joint of the inner tank, and 
each longitudinal and circumferential double welded butt joint of the 
outer jacket, must be examined along its entire length in accordance 
with the requirements of AAR Specifications for Tank Cars, appendix W 
(IBR, see Sec.  171.7 of this subchapter).

[68 FR 75763, Dec. 31, 2003]



Sec.  179.400-16  Access to inner tank.

    (a) The inner tank must be provided with a means of access having a 
minimum inside diameter of 16 inches. Reinforcement of the access 
opening must be made of the same material used in the inner tank. The 
access closure must be of an approved material and design.
    (b) If a welded closure is used, it must be designed to allow it to 
be reopened by grinding or chipping and to be closed again by rewelding, 
preferably without a need for new parts. A cutting torch may not be 
used.



Sec.  179.400-17  Inner tank piping.

    (a) Product lines. The piping system for vapor and liquid phase 
transfer and venting must be made for material compatible with the 
product and having satisfactory properties at the lading temperature. 
The outlets of all vapor phase and liquid phase lines must be located so 
that accidental discharge from these lines will not impinge on any metal 
of the outer jacket, car structures, trucks or safety appliances. 
Suitable provison must be made to allow for thermal expansion and 
contraction.
    (1) Loading and unloading line. A liquid phase transfer line must be 
provided and it must have a manually operated shut-off valve located as 
close as practicable to the outer jacket, plus a secondary closure that 
is liquid and gas tight. This secondary closure must permit any trapped 
pressure to bleed off before the closure can be removed completely. A 
vapor trap must be incorporated in the line and located as close as 
practicable to the inner tank. On a DOT-113A60W tank car, any loading 
and unloading line must be vacuum jacketed between the outer jacket and 
the shut-off valve and the shut-off valve must also be vacuum jacketed.
    (2) Vapor phase line. A vapor phase line must connect to the inner 
tank and must be of sufficient size to permit the pressure relief 
devices specified in Sec.  179.400-20 and connected to this line to 
operate at their design capacity without excessive pressure build-up in 
the tank. The vapor phase line must have a manually operated shut-off 
valve located as close as practicable to the outer jacket, plus a 
secondary closure that is liquid and gas tight. This secondary closure 
must permit any trapped pressure to bleed off before the closure can be 
removed completely.
    (3) Vapor phase blowdown line. A blowdown line must be provided. It 
must be attached to the vapor phase line specified in paragraph (a)(2) 
of this section, upstream of the shut-off valve in that line. A by-pass 
line with a manually operated shut-off valve must be provided to permit 
reduction of the inner tank pressure when the vapor phase line is 
connected to a closed system. The discharge from this line must be 
outside the housing and must be directed upward and away from operating 
personnel.
    (b) Any pressure building system provided for the purpose of 
pressurizing the vapor space of the inner tank to facilitate unloading 
the liquid lading must be approved.

[Amdt. 179-32, 48 FR 27708, June 16, 1983, as amended at 66 FR 45391, 
Aug. 28, 2001]



Sec.  179.400-18  Test of inner tank.

    (a) After all items to be welded to the inner tank have been welded 
in place, the inner tank must be pressure tested at the test pressure 
prescribed in Sec.  179.401-1. The temperature of the pressurizing 
medium may not exceed 38 [deg]C (100 [deg]F) during the test. The inner 
tank must hold the prescribed pressure for a period of not less than ten 
minutes without leakage or distortion. In a pneumatic test, due regard 
for the protection of all personnel should be taken because of the 
potential hazard involved. After a hydrostatic test the container and 
piping must be emptied

[[Page 315]]

of all water and purged of all water vapor.
    (b) Caulking of welded joints to stop leaks developed during the 
test is prohibited. Repairs to welded joints must be made as prescribed 
in AAR Specifications for Tank Cars, appendix W (IBR, see Sec.  171.7 of 
this subchapter).

[Amdt. 179-32, 48 FR 27708, June 16, 1983, as amended at 68 FR 75763, 
Dec. 31, 2003; 73 FR 57008, Oct. 1, 2008]



Sec.  179.400-19  Valves and gages.

    (a) Valves. Manually operated shut-off valves and control valves 
must be provided wherever needed for control of vapor phase pressure, 
vapor phase venting, liquid transfer and liquid flow rates. All valves 
must be made from approved materials compatible with the lading and 
having satisfactory properties at the lading temperature.
    (1) Liquid control valves must be of extended stem design.
    (2) Packing, if used, must be satisfactory for use in contact with 
the lading and of approved materials that will effectively seal the 
valve stem without causing difficulty of operation.
    (3) Each control valve and shut-off valve must be readily operable. 
These valves must be mounted so that their operation will not transmit 
excessive forces to the piping system.
    (b) Gages. Gages, except portable units, must be securely mounted 
within suitable protective housings. A liquid level gage and a vapor 
phase pressure gage must be provided as follows:
    (1) Liquid level gage. (i) A gage of approved design to indicate the 
quantity of liquefied lading within the inner tank, mounted where it 
will be readily visible to an operator during transfer operations or 
storage, or a portable gage with a readily accessible connection, or
    (ii) A fixed length dip tube, with a manually operated shut-off 
valve located as close as practicable to the outer jacket. The dip tube 
must indicate the maximum liquid level for the allowable filling 
density. The inner end of the dip tube must be located on the 
longitudinal centerline of the inner tank and within four feet of the 
transverse centerline of the inner tank.
    (2) Vapor phase pressure gage. A vapor phase pressure gage of 
approved design, with a manually operated shut-off valve located as 
close as practicable to the outer jacket. The gage must indicate the 
vapor pressure within the inner tank and must be mounted where it will 
be readily visible to an operator. An additional fitting for use of a 
test gage must be provided.



Sec.  179.400-20  Pressure relief devices.

    (a) The tank must be provided with pressure relief devices for the 
protection of the tank assembly and piping system. The discharge from 
these devices must be directed away from operating personnel, principal 
load bearing members of the outer jacket, car structure, trucks and 
safety appliances. Vent or weep holes in pressure relief devices are 
prohibited. All main pressure relief devices must discharge to the 
outside of the protective housings in which they are located, except 
that this requirement does not apply to pressure relief valves installed 
to protect isolated sections of lines between the final valve and end 
closure.
    (b) Materials. Materials used in pressure relief devices must be 
suitable for use at the temperature of the lading and otherwise 
compatible with the lading in both the liquid and vapor phases.
    (c) Inner tank. Pressure relief devices for the inner tank must be 
attached to vapor phase piping and mounted so as to remain at ambient 
temperature prior to operation. The inner tank must be equipped with one 
or more pressure relief valves and one or more safety vents (except as 
noted in paragraph (c)(3)(iv) of this section), and installed without an 
intervening shut-off valve (except as noted in paragraph (c)(3)(iii) of 
this section). Additional requirements are as follows:
    (1) Safety vent. The safety vent shall function at the pressure 
specified in Sec.  179.401-1. The safety vent must be flow rated in 
accordance with the applicable provisions of AAR Specifications for Tank 
Cars, appendix A (IBR, see Sec.  171.7 of this subchapter), and provide 
sufficient capacity to meet the requirements of AAR Specifications for 
Tank Cars, appendix A, A8.07(a).
    (2) Pressure relief valve. The pressure relief valve must:
    (i) be set to start-to-discharge at the pressure specified in Sec.  
179.401-1, and

[[Page 316]]

    (ii) meet the requirements of AAR Specifications for Tank Cars, 
appendix A, A8.07(b).
    (3) Installation of safety vent and pressure relief valve--(i) Inlet 
piping. (A) The opening through all piping and fittings between the 
inner tank and its pressure relief devices must have a cross-sectional 
area at least equal to that of the pressure relief device inlet, and the 
flow characteristics of this upstream system must be such that the 
pressure drop will not adversely affect the relieving capacity or the 
proper operation of the pressure relief device.
    (B) When the required relief capacity is met by the use of multiple 
pressure relief device placed on one connection, the inlet internal 
cross-sectional area of this connection must be sufficient to provide 
the required flow capacity for the proper operation of the pressure 
relief device system.
    (ii) Outlet piping. (A) The opening through the discharge lines must 
have a cross-sectional area at least equal to that of the pressure 
relief device outlet and may not reduce the relieving capacity below 
that required to properly protect the inner tank.
    (B) When the required relieving capacity is met by use of multiple 
pressure relief devices placed on a common discharge manifold, the 
manifold outlet internal cross-sectional area must be at least equal to 
the combined outlet areas of the pressure relief devices.
    (iii) Duplicate pressure relief devices may be used when an approved 
3-way selector valve is installed to provide for relief through either 
duplicate pressure relief device. The 3-way valve must be included in 
the mounting prescribed by AAR Specifications for Tank Cars, appendix A, 
A6.02(g), when conducting the flow capacity test on the safety vent 
prescribed by AAR Specifications for Tank Cars, appendix A, A6.01. Flow 
capacity tests must be performed with the 3-way valve at both of the 
extreme positions as well as at the mid-position and the flow capacity 
must be in accordance with AAR Specifications for Tank Cars, appendix A, 
A8.07(a).
    (iv) An alternate pressure relief valve, set as required in Sec.  
179.401-1, may be used in lieu of the safety vent, provided it meets the 
flow capacity prescribed in AAR Specifications for Tank Cars, appendix A 
at a flow rating pressure of 110 percent of its start-to-discharge 
pressure. Installation must--
    (A) Prevent moisture accumulation at the seat by providing drainage 
away from that area,
    (B) Permit periodic drainage of the vent piping, and
    (C) Prevent accumulation of foreign material in the vent system.
    (4) Evaporation control. The routine release of vaporized lading may 
be controlled with a pressure controlling and mixing device, except that 
a pressure controlling and mixing device is required on each DOT-113A60W 
car. Any pressure controlling and mixing device must--
    (i) Be set to start-to-discharge at a pressure not greater than that 
specified in Sec.  179.401-1;
    (ii) Have sufficient capacity to limit the pressure within the inner 
tank to that pressure specified in Sec.  179.401-1, when the discharge 
is equal to twice the normal venting rate during transportation, with 
normal vacuum and the outer shell at 130 [deg]F; and
    (iii) Prevent the discharge of a gas mixture exceeding 50% of the 
lower flammability limit to the atmosphere under normal conditions of 
storage or transportation.
    (5) Safety interlock. If a safety interlock is provided for the 
purpose of allowing transfer of lading at a pressure higher than the 
pressure control valve setting but less than the pressure relief valve 
setting, the design must be such that the safety interlock will not 
affect the discharge path of the pressure relief value or safety vent at 
any time. The safety interlock must automatically provide an 
unrestricted discharge path for the pressure control device at all times 
when the tank car is in transport service.
    (d) Outer jacket. The outer jacket must be provided with a suitable 
system to prevent buildup of annular space pressure in excess of 16 psig 
or the external pressure for which the inner tank was designed, 
whichever is less. The total relief area provided by the system must be 
a minimum of 25

[[Page 317]]

square inches, and means must be provided to prevent clogging of any 
system opening, as well as to ensure adequate communication to all areas 
of the insulation space. If a safety vent is a part of the system, it 
must be designed to prevent distortion of the rupture disc when the 
annular space is evacuated.
    (e) Piping system. Where a piping circuit can be isolated by closing 
a valve, means for pressure relief must be provided.

[Amdt. 179-32, 48 FR 27708, June 16, 1983, as amended at 66 FR 45391, 
Aug. 28, 2001; 68 FR 75763, Dec. 31, 2003]



Sec.  179.400-21  Test of pressure relief valves.

    Each valve must be tested with air or gas for compliance with Sec.  
179.401-1 before being put into service.



Sec.  179.400-22  Protective housings.

    Each valve, gage, closure and pressure relief device, with the 
exception of secondary relief valves for the protection of isolated 
piping, must be enclosed within a protective housing. The protective 
housing must be adequate to protect the enclosed components from direct 
solar radiation, mud, sand, adverse environmental exposure and 
mechanical damage incident to normal operation of the tank car. It must 
be designed to provide reasonable access to the enclosed components for 
operation, inspection and maintenance and so that vapor concentrations 
cannot build up to a dangerous level inside the housing in the event of 
valve leakage or pressure relief valve operation. All equipment within 
the protective housing must be operable by personnel wearing heavy 
gloves and must incorporate provisions for locks or seals. A protective 
housing and its cover must be constructed of metal not less than 0.119 
inch thick.



Sec.  179.400-23  Operating instructions.

    All valves and gages must be clearly identified with corrosion-
resistant nameplates. A plate of corrosion-resistant material bearing 
precautionary instructions for the safe operation of the equipment 
during storage and transfer operations must be securely mounted so as to 
be readily visible to an operator. The instruction plate must be mounted 
in each housing containing operating equipment and controls for product 
handling. These instructions must include a diagram of the tank and its 
piping system with the various gages, control valves and pressure relief 
devices clearly identified and located.



Sec.  179.400-24  Stamping.

    (a) A tank that complies with all specification requirements must 
have the following information plainly and permanently stamped into the 
metal near the center of the head of the outer jacket at the ``B'' end 
of the car, in letters and figures at least \3/8\-inch high, in the 
following order:

------------------------------------------------------------------------
                                            Example of required stamping
------------------------------------------------------------------------
Specification............................  DOT-113A60W.
Design service temperature...............  Minus 423 [deg]F.
Inner tank...............................  Inner Tank.
  Material...............................  ASTM A240-304.
  Shell thickness........................  Shell \3/16\ inch.
  Head thickness.........................  Head \3/16\ inch.
  Inside diameter........................  ID 107 inch.
  Inner tank builder's initials..........  ABC.
  Date of original test (month and year)   00-0000GHK.
   and initials of person conducting
   original test.
  Water capacity.........................  00000 lbs.
Outer jacket.............................  Outer jacket.
  Material...............................  ASTM A515-70.
  Outer jacket builder's initials........  DEF.
Car assembler's initials (if other than    XYZ.
 inner tank or outer jacket builder).
------------------------------------------------------------------------

    (b) Any stamping on the shell or heads of the inner tank is 
prohibited.
    (c) In lieu of the stamping required by paragraph (a) of this 
section, the specified markings may be incorporated on a data plate of 
corrosion-resistant metal, fillet welded in place on the head of the 
outer jacket at the ``B'' end of the car.



Sec.  179.400-25  Stenciling.

    Each tank car must be stenciled in compliance with the provisions of 
the AAR Specifications for Tank Cars, appendix C (IBR, see Sec.  171.7 
of this subchapter). The stenciling must also include the following:
    (a) The date on which the rupture disc was last replaced and the 
initials of the person making the replacement, on the outer jacket in 
letters and figures at least 1\1/2\ inches high.

[[Page 318]]

    (b) The design service temperature and maximum lading weight, in 
letters and figures at least 1\1/2\ inches high adjacent to the 
hazardous material stencil.
    (c) The water capacity, in pounds net at 60 [deg]F., with the tank 
at its coldest operating temperature, after deduction for the volume 
above the inlet to the pressure relief device or pressure control valve, 
structural members, baffles, piping, and other appurtenances inside the 
tank, in letters and figures at least 1\1/2\ inches high.
    (d) Both sides of the tank car, in letters at least 1\1/2\ inches 
high, with the statement ``Do Not Hump or Cut Off While in Motion.''
    (e) The outer jacket, below the tank classification stencil, in 
letters at least 1\1/2\ inches high, with the statement, ``vacuum 
jacketed.''

[Amdt. 179-32, 48 FR 27708, June 16, 1983, as amended at 66 FR 45391, 
Aug. 28, 2001; 68 FR 75763, Dec. 31, 2003]



Sec.  179.400-26  Approval to operate at 286,000 gross rail load (GRL).

    A tank car may be loaded to a gross weight on rail of up to 286,000 
pounds (129,727 kg) upon approval by the Associate Administrator for 
Safety, Federal Railroad Administration (FRA). See Sec.  179.13.

[85 FR 45030, July 24, 2020]



Sec.  179.401  Individual specification requirements applicable to inner  
tanks for cryogenic liquid tank car tanks.



Sec.  179.401-1  Individual specification requirements.

    In addition to Sec.  179.400, the individual specification 
requirements for the inner tank and its appurtenances are as follows:

------------------------------------------------------------------------
        DOT specification               113A60W            113C120W
------------------------------------------------------------------------
Design service temperature,       -423..............  -260.
 [deg]F.
Material........................  Sec.   179.400-5..  Sec.   179.400-5.
Impact test (weld and plate       Sec.   179.400-     Sec.   179.400-
 material).                        5(c).               5(c).
Impact test values..............  Sec.   179.400-     Sec.   179.400-
                                   5(d).               5(d).
Standard heat transfer rate.
  (Btu per day per lb. of water   0.097.............  0.4121.
   capacity, max.) (see Sec.
   179.400-4).
Bursting pressure, min. psig....  240...............  300.
Minimum plate thickness shell,    \3/16\............  \3/16\.
 inches (see Sec.   179.400-
 7(a)).
Minimum head thickness, inches    \3/16\............  \3/16\.
 (see Sec.   179.400-8 (a), (b),
 and (c)).
Test pressure, psig (see Sec.     60................  120.
 179.400-16).
Safety vent bursting pressure,    60................  120.
 max. psig.
Pressure relief valve start-to-   30................  75.
 discharge pressure, psig (3 psi).
Pressure relief valve vapor       24................  60.
 tight pressure, min. psig.
Pressure relief valve flow        40................  85.
 rating pressure, max. psig.
Alternate pressure relief valve   ..................  90.
 start to-discharge pressure,
 psig (3
 psi).
Alternate pressure relief valve   ..................  72.
 vapor tight pressure, min. psig.
Alternate pressure relief valve   ..................  100.
 flow rating pressure, max. psig.
Pressure control valve Start-to-  17................  Not required.
 vent, max. psig (see Sec.
 179.400-20(c)(4)).
Relief device discharge           Sec.   179.400-20.  179.400-20.
 restrictions.
Transfer line insulation........  Sec.   179.400-17.  Not required.
------------------------------------------------------------------------


[Amdt. 179-32, 48 FR 27708, June 16, 1983, as amended at 49 FR 24318, 
June 12, 1984; 65 FR 58632, Sept. 29, 2000; 66 FR 45390, Aug. 28, 2001]



Sec.  179.500  Specification DOT-107A * * * * seamless steel tank car tanks.



Sec.  179.500-1  Tanks built under these specifications shall meet the  
requirements of Sec.  179.500.



Sec.  179.500-3  Type and general requirements.

    (a) Tanks built under this specification shall be hollow forged or 
drawn in one piece. Forged tanks shall be machined inside and outside 
before ends are necked-down and, after necking-down, the ends shall be 
machined to size on the ends and outside diameter. Machining not 
necessary on inside or outside of seamless steel tubing, but required on 
ends after necking-down.
    (b) For tanks made in foreign countries, chemical analysis of 
material

[[Page 319]]

and all tests as specified must be carried out within the limits of the 
United States under supervision of a competent and disinterested 
inspector; in addition to which, provisions in Sec.  179.500-18 (b) and 
(c) shall be carried out at the point of manufacture by a recognized 
inspection bureau with principal office in the United States.
    (c) The term ``marked end'' and ``marked test pressure'' used 
throughout this specification are defined as follows:
    (1) ``Marked end'' is that end of the tank on which marks prescribed 
in Sec.  179.500-17 are stamped.
    (2) ``Marked test pressure'' is that pressure in psig which is 
indicated by the figures substituted for the **** in the marking DOT-
107A **** stamped on the marked end of tank.
    (d) The gas pressure at 130 [deg]F in the tank shall not exceed \7/
10\ of the marked test pressure of the tank.

[Amdt. 179-32, 48 FR 27708, June 16, 1983, as amended at 66 FR 45186, 
45391, Aug. 28, 2001]



Sec.  179.500-4  Thickness of wall.

    (a) Minimum thickness of wall of each finished tank shall be such 
that at a pressure equal to \7/10\ of the marked test pressure of the 
tank, the calculated fiber stress in psi at inner wall of tank 
multiplied by 3.0 will not exceed the tensile strength of any specimen 
taken from the tank and tested as prescribed in Sec.  179.500-7(b). 
Minimum wall thickness shall be \1/4\ inch.
    (b) Calculations to determine the maximum marked test pressure 
permitted to be marked on the tank shall be made by the formula:

P = [10S(D\2\ - d\2\)] / [7(D\2\ + d\2\)]

Where:

P = Maximum marked test pressure permitted;

S = U / 3.0

Where:

U = Tensile strength of that specimen which shows the lower tensile 
          strength of the two specimens taken from the tank and tested 
          as prescribed in Sec.  179.500-7(b).
3 = Factor of safety.

(D\2\ - d\2\/(D\2\ + d\2\) = The smaller value obtained for this factor 
          by the operations specified in Sec.  179.500-4(c).

    (c) Measure at one end, in a plane perpendicular to the longitudinal 
axis of the tank and at least 18 inches from that end before necking-
down:

d = Maximum inside diameter (inches) for the location under 
          consideration; to be determined by direct measurement to an 
          accuracy of 0.05 inch.
t = Minimum thickness of wall for the location under consideration; to 
          be determined by direct measurement to an accuracy of 0.001 
          inch.
Take D = d + 2t.
Calculate the value of (D\2\-d\2\)/(D\2\ + d\2\)

    (1) Make similar measurements and calculation for a corresponding 
location at the other end of the tank.
    (2) Use the smaller result obtained, from the foregoing, in making 
calculations prescribed in paragraph (b) of this section.

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended by Amdt. 179-31, 47 FR 43067, Sept. 30, 1982; 66 FR 45391, 
Aug. 28, 2001]



Sec.  179.500-5  Material.

    (a) Tanks shall be made from open-hearth or electric steel of 
uniform quality. Material shall be free from seams, cracks, laminations, 
or other defects injurious to finished tank. If not free from such 
defects, the surface may be machined or ground to eliminate these 
defects. Forgings and seamless tubing for bodies of tanks shall be 
stamped with heat numbers.
    (b) Steel (see Note 1) must conform to the following requirements as 
to chemical composition:

------------------------------------------------------------------------
                                          Class I    Class II  Class III
              Designation                (percent)  (percent)  (percent)
------------------------------------------------------------------------
Carbon, maximum........................       0.50       0.50       0.53
Manganese, maximum.....................       1.65       1.65       1.85
Phosphorus, maximum....................        .05        .05        .05
Sulphur, maximum.......................        .06        .05        .05
Silicon, maximum.......................        .35        .30        .37
Molybdenum, maximum....................  .........        .25        .30
Chromium, maximum......................  .........        .30        .30
Sum of manganese and carbon not over...       2.10       2.10  .........
------------------------------------------------------------------------
Note 1: Alternate steel containing other alloying elements may be used
  if approved.

    (1) For instructions as to the obtaining and checking of chemical 
analysis, see Sec.  179.500-18(b)(3).
    (2) [Reserved]

[[Page 320]]



Sec.  179.500-6  Heat treatment.

    (a) Each necked-down tank shall be uniformly heat treated. Heat 
treatment shall consist of annealing or normalizing and tempering for 
Class I, Class II and Class III steel or oil quenching and tempering for 
Class III steel. Tempering temperatures shall not be less than 1000 
[deg]F. Heat treatment of alternate steels shall be approved. All scale 
shall be removed from outside of tank to an extent sufficient to allow 
proper inspection.
    (b) To check uniformity of heat treatment, Brinnel hardness tests 
shall be made at 18 inch intervals on the entire longitudinal axis. The 
hardness shall not vary more than 35 points in the length of the tank. 
No hardness tests need be taken within 12 inches from point of head to 
shell tangency.
    (c) A magnetic particle inspection shall be performed after heat 
treatment on all tanks subjected to a quench and temper treatment to 
detect the presence of quenching cracks. Cracks shall be removed to 
sound metal by grinding and the surface exposed shall be blended 
smoothly into the surrounding area. A wall thickness check shall then be 
made of the affected area by ultrasonic equipment or other suitable 
means acceptable to the inspector and if the remaining wall thickness is 
less than the minimum recorded thickness as determined by Sec.  179.500-
4(b) it shall be used for making the calculation prescribed in paragraph 
(b) of this section.



Sec.  179.500-7  Physical tests.

    (a) Physical tests shall be made on two test specimens 0.505 inch in 
diameter within 2-inch gauge length, taken 180 degrees apart, one from 
each ring section cut from each end of each forged or drawn tube before 
necking-down, or one from each prolongation at each end of each necked-
down tank. These test specimen ring sections or prolongations shall be 
heat treated, with the necked-down tank which they represent. The width 
of the test specimen ring section must be at least its wall thickness. 
Only when diameters and wall thickness will not permit removal of 0.505 
by 2-inch tensile test bar, laid in the transverse direction, may test 
bar cut in the longitudinal direction be substituted. When the thickness 
will not permit obtaining a 0.505 specimen, then the largest diameter 
specimen obtainable in the longitudinal direction shall be used. 
Specimens shall have bright surface and a reduced section. When 0.505 
specimen is not used the gauge length shall be a ratio of 4 to 1 length 
to diameter.
    (b) Elastic limit as determined by extensometer, shall not exceed 70 
percent of tensile strength for class I steel or 85 percent of tensile 
strength for class II and class III steel. Determination shall be made 
at cross head speed of not more than 0.125 inch per minute with an 
extensometer reading to 0.0002 inch. The extensometer shall be read at 
increments of stress not exceeding 5,000 psi. The stress at which the 
strain first exceeds

        stress (psi) /30,000,000 (psi) + 0.005 (inches per inch)

shall be recorded as the elastic limit.
    (1) Elongation shall be at least 18 percent and reduction of area at 
least 35 percent.

    Note 1: Upon approval, the ratio of elastic limit to ultimate 
strength may be raised to permit use of special alloy steels of definite 
composition that will give equal or better physical properties than 
steels herein specified.

    (2) [Reserved]

[Amdt. 179-8, 36 FR 18470, Sept. 15, 1971, as amended at 66 FR 45391, 
Aug. 28, 2001]



Sec.  179.500-8  Openings in tanks.

    (a) Each end shall be closed by a cover made of forged steel. Covers 
shall be secured to ends of tank by through bolts or studs not entering 
interior of tank. Covers shall be of a thickness sufficient to meet test 
requirements of Sec.  179.500-12 and to compensate for the openings 
closed by attachments prescribed herein.
    (1) It is also provided that each end may be closed by internal 
threading to accommodate an approved fitting. The internal threads as 
well as the threads on fittings for these openings shall be clean cut, 
even, without checks, and tapped to gauge. Taper threads are required 
and shall be of a length not less than as specified for American 
Standard taper pipe threads. External

[[Page 321]]

threading of an approved type shall be permissible on the internal 
threaded ends.
    (b) Joints between covers and ends and between cover and attachments 
shall be of approved form and made tight against vapor or liquid leakage 
by means of a confined gasket of suitable material.



Sec.  179.500-10  Protective housing.

    (a) Safety devices, and loading and unloading valves on tanks shall 
be protected from accidental damage by approved metal housing, arranged 
so it may be readily opened to permit inspection and adjustment of 
safety relief devices and valves, and securely locked in closed 
position. Housing shall be provided with opening having an opening equal 
to twice the total discharge area of pressure relief device enclosed.
    (b) [Reserved]

[29 FR 18995, Dec. 29, 1964. Redesignated at 32 FR 5606, Apr. 5, 1967, 
and amended at 66 FR 45390, Aug. 28, 2001; 67 FR 61016, Sept. 27, 2002]



Sec.  179.500-11  Loading and unloading valves.

    (a) Loading and unloading valve or valves shall be mounted on the 
cover or threaded into the marked end of tank. These valves shall be of 
approved type, made of metal not subject to rapid deterioration by 
lading or in service, and shall withstand without leakage a pressure 
equal to the marked test pressure of tank. Provision shall be made for 
closing service outlet of valves.
    (b) [Reserved]



Sec.  179.500-12  Pressure relief devices.

    (a) Tank shall be equipped with one or more pressure relief devices 
of approved type and discharge area, mounted on the cover or threaded 
into the non-marked end of the tank. If fittings are mounted on a cover, 
they shall be of the flanged type, made of metal not subject to rapid 
deterioration by lading or in service. Total flow capacity shall be such 
that, with tank filled with air at pressure equal to 70 percent of the 
marked test pressure of tank, flow capacity will be sufficient to reduce 
air pressure to 30 percent of the marked test pressure within 3 minutes 
after pressure relief device opens.
    (b) Pressure relief devices shall open at a pressure not exceeding 
the marked test pressure of tank and not less than \7/10\ of marked test 
pressure. (For tolerance for pressure relief valves, see Sec.  179.500-
16(a).)
    (c) Cars used for the transportation of flammable gases shall have 
the safety devices equipped with an approved ignition device.

[Amdt. 179-32, 48 FR 27708, June 16, 1983, as amended at 66 FR 45391, 
Aug. 28, 2001; 68 FR 57634, Oct. 6, 2003]



Sec.  179.500-13  Fixtures.

    (a) Attachments, other than those mounted on tank covers or serving 
as threaded closures for the ends of the tank, are prohibited.
    (b) [Reserved]



Sec.  179.500-14  Test of tanks.

    (a) After heat-treatment, tanks shall be subjected to hydrostatic 
tests in a water jacket, or by other accurate method, operated so as to 
obtain reliable data. No tank shall have been subjected previously to 
internal pressure greater than 90 percent of the marked test pressure. 
Each tank shall be tested to a pressure at least equal to the marked 
test pressure of the tank. Pressure shall be maintained for 30 seconds, 
and sufficiently longer to insure complete expansion of tank. Pressure 
gauge shall permit reading to accuracy of one percent. Expansion gauge 
shall permit reading of total expansion to accuracy of one percent. 
Expansion shall be recorded in cubic cm.
    (b) No leaks shall appear and permanent volumetric expansion shall 
not exceed 10 percent of the total volumetric expansion at test 
pressure.



Sec.  179.500-15  Handling of tanks failing in tests.

    (a) Tanks rejected for failure in any of the tests prescribed may be 
reheat-treated, and will be acceptable if subsequent to reheat-treatment 
they are subjected to and pass all of the tests.
    (b) [Reserved]



Sec.  179.500-16  Tests of pressure relief devices.

    (a) Pressure relief valves shall be tested by air or gas before 
being put

[[Page 322]]

into service. Valve shall open at pressure not exceeding the marked test 
pressure of tank and shall be vapor-tight at 80 percent of the marked 
test pressure. These limiting pressures shall not be affected by any 
auxiliary closure or other combination.
    (b) For pressure relief devices that incorporate a rupture disc, 
samples of the discs used shall burst at a pressure not exceeding the 
marked test pressure of tank and not less than \7/10\ of marked test 
pressure.

[Amdt. 179-32, 48 FR 27708, June 16, 1983, as amended at 66 FR 45391, 
Aug. 28, 2001]



Sec.  179.500-17  Marking.

    (a) Each tank shall be plainly and permanently marked, thus 
certifying that tank complies with all requirements of this 
specification. These marks shall be stamped into the metal of necked-
down section of tank at marked end, in letters and figures at least \1/
4\ inch high, as follows:
    (1) Spec. DOT-107A * * * *, the * * * * to be replaced by figures 
indicating marked test pressure of the tank. This pressure shall not 
exceed the calculated maximum marked test pressure permitted, as 
determined by the formula in Sec.  179.500-4(b).
    (2) Serial number immediately below the stamped mark specified in 
paragraph (a)(1) of this section.
    (3) Inspector's official mark immediately below the stamped mark 
specified in paragraph (a)(1) of this section.
    (4) Name, mark (other than trademark), or initials of company or 
person for whose use tank is being made, which shall be recorded with 
the Bureau of Explosives.
    (5) Date (such as 1-01, for January 2001) of tank test, so placed 
that dates of subsequent tests may easily be added.
    (6) Date (such as 1-01, for January 2001) of latest test of pressure 
relief device or of the rupture disc, required only when tank is used 
for transportation of flammable gases.
    (b) [Reserved]

[29 FR 18995, Dec. 29, 1964, as amended by Amdt. 179-52, 61 FR 28682, 
June 5, 1996; 66 FR 45391, Aug. 28, 2001]



Sec.  179.500-18  Inspection and reports.

    (a) Before a tank car is placed in service, the party assembling the 
completed car shall furnish to car owner, Bureau of Explosives, and the 
Secretary, Mechanical Division, Association of American Railroads, a 
report in proper form certifying that tanks and their equipment comply 
with all the requirements of this specification and including 
information as to serial numbers, dates of tests, and ownership marks on 
tanks mounted on car structure.
    (b) Purchaser of tanks shall provide for inspection by a competent 
inspector as follows:
    (1) Inspector shall carefully inspect all material and reject that 
not complying with Sec.  179.500-5.
    (2) Inspector shall stamp his official mark on each forging or 
seamless tube accepted by him for use in making tanks, and shall verify 
proper application of heat number to such material by occasional 
inspections at steel manufacturer's plant.
    (3) Inspector shall obtain certified chemical analysis of each heat 
of material.
    (4) Inspector shall make inspection of inside surface of tanks 
before necking-down, to insure that no seams, cracks, laminations, or 
other defects exist.
    (5) Inspector shall fully verify compliance with specification, 
verify heat treatment of tank as proper; obtain samples for all tests 
and check chemical analyses; witness all tests; and report minimum 
thickness of tank wall, maximum inside diameter, and calculated value of 
D, for each end of each tank as prescribed in Sec.  179.500-4(c).
    (6) Inspector shall stamp his official mark on each accepted tank 
immediately below serial number, and make certified report (see 
paragraph (c) of this section) to builder, to company or person for 
whose use tanks are being made, to builder of car structure on which 
tanks are to be mounted, to the Bureau of Explosives, and to the 
Secretary, Mechanical Division, Association of American Railroads.
    (c) Inspector's report required herein shall be in the following 
form:

 (Place)________________________________________________________________
 (Date)_________________________________________________________________

[[Page 323]]

                               Steel Tanks

    It is hereby certified that drawings were submitted for these tanks 
under AAR Application for Approval ____________ and approved by the AAR 
Committee on Tank Cars under date of ____________.
Built for ________________________ Company
Location at_____________________________________________________________
Built by ________________________ Company
Location at_____________________________________________________________
Consigned to __________________ Company
Location at_____________________________________________________________
Quantity________________________________________________________________
Length (inches)_________________________________________________________
Outside diameter (inches)_______________________________________________
Marks stamped into tank as required in Sec.  179.500-17 are:

                             DOT-107A* * * *

    Note 1: The marked test pressure substituted for the * * * * on each 
tank is shown on Record of General Data on Tanks attached hereto.

Serial numbers ____ to ____ inclusive
Inspector's mark________________________________________________________
Owner's mark____________________________________________________________
Test date_______________________________________________________________
Water capacity (see Record of Hydrostatic Tests).
Tare weights (yes or no) (see Record of Hydrostatic Tests).
These tanks were made by process of_____________________________________
    Steel used was identified as indicated by the attached list showing 
the serial number of each tank, followed by the heat number.
    Steel used was verified as to chemical analysis and record thereof 
is attached hereto. Heat numbers were stamped into metal. All material 
was inspected and each tank was inspected both before and after closing 
in ends; all material accepted was found free from seams, cracks, 
laminations, and other defects which might prove injurious to strength 
of tank. Processes of manufacture and heat-treatment of tanks were 
witnessed and found to be efficient and satisfactory.
    Before necking-down ends, each tank was measured at each location 
prescribed in Sec.  179.500-4(c) and minimum wall thickness in inches at 
each location was recorded; maximum inside diameter in inches at each 
location was recorded; value of D in inches at each location was 
calculated and recorded; maximum fiber stress in wall at location 
showing larger value for

(D\2\ + d\2\)/(D\2\-d\2\)

was calculated for \7/10\ the marked test pressure and recorded. 
Calculations were made by the formula:

S=[0.7P(D\2\-d\2\)/(D\2\ + d\2\)]

    Hydrostatic tests, tensile test of material, and other tests as 
prescribed in this specification, were made in the presence of the 
inspector, and all material and tanks accepted were found to be in 
compliance with the requirements of this specification. Records thereof 
are attached hereto.
    I hereby certify that all of these tanks proved satisfactory in 
every way and comply with the requirements of Department of 
Transportation Specification No. 107A* * * *.

 (Signed)_______________________________________________________________
                                                             (Inspector)
 (Place)________________________________________________________________
 (Date)_________________________________________________________________

             Record of Chemical Analysis of Steel for Tanks

Numbered ________ to ________ inclusive
Size __ inches outside diameter by __ inches long
Built by ________________________ Company
For ______________________________ Company

------------------------------------------------------------------------
              Tanks                     Chemical analysis
  Heat     represented  ------------------------------------------------
  No.     (serial Nos.)    C     Mn     P     S    Si    Ni    Cr    Mo
------------------------------------------------------------------------
 
 
------------------------------------------------------------------------

These analyses were made by
 (Signed)_______________________________________________________________
 (Place)________________________________________________________________
 (Date)_________________________________________________________________

              Record of Chemical Analysis of Steel in Tanks

Numbered ________ to ________ inclusive
Size ____ inches outside by ____ inches long
Built by ________________________ Company
For ______________________________ Company

------------------------------------------------------------------------
             Tanks
  Heat    represented    Elastic     Tensile    Elongation    Reduction
  No.       by test       limit     strength    (percent in    of area
         (serial Nos.)    (psi)       (psi)      2 inches)    (percent)
------------------------------------------------------------------------
 
 
------------------------------------------------------------------------

 (Signed)_______________________________________________________________
 (Place)________________________________________________________________
 (Date)_________________________________________________________________

                                      Record of Hydrostatic Tests on Tanks
Numbered.................................  to...........................  inclusive
Size.....................................  inches outside by............  .........  inches long
Built by...........................................................................  Company
For................................................................................  Company
 


[[Page 324]]


----------------------------------------------------------------------------------------------------------------
                                                                   Percent ratio
                                       Total         Permanent     of permanent                     Capacity in
 Serial Nos. of    Actual test       expansion       expansion     expansion to     Tare weight      pounds of
     tanks       pressure (psig)    (cubic cm)      (cubic cm)         total       (pounds) \2\     water at 60
                                                                   expansion \1\                      [deg]F
----------------------------------------------------------------------------------------------------------------
 
 
 
----------------------------------------------------------------------------------------------------------------
\1\ If tests are made by method involving measurement of amount of liquid forced into tank by test pressure,
  then the basic data on which calculations are made, such as pump factors, temperature of liquid, coefficient
  of compressibility of liquid, etc., must also be given.
\2\ Do not include protective housing, but state whether with or without valves.

 (Signed)_______________________________________________________________
 (Place)________________________________________________________________
 (Date)_________________________________________________________________

                                         Record of General Data on Tanks
Numbered.................................  to...........................  inclusive
Built by...........................................................................  Company
For................................................................................  Company
 


----------------------------------------------------------------------------------------------------------------
           Data obtained as prescribed in Sec.   179.500-4(c)
------------------------------------------------------------------------- Larger      (S)
           Marked end of tank                   Other end of tank          value  Calculated   Marked    Minimum
------------------------------------------------------------------------- of the     fiber      test     tensile
                                 (D)                   (d)        (D)     factor   stress in  pressure  strength
         (t) Min.  (d) Max.  Calculated     (t)      Maximum  calculated  D\2\ +  psi at \7/   in psig     of
Serial  thickness   inside   value of D   Minimum    inside   value of D   d\2\/  10\ marked   stamped  material
No. of   of wall   diameter      in      thickness  diameter      in       D\2\-     test      in tank   in psi
 tank   in inches     in     inches=d +   of wall      in     inches=d +   d\2\    pressure             recorded
                    inches       2t      in inches   inches       2t
----------------------------------------------------------------------------------------------------------------
 
 
----------------------------------------------------------------------------------------------------------------

 (Signed)_______________________________________________________________

[Amdt. 179-32, 48 FR 27708, June 16, 1983, as amended by 66 FR 45391, 
Aug. 28, 2001]





     Sec. Appendix A to Part 179--Procedures for Tank-Head Puncture-
                             Resistance Test

    1. This test procedure is designed to verify the integrity of new or 
untried tank-head puncture-resistance systems and to test for system 
survivability after coupler-to-tank-head impacts at relative speeds of 
29 km/hour (18 mph). Tank-head puncture-resistance is a function of one 
or more of the following: Head thickness, jacket thickness, insulation 
thickness, and material of construction.
    2. Tank-head puncture-resistance test. A tank-head puncture-
resistance system must be tested under the following conditions:
    a. The ram car used must weigh at least 119,295 kg (263,000 pounds), 
be equipped with a coupler, and duplicate the condition of a 
conventional draft sill including the draft yoke and draft gear. The 
coupler must protrude from the end of the ram car so that it is the 
leading location of perpendicular contact with the impacted test car.
    b. The impacted test car must be loaded with water at six percent 
outage with internal pressure of at least 6.9 Bar (100 psig) and coupled 
to one or more ``backup'' cars which have a total weight of 217,724 kg 
(480,000 pounds) with hand brakes applied on the last ``backup'' car.
    c. At least two separate tests must be conducted with the coupler on 
the vertical centerline of the ram car. One test must be conducted with 
the coupler at a height of 53.3 cm (21 inches), plus-or-minus 2.5 cm (1 
inch), above the top of the sill; the other test must be conducted with 
the coupler height at 79 cm (31 inches), plus-or-minus 2.5 cm (1 inch), 
above the top of the sill. If the combined thickness of the tank head 
and any additional shielding material is less than the

[[Page 325]]

combined thickness on the vertical centerline of the car, a third test 
must be conducted with the coupler positioned so as to strike the 
thinnest point of the tank head.
    3. One of the following test conditions must be applied:

------------------------------------------------------------------------
                                   Minimum velocity
 Minimum weight of attached ram    of impact in km/      Restrictions
       cars in kg (pounds)            hour (mph)
------------------------------------------------------------------------
119,295 (263,000)...............  29 (18)..........  One ram car only.
155,582 (343,000)...............  25.5 (16)........  One ram car or one
                                                      car plus one
                                                      rigidly attached
                                                      car.
311,164 (686,000)...............  22.5 (14)........  One ram car plus
                                                      one or more
                                                      rigidly attached
                                                      cars.
------------------------------------------------------------------------

    4. A test is successful if there is no visible leak from the 
standing tank car for at least one hour after impact.

[Amdt. 179-50, 60 FR 49078, Sept. 21, 1995, as amended by Amdt. 179-50, 
61 FR 33256, June 26, 1996; 66 FR 45390, Aug. 28, 2001]



  Sec. Appendix B to Part 179--Procedures for Simulated Pool and Torch-
                              Fire Testing

    1. This test procedure is designed to measure the thermal effects of 
new or untried thermal protection systems and to test for system 
survivability when exposed to a 100-minute pool fire and a 30-minute 
torch fire.
    2. Simulated pool fire test.
    a. A pool-fire environment must be simulated in the following 
manner:
    (1) The source of the simulated pool fire must be hydrocarbon fuel 
with a flame temperature of 871 [deg]C plus or minus 55.6 [deg]C (1600 
[deg]F plus-or-minus 100 [deg]F) throughout the duration of the test.
    (2) A square bare plate with thermal properties equivalent to the 
material of construction of the tank car must be used. The plate 
dimensions must be not less than one foot by one foot by nominal 1.6 cm 
(0.625 inch) thick. The bare plate must be instrumented with not less 
than nine thermocouples to record the thermal response of the bare 
plate. The thermocouples must be attached to the surface not exposed to 
the simulated pool fire and must be divided into nine equal squares with 
a thermocouple placed in the center of each square.
    (3) The pool-fire simulator must be constructed in a manner that 
results in total flame engulfment of the front surface of the bare 
plate. The apex of the flame must be directed at the center of the 
plate.
    (4) The bare plate holder must be constructed in such a manner that 
the only heat transfer to the back side of the bare plate is by heat 
conduction through the plate and not by other heat paths.
    (5) Before the bare plate is exposed to the simulated pool fire, 
none of the temperature recording devices may indicate a plate 
temperature in excess of 37.8 [deg]C (100 [deg]F) nor less than 0 [deg]C 
(32 [deg]F).
    (6) A minimum of two thermocouple devices must indicate 427 [deg]C 
(800 [deg]F) after 13 minutes, plus-or-minus one minute, of simulated 
pool-fire exposure.
    b. A thermal protection system must be tested in the simulated pool-
fire environment described in paragraph 2a of this appendix in the 
following manner:
    (1) The thermal protection system must cover one side of a bare 
plate as described in paragraph 2a(2) of this appendix.
    (2) The non-protected side of the bare plate must be instrumented 
with not less than nine thermocouples placed as described in paragraph 
2a(2) of this appendix to record the thermal response of the plate.
    (3) Before exposure to the pool-fire simulation, none of the 
thermocouples on the thermal protection system configuration may 
indicate a plate temperature in excess of 37.8 [deg]C (100 [deg]F) nor 
less than 0 [deg]C (32 [deg]F).
    (4) The entire surface of the thermal protection system must be 
exposed to the simulated pool fire.
    (5) A pool-fire simulation test must run for a minimum of 100 
minutes. The thermal protection system must retard the heat flow to the 
plate so that none of the thermocouples on the non-protected side of the 
plate indicate a plate temperature in excess of 427 [deg]C (800 [deg]F).
    (6) A minimum of three consecutive successful simulation fire tests 
must be performed for each thermal protection system.
    3. Simulated torch fire test.
    a. A torch-fire environment must be simulated in the following 
manner:
    (1) The source of the simulated torch must be a hydrocarbon fuel 
with a flame temperature of 1,204 [deg]C plus-or-minus 55.6 [deg]C 
(2,200 [deg]F plus or minus 100 [deg]F), throughout the duration of the 
test. Furthermore, torch velocities must be 64.4 km/h 16 km/h (40 mph 10 mph) throughout 
the duration of the test.
    (2) A square bare plate with thermal properties equivalent to the 
material of construction of the tank car must be used. The plate 
dimensions must be at least four feet by four feet by nominal 1.6 cm 
(0.625 inch) thick. The bare plate must be instrumented with not less 
than nine thermocouples to record the thermal response of the plate. The 
thermocouples must be attached to the surface not exposed to the 
simulated torch and must be divided into nine equal squares with a 
thermocouple placed in the center of each square.
    (3) The bare plate holder must be constructed in such a manner that 
the only heat transfer to the back side of the plate is by heat 
conduction through the plate and not

[[Page 326]]

by other heat paths. The apex of the flame must be directed at the 
center of the plate.
    (4) Before exposure to the simulated torch, none of the temperature 
recording devices may indicate a plate temperature in excess of 37.8 
[deg]C (100 [deg]F) or less than 0 [deg]C (32 [deg]F).
    (5) A minimum of two thermocouples must indicate 427 [deg]C (800 
[deg]F) in four minutes, plus-or-minus 30 seconds, of torch simulation 
exposure.
    b. A thermal protection system must be tested in the simulated 
torch-fire environment described in paragraph 3a of this appendix in the 
following manner:
    (1) The thermal protection system must cover one side of the bare 
plate identical to that used to simulate a torch fire under paragraph 
3a(2) of this appendix.
    (2) The back of the bare plate must be instrumented with not less 
than nine thermocouples placed as described in paragraph 3a(2) of this 
appendix to record the thermal response of the material.
    (3) Before exposure to the simulated torch, none of the 
thermocouples on the back side of the thermal protection system 
configuration may indicate a plate temperature in excess of 37.8 [deg]C 
(100 [deg]F) nor less than 0 [deg]C (32 [deg]F).
    (4) The entire outside surface of the thermal protection system must 
be exposed to the simulated torch-fire environment.
    (5) A torch-simulation test must be run for a minimum of 30 minutes. 
The thermal protection system must retard the heat flow to the plate so 
that none of the thermocouples on the backside of the bare plate 
indicate a plate temperature in excess of 427 [deg]C (800 [deg]F).
    (6) A minimum of two consecutive successful torch-simulation tests 
must be performed for each thermal protection system.

[Amdt. 179-50, 60 FR 49078, Sept. 21, 1995, as amended at 75 FR 53597, 
Sept. 1, 2010; 77 FR 60945, Oct. 5, 2012]



PART 180_CONTINUING QUALIFICATION AND MAINTENANCE OF PACKAGINGS--Table of   
                                Contents



                            Subpart A_General

Sec.
180.1 Purpose and scope.
180.2 Applicability.
180.3 General requirements.

Subpart B [Reserved]

        Subpart C_Qualification, Maintenance and Use of Cylinders

180.201 Applicability.
180.203 Definitions.
180.205 General requirements for requalification of specification 
          cylinders.
180.207 Requirements for requalification of UN pressure receptacles.
180.209 Requirements for requalification of specification cylinders.
180.211 Repair, rebuilding and reheat treatment of DOT-4 series 
          specification cylinders.
180.212 Repair of seamless DOT 3-series specification cylinders and 
          seamless UN pressure receptacles.
180.213 Requalification markings.
180.215 Reporting and record retention requirements.
180.217 Requalification requirements for MEGCs.

             Subpart D_Qualification and Maintenance of IBCs

180.350 Applicability and definitions.
180.351 Qualification of IBCs.
180.352 Requirements for retest and inspection of IBCs.

         Subpart E_Qualification and Maintenance of Cargo Tanks

180.401 Applicability.
180.403 Definitions.
180.405 Qualification of cargo tanks.
180.407 Requirements for test and inspection of specification cargo 
          tanks.
180.409 Minimum qualifications for inspectors and testers.
180.411 Acceptable results of tests and inspections.
180.413 Repair, modification, stretching, rebarrelling, or mounting of 
          specification cargo tanks.
180.415 Test and inspection markings.
180.416 Discharge system inspection and maintenance program for cargo 
          tanks transporting liquefied compressed gases.
180.417 Reporting and record retention requirements.

          Subpart F_Qualification and Maintenance of Tank Cars

180.501 Applicability.
180.503 Definitions.
180.505 Quality assurance program.
180.507 Qualification of tank cars.
180.509 Requirements for inspection and test of specification tank cars.
180.511 Acceptable results of inspections and tests.
180.513 Repairs, alterations, conversions, and modifications.
180.515 Markings.
180.517 Reporting and record retention requirements.
180.519 Periodic retest and inspection of tank cars other than single-
          unit tank car tanks.

[[Page 327]]

        Subpart G_Qualification and Maintenance of Portable Tanks

180.601 Applicability.
180.603 Qualification of portable tanks.
180.605 Requirements for periodic testing, inspection, and repair of 
          portable tanks.

Appendix A to Part 180--Internal Self-closing Stop Valve Emergency 
          Closure Test for Liquefied Compressed Gases
Appendix B to Part 180--Acceptable Internal Self-closing Stop Valve 
          Leakage Tests for Cargo Tanks Transporting Liquefied 
          Compressed Gases
Appendix C to Part 180--Eddy Current Examination With Visual Inspection 
          for DOT 3AL Cylinders Manufactured of Aluminum Alloy 6351-T6
Appendix D to Part 180--Hazardous Materials Corrosive to Tanks or 
          Service Equipment

    Authority: 49 U.S.C. 5101-5128; 49 CFR 1.81 and 1.97.

    Source: Amdt. 180-2, 54 FR 25032, June 12, 1989, unless otherwise 
noted.



                            Subpart A_General



Sec.  180.1  Purpose and scope.

    This part prescribes requirements pertaining to the maintenance, 
reconditioning, repair, inspection and testing of packagings, and any 
other function having an effect on the continuing qualification and use 
of a packaging under the requirements of this subchapter.



Sec.  180.2  Applicability.

    (a) Any person who performs a function prescribed in this part shall 
perform that function in accordance with this part.
    (b) Any person who performs a function prescribed in this part is 
considered subject to the regulations of this subchapter when that 
person--
    (1) Makes any representation indicating compliance with one or more 
of the requirements of this part; or
    (2) Reintroduces into commerce a packaging that bears markings 
indicating compliance with this part.

[Amdt. 180-2, 54 FR 25032, June 12, 1989, as amended by Amdt. 180-2, 56 
FR 27877, June 17, 1991]



Sec.  180.3  General requirements.

    (a) No person may represent, mark, certify, sell, or offer a 
packaging or container as meeting the requirements of this part, or a 
special permit pertaining to this part issued under subchapter A of this 
chapter, whether or not the packaging or container is intended to be 
used for the transportation of a hazardous material, unless it is 
marked, maintained, reconditioned, repaired, or retested, as 
appropriate, in accordance with this part, an approval issued 
thereunder, or a special permit issued under subchapter A of this 
chapter.
    (b) The representations, markings, and certifications subject to the 
prohibitions of paragraph (a) of this section include:
    (1) Identifications that include the letters ``DOT'', ``MC'', 
``ICC'', or ``UN'';
    (2) Special permit, approval, and registration numbers that include 
the letters ``DOT'';
    (3) Test dates displayed in association with specification, 
registration, approval, or exemption markings indicating conformance to 
a test or retest requirement of this subchapter, an approval issued 
thereunder, or a special permit issued under subchapter A of this 
chapter;
    (4) Documents indicating conformance to the testing, inspection, 
maintenance or other continuing qualification requirements of this part; 
and
    (5) Sales literature, including advertising, indicating that the 
packaging or container represented therein conforms to requirements 
contained in subchapter A or C of this chapter.

[Amdt. 180-2, 54 FR 25032, June 12, 1989, as amended by Amdt. 180-3, 58 
FR 33306, June 16, 1993; 70 FR 73166, Dec. 9, 2005]

Subpart B [Reserved]



        Subpart C_Qualification, Maintenance and Use of Cylinders

    Source: 67 FR 51660, Aug. 8, 2002, unless otherwise noted.



Sec.  180.201  Applicability.

    This subpart prescribes requirements, in addition to those contained 
in parts 107, 171, 172, 173, and 178 of this

[[Page 328]]

chapter, for the continuing qualification, maintenance, or periodic 
requalification of DOT specification and exemption cylinders and UN 
pressure receptacles.

[71 FR 33894, June 12, 2006]



Sec.  180.203  Definitions.

    As used in this section, the word ``cylinder'' includes UN pressure 
receptacles. In addition to the definitions contained in Sec.  171.8 of 
this subchapter, the following definitions apply to this subpart:
    Commercially free of corrosive components means a hazardous material 
having a moisture content less than 55 ppm and free of components that 
will adversely react with the cylinder (e.g., chemical stress 
corrosion).
    Condemn means a determination that a cylinder is unserviceable for 
the continued transportation of hazardous materials in commerce and that 
the cylinder may not be restored by repair, rebuilding, requalification, 
or any other procedure.
    Filled or charged means an introduction or presence of a hazardous 
material in a cylinder.
    Mobile unit means a vehicle specifically authorized under a RIN to 
carry out requalification operations identified under the RIN within 
specified geographic areas away from the principle place of business. 
Mobile units must comply with the requirements outlined in the approval 
issuance letter from the Associate Administrator for Hazardous Materials 
Safety (see Sec.  107.805 of subchapter A of this chapter).
    Non-corrosive service means a hazardous material that, in the 
presence of moisture, is not corrosive to the materials of construction 
of a cylinder (including valve, pressure relief device, etc.).
    Over-heated means a condition in which the temperature of any 
portion of an aluminum cylinder has reached 176 [deg]C (350 [deg]F) or 
higher, or in which the temperature of any portion of a steel or nickel 
cylinder has reached 343 [deg]C (650 [deg]F) or higher.
    Over-pressurized means a condition in which the internal pressure 
applied to a cylinder has reached or exceeded the yield point of the 
cylinder.
    Permanent expansion means a permanent increase in a cylinder's 
volume after the test pressure is released.
    Proof pressure test means a liquid-based pressure test by interior 
pressurization without the determination of a cylinder's expansion.
    Rebuild means the replacement of a pressure part (e.g. a wall, head, 
or pressure fitting) by welding.
    Repair means a procedure for correction of a rejected cylinder that 
may involve welding.
    Requalification means the completion of a visual inspection and/or 
the test(s) required to be performed on a cylinder to determine its 
suitability for continued service.
    Requalification identification number or RIN means a code assigned 
by DOT to uniquely identify a cylinder requalification, repair, or 
rebuilding facility.

[67 FR 51660, Aug. 8, 2002, as amended at 71 FR 33894, June 12, 2006; 85 
FR 85432, Dec. 28, 2020]



Sec.  180.205  General requirements for requalification of specification 
cylinders.

    (a) General. Each cylinder used for the transportation of hazardous 
materials must be an authorized packaging. To qualify as an authorized 
packaging, each cylinder must conform to this subpart, the applicable 
requirements specified in part 173 of this subchapter, and the 
applicable requirements of subpart C of part 178 of this subchapter.
    (b) Persons performing requalification functions. No person may 
represent that a repair or requalification of a cylinder has been 
performed in accordance with the requirements in this subchapter unless 
that person holds a current approval issued under the procedural 
requirements prescribed in subpart I of part 107 of this chapter. No 
person may mark a cylinder with a RIN and a requalification date or 
otherwise represent that a DOT specification or special permit cylinder 
has been requalified unless all applicable requirements of this subpart 
have been met. A person who requalifies cylinders must maintain the 
records prescribed in Sec.  180.215 at each location at which it 
inspects, tests, or marks cylinders.
    (c) Periodic requalification of cylinders. Each cylinder bearing a 
DOT, CRC,

[[Page 329]]

BTC, or CTC specification marking must be requalified and marked as 
specified in the requalification table in Sec.  180.209(a) or 
requalified and marked by a facility registered by Transport Canada in 
accordance with the Transport Canada TDG Regulations (IBR, see Sec.  
171.7 of this subchapter). Each cylinder bearing both a TC specification 
marking and also marked with a corresponding DOT specification marking 
must be requalified and marked as specified in the requalification table 
in Sec.  180.209(a) or requalified and marked by a facility registered 
by Transport Canada in accordance with the Transport Canada TDG 
Regulations. Each cylinder bearing a DOT special permit (or exemption) 
number must be requalified and marked in conformance with this section 
and the terms of the applicable special permit (or exemption). Each 
cylinder bearing only a TC mark must be requalified and marked as 
specified in the Transport Canada TDG Regulations, except that 
registration with Transport Canada is not required and cylinders must be 
marked with the requalifier's DOT issued requalifier identification 
number. No cylinder may be filled with a hazardous material and offered 
for transportation in commerce unless that cylinder has been 
successfully requalified and marked in accordance with this subpart. A 
cylinder may be requalified at any time during or before the month and 
year that the requalification is due. However, a cylinder filled before 
the requalification becomes due may remain in service until it is 
emptied. A cylinder with a specified service life may not be refilled 
and offered for transportation after its authorized service life has 
expired.
    (1) Each cylinder that is requalified in accordance with the 
requirements specified in this section must be marked in accordance with 
Sec.  180.213 or the requirements of the Transport Canada TDG 
Regulations, or in the case of a TC cylinder requalified in the United 
States by a DOT RIN holder, in accordance with the requirements of the 
Transport Canada TDG Regulations except that registration with Transport 
Canada is not required and cylinders must be marked with the 
requalifiers DOT issued requalifier identification number.
    (2) Each cylinder that fails requalification must be:
    (i) Rejected and may be repaired or rebuilt in accordance with Sec.  
180.211 or Sec.  180.212, as appropriate; or
    (ii) Condemned in accordance with paragraph (i) of this section.
    (3) For DOT specification cylinders, the marked service pressure may 
be changed upon approval of the Associate Administrator and in 
accordance with written procedures specified in the approval.
    (4) For a specification 3, 3A, 3AA, 3AL, 3AX, 3AAX, 3B, 3BN, or 3T 
cylinder filled with gases in other than Division 2.2, from the first 
requalification due on or after December 31, 2003, the burst pressure of 
a CG-1, CG-4, or CG-5 pressure relief device must be at test pressure 
with a tolerance of plus zero to minus 10%. An additional 5% tolerance 
is allowed when a combined rupture disc is placed inside a holder. This 
requirement does not apply if a CG-2, CG-3 or CG-9 thermally activated 
relief device or a CG-7 reclosing pressure valve is used on the 
cylinder.
    (d) Conditions requiring test and inspection of cylinders. Without 
regard to any other periodic requalification requirements, a cylinder 
must be tested and inspected in accordance with this section prior to 
further use if--
    (1) The cylinder shows evidence of dents, corrosion, cracked or 
abraded areas, leakage, or any other condition that might render it 
unsafe for use in transportation;
    (2) The cylinder has been in an accident and has been damaged to an 
extent that may adversely affect its lading retention capability;
    (3) The cylinder shows evidence of or is known to have thermal 
damage, or have been over-heated;
    (4) Except in association with an authorized repair, evidence of 
removal of wall thickness via grinding, sanding or other means; or
    (5) The Associate Administrator determines that the cylinder may be 
in an unsafe condition.
    (e) Cylinders containing Class 8 (corrosive) liquids. A cylinder 
previously containing a Class 8 (corrosive) liquid may

[[Page 330]]

not be used to transport a Class 2 material in commerce unless the 
cylinder is--
    (1) Visually inspected, internally and externally, in accordance 
with paragraph (f) of this section and the inspection is recorded as 
prescribed in Sec.  180.215;
    (2) Requalified in accordance with this section, regardless of the 
date of the previous requalification;
    (3) Marked in accordance with Sec.  180.213; and
    (4) Decontaminated to remove all significant residue or impregnation 
of the Class 8 material.
    (f) Visual inspection. Except as otherwise provided in this subpart, 
each time a cylinder is pressure tested, it must be given an internal 
and external visual inspection.
    (1) The visual inspection must be performed in accordance with the 
following CGA Pamphlets: C-6 for steel and nickel cylinders (IBR, see 
Sec.  171.7 of this subchapter); C-6.1 for seamless aluminum cylinders 
(IBR, see Sec.  171.7 of this subchapter); C-6.2 for fiber reinforced 
composite special permit cylinders (IBR, see Sec.  171.7 of this 
subchapter); C-6.3 for low pressure aluminum cylinders (IBR, see Sec.  
171.7 of this subchapter); C-8 for DOT 3HT cylinders (IBR, see Sec.  
171.7 of this subchapter); and C-13 for DOT 8 series cylinders (IBR, see 
Sec.  171.7 of this subchapter).
    (2) For each cylinder with a coating or attachments that would 
inhibit inspection of the cylinder, the coating or attachments must be 
removed before performing the visual inspection.
    (3) Each cylinder subject to visual inspection must be approved, 
rejected, or condemned according to the criteria in the applicable CGA 
pamphlet.
    (4) In addition to other requirements prescribed in this paragraph 
(f), each specification cylinder manufactured of aluminum alloy 6351-T6 
and used in self-contained underwater breathing apparatus (SCUBA), self-
contained breathing apparatus (SCBA), or oxygen service must be 
inspected for sustained load cracking in accordance with Appendix C of 
this part at the first scheduled 5-year requalification period after 
January 1, 2007, and every five years thereafter.
    (5) Except in association with an authorized repair, removal of wall 
thickness via grinding, sanding or other means is not permitted. Removal 
of paint or loose material to prepare the cylinder for inspection is 
permitted (e.g., shot blasting).
    (6) Chasing of cylinder threads to clean them is permitted, but 
removal of metal must not occur. Re-tapping of cylinder threads is not 
permitted, except by the original manufacturer, as provided in Sec.  
180.212.
    (g) Pressure test. (1) Unless otherwise provided, each cylinder 
required to be retested under this subpart must be retested by means 
suitable for measuring the expansion of the cylinder under pressure. 
Testing must be performed in accordance with CGA C-1 (except for 
paragraph 5.3.2.2, if the required accuracy of the pressure indicating 
device can be demonstrated by other recognized means such as calibration 
certificates) (IBR, see Sec.  171.7 of this subchapter).
    (2) The pressure indicating device and expansion indicating device 
must meet the resolution requirements of CGA C-1. Midpoint visual 
interpolation is allowed.
    (3) Each day before retesting, the retester shall confirm, by using 
a calibrated cylinder or other method authorized in writing by the 
Associate Administrator, that:
    (i) The pressure-indicating device, as part of the retest apparatus, 
is accurate within 1.0% of the prescribed test 
pressure of any cylinder tested that day. The pressure indicating 
device, itself, must be certified as having an accuracy of 0.5%, or better, of its full range, and must permit 
readings of pressure from 90%-110% of the minimum prescribed test 
pressure of the cylinder to be tested. The accuracy of the pressure 
indicating device within the test system can be demonstrated at any 
point within 500 psig of the actual test pressure for test pressures at 
or above 3000 psig, or 10% of the actual test pressure for test 
pressures below 3000 psig.
    (ii) The expansion-indicating device, as part of the retest 
apparatus, meets the accuracy requirements of CGA C-1.

[[Page 331]]

    (4) Test equipment must be verified each day before retesting as 
required in CGA C-1.
    (i) The retester must demonstrate calibration in conformance with 
this paragraph (g) to an authorized inspector on any day that it retests 
cylinders.
    (ii) A retester must maintain calibrated cylinder certificates in 
conformance with Sec.  180.215(b)(4).
    (5) A system check may be performed at or below 90% of test pressure 
prior to the retest. In the case of a malfunction of the test equipment 
or operator error, the test may be repeated in accordance with CGA C-1, 
section 5.7.1. This paragraph (g) does not authorize retest of a 
cylinder otherwise required to be condemned under paragraph (i) of this 
section.
    (h) Cylinder rejection. A cylinder must be rejected when, after a 
visual inspection, it meets a condition for rejection under the visual 
inspection requirements of paragraph (f) of this section.
    (1) Except as provided in paragraphs (h)(3) and (h)(4) of this 
section, a cylinder that is rejected may not be marked as meeting the 
requirements of this section.
    (2) The requalifier must notify the cylinder owner, in writing, that 
the cylinder has been rejected.
    (3) Unless the cylinder is repaired or rebuilt in conformance with 
requirements in Sec.  180.211, it may not be filled with a hazardous 
material and offered for transportation where use of a specification 
packaging is required.
    (4) A rejected cylinder with a service pressure of less than 900 
psig may be requalified and marked if the cylinder is repaired or 
rebuilt and subsequently inspected and tested in conformance with--
    (i) The visual inspection requirements of paragraph (f) of this 
section;
    (ii) Part 178 of this subchapter and this part;
    (iii) Any special permit covering the manufacture, requalification, 
and/or use of that cylinder; and
    (iv) Any approval required under Sec.  180.211.
    (i) Cylinder condemnation. (1) A cylinder must be condemned when--
    (i) The cylinder meets a condition for condemnation under the visual 
inspection requirements of paragraph (f) of this section.
    (ii) The cylinder leaks through its wall.
    (iii) Evidence of cracking exists to the extent that the cylinder is 
likely to be weakened appreciably.
    (iv) For a DOT specification cylinder, other than a DOT 4E aluminum 
cylinder or a special permit cylinder, permanent expansion exceeds 10 
percent of total expansion.
    (v) For a DOT 3HT cylinder--
    (A) The pressure test yields an elastic expansion exceeding the 
marked rejection elastic expansion (REE) value.
    (B) The cylinder shows evidence of denting or bulging.
    (C) The cylinder bears a manufacture or an original test date older 
than twenty-four years or after 4380 pressurizations, whichever occurs 
first. If a cylinder is refilled, on average, more than once every other 
day, an accurate record of the number of rechargings must be maintained 
by the cylinder owner or the owner's agent.
    (vi) For a DOT 4E aluminum cylinder, permanent expansion exceeds 12 
percent of total expansion.
    (vii) For a DOT special permit cylinder, permanent expansion exceeds 
the limit in the applicable special permit, or the cylinder meets 
another criterion for condemnation in the applicable special permit.
    (viii) For an aluminum or an aluminum-lined composite special permit 
cylinder, the cylinder is known to have been or shows evidence of having 
been overheated. Arc burns must be considered evidence of overheating.
    (ix) The cylinder is known to have been or shows evidence of having 
been over-pressurized.
    (x) For a cylinder with a specified service life, its authorized 
service life has expired.
    (xi) The cylinder has been stamped on the sidewall, except as 
provided in part 178 of this subchapter.
    (2) When a cylinder must be condemned, the requalifier must--
    (i) Communicate condemnation of the cylinder as follows:
    (A) Stamp a series of Xs over the DOT-specification number and the

[[Page 332]]

marked pressure or stamp ``CONDEMNED'' on the shoulder, top head, or 
neck using a steel stamp;
    (B) For composite cylinders, securely affix to the cylinder a label 
with the word ``CONDEMNED'' overcoated with epoxy near, but not 
obscuring, the original cylinder manufacturer's label; or
    (C) As an alternative to the stamping or labeling as described in 
this paragraph (i)(2), at the direction of the owner, the requalifier 
may render the cylinder incapable of holding pressure; and
    (ii) Notify the cylinder owner, in writing, that the cylinder is 
condemned and may not be filled with hazardous material and offered for 
transportation in commerce where use of a specification packaging is 
required.
    (3) No person may remove, obliterate, or alter the required 
condemnation communication of paragraph (i)(2) of this section.
    (j) Training materials. Training materials may be used for training 
persons who requalify cylinders using the volumetric expansion test 
method.

[67 FR 51660, Aug. 8, 2002, as amended at 68 FR 24662, May 8, 2003; 68 
FR 75764, Dec. 31, 2003; 70 FR 34077, June 13, 2005; 70 FR 73166, Dec. 
9, 2005; 71 FR 51128, Aug. 29, 2006; 73 FR 4720, Jan. 28, 2008; 75 FR 
53597, Sept. 1, 2010; 82 FR 15896, Mar. 30, 2017; 85 FR 85433, Dec. 28, 
2020]



Sec.  180.207  Requirements for requalification of UN pressure receptacles.

    (a) General. (1) Each UN pressure receptacle used for the 
transportation of hazardous materials must conform to the requirements 
prescribed in paragraphs (a), (b) and (d) in Sec.  180.205.
    (2) No pressure receptacle due for requalification may be filled 
with a hazardous material and offered for transportation in commerce 
unless that pressure receptacle has been successfully requalified and 
marked in accordance with this subpart or requalified and marked by a 
facility registered by Transport Canada in accordance with the Transport 
Canada TDG Regulations (IBR, see Sec.  171.7 of this subchapter). A 
pressure receptacle may be requalified at any time during or before the 
month and year that the requalification is due. However, a pressure 
receptacle filled before the requalification becomes due may remain in 
service until it is emptied. In accordance with the Transport Canada TDG 
Regulations a CAN marked UN cylinder may be requalified in the United 
States by a domestic requalifier, provided the requirements in 
Sec. Sec.  178.69, 178.70, and 178.71, as applicable, are met.
    (3) A pressure receptacle with a specified service life may not be 
requalified after its authorized service life has expired. A pressure 
receptacle with a specified service life may not be refilled and offered 
for transportation after its authorized service life has expired unless 
approval has been obtained in writing from the Associate Administrator.
    (b) Periodic requalification of UN pressure receptacles. (1) Each 
pressure receptacle that is successfully requalified in accordance with 
the requirements specified in this section must be marked in accordance 
with Sec.  180.213. The requalification results must be recorded in 
accordance Sec.  180.215.
    (2) Each pressure receptacle that fails requalification must be 
rejected or condemned in accordance with the applicable ISO 
requalification standard.
    (c) Requalification interval. Each UN pressure receptacle that 
becomes due for periodic requalification must be requalified at the 
interval specified in the following table before it is filled:

      Table 1--Requalification Intervals of UN Pressure Receptacles
------------------------------------------------------------------------
      Interval (years)       UN pressure receptacles/hazardous materials
------------------------------------------------------------------------
10.........................  Pressure receptacles for all hazardous
                              materials except as noted below (also for
                              dissolved acetylene, see paragraph (d)(3)
                              of this section):
5..........................  Composite pressure receptacles.
5..........................  Metal hydride storage systems
5..........................  Pressure receptacles used for:
                             All Division 2.3 materials.
                             UN1013, Carbon dioxide.

[[Page 333]]

 
                                UN1043, Fertilizer ammoniating solution
                                 with free ammonia.
                             UN1051, Hydrogen cyanide, stabilized
                              containing less than 3% water.
                             UN1052, Hydrogen fluoride, anhydrous.
                             UN1745, Bromine pentafluoride.
                                UN1746, Bromine trifluoride.
                             UN2073, Ammonia solution.
                             UN2495, Iodine pentafluoride.
                             UN2983, Ethylene Oxide and Propylene oxide
                              mixture, not more than 30% ethylene oxide.
5..........................  Pressure receptacles used for adsorbed
                              gases.
------------------------------------------------------------------------

    (d) Requalification procedures. Each UN pressure receptacle must be 
requalified in conformance with the procedures contained in the 
following standards, as applicable. Furthermore, when a pressure test is 
performed on a UN pressure receptacle, the test must be a water jacket 
volumetric expansion test suitable for the determination of the cylinder 
expansion or a hydraulic proof pressure test. The test equipment must 
conform to the accuracy requirements in Sec.  180.205(g). Alternative 
methods (e.g., acoustic emission) or requalification procedures may be 
performed if prior approval has been obtained in writing from the 
Associate Administrator.
    (1) Seamless steel: Each seamless steel UN pressure receptacle, 
including pressure receptacles exceeding 150 L capacity installed in 
MEGCs or in other service, must be requalified in accordance with ISO 
6406:2005(E) (IBR, see Sec.  171.7 of this subchapter). However, UN 
cylinders with a tensile strength greater than or equal to 950 MPa must 
be requalified by ultrasonic examination in accordance with ISO 
6406:2005(E). For seamless steel cylinders and tubes, the internal 
inspection and hydraulic pressure test may be replaced by a procedure 
conforming to ISO 16148:2016(E) (IBR, see Sec.  171.1).
    (2) Seamless UN aluminum: Each seamless aluminum UN pressure 
receptacle must be requalified in accordance with ISO 10461 (IBR, see 
Sec.  171.7 of this subchapter).
    (3) Dissolved acetylene UN cylinders: Each dissolved acetylene 
cylinder must be requalified in accordance with ISO 10462:2013(E) (IBR, 
see Sec.  171.7 of this subchapter). A cylinder previously requalified 
in accordance with the second edition of ISO 10462(E) up until December 
31, 2018, may continue to be used until the next required 
requalification. The porous mass and the shell must be requalified no 
sooner than 3 years, 6 months, from the date of manufacture. Thereafter, 
subsequent requalifications of the porous mass and shell must be 
performed at least once every ten years.
    (4) Composite UN cylinders: Each composite cylinder must be 
inspected and tested in accordance with ISO 11623:2015(E) (IBR, see 
Sec.  171.7 of this subchapter). Until December 31, 2020, ISO 
11623:2002(E) (IBR, see Sec.  171.7 of this subchapter) may be used.
    (5) UN cylinders for adsorbed gases: Each UN cylinder for adsorbed 
gases must be inspected and tested in accordance with Sec.  173.302c and 
ISO 11513:2011 (IBR, see Sec.  171.7 of this subchapter).
    (6) Valves: Inspection and maintenance of cylinder valves must be 
carried out in accordance with ISO 22434:2006 Transportable gas 
cylinders--Inspection and maintenance of cylinder valves (IBR, see Sec.  
171.7 of this subchapter).
    (7) UN cylinder bundles: UN cylinder bundles containing compressed, 
liquefied, and dissolved gas must be inspected and tested in accordance 
with ISO 20475:2018(E) (IBR, see Sec.  171.7 of this subchapter).

[71 FR 33894, June 12, 2006, as amended at 71 FR 54397, Sept. 14, 2006; 
76 FR 3389, Jan. 19, 2011; 80 FR 1168, Jan. 8, 2015; 82 FR 15897, Mar. 
30, 2017; 85 FR 27901, May 11, 2020; 85 FR 85434, Dec. 28, 2020; 86 FR 
45000, July 26, 2022]



Sec.  180.209  Requirements for requalification of specification cylinders.

    (a) Periodic qualification of cylinders. Each specification cylinder 
that becomes due for periodic requalification, as specified in the 
following table,

[[Page 334]]

must be requalified and marked in conformance with the requirements of 
this subpart. Requalification records must be maintained in accordance 
with Sec.  180.215. Table 1 follows:

       Table 1 to Paragraph (a) --Requalification of Cylinders \1\
------------------------------------------------------------------------
                                     Minimum test
    Specification under which       pressure (psig)     Requalification
        cylinder was made                 \2\           period (years)
------------------------------------------------------------------------
3...............................  3000 psig.........  5.
3A, 3AA.........................  5/3 times service   5, 10, or 12 (see
                                   pressure, except    Sec.
                                   non-corrosive       180.209(b), (f),
                                   service (see Sec.   (h), and (j)).
                                     180.209(g)).
3AL.............................  5/3 times service   5 or 12 (see Sec.
                                   pressure.            180.209(j)
                                                       and(m) \3\).
3AX, 3AAX.......................  5/3 times service   5.
                                   pressure.
3B, 3BN.........................  2 times service     5 or 10 (see Sec.
                                   pressure (see        180.209(f)).
                                   Sec.
                                   180.209(g)).
3E..............................  Test not required.
3HT.............................  5/3 times service   3 (see Sec.  Sec.
                                   pressure.            180.209(k) and
                                                       180.213(c)).
3T..............................  5/3 times service   5.
                                   pressure.
4AA480..........................  2 times service     5 or 10 (see Sec.
                                   pressure (see        180.209(h)).
                                   Sec.
                                   180.209(g)).
4B, 4BA, 4BW, 4B-240ET..........  2 times service     5, 7, 10, or 12
                                   pressure, except    (see Sec.
                                   non-corrosive       180.209(e), (f),
                                   service (see Sec.   and (j)).
                                     180.209(g)).
4D, 4DA, 4DS....................  2 times service     5.
                                   pressure.
4E..............................  2 times service     5, 10, or 12 (see
                                   pressure, except    Sec.
                                   non-corrosive       180.209(e)).
                                   service (see Sec.
                                     180.209(g)).
4L..............................  Test not required.
8, 8AL..........................  ..................  10 or 20 (see Sec.
                                                         180.209(i)).
Exemption or special permit       See current         See current
 cylinder.                         exemption or        exemption or
                                   special permit.     special permit.
Foreign cylinder (see Sec.        As marked on        5 (see Sec.  Sec.
 173.301(j) of this subchapter     cylinder, but not    180.209(l) and
 for restrictions on use).         less than \5/3\     180.213(d)(2)).
                                   of any service or
                                   working pressure
                                   marking.
------------------------------------------------------------------------
\1\ Any cylinder not exceeding 2 inches outside diameter and less than 2
  feet in length is excepted from volumetric expansion test.
\2\ For cylinders not marked with a service pressure, see Sec.
  173.301a(b) of this subchapter.
\3\ This provision does not apply to cylinders used for carbon dioxide,
  fire extinguisher, or other industrial gas service.

    (b) DOT 3A or 3AA cylinders. (1) A cylinder conforming to 
specification DOT 3A or 3AA with a water capacity of 56.7 kg (125 lb) or 
less that is removed from any cluster, bank, group, rack, or vehicle 
each time it is filled, may be requalified every ten years instead of 
every five years, provided the cylinder conforms to all of the following 
conditions:
    (i) The cylinder was manufactured after December 31, 1945.
    (ii) The cylinder is used exclusively for air; argon; cyclopropane; 
ethylene; helium; hydrogen; krypton; neon; nitrogen; nitrous oxide; 
oxygen; sulfur hexafluoride; xenon; chlorinated hydrocarbons, 
fluorinated hydrocarbons, liquefied hydrocarbons, and mixtures thereof 
that are commercially free from corroding components; permitted mixtures 
of these gases (see Sec.  173.301(d) of this subchapter); and permitted 
mixtures of these gases with up to 30 percent by volume of carbon 
dioxide, provided the gas has a dew point at or below minus (52 [deg]F) 
at 1 atmosphere.
    (iii) [Reserved]
    (iv) The cylinder is dried immediately after hydrostatic testing to 
remove all traces of water.
    (v) The cylinder is not used for underwater breathing.
    (vi) Each cylinder is stamped with a five-pointed star at least one-
fourth of an inch high immediately following the test date.
    (2) If, since the last required requalification, a cylinder has not 
been used exclusively for the gases specifically identified in paragraph 
(b)(1)(ii) of this section, but currently conforms with all other 
provisions of paragraph (b)(1) of this section, it may be requalified 
every 10 years instead of every five years, provided it is first 
requalified and examined as prescribed by Sec.  173.302a(b) (2), (3) and 
(4) of this subchapter.
    (3) Except as specified in paragraph (b)(2) of this section, if a 
cylinder, marked with a star, is filled with a compressed gas other than 
as specified in paragraph (b)(1)(ii) of this section, the star following 
the most recent test date must be obliterated. The cylinder

[[Page 335]]

must be requalified five years from the marked test date, or prior to 
the first filling with a compressed gas, if the required five-year 
requalification period has passed.
    (c) DOT 4-series cylinders. A DOT 4-series cylinder, except a 4L 
cylinder, that at any time shows evidence of a leak, internal or 
external corrosion, denting, bulging or rough usage to the extent that 
it is likely to be weakened appreciably, or that has lost 5 percent or 
more of its official tare weight must be requalified before being 
refilled and offered for transportation. (Refer to CGA C-6 or C-6.3 
(IBR, see Sec.  171.7 of this subchapter), as applicable, regarding 
cylinder weakening.) After testing, the actual tare weight must be 
recorded as the new tare weight on the test report and marked on the 
cylinder. The previous tare weight must be strike-lined through, but not 
obliterated.
    (d) Cylinders 5.44 kg (12 lb) or less with service pressures of 300 
psig or less. A cylinder of 5.44 (12 lb) or less water capacity 
authorized for service pressure of 300 psig or less must be given a 
complete external visual inspection at the time periodic requalification 
becomes due. External visual inspection must be in accordance with CGA 
Pamphlet C-6 or C-6.1 (IBR, see Sec.  171.7 of this subchapter). The 
cylinder may be proof pressure tested. The test is successful if the 
cylinder, when examined under test pressure, does not display a defect 
described in Sec.  180.205(i)(1) (ii) or (iii). Upon successful 
completion of the test and inspection, the cylinder must be marked in 
accordance with Sec.  180.213.
    (e) Cylinders in non-corrosive gas service. A cylinder made in 
conformance with DOT Specifications 4B, 4BA, 4BW, or 4E protected 
externally by a suitable corrosion-resistant coating and used 
exclusively for non-corrosive gas that is commercially free from 
corroding components may be requalified by volumetric expansion testing 
every 12 years instead of every 5 years. As an alternative, the cylinder 
may be subjected to a proof pressure test at least two times the marked 
service pressure, but this latter type of test must be repeated every 10 
years after expiration of the initial 12-year period. When subjected to 
a proof pressure test, as prescribed in CGA C-1 (IBR, see Sec.  171.7 of 
this subchapter), the cylinder must be carefully examined under test 
pressure and removed from service if a leak or defect is found.
    (f) Poisonous materials. A cylinder conforming to specification DOT 
3A, 3AA, 3B, 4BA, or 4BW having a service pressure of 300 psig or less 
and used exclusively for methyl bromide, liquid; mixtures of methyl 
bromide and ethylene dibromide, liquid; mixtures of methyl bromide and 
chlorpicrin, liquid; mixtures of methyl bromide and petroleum solvents, 
liquid; or methyl bromide and nonflammable, nonliquefied compressed gas 
mixtures, liquid; commercially free of corroding components, and 
protected externally by a suitable corrosion resistant coating (such as 
galvanizing or painting) and internally by a suitable corrosion 
resistant lining (such as galvanizing) may be tested every 10 years 
instead of every five years, provided a visual internal and external 
examination of the cylinder is conducted every five years in accordance 
with CGA Pamphlet C-6. The cylinder must be examined at each filling, 
and rejected if a dent, corroded area, leak or other condition indicates 
possible weakness.
    (g) Visual inspections. A cylinder conforming to a specification 
listed in the table in this paragraph (g) and used exclusively in the 
service indicated may, instead of a periodic hydrostatic test, be given 
a complete external visual inspection at the time periodic 
requalification becomes due. External visual inspection must be in 
conformance with CGA C-6 or C-6.3, as applicable. When this inspection 
is used instead of hydrostatic testing, subsequent inspections are 
required at five-year intervals after the first inspection. Inspections 
must be made only by persons holding a current RIN and the results 
recorded and maintained in conformance with Sec.  180.215. Records must 
include: Date of inspection (month and year); DOT-specification number; 
cylinder identification (registered symbol and serial number, date of 
manufacture, and owner); type of cylinder protective coating (including 
statement as to need of refinishing or recoating); conditions checked 
(e.g., leakage, corrosion, gouges, dents or digs in shell or heads,

[[Page 336]]

broken or damaged footring or protective ring or fire damage); and 
disposition of cylinder (returned to service, returned to cylinder 
manufacturer for repairs or condemned). A cylinder passing 
requalification by the external visual inspection must be marked in 
conformance with Sec.  180.213. Specification cylinders must be in 
exclusive service as shown in table 2 to this paragraph (g):

[[Page 337]]



                                            Table 2 to Paragraph (g)
----------------------------------------------------------------------------------------------------------------
               Cylinders conforming to--                                  Used exclusively for--
----------------------------------------------------------------------------------------------------------------
DOT 3A, DOT 3AA, DOT 3A480X, DOT 4AA480................  Anhydrous ammonia of at least 99.95% purity.
DOT 3A, DOT 3AA, DOT 3A480X, DOT 3B, DOT 4B, DOT 4BA,    Butadiene, inhibited, that is commercially free from
 DOT 4BW.                                                 corroding components.
DOT 3A, DOT 3AA, DOT 3A480X, DOT 3B. DOT 4AA480, DOT     Cyclopropane that is commercially free from corroding
 4B, DOT 4BA, DOT 4BW.                                    components.
DOT 3A, DOT 3AA, DOT 3A480X, DOT 4B, DOT 4BA, DOT 4BW,   Chlorinated hydrocarbons and mixtures thereof that are
 DOT 4E.                                                  commercially free from corroding components.
DOT 3A, DOT 3AA, DOT 3A480X, DOT 4B, DOT 4BA, DOT 4BW,   Fluorinated hydrocarbons and mixtures thereof that are
 DOT 4E.                                                  commercially free from corroding components.
DOT 3A, DOT 3AA, DOT 3A480X, DOT 3B, DOT 4B, DOT 4BA,    Liquefied hydrocarbon gas that is commercially free of
 DOT 4BW, DOT 4E.                                         corroding components.
DOT 3A, DOT 3AA, DOT 3A480X, DOT 3B, DOT 4B, DOT 4BA,    Liquefied petroleum gas that meets the detail
 DOT 4BW, DOT 4E.                                         requirements limits in Table 1 of ASTM 1835, Standard
                                                          Specification for Liquefied Petroleum (LP) Gases
                                                          (incorporated by reference; see Sec.   171.7 of this
                                                          subchapter) or an equivalent standard containing the
                                                          same limits.
DOT 3A, DOT 3AA, DOT 3B, DOT 4B, DOT 4BA, DOT 4BW, DOT   Methylacetylene-propadiene, stabilized, that is
 4E.                                                      commercially free from corroding components.
DOT 3A, DOT 3AA, DOT 3B, DOT 4B, DOT 4BA, DOT 4BW, DOT   Propylene that is commercially free from corroding
 4E.                                                      components.
DOT 3A, DOT 3AA, DOT 3B, DOT 4B, DOT 4BA, DOT 4BW......  Anhydrous mono, di, trimethylamines that are
                                                          commercially free from corroding components.
DOT 4B240, DOT 4BW240..................................  Ethyleneimine, stabilized.
DOT 4BW................................................  Alkali metal alloys, liquid, n.o.s., Alkali metal
                                                          dispersions or Alkaline earth metal dispersions,
                                                          Potassium, Potassium Sodium alloys and Sodium that are
                                                          commercially free of corroding components.
----------------------------------------------------------------------------------------------------------------


[[Page 338]]

    (h) Cylinders containing anhydrous ammonia. A cylinder conforming to 
specification DOT 3A, 3A480X, or 4AA480 used exclusively for anhydrous 
ammonia, commercially free from corroding components, and protected 
externally by a suitable corrosion-resistant coating (such as paint) may 
be requalified every 10 years instead of every five years.
    (i) Requalification of DOT-8 series cylinders. (1) Each owner of a 
DOT-8 series cylinder used to transport acetylene must have the cylinder 
shell and the porous filler requalified in accordance with CGA Pamphlet 
C-13 (IBR, see Sec.  171.7 of this subchapter). Requalification must be 
performed in accordance with the following schedule:

----------------------------------------------------------------------------------------------------------------
                                         Shell (visual inspection)             Porous filler requalification
                                              requalification            ---------------------------------------
  Date of cylinder manufacture   ----------------------------------------
                                        Initial           Subsequent            Intial            Subsequent
----------------------------------------------------------------------------------------------------------------
Before January 1, 1991..........  Before January 1,   10 years..........  Before January 1,   Not required.
                                   2001.                                   2011.
On or after January 1, 1991.....  10 years \1\......  10 years..........  5 to 20 years \2\.  Not required.
----------------------------------------------------------------------------------------------------------------
\1\ Years from the date of cylinder manufacture.
\2\ No sooner than 5 years, and no later than 20 years from the date of manufacture.

    (2) Unless requalified and marked in accordance with CGA Pamphlet C-
13 before October 1, 1994, an acetylene cylinder must be requalified by 
a person who holds a current RIN.
    (3) If a cylinder valve is replaced, a cylinder valve of the same 
weight must be used or the tare weight of the cylinder must be adjusted 
to compensate for valve weight differential.
    (4) The person performing a visual inspection or requalification 
must record the results as specified in Sec.  180.215.
    (5) The person performing a visual inspection or requalification 
must mark the cylinder as specified in Sec.  180.213.
    (j) Cylinder used as a fire extinguisher. Only a DOT-specification 
cylinder used as a fire extinguisher in conformance with Sec.  
173.309(a) of this subchapter may be requalified in conformance with 
this paragraph (j). The testing procedures, calibration of the testing 
equipment, accuracy of the pressure indicating device, accuracy of the 
testing equipment must be as prescribed in CGA C-1.
    (1) A DOT 4B, 4BA, 4B240ET or 4BW cylinder used as a fire 
extinguisher may be tested as follows:
    (i) For a cylinder with a water capacity of 5.44 kg (12 pounds) or 
less, by the water-jacket, direct expansion or proof pressure test 
methods as prescribed in CGA C-1. A requalification must be performed by 
the end of 12 years after the original test date and at 12-year 
intervals thereafter.
    (A) Each cylinder must be tested to a minimum of two (2) times 
service pressure.
    (B) When testing using the water-jacket or direct expansion test 
method, the permanent volumetric expansion may not exceed 10 percent of 
total volumetric expansion at test pressure.
    (C) When testing using the proof pressure test method, the cylinder 
must be carefully examined under test pressure and removed from service 
if a leak or defect is found.
    (ii) For a cylinder having a water capacity over 5.44 kg (12 
pounds), by the water-jacket, direct expansion or proof pressure test 
methods as prescribed in CGA C-1. For the water-jacket or direct 
expansion test, the requalification must be performed by the end of 12 
years after the original test date and at 12-year intervals theafter. 
For the proof-pressure test, a requalification must be performed by the 
end of 12 years after the original test date and at seven (7) year 
intervals.
    (A) Each cylinder must be tested to a minimum of two (2) times 
service pressure.
    (B) When testing using the water-jacket or direct expansion test 
method, the permanent volumetric expansion may not exceed 10 percent of 
total volumetric expansion at test pressure.
    (C) When testing using the proof pressure test method, the cylinder 
must be carefully examined under test pressure and removed from service 
if a leak or defect is found.

[[Page 339]]

    (2) A DOT 3A, 3AA, or 3AL cylinder must be requalified by:
    (i) The water-jacket or direct expansion method. A requalification 
must be performed 12 years after the original test date and at 12-year 
intervals thereafter.
    (ii) Each cylinder must be tested to a minimum of \5/3\ times 
service pressure.
    (iii) When testing using the water-jacket or direct expansion test 
method, the permanent volumetric expansion may not exceed 10 percent of 
total volumetric expansion at test pressure.
    (k) 3HT cylinders. In addition to the other requirements of this 
section, a cylinder marked DOT-3HT must be requalified in accordance 
with CGA C-8 (IBR, see Sec.  171.7 of this subchapter).
    (l) Requalification of foreign cylinders filled for export. A 
cylinder manufactured outside the United States, other than as provided 
in Sec. Sec.  171.12(a) and 171.23(a) of this subchapter, that has not 
been manufactured, inspected, tested and marked in accordance with part 
178 of this subchapter may be filled with compressed gas in the United 
States, and shipped solely for export if it meets the following 
requirements, in addition to other requirements of this subchapter:
    (1) It has been inspected, tested and marked in conformance with the 
procedures and requirements of this subpart or the Associate 
Administrator has authorized the filling company to fill foreign 
cylinders under an alternative method of qualification; and
    (2) It is offered for transportation in conformance with the 
requirements of Sec. Sec.  171.12(a)(4) or 171.23(a)(5) of this 
subchapter.
    (m) DOT-3AL cylinders manufactured of 6351-T6 aluminum alloy. In 
addition to the periodic requalification and marking described in Sec.  
180.205, each cylinder manufactured of aluminum alloy 6351-T6 used in 
self-contained underwater breathing apparatus (SCUBA), self-contained 
breathing apparatus (SCBA), or oxygen service must be requalified and 
inspected for sustained load cracking in accordance with the non-
destructive examination method described in the following table. Each 
cylinder with sustained load cracking that has expanded into the neck 
threads must be condemned in accordance with Sec.  180.205(i). This 
provision does not apply to cylinders used for carbon dioxide, fire 
extinguisher or other industrial gas service.

               Requalification and Inspection of DOT-3AL Cylinders Made of Aluminum Alloy 6351-T6
----------------------------------------------------------------------------------------------------------------
                                                                       Sustained Load Cracking   Requalification
      Requalification requirement         Examination procedure \1\   Condemnation Criteria \2\   period (years)
----------------------------------------------------------------------------------------------------------------
Eddy current examination combined with   Eddy current--In            Any crack in the neck or                5
 visual inspection.                       accordance with Appendix    shoulder of 2 thread
                                          C of this part.             lengths or more.
                                         Visual inspection--In
                                          accordance with CGA
                                          Pamphlet C-6.1 (IBR; see
                                          Sec.   171.7 of this
                                          subchapter).
----------------------------------------------------------------------------------------------------------------
\1\ The requalifier performing eddy current must be familiar with the eddy current equipment and must
  standardize (calibrate) the system in accordance with the requirements provided in Appendix C to this part.
\2\ The eddy current must be applied from the inside of the cylinder's neck to detect any sustained load
  cracking that has expanded into the neck threads.


[67 FR 51660, Aug. 8, 2002, as amended at 68 FR 24662, May 8, 2003; 68 
FR 55544, Sept. 26, 2003; 68 FR 48572, Aug. 14, 2003; 68 FR 75764, Dec. 
31, 2003; 70 FR 73166, Dec. 9, 2005; 71 FR 51128, Aug. 29, 2005; 72 FR 
55696, Oct. 1, 2007; 74 FR 53189, Oct. 16, 2009; 81 FR 3685, Jan. 21, 
2016; 81 FR 35545, June 2, 2016; 85 FR 68797, Oct. 30, 2020; 85 FR 
75716, Nov. 25, 2020; 85 FR 85434, Dec. 28, 2020]

    Editorial Note: At 71 FR 54397, Sept. 14, 2006, Sec.  180.209 was 
amended in (a)(1) table 1; however, because of the inaccurate amendatory 
language, the amendment could not be incorporated.



Sec.  180.211  Repair, rebuilding and reheat treatment of DOT-4 series 
specification cylinders.

    (a) General requirements for repair and rebuilding. Any repair or 
rebuilding of a DOT-4 series cylinder must be performed by a person 
holding an approval as specified in Sec.  107.805 of this chapter or by 
a registered facility in Canada in accordance with the Transport Canada 
TDG Regulations (IBR, see Sec.  171.7 of this subchapter). A person 
performing

[[Page 340]]

a rebuild function is considered a manufacturer subject to the 
requirements of Sec.  178.2(a)(2) and subpart C of part 178 of this 
subchapter. The person performing a repair, rebuild, or reheat treatment 
must record the test results as specified in Sec.  180.215. Each 
cylinder that is successfully repaired or rebuilt must be marked in 
accordance with Sec.  180.213.
    (b) General repair requirements. Each repair of a DOT 4-series 
cylinder must be made in accordance with the following conditions:
    (1) The repair and the inspection of the work performed must be made 
in accordance with the requirements of the cylinder specification.
    (2) The person performing the repair must use the procedure, 
equipment, and filler metal or brazing material as authorized by the 
approval issued under Sec.  107.805 of this chapter.
    (3) Welding and brazing must be performed on an area free from 
contaminants.
    (4) A weld defect, such as porosity in a pressure retaining seam, 
must be completely removed before re-welding. Puddling may be used to 
remove a weld defect only by the tungsten inert gas shielded arc 
process.
    (5) After removal of a non-pressure attachment and before its 
replacement, the cylinder must be given a visual inspection in 
accordance with Sec.  180.205(f).
    (6) Reheat treatment of DOT 4B, 4BA or 4BW specification cylinders 
after replacement of non-pressure attachments is not required when the 
total weld material does not exceed 20.3 cm (8 inches). Individual welds 
must be at least 7.6 cm (3 inches) apart.
    (7) After repair of a DOT 4B, 4BA or 4BW cylinder, the weld area 
must be leak tested at the service pressure of the cylinder.
    (8) Repair of weld defects must be free of cracks.
    (9) When a non-pressure attachment with the original cylinder 
specification markings is replaced, all markings must be transferred to 
the attachment on the repaired cylinder.
    (10) Walls, heads or bottoms of cylinders with defects or leaks in 
base metal may not be repaired, but may be replaced as provided for in 
paragraph (d) of this section.
    (c) Additional repair requirements for 4L cylinders. (1) Repairs to 
a DOT 4L cylinder must be performed in accordance with paragraphs (a) 
and (b) of this section and are limited to the following:
    (i) The removal of either end of the insulation jacket to permit 
access to the cylinder, piping system, or neck tube.
    (ii) The replacement of the neck tube. At least a 13 mm (0.51 inch) 
piece of the original neck tube must be protruding above the cylinder's 
top end. The original weld attaching the neck tube to the cylinder must 
be sound and the replacement neck tube must be welded to this remaining 
piece of the original neck tube.
    (iii) The replacement of material such as, but not limited to, the 
insulating material and the piping system within the insulation space is 
authorized. The replacement material must be equivalent to that used at 
the time of original manufacture.
    (iv) Other welding procedures that are permitted by CGA Pamphlet C-3 
(IBR, see Sec.  171.7 of this subchapter), and not excluded by the 
definition of ``rebuild,'' are authorized.
    (2) After repair, the cylinder must be--
    (i) Pressure tested in accordance with the specifications under 
which the cylinder was originally manufactured;
    (ii) Leak tested before and after assembly of the insulation jacket 
using a mass spectrometer detection system; and
    (iii) Tested for heat conductivity requirements.
    (d) General rebuilding requirements. (1) The rebuilding of a DOT 4-
series cylinder must be made in accordance with the following 
requirements:
    (i) The person rebuilding the cylinder must use the procedures and 
equipment as authorized by the approval issued under Sec.  107.805 of 
this chapter.
    (ii) After removal of a non-pressure component and before 
replacement of any non-pressure component, the cylinder must be visually 
inspected in accordance with CGA Pamphlet C-6 (IBR, see Sec.  171.7 of 
this subchapter).
    (iii) The rebuilder may rebuild a DOT 4B, 4BA or 4BW cylinder having 
a water capacity of 9.07 kg (20 lb) or

[[Page 341]]

greater by replacing a head of the cylinder using a circumferential 
joint. When this weld joint is located at other than an original welded 
joint, a notation of this modification must be shown on the 
Manufacturer's Report of Rebuilding in Sec.  180.215(c)(2). The weld 
joint must be on the cylindrical section of the cylinder.
    (iv) Any welding and the inspection of the rebuilt cylinder must be 
in accordance with the requirements of the applicable cylinder 
specification and the following requirements:
    (A) Rebuilding of any cylinder involving a joint subject to internal 
pressure may only be performed by fusion welding;
    (B) Welding must be performed on an area free from contaminants; and
    (C) A weld defect, such as porosity in a pressure retaining seam, 
must be completely removed before re-welding. Puddling may be used to 
remove a weld defect only by using the tungsten inert gas shielded arc 
process.
    (2) Any rebuilt cylinder must be--
    (i) Heat treated in accordance with paragraph (f) of this section;
    (ii) Subjected to a volumetric expansion test on each cylinder. The 
results of the tests must conform to the applicable cylinder 
specification;
    (iii) Inspected and have test data reviewed to determine conformance 
with the applicable cylinder specification; and
    (iv) Made of material conforming to the specification. Determination 
of conformance shall include chemical analysis, verification, inspection 
and tensile testing of the replaced part. Tensile tests must be 
performed on the replaced part after heat treatment by lots defined in 
the applicable specification.
    (3) For each rebuilt cylinder, an inspector's report must be 
prepared to include the information listed in Sec.  180.215(c).
    (4) Rebuilding a cylinder with brazed seams is prohibited.
    (5) When an end with the original cylinder specification markings is 
replaced, all markings must be transferred to the rebuilt cylinder.
    (e) Additional rebuilding requirements for DOT 4L cylinders. (1) The 
rebuilding of a DOT 4L cylinder must be performed in accordance with 
paragraph (d) of this section. Rebuilding of a DOT 4L cylinder is:
    (i) Substituting or adding material in the insulation space not 
identical to that used in the original manufacture of that cylinder;
    (ii) Making a weld repair not to exceed 150 mm (5.9 inches) in 
length on the longitudinal seam of the cylinder or 300 mm (11.8 inches) 
in length on a circumferential weld joint of the cylinder; or
    (iii) Replacing the outer jacket.
    (2) Reheat treatment of cylinders is prohibited.
    (3) After rebuilding, each inner containment vessel must be proof 
pressure tested at 2 times its service pressure. Each completed assembly 
must be leak-tested using a mass spectrometer detection system.
    (f) Reheat treatment. (1) Prior to reheat treatment, each cylinder 
must be given a visual inspection, internally and externally, in 
accordance with Sec.  180.205(f).
    (2) Cylinders must be segregated in lots for reheat treatment. The 
reheat treatment and visual inspection must be performed in accordance 
with the specification for the cylinders except as provided in paragraph 
(f)(4) of this section.
    (3) After reheat treatment, each cylinder in the lot must be 
subjected to a volumetric expansion test and meet the acceptance 
criteria in the applicable specification or be scrapped.
    (4) After all welding and heat treatment, a test of the new weld 
must be performed as required by the original specification. The test 
results must be recorded in accordance with Sec.  180.215.
    (g) Repair, rebuilding and reheat treatment in Canada. Repair, 
rebuilding, or reheat treatment of a DOT-4 series specification cylinder 
performed by a registered facility in Canada in accordance with the 
Transport Canada TDG Regulations (IBR, see Sec.  171.7 of this 
subchapter) is authorized.

[67 FR 51660, Aug. 8, 2002, as amended at 68 FR 24664, May 8, 2003; 68 
FR 75764, Dec. 31, 2003; 71 FR 54398, Sept. 14, 2006; 82 FR 15897, Mar. 
30, 2017]

[[Page 342]]



Sec.  180.212  Repair of seamless DOT 3-series specification cylinders and 
seamless UN pressure receptacles.

    (a) General requirements for repair of DOT 3-series cylinders and UN 
pressure receptacles. (1) No person may repair a DOT 3-series cylinder 
or a seamless UN pressure receptacle unless--
    (i) The repair facility holds an approval issued under the 
provisions in Sec.  107.805 of this chapter; and
    (ii) Except as provided in paragraph (b) of this section, the repair 
and the inspection is performed under the provisions of an approval 
issued under subpart H of part 107 of this chapter or by a facility 
registered by Transport Canada in accordance with the Transport Canada 
TDG Regulations (IBR; see Sec.  171.7 of this subchapter) and conform to 
the applicable cylinder specification or ISO standard contained in part 
178 of this subchapter.
    (2) The person performing the repair must prepare a report 
containing, at a minimum, the results prescribed in Sec.  180.215.
    (3) If grinding is performed on a DOT 3-series cylinder or a 
seamless UN pressure receptacle, the following conditions apply after 
grinding has been completed. Grinding must not be used to remove arc 
burns from a cylinder, as such a cylinder must be condemned:
    (i) Ultrasonic examination must be conducted to ensure that the wall 
thickness is not less than the minimum design requirement. The wall 
thickness must be measured in at least 3 different areas for every 10 
square inches of grinding area.
    (ii) The cylinder must be requalified in conformance with Sec.  
180.205.
    (iii) The cylinder must be marked in accordance with Sec.  
180.213(f)(10) to indicate compliance with this paragraph (a)(3).
    (b) Repairs not requiring prior approval. Approval is not required 
for the following specific repairs:
    (1) The removal and replacement of a neck ring or foot ring on a DOT 
3A, 3AA or 3B cylinder or a UN pressure receptacle that does not affect 
a pressure part of the cylinder when the repair is performed by a repair 
facility or a cylinder manufacturer of these types of cylinders. The 
repair may be made by welding or brazing in conformance with the 
original specification. After removal and before replacement, the 
cylinder must be visually inspected and any defective cylinder must be 
rejected. The heat treatment, testing and inspection of the repair must 
be performed under the supervision of an inspector and must be performed 
in accordance with the original specification.
    (2) External re-threading of DOT 3AX, 3AAX or 3T specification 
cylinders or a UN pressure receptacle mounted in a MEGC; or the internal 
re-threading of a DOT-3 series cylinder or a seamless UN pressure 
receptacle when performed by a cylinder manufacturer of these types of 
cylinders. The repair work must be performed under the supervision of an 
independent inspection agency. Upon completion of the re-threading, the 
threads must be gauged in accordance with Federal Standard H-28 or an 
equivalent standard containing the same specification limits. The re-
threaded cylinder must be stamped clearly and legibly with the words 
``RETHREAD'' on the shoulder, top head, or neck. No DOT specification 
cylinder or UN cylinder may be re-threaded more than one time without 
approval of the Associate Administrator.

[71 FR 33895, June 12, 2006, as amended at 71 FR 54398, Sept. 14, 2006; 
72 FR 55697, Oct. 1, 2007; 82 FR 15897, Mar. 30, 2017; 85 FR 85435, Dec. 
28, 2020]



Sec.  180.213  Requalification markings.

    (a) General. Each cylinder or UN pressure receptacle requalified in 
accordance with this subpart with acceptable results must be marked as 
specified in this section. Required specification markings may not be 
altered or removed.
    (b) Placement of markings. Each cylinder must be plainly and 
permanently marked on the metal of the cylinder as permitted by the 
applicable specification. Unless authorized by the cylinder 
specification, marking on the cylinder sidewall is prohibited.
    (1) Requalification and required specification markings must be 
legible so as to be readily visible at all times. Illegible 
specification markings may be remarked on the cylinder as provided

[[Page 343]]

by the original specification. Requalification markings may be placed on 
any portion of the upper end of the cylinder excluding the sidewall, as 
provided in this section. Requalification and required specification 
markings that are illegible may be reproduced on a metal plate and 
attached as provided by the original specification.
    (2) Previous requalification markings may not be obliterated, except 
that, when the space originally provided for requalification dates 
becomes filled, additional dates may be added as follows:
    (i) All preceding requalification dates may be removed by peening 
provided that--
    (A) Permission is obtained from the cylinder owner;
    (B) The minimum wall thickness is maintained in accordance with 
manufacturing specifications for the cylinder; and
    (C) The original manufacturing test date is not removed.
    (ii) When the cylinder is fitted with a footring, additional dates 
may be marked on the external surface of the footring.
    (c) Requalification marking method. The depth of requalification 
markings may not be greater than specified in the applicable 
specification. The markings must be made by stamping, engraving, 
scribing or applying a label embedded in epoxy that will remain legible 
and durable throughout the life of the cylinder, or by other methods 
that produce a legible, durable mark.
    (1) A cylinder used as a fire extinguisher (see Sec.  180.209(j)) 
may be marked by using a pressure sensitive label.
    (2) For a DOT 3HT cylinder, when stamped, the test date and RIN must 
be applied by low-stress steel stamps to a depth no greater than that 
prescribed at the time of manufacture. Stamping on the sidewall is not 
authorized.
    (3) For a composite cylinder, the requalification markings must be 
applied on a pressure sensitive label, securely affixed and overcoated 
with epoxy in a manner prescribed by the cylinder manufacturer, near the 
original manufacturer's label. Stamping of the composite surface is not 
authorized.
    (d) Requalification markings. Each cylinder successfully passing 
requalification must be marked with the RIN set in a square pattern, 
between the month and year of the requalification date. The first 
character of the RIN must appear in the upper left corner of the square 
pattern; the second in the upper right; the third in the lower right; 
and the fourth in the lower left. Example: A cylinder requalified in 
September 2006, and approved by a person who has been issued RIN 
``A123'', would be marked plainly and permanently into the metal of the 
cylinder in accordance with location requirements of the cylinder 
specification or on a metal plate permanently secured to the cylinder in 
accordance with paragraph (b) of this section. An example of the 
markings prescribed in this paragraph (d) is as follows:

 A1


 9 06 X


 32

Where:

``9'' is the month of requalification
``A123'' is the RIN
``06'' is the year of requalification, and
``X'' represents the symbols described in paragraphs (f)(2) through 
          (f)(8) of this section.

    (1) Upon written request, variation from the marking requirement may 
be approved by the Associate Administrator.
    (2) A cylinder subject to the requirements of Sec.  171.23(a)(5) of 
this subchapter must be marked with the date and RIN in accordance with 
this paragraph (d) and paragraph (f)(11) of this section, or marked in 
accordance with the requalification authorized by the Associate 
Administrator in accordance with Sec.  171.23(a)(5)(i) of this 
subchapter.
    (e) Size of markings. The size of the markings must be at least 6.35 
mm (\1/4\ in.) high, except RIN characters must be at least 3.18 mm (\1/
8\ in.) high.
    (f) Marking illustrations. Examples of required requalification 
markings for DOT specification and special permit cylinders are 
illustrated as follows:
    (1) For designation of the 5-year volumetric expansion test, 10-year 
volumetric expansion test for UN cylinders and cylinders conforming to 
Sec.  180.209(f)

[[Page 344]]

and (h), or 12-year volumetric expansion test for fire extinguishers 
conforming to Sec.  173.309(a) of this subchapter and cylinders 
conforming to Sec.  180.209(e) and (g), the marking is as illustrated in 
paragraph (d) of this section.
    (2) For designation of the 10-year volumetric expansion test for 
cylinders conforming to Sec.  180.209(b), the marking is as illustrated 
in paragraph (d) of this section, except that the ``X'' is replaced with 
a five-point star.
    (3) For designation of special filling limits up to 10% in excess of 
the marked service pressure for cylinders conforming to Sec.  
173.302a(b) of this subchapter, the marking is as illustrated in 
paragraph (d) of this section, except that the ``X'' is replaced with a 
plus sign `` + ''.
    (4) For designation of the proof pressure test, the marking is as 
illustrated in paragraph (d) of this section, except that the ``X'' is 
replaced with the letter ``S''.
    (5) For designation of the 5-year external visual inspection for 
cylinders conforming to Sec.  180.209(g), the marking is as illustrated 
in paragraph (d) of this section, except that the ``X'' is replaced with 
the letter ``E''.
    (6) For designation of DOT 8 series cylinder shell requalification 
only, the marking is as illustrated in paragraph (d) of this section, 
except that the ``X'' is replaced with the letter ``S''.
    (7) For designation of DOT 8 series and UN cylinder shell and porous 
filler requalification, the marking is as illustrated in paragraph (d) 
of this section, except that the ``X'' is replaced with the letters 
``FS.''
    (8) For designation of a nondestructive examination combined with a 
visual inspection, the marking is as illustrated in paragraph (d) of 
this section, except that the ``X'' is replaced with the type of test 
performed, for example the letters ``AE'' for acoustic emission or 
``UE'' for ultrasonic examination.
    (9) For designation of the eddy current examination combined with a 
visual inspection, the marking is as illustrated in paragraph (d) of 
this section, except the ``X'' is replaced with the letters ``VE.''
    (10) For designation of grinding with ultrasonic wall thickness 
examination, the marking is as illustrated in paragraph (d) of this 
section, except the ``X'' is replaced with the letter ``R''.
    (11) For designation of requalification of a foreign cylinder 
requalified in conformance with Sec. Sec.  171.23(a)(5) of this 
subchapter and 180.209(l), the marking is as illustrated in paragraph 
(d) of this section, except that the ``X'' is replaced with the letters 
``EX'' to indicate that the cylinder is for export only.
    (g) Visual inspection requalification markings. (1) Alternative to 
the marking requirements of paragraphs (d) and (f)(5) of this section, 
each cylinder successfully passing a visual inspection only, in 
accordance with Sec.  180.209(g), may be marked with the visual 
inspection number (e.g., V123456) issued to a person performing visual 
inspections. Examples of the way the markings may be applied are as 
follows:
[GRAPHIC] [TIFF OMITTED] TR28DE20.498

(2) Where:

(i) ``03'' is the month of requalification (the additional numeral ``0'' 
          is optional'');

[[Page 345]]

(ii) ``V123456'' is the RIN;
(iii) ``14'' is the year of requalification; and
(iv) ``E'' to indicate visual inspection.

[67 FR 51660, Aug. 8, 2002, as amended at 70 FR 73166, Dec. 9, 2005; 71 
FR 33896, June 12, 2006; 71 FR 51128, Aug. 29, 2006; 71 FR 78635, Dec. 
29, 2006; 75 FR 53597, Sept. 1, 2010; 80 FR 72929, Nov. 23, 2015; 81 FR 
3686, Jan. 21, 2016; 85 FR 75716, Nov. 25, 2020; 85 FR 85435, Dec. 28, 
2020]



Sec.  180.215  Reporting and record retention requirements.

    (a) Facility records. A person who requalifies, repairs or rebuilds 
cylinders must maintain the following records where the requalification 
is performed:
    (1) Current RIN issuance letter;
    (2) If the RIN has expired and renewal is pending, a copy of the 
renewal request;
    (3) Copies of notifications to Associate Administrator required 
under Sec.  107.805 of this chapter;
    (4) Current copies of those portions of this subchapter applicable 
to its cylinder requalification and marking activities at that location;
    (5) Current copies of all special permits governing exemption 
cylinders requalified or marked by the requalifier at that location; and
    (6) The information contained in each applicable CGA or ASTM 
standard incorporated by reference in Sec.  171.7 of this subchapter 
applicable to the requalifier's activities.
    (b) Requalification records. Daily records of visual inspection, 
pressure test, eddy current examination if required, and ultrasonic 
examination if permitted under a special permit, as applicable, must be 
maintained by the person who performs the requalification until either 
the expiration of the requalification period or until the cylinder is 
again requalified, whichever occurs first. A single date may be used for 
each test sheet, provided each test on the sheet was conducted on that 
date. Ditto marks or a solid vertical line may be used to indicate 
repetition of the preceding entry for the following entries only: Date; 
actual dimensions; manufacturer's name or symbol, if present; owner's 
name or symbol, if present; and test operator. Blank spaces may not be 
used to indicate repetition of a prior entry. A symbol may be used for 
the actual dimensions if there is a reference chart available at the 
facility that lists the actual dimensions of every symbol used. The 
records must include the following information:
    (1) Calibration test records. For each test to demonstrate 
calibration, the date; serial number of the calibrated cylinder; 
calibration test pressure; total, elastic and permanent expansions; and 
legible identification of test operator. The test operator must be able 
to demonstrate that the results of the daily calibration verification 
correspond to the hydrostatic tests performed on that day. The daily 
verification of calibration(s) may be recorded on the same sheets as, 
and with, test records for that date, or may be recorded on a separate 
sheet.
    (2) Pressure test and visual inspection records. The date of 
requalification; serial number; DOT-specification or special permit 
number; marked pressure; actual dimensions; manufacturer's name or 
symbol, if present; year of manufacture; owner's name or symbol, if 
present; gas service; result of visual inspection; actual test pressure; 
total, elastic and permanent expansions; percent permanent expansion; 
disposition, with reason for any repeated test, rejection or 
condemnation; and legible identification of test operator. For each 
cylinder marked pursuant to Sec.  173.302a(b)(5) of this subchapter, the 
test sheet must indicate the method by which any average or maximum wall 
stress was computed. Records must be kept for all completed, as well as 
unsuccessful tests. The entry for a repeated test must indicate the date 
of the earlier test, if conducted on a different day.
    (3) Wall stress. Calculations of average and maximum wall stress 
pursuant to Sec.  173.302a(b)(3) of this subchapter, if performed.
    (4) Calibration certificates. The most recent certificate of 
calibration must be maintained for each calibrated cylinder, pressure 
indicating device, and expansion indicating device.
    (c) Repair, rebuilding or reheat treatment records. (1) Records 
covering welding or brazing repairs, rebuilding or reheat treating shall 
be retained for a minimum of fifteen years by the approved facility.

[[Page 346]]

    (2) A record of rebuilding, in accordance with Sec.  180.211(d), 
must be completed for each cylinder rebuilt. The record must be clear, 
legible, and contain the following information:
    (i) Name and address of test facility, date of test report, and name 
of original manufacturer;
    (ii) Marks stamped on cylinder to include specification number, 
service pressure, serial number, symbol of manufacturer, inspector's 
mark, and other marks, if any;
    (iii) Cylinder outside diameter and length in inches;
    (iv) Rebuild process (welded, brazed, type seams, etc.);
    (v) Description of assembly and any attachments replaced (e.g., 
neckrings, footrings);
    (vi) Chemical analysis of material for the cylinder, including seat 
and Code No., type of analysis (ladle, check), chemical components 
(Carbon (C), Phosphorous (P), Sulfur (S), Silicon (Si), Manganese (Mn), 
Nickel (Ni), Chromium (Cr), Molybdenum (Mo), Copper (Cu), Aluminum (Al), 
Zinc (Zn)), material manufacturer, name of person performing the 
analysis, results of physical tests of material for cylinder (yield 
strength (psi), tensile strength (psi), elongation percentage (inches), 
reduction in area percentage, weld bend, tensile bend, name of 
inspector);
    (vii) Results of a test on a cylinder, including test method, test 
pressure, total expansion, permanent expansion, elastic expansion, 
percent permanent expansion (permanent expansion may not exceed ten 
percent (10 percent) of total expansion), and volumetric capacity 
(volumetric capacity of a rebuilt cylinder must be within 3 percent of the calculated capacity);
    (viii) Each report must include the following certification 
statement: ``I certify that this rebuilt cylinder is accurately 
represented by the data above and conforms to all of the requirements in 
Subchapter C of Chapter I of Title 49 of the Code of Federal 
Regulations.''. The certification must be signed by the rebuild 
technician and principal, officer, or partner of the rebuild facility.
    (3) A record of grinding and ultrasonic examination in conformance 
with Sec.  180.212(a)(3) must be completed for each cylinder on which 
grinding is performed. The record must be clear, legible, and contain 
the following information:
    (i) Name and address of the test facility, date of test report, and 
name or original manufacturer;
    (ii) Marks stamped on cylinder to include specification number, 
service pressure, serial number, symbol of manufacturer, and date of 
manufacture;
    (iii) Cylinder outside diameter and length in inches;
    (iv) Detailed map of where the grinding was performed on the 
cylinder; and
    (v) Wall thickness measurements in grind area in conformance with 
Sec.  180.212(a)(3)(i).

[67 FR 51660, Aug. 8, 2002, as amended at 68 FR 24664, May 8, 2003; 70 
FR 73166, Dec. 9, 2005; 71 FR 54398, Sept. 14, 2006; 72 FR 55697, Oct. 
1, 2007; 85 FR 85436, Dec. 28, 2020]



Sec.  180.217  Requalification requirements for MEGCs.

    (a) Periodic inspections. Each MEGC must be given an initial visual 
inspection and test in accordance with Sec.  178.75(i) of this 
subchapter before being put into service for the first time. After the 
initial inspection, a MEGC must be inspected at least once every five 
years in accordance with this subpart or by a facility registered by 
Transport Canada in accordance with the Transport Canada TDG Regulations 
(IBR, see Sec.  171.7 of this subchapter).
    (b) Exceptional inspection and test. If a MEGC shows evidence of 
damaged or corroded areas, leakage, or other conditions that indicate a 
deficiency that could affect the integrity of the MEGC, an exceptional 
inspection and test must be performed, regardless of the last periodic 
inspection and test. The extent of the exceptional inspection and test 
will depend on the amount of damage or deterioration of the MEGC. As a 
minimum, an exceptional inspection of a MEGC must include inspection as 
specified in paragraph (a)(1) of this section.
    (c) Correction of unsafe condition. When evidence of any unsafe 
condition

[[Page 347]]

is discovered, the MEGC may not be returned to service until the unsafe 
condition has been corrected and the MEGC has been requalified in 
accordance with the applicable tests and inspection.
    (d) Repairs and modifications to MEGCs. No person may perform a 
modification to an approved MEGC that may affect conformance to the 
applicable ISO standard or safe use, and that involve a change to the 
design type or affect its ability to retain the hazardous material in 
transportation. Before making any modification changes to an approved 
MEGC, the owner must obtain approval from the Associate Administrator as 
prescribed in Sec.  178.74 of this subchapter. The repair of a MEGC's 
structural equipment is authorized provided such repairs are made in 
accordance with the requirements prescribed for its approved design and 
construction. Any repair to the pressure receptacles of a MEGC must meet 
the requirements of Sec.  180.212.
    (e) Requalification markings. Each MEGC must be durably and legibly 
marked in English, with the year and month, and the type of the most 
recent periodic requalification performed (e.g., 2004-05 AE/UE, where 
``AE'' represents acoustic emission and ``UE'' represents ultrasonic 
examination) followed by the stamp of the approval agency who performed 
or witnessed the most recent test.
    (f) Records. The owner of each MEGC or the owner's authorized agent 
must retain a written record of the date and results of all repairs and 
required inspections and tests. The report must contain the name and 
address of the person performing the inspection or test. The periodic 
test and inspection records must be retained until the next inspection 
or test is completed. Repair records and the initial exceptional 
inspection and test records must be retained during the period the MEGC 
is in service and for one year thereafter. These records must be made 
available for inspection by a representative of the Department on 
request.

[71 FR 33896, June 12, 2006, as amended at 85 FR 27901, May 11, 2020]



             Subpart D_Qualification and Maintenance of IBCs



Sec.  180.350  Applicability and definitions.

    This subpart prescribes requirements, in addition to those contained 
in parts 107, 171, 172, 173 and 178 of this subchapter, applicable to 
any person responsible for the continuing qualification, maintenance, or 
periodic retesting of an IBC. The following definitions apply:
    (a) Remanufactured IBCs are metal, rigid plastic or composite IBCs 
produced as a UN type from a non-UN type, or are converted from one UN 
design type to another UN design type. Remanufactured IBCs are subject 
to the same requirements of this subchapter that apply to new IBCs of 
the same type (also see Sec.  178.801(c)(1) of this subchapter for 
design type definition).
    (b) Repaired IBCs are metal, rigid plastic or composite IBCs that, 
as a result of impact or for any other cause (such as corrosion, 
embrittlement or other evidence of reduced strength as compared to the 
design type), are restored so as to conform to the design type and to be 
able to withstand the design type tests. For the purposes of this 
subchapter, the replacement of the rigid inner receptacle of a composite 
IBC with one from the original manufacturer is considered a repair. 
Routine maintenance of IBCs (see definition in paragraph (c) of this 
section) is not considered repair. The bodies of rigid plastic IBCs and 
the inner receptacles of composite IBCs are not repairable.
    (c) Routine maintenance of IBCs is the routine performance on:
    (1) Metal, rigid plastic or composite IBCs of operations such as:
    (i) Cleaning;
    (ii) Removal and reinstallation or replacement of body closures 
(including associated gaskets), or of service equipment conforming to 
the original manufacturer's specifications provided that the 
leaktightness of the IBC is verified; or
    (iii) Restoration of structural equipment not directly performing a 
hazardous material containment or discharge pressure retention function 
so as to conform to the design type (for example, the straightening of 
legs or

[[Page 348]]

lifting attachments), provided the containment function of the IBC is 
not affected.
    (2) Plastics or textile flexible IBCs of operations, such as:
    (i) Cleaning; or
    (ii) Replacement of non-integral components, such as non-integral 
liners and closure ties, with components conforming to the original 
manufacturer's specification; provided that these operations do not 
adversely affect the containment function of the flexible IBC or alter 
the design type.

[68 FR 45042, July 31, 2003, as amended at 69 FR 76186, Dec. 20, 2004; 
76 FR 3389, Jan. 19, 2011]



Sec.  180.351  Qualification of IBCs.

    (a) General. Each IBC used for the transportation of hazardous 
materials must be an authorized packaging.
    (b) IBC specifications. To qualify as an authorized packaging, each 
IBC must conform to this subpart, the applicable requirements specified 
in part 173 of this subchapter, and the applicable requirements of 
subparts N and O of part 178 of this subchapter.

[Amdt. 180-5, 59 FR 38079, July 26, 1994, as amended at 66 FR 45391, 
Aug. 28, 2001]



Sec.  180.352  Requirements for retest and inspection of IBCs.

    (a) General. Each IBC constructed in accordance with a UN standard 
for which a test or inspection specified in paragraphs (b)(1), (b)(2) 
and (b)(3) of this section is required may not be filled and offered for 
transportation or transported until the test or inspection has been 
successfully completed. This paragraph does not apply to any IBC filled 
prior to the test or inspection due date. The requirements in this 
section do not apply to DOT 56 and 57 portable tanks.
    (b) Test and inspections for metal, rigid plastic, and composite 
IBCs. Each IBC is subject to the following test and inspections:
    (1) Each IBC intended to contain solids that are loaded or 
discharged under pressure or intended to contain liquids must be tested 
in accordance with the leakproofness test prescribed in Sec.  178.813 of 
this subchapter prior to its first use in transportation and every 2.5 
years thereafter, starting from the date of manufacture or the date of a 
repair conforming to paragraph (d)(1) of this section. For this test, 
the IBC is not required to have its closures fitted.
    (2) An external visual inspection must be conducted initially after 
production and every 2.5 years starting from the date of manufacture or 
the date of a repair conforming to paragraph (d)(1) of this section to 
ensure that:
    (i) The IBC is marked in accordance with requirements in Sec.  
178.703 of this subchapter. Missing or damaged markings, or markings 
difficult to read must be restored or returned to original condition.
    (ii) Service equipment is fully functional and free from damage 
which may cause failure. Missing, broken, or damaged parts must be 
repaired or replaced.
    (iii) The IBC is capable of withstanding the applicable design 
qualification tests. The IBC must be externally inspected for cracks, 
warpage, corrosion or any other damage which might render the IBC unsafe 
for transportation. An IBC found with such defects must be removed from 
service or repaired in accordance with paragraph (d) of this section. 
The inner receptacle of a composite IBC must be removed from the outer 
IBC body for inspection unless the inner receptacle is bonded to the 
outer body or unless the outer body is constructed in such a way (e.g., 
a welded or riveted cage) that removal of the inner receptacle is not 
possible without impairing the integrity of the outer body. Defective 
inner receptacles must be replaced in accordance with paragraph (d) of 
this section or the entire IBC must be removed from service. For metal 
IBCs, thermal insulation must be removed to the extent necessary for 
proper examination of the IBC body.
    (3) Each metal, rigid plastic and composite IBC must be internally 
inspected at least every five years to ensure that the IBC is free from 
damage and to ensure that the IBC is capable of withstanding the 
applicable design qualification tests.
    (i) The IBC must be internally inspected for cracks, warpage, and 
corrosion or any other defect that might

[[Page 349]]

render the IBC unsafe for transportation. An IBC found with such defects 
must be removed from hazardous materials service until restored to the 
original design type of the IBC.
    (ii) Metal IBCs must be inspected to ensure the minimum wall 
thickness requirements in Sec.  178.705(c)(1)(iv) of this subchapter are 
met. Metal IBCs not conforming to minimum wall thickness requirements 
must be removed from hazardous materials service.
    (c) Visual inspection for flexible, fiberboard, or wooden IBCs. Each 
IBC must be visually inspected prior to first use and permitted reuse, 
by the person who places hazardous materials in the IBC, to ensure that:
    (1) The IBC is marked in accordance with requirements in Sec.  
178.703 of this subchapter. Additional marking allowed for each design 
type may be present. Required markings that are missing, damaged or 
difficult to read must be restored or returned to original condition.
    (2) Proper construction and design specifications have been met.
    (i) Each flexible IBC must be inspected to ensure that:
    (A) Lifting straps if used, are securely fastened to the IBC in 
accordance with the design type.
    (B) Seams are free from defects in stitching, heat sealing or gluing 
which would render the IBC unsafe for transportation of hazardous 
materials. All stitched seam-ends must be secure.
    (C) Fabric used to construct the IBC is free from cuts, tears and 
punctures. Additionally, fabric must be free from scoring which may 
render the IBC unsafe for transport.
    (ii) Each fiberboard IBC must be inspected to ensure that:
    (A) Fluting or corrugated fiberboard is firmly glued to facings.
    (B) Seams are creased and free from scoring, cuts, and scratches.
    (C) Joints are appropriately overlapped and glued, stitched, taped 
or stapled as prescribed by the design. Where staples are used, the 
joints must be inspected for protruding staple-ends which could puncture 
or abrade the inner liner. All such ends must be protected before the 
IBC is authorized for hazardous materials service.
    (iii) Each wooden IBC must be inspected to ensure that:
    (A) End joints are secured in the manner prescribed by the design.
    (B) IBC walls are free from defects in wood. Inner protrusions which 
could puncture or abrade the liner must be covered.
    (d) Requirements applicable to repair of IBCs. (1) Except for 
flexible and fiberboard IBCs and the bodies of rigid plastic and 
composite IBCs, damaged IBCs may be repaired and the inner receptacles 
of composite packagings may be replaced and returned to service 
provided:
    (i) The repaired IBC conforms to the original design type, is 
capable of withstanding the applicable design qualification tests, and 
is retested and inspected in accordance with the applicable requirements 
of this section;
    (ii) An IBC intended to contain liquids or solids that are loaded or 
discharged under pressure is subjected to a leakproofness test as 
specified in Sec.  178.813 of this subchapter and is marked with the 
date of the test; and
    (iii) The IBC is subjected to the internal and external inspection 
requirements as specified in paragraph (b) of this section.
    (iv) The person performing the tests and inspections after the 
repair must durably mark the IBC near the manfacturer's UN design type 
marking to show the following:
    (A) The country in which the tests and inspections were performed;
    (B) The name or authorized symbol of the person performing the tests 
and inspections; and
    (C) The date (month, year) of the tests and inspections.
    (v) Retests and inspections performed in accordance with paragraphs 
(d)(1)(i) and (ii) of this section may be used to satisfy the 
requirements for the 2.5 and five year periodic tests and inspections 
required by paragraph (b) of this section, as applicable.
    (2) Except for flexible and fiberboard IBCs, the structural 
equipment of an IBC may be repaired and returned to service provided:
    (i) The repaired IBC conforms to the original design type and is 
capable of withstanding the applicable design qualification tests; and

[[Page 350]]

    (ii) The IBC is subjected to the internal and external inspection 
requirements as specified in paragraph (b) of this section.
    (3) Service equipment may be replaced provided:
    (i) The repaired IBC conforms to the original design type and is 
capable of withstanding the applicable design qualification tests;
    (ii) The IBC is subjected to the external visual inspection 
requirements as specified in paragraph (b) of this section; and
    (iii) The proper functioning and leak tightness of the service 
equipment, if applicable, is verified.
    (e) Requirements applicable to routine maintenance of IBCs. Except 
for routine maintenance of metal, rigid plastics and composite IBCs 
performed by the owner of the IBC, whose State and name or authorized 
symbol is durably marked on the IBC, the party performing the routine 
maintenance shall durably mark the IBC near the manufacturer's UN design 
type marking to show the following:
    (1) The country in which the routine maintenance was carried out; 
and
    (2) The name or authorized symbol of the party performing the 
routine maintenance.
    (f) Retest date. The date of the most recent periodic retest must be 
marked as provided in Sec.  178.703(b) of this subchapter.
    (g) Record retention. (1) The owner or lessee of the IBC must keep 
records of periodic retests, initial and periodic inspections, and tests 
performed on the IBC if it has been repaired or remanufactured.
    (2) Records must include design types and packaging specifications, 
test and inspection dates, name and address of test and inspection 
facilities, names or name of any persons conducting test or inspections, 
and test or inspection specifics and results.
    (3) Records must be kept for each packaging at each location where 
periodic tests are conducted, until such tests are successfully 
performed again or for at least 2.5 years from the date of the last 
test. These records must be made available for inspection by a 
representative of the Department on request.

[Amdt. 180-5, 59 FR 38079, July 26, 1994, as amended at 64 FR 10782, 
Mar. 5, 1999; 65 FR 58632, Sept. 29, 2000; 66 FR 45186, 45391, Aug. 28, 
2001; 68 FR 45042, July 31, 2003; 69 FR 76186, Dec. 20, 2004; 70 FR 
34399, June 14, 2005; 70 FR 56099, Sept. 23, 2005; 71 FR 78635, Dec. 29, 
2006]



         Subpart E_Qualification and Maintenance of Cargo Tanks



Sec.  180.401  Applicability.

    This subpart prescribes requirements, in addition to those contained 
in parts 107, 171, 172, 173 and 178 of this subchapter, applicable to 
any person responsible for the continuing qualification, maintenance or 
periodic testing of a cargo tank.

[Amdt. 180-2, 54 FR 25032, June 12, 1989, as amended at 55 FR 37065, 
Sept. 7, 1990]



Sec.  180.403  Definitions.

    In addition to the definitions contained in Sec. Sec.  171.8, 
178.320(a) and 178.345-1 of this subchapter, the following definitions 
apply to this subpart:
    Corroded or abraded means any visible reduction in the material 
thickness of the cargo tank wall or valve due to pitting, flaking, 
gouging, or chemical reaction to the material surface that effects the 
safety or serviceability of the cargo tank. The term does not include 
cosmetic or minor surface degradation that does not effect the safety or 
serviceability of the cargo tank
    Corrosive to the tank or valve means that the lading has been shown 
through experience or test data to reduce the thickness of the material 
of construction of the tank wall or valve.
    Delivery hose assembly means a liquid delivery hose and its attached 
couplings.
    Modification means any change to the original design and 
construction of a cargo tank or a cargo tank motor vehicle that affects 
its structural integrity or lading retention capability including 
changes to equipment certified as part of an emergency discharge control 
system required by Sec.  173.315(n)(2) of this subchapter. Any 
modification that involves welding on the cargo tank wall must also meet 
all requirements for

[[Page 351]]

``Repair'' as defined in this section. Excluded from this category are 
the following:
    (1) A change to motor vehicle equipment such as lights, truck or 
tractor power train components, steering and brake systems, and 
suspension parts, and changes to appurtenances, such as fender 
attachments, lighting brackets, ladder brackets; and
    (2) Replacement of components such as valves, vents, and fittings 
with a component of a similar design and of the same size.
    Owner means the person who owns a cargo tank motor vehicle used for 
the transportation of hazardous materials, or that person's authorized 
agent.
    Piping system means any component of a cargo tank delivery system, 
other than a delivery hose assembly, that contains product during 
loading or unloading.
    Rebarrelling means replacing more than 50 percent of the combined 
shell and head material of a cargo tank.
    Repair means any welding on a cargo tank wall done to return a cargo 
tank or a cargo tank motor vehicle to its original design and 
construction specification, or to a condition prescribed for a later 
equivalent specification in effect at the time of the repair. Excluded 
from this category are the following:
    (1) A change to motor vehicle equipment such as lights, truck or 
tractor power train components, steering and brake systems, and 
suspension parts, and changes to appurtenances, such as fender 
attachments, lighting brackets, ladder brackets; and
    (2) Replacement of components such as valves, vents, and fittings 
with a component of a similar design and of the same size.
    (3) Replacement of an appurtenance by welding to a mounting pad.
    Replacement of a barrel means to replace the existing tank on a 
motor vehicle chassis with an unused (new) tank. For the definition of 
tank, see Sec.  178.320, Sec.  178.345, or Sec.  178.338-1 of this 
subchapter, as applicable.
    Stretching means any change in length, width or diameter of the 
cargo tank, or any change to a cargo tank motor vehicle's undercarriage 
that may affect the cargo tank's structural integrity.

[Amdt. 180-2, 54 FR 25032, June 12, 1989, as amended at 55 FR 37065, 
Sept. 7, 1990; Amdt. 180-3, 57 FR 45466, Oct. 1, 1992; Amdt. 180-7, 59 
FR 55177, Nov. 3, 1994; 60 FR 17402, Apr. 5, 1995; Amdt. 180-10, 61 FR 
51342, Oct. 1, 1996; 63 FR 52850, Oct. 1, 1998; 64 FR 28050, May 24, 
1999; 68 FR 19286, Apr. 18, 2003; 69 FR 54047, Sept. 7, 2004]



Sec.  180.405  Qualification of cargo tanks.

    (a) General. Unless otherwise provided in this subpart, each cargo 
tank used for the transportation of hazardous material must be an 
authorized packaging.
    (b) Cargo tank specifications. (1) To qualify as an authorized 
packaging, each cargo tank must conform to this subpart, the applicable 
requirements specified in part 173 of this subchapter for the specific 
lading, and where a DOT specification cargo tank is required, an 
applicable specification in effect on the date initial construction 
began: MC 300, MC 301, MC 302, MC 303, MC 304, MC 305, MC 306, MC 307, 
MC 310, MC 311, MC 312, MC 330, MC 331, MC 338, DOT 406, DOT 407, or DOT 
412 (Sec. Sec.  178.337, 178.338, 178.345, 178.346, 178.347, 178.348 of 
this subchapter). However, except as provided in paragraphs (b)(2), (d), 
(e), (f)(5), and (f)(6) of this section, no cargo tank may be marked or 
certified after August 31, 1995, to the applicable MC 306, MC 307, MC 
312, MC 331, or MC 338 specification in effect on December 30, 1990.
    (2) Exception. A cargo tank originally manufactured to the MC 306, 
MC 307, or MC 312 specification may be recertified to the original 
specification provided:
    (i) Records are available verifying the cargo tank was originally 
manufactured to the specification;
    (ii) If the cargo tank was stretched, rebarrelled, or modified, 
records are available verifying that the stretching, rebarrelling, or 
modification was performed in accordance with the National Board 
Inspection Code and this part;
    (iii) A Design Certifying Engineer or Registered Inspector verifies 
the cargo tank conforms to all applicable requirements of the original 
specification and furnishes to the owner written documentation that 
verifies the tank

[[Page 352]]

conforms to the original structural design requirements in effect at the 
time the tank was originally constructed;
    (iv) The cargo tank meets all applicable tests and inspections 
required by Sec.  180.407(c); and
    (v) The cargo tank is recertified to the original specification in 
accordance with the reporting and record retention provisions of Sec.  
180.417. The certification documents required by Sec.  180.417(a)(3) 
must include both the date the cargo tank was originally certified to 
the specification and the date it was recertified. The specification 
plate on the cargo tank or the cargo tank motor vehicle must display the 
date the cargo tank was originally certified to the specification.
    (c) Cargo tank specifications no longer authorized for construction. 
(1) A cargo tank made to a specification listed in column 1 of table 1 
or table 2 of this paragraph (c)(1) may be used when authorized in this 
part, provided--
    (i) The cargo tank initial construction began on or before the date 
listed in table 1, column 2, as follows:

                                 Table 1
------------------------------------------------------------------------
                  Column 1                             Column 2
------------------------------------------------------------------------
MC 300.....................................  Sept. 2, 1967
MC 301.....................................  June 12, 1961
MC 302, MC 303, MC 304, MC 305, MC 310, MC   Sept. 2, 1967
 311.
MC 330.....................................  May 15, 1967
------------------------------------------------------------------------

    (ii) The cargo tank was marked or certified before the date listed 
in table 2, column 2, as follows:

                                 Table 2
------------------------------------------------------------------------
                  Column 1                             Column 2
------------------------------------------------------------------------
MC 306, MC 307, MC 312.....................  Sept. 1, 1995
------------------------------------------------------------------------

    (2) A cargo tank of a specification listed in paragraph (c)(1) of 
this section may have its pressure relief devices and outlets modified 
as follows:
    (i) A Specification MC 300, MC 301, MC 302, MC 303, or MC 305 cargo 
tank, to conform with a Specification MC 306 or DOT 406 cargo tank (See 
Sec. Sec.  178.346-3 and 178.346-4 of this subchapter).
    (ii) A Specification MC 306 cargo tank to conform to a Specification 
DOT 406 cargo tank (See Sec. Sec.  178.346-3 and 178.346-4 of this 
subchapter).
    (iii) A Specification MC 304 cargo tank, to conform with a 
Specification MC 307 or DOT 407 cargo tank (See Sec. Sec.  178.347-4 and 
178.345-11 of this subchapter).
    (iv) A Specification MC 307 cargo tank, to conform with a 
Specification DOT 407 cargo tank (See Sec. Sec.  178.347-4 and 178.345-
11 of this subchapter).
    (v) A Specification MC 310 or MC 311 cargo tank, to conform with a 
Specification MC 312 or DOT 412 cargo tank (See Sec. Sec.  178.348-4 and 
178.345-11 of this subchapter).
    (vi) A Specification MC 312 cargo tank, to conform with a 
Specification DOT 412 cargo tank (See Sec. Sec.  178.348-4 and 178.345-
11 of this subchapter).
    (vii) A Specification MC 330 cargo tank, to conform with a 
Specification MC 331 cargo tank, except as specifically required by 
Sec.  173.315 of this subchapter (see Sec. Sec.  178.337-8 and 178.337-9 
of this subchapter).
    (d) MC 338 cargo tank. The owner of a cargo tank that conforms to 
and was used under the terms of an exemption issued before October 1, 
1984, that authorizes the transportation of a cryogenic liquid shall 
remove the exemption number stenciled on the cargo tank and stamp the 
specification plate (or a plate placed adjacent to the specification 
plate) ``DOT MC 338'' followed by the exemption number, for example, 
``DOT MC 338-E * * * *''. (Asterisks to be replaced by the exemption 
number). The cargo tank must be remarked prior to the expiration date of 
the exemption. During the period the cargo tank is in service, the owner 
of a cargo tank that is remarked in this manner must retain at its 
principal place of business a copy of the last exemption in effect. No 
new construction of cargo tanks pursuant to such exemption is 
authorized.
    (1) The holding time must be determined, as required in Sec.  
178.338-9 of this subchapter, on each cargo tank or on at least one 
cargo tank of each design. Any subsequent cargo tank manufactured to the 
same design type (see Sec.  178.320), if not individually tested, must 
have the optional test regimen performed during the first shipment (see 
Sec.  178.338-9 (b) and (c) of this subchapter).

[[Page 353]]

    (2) The holding time determined by test for one authorized cryogenic 
liquid may be used as the basis for establishing the holding time for 
other authorized cryogenic liquids.
    (e) MC 331 cargo tanks. The owner of a MC 331 (Sec.  178.337 of this 
subchapter) cargo tank that conforms to and was used under an exemption 
issued before October 1, 1984, that authorizes the transportation of 
ethane, refrigerated liquid; ethane-propane mixture, refrigerated 
liquid; or hydrogen chloride, refrigerated liquid shall remove the 
exemption number stenciled on the cargo tank and stamp the exemption 
number on the specification plate (or a plate placed adjacent to the 
specification plate), immediately after the DOT Specification, for 
example, ``DOT MC 331-E * * * *''. (Asterisks to be replaced by the 
exemption number.) The cargo tank must be remarked prior to the 
expiration date of the exemption. During the period the cargo tank is in 
service, the owner of a cargo tank that is remarked in this manner must 
retain at the owner's principal place of business a copy of the last 
exemption in effect.
    (f) MC 306, MC 307, MC 312 cargo tanks. Either a Registered 
Inspector or a Design Certifying Engineer and the owner of a MC 306, MC 
307 or MC 312 cargo tank motor vehicle constructed in accordance with 
and used under an exemption issued before December 31, 1990, that 
authorizes a condition specified in this paragraph shall examine the 
cargo tank motor vehicle and its design to determine if it meets the 
requirements of the applicable MC 306, MC 307 or MC 312 specification in 
effect at the time of manufacture, except as specified herein.
    (1) A cargo tank motor vehicle constructed after August 1, 1981, or 
the date specified in the applicable exemption, in conformance with the 
following conditions that apply, may be remarked and certified in 
accordance with paragraphs (f) (5) and (6) of this section:
    (i) A vacuum-loaded cargo tank must have an ASME Code stamped 
specification plate marked with a minimum internal design pressure of 25 
psig, and be designed for a minimum external design pressure of 15 psig.
    (ii) An outlet equipped with a self-closing system which includes an 
external stop-valve must have the stop valve and associated piping 
protected within the vehicle's rear-end tank protection device, vehicle 
frame or an equally adequate accident damage protection device (See 
Sec.  178.345-8 of this subchapter.) The self-closing system (See Sec.  
178.345-11 of this subchapter) must be equipped with a remotely actuated 
means of closure as follows:
    (A) For a cargo tank used in other than corrosive service, the 
remote means of closure must be activated for closure by manual or 
mechanical means and, in case of fire, by an automatic heat activated 
means.
    (B) For a cargo tank used in corrosive service, the remote means of 
closure may be actuated by manual or mechanical means only.
    (iii) A cargo tank having an unreinforced portion of the shell 
exceeding 60 inches must have the circumferential reinforcement located 
so that the thickness and tensile strength of shell material in 
combination with the frame and circumferential reinforcement produces a 
structural integrity at least equal to that prescribed in Sec.  178.345-
3 of this subchapter or the specification in effect at time of 
manufacture.
    (iv) A cargo tank having a projection from the tank shell or head 
that may contain lading in any tank position is authorized, provided 
such projection is as strong as the tank shell or head and is located 
within the motor vehicle's rear-end tank protection or other appropriate 
accident damage protection device.
    (v) A cargo tank may be constructed of nickel, titanium, or other 
ASME sheet or plate materials in accordance with an exemption.
    (2) A vacuum-loaded cargo tank constructed after August 1, 1981, or 
the date specified in the applicable exemption, in conformance with 
paragraph (f)(1) of this section, except that an outlet equipped with an 
external valve which is not part of a self-closing system:
    (i) Must be equipped with a self-closing system prior to September 
1, 1993.
    (ii) May be remarked and certified in accordance with paragraphs 
(f)(5) and

[[Page 354]]

(6) of this section after the cargo tank motor vehicle has been equipped 
with the self-closing system.
    (3) A vacuum-loaded cargo tank constructed prior to August 1, 1981, 
in conformance with paragraph (f)(1) of this section, except for 
paragraph (f)(1)(i), may be remarked and certified in accordance with 
paragraphs (f) (5) and (6) of this section.
    (4) A vacuum-loaded cargo tank constructed prior to August 1, 1981, 
in conformance with paragraph (f)(1) of this section, except for 
paragraph (f)(1)(i) of this section, and except that an outlet is 
equipped with an external valve which is not part of a self-closing 
system:
    (i) Must be equipped with a self-closing system prior to September 
1, 1993.
    (ii) May be remarked and certified in accordance with paragraphs 
(f)(5) and (6) of this section after the cargo tank motor vehicle has 
been equipped with the self-closing system.
    (5) The owner of a cargo tank for which a determination has been 
made that the cargo tank is in conformance with paragraph (f) (1), (2), 
(3), or (4) of this section shall complete a written certification, in 
English, signed by the owner and containing at least the following 
information:
    (i) A statement certifying that each cargo tank conforms to Sec.  
180.405 (f) (1), (2), (3), or (4);
    (ii) The applicable DOT exemption number, the applicable 
specification number and the owner's and manufacturer's serial number 
for the cargo tank;
    (iii) A statement setting forth any modifications made to bring the 
cargo tank into conformance with Sec.  180.405(f) (1), (2), (3), or (4), 
or the applicable specification;
    (iv) A statement identifying the person certifying the cargo tank 
and the date of certification.
    (6) The owner of a certified cargo tank shall remove the exemption 
number stenciled on the cargo tank and shall durably mark the 
specification plate (or a plate placed adjacent to the specification 
plate) ``MC + + + -E ****'' (where `` + + + '' is to be replaced by 
the applicable specification number, ``* * * *'' by the exemption number 
and ``   '' by the alloy.)
    (7) A cargo tank remarked and certified in conformance with this 
paragraph (f) is excepted from the provisions of Sec.  180.405(c).
    (8) During the period the cargo tank is in service, and for one year 
thereafter, the owner of a cargo tank that is certified and remarked in 
this manner must retain on file at its principal place of business a 
copy of the certificate and the last exemption in effect.
    (g) Cargo tank manhole assemblies. (1) MC 306, MC 307, and MC 312 
cargo tanks marked or certified after December 30, 1990, and DOT 406, 
DOT 407, and DOT 412 cargo tank motor vehicles must be equipped with 
manhole assemblies conforming with Sec.  178.345-5 of this subchapter.
    (2) On or before August 31, 1995, each owner of a cargo tank marked 
or certified before December 31, 1990, authorized for the transportation 
of a hazardous material, must have the cargo tank equipped with manhole 
assemblies conforming with Sec.  178.345-5, except for the dimensional 
requirements in Sec.  178.345-5(a), the hydrostatic testing requirements 
in Sec.  178.345-5(b), and the marking requirements in Sec.  178.345-
5(e) of this subchapter. A manhole assembly meeting one of the following 
provisions is considered to be in compliance with this paragraph:
    (i) Manhole assemblies on MC 300, MC 301, MC 302, MC 303, MC 305, MC 
306, MC 310, MC 311, and MC 312 cargo tanks that are marked or certified 
in writing as conforming to Sec.  178.345-5 of this subchapter or TTMA 
RP No. 61-98 (incorporated by reference; see Sec.  171.7 of this 
subchapter), or are tested and certified in accordance with TTMA TB No. 
107 (incorporated by reference; see Sec.  171.7 of this subchapter).
    (ii) Manhole assemblies on MC 304 and MC 307 cargo tanks.
    (iii) Manhole assemblies on MC 310, MC 311, and MC 312 cargo tanks 
with a test pressure of 36 psig or greater.
    (3) [Reserved]
    (h) Pressure relief system. Properly functioning reclosing pressure 
relief valves and frangible or fusible vents need not be replaced. 
However, replacement of reclosing pressure relief valves on MC-
specification cargo tanks is authorized subject to the following 
requirements:

[[Page 355]]

    (1) Until August 31, 1998, the owner of a cargo tank may replace a 
reclosing pressure relief device with a device which is in compliance 
with the requirements for pressure relief devices in effect at the time 
the cargo tank specification became superseded. If the pressure relief 
device is installed as an integral part of a manhole cover assembly, the 
manhole cover must comply with the requirements of paragraph (g) of this 
section.
    (2) After August 31, 1998, replacement for any reclosing pressure 
relief valve must be capable of reseating to a leak-tight condition 
after a pressure surge, and the volume of lading released may not exceed 
1 L. Specific performance requirements for these pressure relief valves 
are set forth in Sec.  178.345-10(b)(3) of this subchapter.
    (3) As provided in paragraph (c)(2) of this section, the owner of a 
cargo tank may elect to modify reclosing pressure relief devices to more 
recent cargo tank specifications. However, replacement devices 
constructed to the requirements of Sec.  178.345-10 of this subchapter 
must provide the minimum venting capacity required by the original 
specification to which the cargo tank was designed and constructed.
    (i) Flammable cryogenic liquids. Each cargo tank used to transport a 
flammable cryogenic liquid must be examined after each shipment to 
determine its actual holding time (See Sec.  173.318(g)(3) of this 
subchapter.)
    (j) Withdrawal of certification. A specification cargo tank that for 
any reason no longer meets the applicable specification may not be used 
to transport hazardous materials unless the cargo tank is repaired and 
retested in accordance with Sec. Sec.  180.413 and 180.407 prior to 
being returned to hazardous materials service. If the cargo tank is not 
in conformance with the applicable specification requirements, the 
specification plate on the cargo tank must be removed, obliterated or 
securely covered. The details of the conditions necessitating withdrawal 
of the certification must be recorded and signed on the written 
certificate for that cargo tank. The vehicle owner shall retain the 
certificate for at least 1 year after withdrawal of the certification.
    (k) DOT-specification cargo tank with no marked design pressure or a 
marked design pressure of less than 3 psig. The owner of an MC 300, MC 
301, MC 302, MC 303, MC 305, MC 306, or MC 312 cargo tank with a 
pressure relief system set at 3 psig, must mark or remark the cargo tank 
with an MAWP or design pressure of not less than 3 psig.
    (l) MC 300, MC 301, MC 302, MC 303, MC 305, MC 306 cargo tank--Rear 
accident damage protection. (1) Notwithstanding the requirements in 
Sec.  180.405(b), the applicable specification requirement for a rear 
bumper or rear-end tank protection device on MC 300, MC 301, MC 302, MC 
303, MC 305, and MC 306 cargo tanks does not apply to a cargo tank truck 
(power unit) until July 1, 1992, if the cargo tank truck--
    (i) Was manufactured before July 1, 1989;
    (ii) Is used to transport gasoline or any other petroleum distillate 
product; and
    (iii) Is operated in combination with a cargo tank full trailer. 
However, an empty cargo tank truck, without a cargo tank full trailer 
attached, may be operated without the required rear bumper or rear-end 
tank protection device on a one-time basis while being transported to a 
repair facility for installation of a rear bumper or rear-end protection 
device.
    (2) Each cargo tank shall be provided with a rear accident damage 
protection device to protect the tank and piping in the event of a rear-
end collision and reduce the likelihood of damage which could result in 
the loss of lading. The rear-end protection device must be in the form 
of a rear-end tank protection device meeting the requirements of Sec.  
178.345-8(d) or a rear bumper meeting the following:
    (i) The bumper shall be located at least 6 inches to the rear of any 
vehicle component used for loading or unloading or that may contain 
lading while the vehicle is in transit.
    (ii) The dimensions of the bumper shall conform to Sec.  393.86 of 
this title.
    (iii) The structure of the bumper must be designed in accordance 
with Sec.  178.345-8(d)(3) of this subchapter.
    (m) Specification MC 330, MC 331 cargo tank motor vehicles, and 
nonspecification cargo tank motor vehicles conforming to

[[Page 356]]

Sec.  173.315(k) of this subchapter, intended for use in the 
transportation of liquefied compressed gases. (1) No later than the date 
of its first scheduled pressure test after July 1, 2001, each 
specification MC 330 and MC 331 cargo tank motor vehicle, and each 
nonspecification cargo tank motor vehicle conforming to Sec.  173.315(k) 
of this subchapter, marked and certified before July 1, 2001, that is 
used to transport a Division 2.1 material, a Division 2.2 material with 
a subsidiary hazard, a Division 2.3 material, or anhydrous ammonia must 
have an emergency discharge control capability as specified in Sec.  
173.315(n) of this subchapter. Each passive shut-off system installed 
prior to July 1, 2001, must be certified by a Design Certifying Engineer 
that it meets the requirements of Sec.  173.315(n)(2) of this 
subchapter.
    (2) The requirement in paragraph (m)(1) of this section does not 
apply to a cargo tank equal to or less than 13,247.5 L (3,500 gallons) 
water capacity transporting in metered delivery service a Division 2.1 
material, a Division 2.2 material with a subsidiary hazard, or anhydrous 
ammonia equipped with an off-truck remote shut-off device that was 
installed prior to July 1, 2000. The device must be capable of stopping 
the transfer of lading by operation of a transmitter carried by a 
qualified person attending unloading of the cargo tank. The device is 
subject to the requirement in Sec.  177.840(o) of this subchapter for a 
daily test at 45.72 meters (150 feet).
    (3) Each specification MC 330 and MC 331 cargo tank in metered 
delivery service of greater than 13,247.5 L (3,500 gallons) water 
capacity transporting a Division 2.1 material, a Division 2.2 material 
with a subsidiary hazard, or anhydrous ammonia, marked and certified 
before July 1, 1999, must have an emergency discharge control capability 
as specified in Sec. Sec.  173.315(n) and 177.840 of this subchapter no 
later than the date of its first scheduled pressure test after July 1, 
2001, or July 1, 2003, whichever is earlier.
    (n) Thermal activation. No later than the date of its first 
scheduled leakage test after July 1, 1999, each specification MC 330 or 
MC 331 cargo tank motor vehicle and each nonspecification cargo tank 
motor vehicle conforming to Sec.  173.315(k) of this subchapter, marked 
and certified before July 1, 1999, that is used to transport a liquefied 
compressed gas, other than carbon dioxide and chlorine, that has a water 
capacity of 13,247.5 L (3,500 gallons) or less must be equipped with a 
means of thermal activation for the internal self-closing stop valve as 
specified in Sec.  178.337-8(a)(4) of this subchapter.
    (o) On-truck remote control of self-closing stop valves--MC 330, MC 
331, and MC 338. On or before October 2, 2006--
    (1) Each owner of an MC 330 or MC 331 cargo tank motor vehicle 
marked or certified before January 1, 1995, must equip the cargo tank 
with an on-vehicle remote means of closure of the internal self-closing 
stop valve in conformance with Sec.  178.337-8(a)(4) of this subchapter. 
This requirement does not apply to cargo tanks used only for carbon 
dioxide and marked ``For carbon dioxide only'' or intended for use in 
chlorine service only.
    (2) Each owner of an MC 338 cargo tank motor vehicle marked or 
certified before January 1, 1995, must equip each remotely controlled 
shutoff valve with an on-vehicle remote means of automatic closure in 
conformance with Sec.  178.338-11(c) of this subchapter. This 
requirement does not apply to cargo tanks used for the transportation of 
argon, carbon dioxide, helium, krypton, neon, nitrogen, or xenon, or 
mixtures thereof.

[Amdt. 180-2, 54 FR 25032, June 12, 1989]

    Editorial Note: For Federal Register citations affecting Sec.  
180.405, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.govinfo.gov.



Sec.  180.407  Requirements for test and inspection of specification cargo 
tanks.

    (a) General. (1) A cargo tank constructed in accordance with a DOT 
specification for which a test or inspection specified in this section 
has become due, may not be filled and offered for transportation or 
transported until the test or inspection has been successfully 
completed. This paragraph does not apply to any cargo tank filled prior 
to the test or inspection due date.

[[Page 357]]

    (2) Except during a pressure test, a cargo tank may not be subjected 
to a pressure greater than its design pressure or MAWP.
    (3) A person witnessing or performing a test or inspection specified 
in this section must meet the minimum qualifications prescribed in Sec.  
180.409.
    (4) Each cargo tank must be evaluated in accordance with the 
acceptable results of tests and inspections prescribed in Sec.  180.411.
    (5) Each cargo tank which has successfully passed a test or 
inspection specified in this section must be marked in accordance with 
Sec.  180.415.
    (6) A cargo tank which fails a prescribed test or inspection must:
    (i) Be repaired and retested in accordance with Sec.  180.413; or
    (ii) Be removed from hazardous materials service and the 
specification plate removed, obliterated or covered in a secure manner.
    (b) Conditions requiring test and inspection of cargo tanks. Without 
regard to any other test or inspection requirements, a specification 
cargo tank must be tested and inspected in accordance with this section 
prior to further use if:
    (1) The cargo tank shows evidence of dents, cuts, gouges, corroded 
or abraded areas, leakage, or any other condition that might render it 
unsafe for hazardous materials service. At a minimum, any area of a 
cargo tank showing evidence of dents, cuts, digs, gouges, or corroded or 
abraded areas must be thickness tested in accordance with the procedures 
set forth in paragraphs (i)(2), (i)(3), (i)(5), (i)(6), (i)(9), and 
(i)(10) of this section and evaluated in accordance with the criteria 
prescribed in Sec.  180.411. Any signs of leakage must be repaired in 
accordance with Sec.  180.413. The suitability of any repair affecting 
the structural integrity of the cargo tank must be determined either by 
the testing required in the applicable manufacturing specification or in 
paragraph (g)(1)(iv) of this section.
    (2) The cargo tank has sustained damage to an extent that may 
adversely affect its lading retention capability. A damaged cargo tank 
must be pressure tested in accordance with the procedures set forth in 
paragraph (g) of this section.
    (3) The cargo tank has been out of hazardous materials 
transportation service for a period of one year or more. Each cargo tank 
that has been out of hazardous materials transportation service for a 
period of one year or more must be pressure tested in accordance with 
Sec.  180.407(g) prior to further use.
    (4) [Reserved]
    (5) The Department so requires based on the existence of probable 
cause that the cargo tank is in an unsafe operating condition.
    (c) Periodic test and inspection. Each specification cargo tank must 
be tested and inspected as specified in the following table by an 
inspector meeting the qualifications in Sec.  180.409. The retest date 
shall be determined from the specified interval identified in the 
following table from the most recent inspection or the CTMV 
certification date.

     Compliance Dates--Inspections and Test Under Sec.   180.407(c)
------------------------------------------------------------------------
                                         Date by which
   Test or inspection (cargo tank     first test must be     Interval
  specification, configuration, and     completed (see     period after
              service)                      Note 1)         first test
------------------------------------------------------------------------
External Visual Inspection:
    All cargo tanks designed to be    September 1, 1991.  6 months.
     loaded by vacuum with full
     opening rear heads.
    All other cargo tanks...........  September 1, 1991.  1 year.
Internal Visual Inspection:
    All insulated cargo tanks,        September 1, 1991.  1 year.
     except MC 330, MC 331, MC 338
     (see Note 4).
    All cargo tanks transporting      September 1, 1991.  1 year.
     lading corrosive to the tank.
    MC 331 cargo tanks less than      ..................  10 years.
     3,500 gallons water capacity in
     dedicated propane service
     constructed of nonquenched and
     tempered NQT SA-612 steel (see
     Note 5).
    All other cargo tanks, except MC  September 1, 1995.  5 years.
     338.
Lining Inspection:
    All lined cargo tanks             September 1, 1991.  1 year.
     transporting lading corrosive
     to the tank.
Leakage Test:
    MC 330 and MC 331 cargo tanks in  September 1, 1991.  2 years.
     chlorine service.

[[Page 358]]

 
    All other cargo tanks except MC   September 1, 1991.  1 year.
     338.
Pressure Test:
    (Hydrostatic or pneumatic) (See
     Notes 2 and 3).
    All cargo tanks which are         September 1, 1991.  1 year.
     insulated with no manhole or
     insulated and lined, except MC
     338.
    All cargo tanks designed to be    September 1, 1992.  2 years.
     loaded by vacuum with full
     opening rear heads.
    MC 330 and MC 331 cargo tanks in  September 1, 1992.  2 years.
     chlorine service.
    MC 331 cargo tanks less than                          10 years.
     3,500 gallons water capacity in
     dedicated propane service
     constructed of nonquenched and
     tempered NQT SA-612 steel (See
     Note 5).
    All other cargo tanks...........  September 1, 1995.  5 years.
Thickness Test:
    All unlined cargo tanks           September 1, 1992.  2 years.
     transporting material corrosive
     to the tank, except MC 338.
------------------------------------------------------------------------
Note 1: If a cargo tank is subject to an applicable inspection or test
  requirement under the regulations in effect on December 30, 1990, and
  the due date (as specified by a requirement in effect on December 30,
  1990) for completing the required inspection or test occurs before the
  compliance date listed in table I, the earlier date applies.
Note 2: Pressure testing is not required for MC 330 or MC 331 cargo
  tanks in dedicated sodium metal service.
Note 3: Pressure testing is not required for uninsulated lined cargo
  tanks, with a design pressure MAWP 15 psig or less, which receive an
  external visual inspection and lining inspection at least once each
  year.
Note 4: Insulated cargo tanks equipped with manholes or inspection
  openings may perform either an internal visual inspection in
  conjunction with the external visual inspection or a hydrostatic or
  pneumatic pressure-test of the cargo tank.
Note 5: A 10-year inspection interval period also applies to cargo tanks
  constructed of NQT SA-202 or NQT SA-455 steel provided the materials
  have full-size equivalent (FSE) Charpy vee notch (CVN) energy test
  data that demonstrated 75% shear-area ductility at 32[emsp14] [deg]F
  with an average of 3 or more samples 15 ft-lb FSE with no
  sample <10 ft-lb FSE.

    (d) External visual inspection and testing. The following applies to 
the external visual inspection and testing of cargo tanks:
    (1) Where insulation precludes a complete external visual inspection 
as required by paragraphs (d)(2) through (d)(6) of this section, the 
cargo tank also must be given an internal visual inspection in 
accordance with paragraph (e) of this section. If external visual 
inspection is precluded because any part of the cargo tank wall is 
externally lined, coated, or designed to prevent an external visual 
inspection, those areas of the cargo tank must be internally inspected. 
If internal visual inspection is precluded because the cargo tank is 
lined, coated, or designed so as to prevent access for internal 
inspection, the tank must be hydrostatically or pneumatically tested in 
accordance with paragraph (g)(1)(iv) of this section. Those items able 
to be externally inspected must be externally inspected and noted in the 
inspection report.
    (2) The external visual inspection and testing must include as a 
minimum the following:
    (i) The tank shell and heads must be inspected for corroded or 
abraded areas, dents, distortions, defects in welds and any other 
conditions, including leakage, that might render the tank unsafe for 
transportation service;
    (ii) The piping, valves, and gaskets must be carefully inspected for 
corroded areas, defects in welds, and other conditions, including 
leakage, that might render the tank unsafe for transportation service;
    (iii) All devices for tightening manhole covers must be operative 
and there must be no evidence of leakage at manhole covers or gaskets;
    (iv) All emergency devices and valves including self-closing stop 
valves, excess flow valves and remote closure devices must be free from 
corrosion, distortion, erosion and any external damage that will prevent 
safe operation. Remote closure devices and self-closing stop valves must 
be functioned to demonstrate proper operation;
    (v) Missing bolts, nuts and fusible links or elements must be 
replaced, and loose bolts and nuts must be tightened;
    (vi) All markings on the cargo tank required by parts 172, 178 and 
180 of this subchapter must be legible;
    (vii) [Reserved]
    (viii) All major appurtenances and structural attachments on the 
cargo

[[Page 359]]

tank including, but not limited to, suspension system attachments, 
connecting structures, and those elements of the upper coupler (fifth 
wheel) assembly that can be inspected without dismantling the upper 
coupler (fifth wheel) assembly must be inspected for any corrosion or 
damage which might prevent safe operation;
    (ix) For cargo tanks transporting lading corrosive to the tank, 
areas covered by the upper coupler (fifth wheel) assembly must be 
inspected at least once in each two year period for corroded and abraded 
areas, dents, distortions, defects in welds, and any other condition 
that might render the tank unsafe for transportation service. The upper 
coupler (fifth wheel) assembly must be removed from the cargo tank for 
this inspection.
    (3) All reclosing pressure relief valves must be externally 
inspected for any corrosion or damage which might prevent safe 
operation. All reclosing pressure relief valves on cargo tanks carrying 
lading corrosive to the valve must be removed from the cargo tank for 
inspection and testing. Each reclosing pressure relief valve required to 
be removed and tested must be tested according to the requirements set 
forth in paragraph (j) of this section.
    (4) Ring stiffeners or other appurtenances, installed on cargo tanks 
constructed of mild steel or high-strength, low-alloy steel, that create 
air cavities adjacent to the tank shell that do not allow for external 
visual inspection must be thickness tested in accordance with paragraphs 
(i)(2) and (i)(3) of this section, at least once every 2 years. At least 
four symmetrically distributed readings must be taken to establish an 
average thickness for the ring stiffener or appurtenance. If any 
thickness reading is less than the average thickness by more than 10%, 
thickness testing in accordance with paragraphs (i)(2) and (i)(3) of 
this section must be conducted from the inside of the cargo tank on the 
area of the tank wall covered by the appurtenance or ring stiffener.
    (5) Corroded or abraded areas of the cargo tank wall must be 
thickness tested in accordance with the procedures set forth in 
paragraphs (i)(2), (i)(3), (i)(5), (i)(6), (i)(9), and (i)(10) of this 
section.
    (6) The gaskets on any full opening rear head must be:
    (i) Visually inspected for cracks or splits caused by weather or 
wear; and
    (ii) Replaced if cuts or cracks which are likely to cause leakage, 
or are of a depth one-half inch or more, are found.
    (7) The inspector must record the results of the external visual 
examination as specified in Sec.  180.417(b).
    (e) Internal visual inspection. (1) When the cargo tank is not 
equipped with a manhole or inspection opening, or the cargo tank design 
precludes an internal inspection, the tank shall be hydrostatically or 
pneumatically tested in accordance with 180.407(c) and (g).
    (2) The internal visual inspection must include as a minimum the 
following:
    (i) The tank shell and heads must be inspected for corroded and 
abraded areas, dents, distortions, defects in welds, and any other 
condition that might render the tank unsafe for transportation service.
    (ii) Tank liners must be inspected as specified in Sec.  180.407(f).
    (3) Corroded or abraded areas of the cargo tank wall must be 
thickness tested in accordance with paragraphs (i)(2), (i)(3), (i)(5), 
(i)(6), (i)(9), and (i)(10) of this section.
    (4) The inspector must record the results of the internal visual 
inspection as specified in Sec.  180.417(b).
    (f) Lining inspection. The integrity of the lining on all lined 
cargo tanks, when lining is required by this subchapter, must be 
verified at least once each year as follows:
    (1) Rubber (elastomeric) lining must be tested for holes as follows:
    (i) Equipment must consist of:
    (A) A high frequency spark tester capable of producing sufficient 
voltage to ensure proper calibration;
    (B) A probe with an ``L'' shaped 2.4 mm (0.09 inch) diameter wire 
with up to a 30.5 cm (12-inch) bottom leg (end bent to a 12.7 mm (0.5 
inch) radius), or equally sensitive probe; and
    (C) A steel calibration coupon 30.5 cm x 30.5 cm (12 inches x 12 
inches) covered with the same material and thickness as that to be 
tested. The material on the coupon shall have a test hole to the metal 
substrate made by puncturing

[[Page 360]]

the material with a 22 gauge hypodermic needle or comparable piercing 
tool.
    (ii) The probe must be passed over the surface of the calibration 
coupon in a constant uninterrupted manner until the hole is found. The 
hole is detected by the white or light blue spark formed. (A sound 
lining causes a dark blue or purple spark.) The voltage must be adjusted 
to the lowest setting that will produce a minimum 12.7 mm (0.5 inch) 
spark measured from the top of the lining to the probe. To assure that 
the setting on the probe has not changed, the spark tester must be 
calibrated periodically using the test calibration coupon, and the same 
power source, probe, and cable length.
    (iii) After calibration, the probe must be passed over the lining in 
an uninterrupted stroke.
    (iv) Holes that are found must be repaired using equipment and 
procedures prescribed by the lining manufacturer or lining installer.
    (2) Linings made of other than rubber (elastomeric material) must be 
tested using equipment and procedures prescribed by the lining 
manufacturer or lining installer.
    (3) Degraded or defective areas of the cargo tank liner must be 
removed and the cargo tank wall below the defect must be inspected. 
Corroded areas of the tank wall must be thickness tested in accordance 
with paragraphs (i)(2), (i)(3), (i)(5) and (i)(6) of this section.
    (4) The inspector must record the results of the lining inspection 
as specified in Sec.  180.417(b).
    (g) Pressure test. All components of the cargo tank wall, as defined 
in Sec.  178.320(a) of this subchapter, must be pressure tested as 
prescribed by this paragraph.
    (1) Test Procedure--(i) As part of the pressure test, the inspector 
must perform an external and internal visual inspection, except that on 
an MC 338 cargo tank, or a cargo tank not equipped with a manhole or 
inspection opening, an internal inspection is not required.
    (ii) All self-closing pressure relief valves, including emergency 
relief vents and normal vents, must be removed from the cargo tank for 
inspection and testing according to the requirements in paragraph (j) of 
this section.
    (iii) Except for cargo tanks carrying lading corrosive to the tank, 
areas covered by the upper coupler (fifth wheel) assembly must be 
inspected for corroded and abraded areas, dents, distortions, defects in 
welds, and any other condition that might render the tank unsafe for 
transportation service. The upper coupler (fifth wheel) assembly must be 
removed from the cargo tank for this inspection.
    (iv) Each cargo tank must be tested hydrostatically or pneumatically 
to the internal pressure specified in the following table. At no time 
during the pressure test may a cargo tank be subject to pressures that 
exceed those identified in the following table:

                     Table 1 to Paragraph (g)(1)(iv)
------------------------------------------------------------------------
           Specification                        Test pressure
------------------------------------------------------------------------
MC 300, 301, 302, 303, 305, 306...  The test pressure on the name plate
                                     or specification plate, 20.7 kPa (3
                                     psig) or design pressure, whichever
                                     is greater.
MC 304, 307.......................  The test pressure on the name plate
                                     or specification plate, 275.8 kPa
                                     (40 psig) or 1.5 times the design
                                     pressure, whichever is greater.
MC 310, 311, 312..................  The test pressure on the name plate
                                     or specification plate, 20.7 kPa (3
                                     psig) or 1.5 times the design
                                     pressure, whichever is greater.
MC 330, 331.......................  The test pressure on the name plate
                                     or specification plate, 1.5 times
                                     either the MAWP or the re-rated
                                     pressure, whichever is applicable.
MC 338............................  The test pressure on the name plate
                                     or specification plate, 1.25 times
                                     either the MAWP or the re-rated
                                     pressure, whichever is applicable.
DOT 406...........................  The test pressure on the name plate
                                     or specification plate, 34.5 kPa (5
                                     psig) or 1.5 times the MAWP,
                                     whichever is greater.
DOT 407...........................  The test pressure on the name plate
                                     or specification plate, 275.8 kPa
                                     (40 psig) or 1.5 times the MAWP,
                                     whichever is greater.
DOT 412...........................  The test pressure on the name plate
                                     or specification plate, or 1.5
                                     times the MAWP, whichever is
                                     greater.
------------------------------------------------------------------------


[[Page 361]]

    (v) [Reserved]
    (vi) Each cargo tank of a multi-tank cargo tank motor vehicle must 
be tested with the adjacent cargo tanks empty and at atmospheric 
pressure.
    (vii) All closures except pressure relief devices must be in place 
during the test. All prescribed loading and unloading venting devices 
rated at less than test pressure may be removed during the test. If 
retained, the devices must be rendered inoperative by clamps, plugs, or 
other equally effective restraining devices. Restraining devices may not 
prevent detection of leaks or damage the venting devices and must be 
removed immediately after the test is completed.
    (viii) Hydrostatic test method. Each cargo tank, including its 
domes, must be filled with water or other liquid having similar 
viscosity, at a temperature not exceeding 100 [deg]F. The cargo tank 
must then be pressurized to not less than the pressure specified in 
paragraph (g)(1)(iv) of this section. The cargo tank, including its 
closures, must hold the prescribed test pressure for at least 10 minutes 
during which time it shall be inspected for leakage, bulging or any 
other defect.
    (ix) Pneumatic test method. Pneumatic testing may involve higher 
risk than hydrostatic testing. Therefore, suitable safeguards must be 
provided to protect personnel and facilities should failure occur during 
the test. The cargo tank must be pressurized with air or an inert gas. 
The pneumatic test pressure in the cargo tank must be reached by 
gradually increasing the pressure to one-half of the test pressure. 
Thereafter, the pressure must be increased in steps of approximately 
one-tenth of the test pressure until the required test pressure has been 
reached. The test pressure must be held for at least 5 minutes. The 
pressure must then be reduced to the MAWP, which must be maintained 
during the time the entire cargo tank surface is inspected. During the 
inspection, a suitable method must be used for detecting the existence 
of leaks. This method must consist either of coating the entire surface 
of all joints under pressure with a solution of soap and water, or using 
other equally sensitive methods.
    (2) When testing an insulated cargo tank, the insulation and 
jacketing need not be removed unless it is otherwise impossible to reach 
test pressure and maintain a condition of pressure equilibrium after 
test pressure is reached, or the vacuum integrity cannot be maintained 
in the insulation space. If an MC 338 cargo tank used for the 
transportation of a flammable gas or oxygen, refrigerated liquid is 
opened for any reason, the cleanliness must be verified prior to closure 
using the procedures contained in Sec.  178.338-15 of this subchapter.
    (3) Each MC 330 and MC 331 cargo tank constructed of quenched and 
tempered steel in accordance with Part UHT in Section VIII of the ASME 
Code (IBR, see Sec.  171.7 of this subchapter), or constructed of other 
than quenched and tempered steel but without postweld heat treatment, 
used for the transportation of anhydrous ammonia or any other hazardous 
materials that may cause corrosion stress cracking, must be internally 
inspected by the wet fluorescent magnetic particle method immediately 
prior to and in conjunction with the performance of the pressure test 
prescribed in this section. Each MC 330 and MC 331 cargo tank 
constructed of quenched and tempered steel in accordance with Part UHT 
in Section VIII of the ASME Code and used for the transportation of 
liquefied petroleum gas must be internally inspected by the wet 
fluorescent magnetic particle method immediately prior to and in 
conjunction with the performance of the pressure test prescribed in this 
section. The wet fluorescent magnetic particle inspection must be in 
accordance with Section V of the ASME Code and CGA Technical Bulletin 
TB-2 (IBR, see Sec.  171.7 of this subchapter). This paragraph does not 
apply to cargo tanks that do not have manholes. (See Sec.  180.417(c) 
for reporting requirements.)
    (4) All pressure bearing portions of a cargo tank heating system 
employing a medium such as, but not limited to, steam or hot water for 
heating the lading must be hydrostatically pressure tested at least once 
every 5 years. The test pressure must be at least the maximum system 
design operating pressure

[[Page 362]]

and must be maintained for five minutes. A heating system employing 
flues for heating the lading must be tested to ensure against lading 
leakage into the flues or into the atmosphere.
    (5) Exceptions. (i) Pressure testing is not required for MC 330 and 
MC 331 cargo tanks in dedicated sodium metal service.
    (ii) Pressure testing is not required for uninsulated lined cargo 
tanks, with a design pressure or MAWP of 15 psig or less, which receive 
an external visual inspection and a lining inspection at least once each 
year.
    (6) Acceptance criteria. A cargo tank that leaks, fails to retain 
test pressure or pneumatic inspection pressure, shows distortion, 
excessive permanent expansion, or other evidence of weakness that might 
render the cargo tank unsafe for transportation service, may not be 
returned to service, except as follows: A cargo tank with a heating 
system which does not hold pressure may remain in service as an unheated 
cargo tank if:
    (i) The heating system remains in place and is structurally sound 
and no lading may leak into the heating system, and
    (ii) The specification plate heating system information is changed 
to indicate that the cargo tank has no working heating system.
    (7) The inspector must record the results of the pressure test as 
specified in Sec.  180.417(b).
    (h) Leakage test. The following requirements apply to cargo tanks 
requiring a leakage test:
    (1) Each cargo tank must be tested for leaks in accordance with 
paragraph (c) of this section. The leakage test must include testing 
product piping with all valves and accessories in place and operative, 
except that any venting devices set to discharge at less than the 
leakage test pressure must be removed or rendered inoperative during the 
test. All internal or external self-closing stop valves must be tested 
for leak tightness. Each cargo tank of a multi-cargo tank motor vehicle 
must be tested with adjacent cargo tanks empty and at atmospheric 
pressure. Test pressure must be maintained for at least 5 minutes. Cargo 
tanks in liquefied compressed gas service must be externally inspected 
for leaks during the leakage test. Suitable safeguards must be provided 
to protect personnel should a failure occur. Cargo tanks may be leakage 
tested with hazardous materials contained in the cargo tank during the 
test. Leakage test pressure must be no less than 80% of MAWP marked on 
the specification plate except as follows:
    (i) A cargo tank with an MAWP of 690 kPa (100 psig) or more may be 
leakage tested at its maximum normal operating pressure provided it is 
in dedicated service or services; or
    (ii) An MC 330 or MC 331 cargo tank in dedicated liquified petroleum 
gas service may be leakage tested at not less than 414 kPa (60 psig).
    (iii) An operator of a specification MC 330 or MC 331 cargo tank, 
and a nonspecification cargo tank authorized under Sec.  173.315(k) of 
this subchapter, equipped with a meter may check leak tightness of the 
internal self-closing stop valve by conducting a meter creep test. (See 
appendix B to this part.)
    (iv) An MC 330 or MC 331 cargo tank in dedicated service for 
anhydrous ammonia may be leakage tested at not less than 414 kPa (60 
psig).
    (v) A non-specification cargo tank required by Sec.  173.8(d) of 
this subchapter to be leakage tested, must be leakage tested at not less 
than 16.6 kPa (2.4 psig), or as specified in paragraph (h)(2) of this 
section.
    (2) Cargo tanks used to transport petroleum distillate fuels that 
are equipped with vapor collection equipment may be leak tested in 
accordance with the Environmental Protection Agency's ``Method 27--
Determination of Vapor Tightness of Gasoline Delivery Tank Using 
Pressure-Vacuum Test,'' as set forth in Appendix A to 40 CFR part 60. 
Test methods and procedures and maximum allowable pressure and vacuum 
changes are in 40 CFR 63.425(e). The hydrostatic test alternative, using 
liquid in Environmental Protection Agency's ``Method 27--Determination 
of Vapor Tightness of Gasoline Delivery Tank Using Pressure-Vacuum 
Test,'' may not be used to satisfy the leak testing requirements of this 
paragraph. The test must be conducted using air.

[[Page 363]]

    (3) A cargo tank that fails to retain leakage test pressure may not 
be returned to service as a specification cargo tank, except under 
conditions specified in Sec.  180.411(d).
    (4) After July 1, 2000, Registered Inspectors of specification MC 
330 and MC 331 cargo tanks, and nonspecification cargo tanks authorized 
under Sec.  173.315(k) of this subchapter must visually inspect the 
delivery hose assembly and piping system while the assembly is under 
leakage test pressure utilizing the rejection criteria listed in Sec.  
180.416(g). Delivery hose assemblies not permanently attached to the 
cargo tank motor vehicle may be inspected separately from the cargo tank 
motor vehicle. In addition to a written record of the inspection 
prepared in accordance with Sec.  180.417(b), the Registered Inspector 
conducting the test must note the hose identification number, the date 
of the test, and the condition of the hose assembly and piping system 
tested.
    (5) The inspector must record the results of the leakage test as 
specified in Sec.  180.417(b).
    (i) Thickness testing. (1) The shell and head thickness of all 
unlined cargo tanks used for the transportation of materials corrosive 
to the tank must be measured at least once every 2 years, except that 
cargo tanks measuring less than the sum of the minimum prescribed 
thickness, plus one-fifth of the original corrosion allowance, must be 
tested annually.
    (2) Measurements must be made using a device capable of accurately 
measuring thickness to within 0.002 of an inch.
    (3) Any person performing thickness testing must be trained in the 
proper use of the thickness testing device used in accordance with the 
manufacturer's instruction.
    (4) Thickness testing must be performed in the following areas of 
the cargo tank wall, as a minimum:
    (i) Areas of the tank shell and heads and shell and head area around 
any piping that retains lading;
    (ii) Areas of high shell stress such as the bottom center of the 
tank;
    (iii) Areas near openings;
    (iv) Areas around weld joints;
    (v) Areas around shell reinforcements;
    (vi) Areas around appurtenance attachments;
    (vii) Areas near upper coupler (fifth wheel) assembly attachments;
    (viii) Areas near suspension system attachments and connecting 
structures;
    (ix) Known thin areas in the tank shell and nominal liquid level 
lines; and
    (x) Connecting structures joining multiple cargo tanks of carbon 
steel in a self-supporting cargo tank motor vehicle.
    (5) Minimum thicknesses for MC 300, MC 301, MC 302, MC 303, MC 304, 
MC 305, MC 306, MC 307, MC 310, MC 311, and MC 312 cargo tanks are 
determined based on the definition of minimum thickness found in Sec.  
178.320(a) of this subchapter. The following Tables I and II identify 
the ``In-Service Minimum Thickness'' values to be used to determine the 
minimum thickness for the referenced cargo tanks. The column headed 
``Minimum Manufactured Thickness'' indicates the minimum values required 
for new construction of DOT 400 series cargo tanks, found in Tables I 
and II of Sec. Sec.  178.346-2, 178.347-2, and 178.348-2 of this 
subchapter. In-Service Minimum Thicknesses for MC 300, MC 301, MC 302, 
MC 303, MC 304, MC 305, MC 306, MC 307, MC 310, MC 311, and MC 312 cargo 
tanks are based on 90 percent of the manufactured thickness specified in 
the DOT specification, rounded to three places.

  Table I--In-Service Minimum Thickness for MC 300, MC 303, MC 304, MC
    306, MC 307, MC 310, MC 311, and MC 312 Specification Cargo Tanks
                  Constructed of Steel and Steel Alloys
------------------------------------------------------------------------
                                                                  In-
                                                     Nominal    service
   Minimum manufactured thickness (US gauge or       decimal    minimum
                     inches)                       equivalent  thickness
                                                       for     reference
                                                    (inches)    (inches)
------------------------------------------------------------------------
19...............................................      0.0418      0.038
18...............................................      0.0478      0.043
17...............................................      0.0538      0.048
16...............................................      0.0598      0.054
15...............................................      0.0673      0.061
14...............................................      0.0747      0.067
13...............................................      0.0897      0.081
12...............................................      0.1046      0.094
11...............................................      0.1196      0.108
10...............................................      0.1345      0.121
9................................................      0.1495      0.135

[[Page 364]]

 
8................................................      0.1644      0.148
7................................................      0.1793      0.161
3/16.............................................      0.1875      0.169
1/4..............................................      0.2500      0.225
5/16.............................................      0.3125      0.281
3/8..............................................      0.3750      0.338
------------------------------------------------------------------------


  Table II--In-Service Minimum Thickness for MC 301, MC 302, MC 304, MC
    305, MC 306, MC 307, MC 311, and MC 312 Specification Cargo Tanks
               Constructed of Aluminum and Aluminum Alloys
------------------------------------------------------------------------
                                                                  In-
                                                                service
                Minimum manufactured thickness                  minimum
                                                               thickness
                                                                (inches)
------------------------------------------------------------------------
0.078........................................................      0.070
0.087........................................................      0.078
0.096........................................................      0.086
0.109........................................................      0.098
0.130........................................................      0.117
0.141........................................................      0.127
0.151........................................................      0.136
0.172........................................................      0.155
0.173........................................................      0.156
0.194........................................................      0.175
0.216........................................................      0.194
0.237........................................................      0.213
0.270........................................................      0.243
0.360........................................................      0.324
0.450........................................................      0.405
0.540........................................................      0.486
------------------------------------------------------------------------

    (6) An owner of a cargo tank that no longer conforms to the minimum 
thickness prescribed for the design as manufactured may use the cargo 
tank to transport authorized materials at reduced maximum weight of 
lading or reduced maximum working pressure, or combinations thereof, 
provided the following conditions are met:
    (i) A Design Certifying Engineer must certify that the cargo tank 
design and thickness are appropriate for the reduced loading conditions 
by issuance of a revised manufacturer's certificate, and
    (ii) The cargo tank motor vehicle's nameplate must reflect the 
revised service limits.
    (7) An owner of a cargo tank that no longer conforms with the 
minimum thickness prescribed for the specification may not return the 
cargo tank to hazardous materials service. The tank's specification 
plate must be removed, obliterated or covered in a secure manner.
    (8) The inspector must record the results of the thickness test as 
specified in Sec.  180.417(b).
    (9) For MC 331 cargo tanks constructed before October 1, 2003, 
minimum thickness shall be determined by the thickness indicated on the 
U1A form minus any corrosion allowance. For MC 331 cargo tanks 
constructed after October 1, 2003, the minimum thickness will be the 
value indicated on the specification plate. If no corrosion allowance is 
indicated on the U1A form then the thickness of the tank shall be the 
thickness of the material of construction indicated on the UIA form with 
no corrosion allowance.
    (10) For 400-series cargo tanks, minimum thickness is calculated 
according to tables in each applicable section of this subchapter for 
that specification: Sec.  178.346-2 for DOT 406 cargo tanks, Sec.  
178.347-2 for DOT 407 cargo tanks, and Sec.  178.348-2 for DOT 412 cargo 
tanks.
    (j) Pressure vent bench test. When required by this section, 
pressure relief valves must be tested for proper function as follows:
    (1) Each self-closing pressure relief valve must open and reseat to 
a leaktight condition at the pressures prescribed for the applicable 
cargo tank specification or at the following pressures:
    (i) For MC 306 cargo tanks:
    (A) With MC 306 reclosing pressure relief valves, it must open at 
not less than 3 psi and not more than 4.4 psi and must reseat to a leak 
tight-condition at no less than 2.7 psi.
    (B) With reclosing pressure relief valves modified as provided in 
Sec.  180.405(c) to conform with DOT 406 specifications, according to 
the pressures set forth for a DOT 406 cargo tank in Sec.  178.346-3 of 
this subchapter.
    (ii) For MC 307 cargo tanks:
    (A) With MC 307 reclosing pressure relief valves, it must open at 
not less than the cargo tank MAWP and not more than 110% of the cargo 
tank MAWP and must reseat to a leak tight-

[[Page 365]]

condition at no less than 90% of the cargo tank MAWP.
    (B) With reclosing pressure relief valves modified as provided in 
Sec.  180.405(c) to conform with DOT 407 specifications, according to 
the pressures set forth for a DOT 407 cargo tank in Sec.  178.347-4 of 
this subchapter.
    (iii) For MC 312 cargo tanks:
    (A) With MC 312 reclosing pressure relief valves, it must open at 
not less than the cargo tank MAWP and not more than 110% of the cargo 
tank MAWP and must reseat to a leak tight-condition at no less than 90% 
of the cargo tank MAWP.
    (B) With reclosing pressure relief valves modified as provided in 
Sec.  180.405(c) to conform with DOT 412 specifications, according to 
the pressures set forth for a DOT 412 cargo tank in Sec.  178.348-4 of 
this subchapter.
    (iv) For MC 330 or MC 331 cargo tanks, it must open at not less than 
the required set pressure and not more than 110% of the required set 
pressure and must reseat to a leak-tight condition at no less than 90% 
of the required set pressure.
    (v) For DOT 400-series cargo tanks, according to the pressures set 
forth for the applicable cargo tank specification in Sec. Sec.  178.346-
3, 178.347-4, and 178.348-4, respectively, of this subchapter.
    (vi) For cargo tanks not specified in this paragraph, it must open 
at not less than the required set pressure and not more than 110% of the 
required set pressure and must reseat to a leak-tight condition at no 
less than 90% of the required set pressure or the pressure prescribed 
for the applicable cargo tank specification.
    (2) Normal vents (1 psig vents) must be tested according to the 
testing criteria established by the valve manufacturer.
    (3) Self-closing pressure relief devices not tested or failing the 
tests in paragraph (j)(1) of this section must be repaired or replaced.

[Amdt. 180-2, 54 FR 25032, June 12, 1989]

    Editorial Note: For Federal Register citations affecting Sec.  
180.407, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.govinfo.gov.



Sec.  180.409  Minimum qualifications for inspectors and testers.

    (a) Except as otherwise provided in this section, any person 
performing or witnessing the inspections and tests specified in Sec.  
180.407(c) must--
    (1) Be registered with the Federal Motor Carrier Safety 
Administration in accordance with part 107, subpart F of this chapter,
    (2) Be familiar with DOT-specification cargo tanks and trained and 
experienced in use of the inspection and testing equipment needed, and
    (3) Have the training and experience required to meet the definition 
of ``Registered Inspector'' in Sec.  171.8 of this chapter.
    (b) A person who only performs annual external visual inspections 
and leakage tests on a cargo tank motor vehicle, owned or operated by 
that person, with a capacity of less than 13,250 L (3,500 gallons) used 
exclusively for flammable liquid petroleum fuels, is not required to 
meet the educational and years of experience requirements set forth in 
the definition of ``Registered Inspector'' in Sec.  171.8 of this 
subchapter. Although not required to meet the educational and years of 
experience requirements, a person who performs visual inspections or 
leakage tests or signs the inspection reports must have the knowledge 
and ability to perform such inspections and tests and must perform them 
as required by this subchapter, and must register with the Department as 
required by subpart F of part 107 of this chapter.
    (c) A person who performs only annual external visual inspections 
and leakage tests on a permanently mounted non-bulk tank, owned or 
operated by that person, for petroleum products as authorized by Sec.  
173.8(c) of this subchapter, is not required to be registered in 
accordance with subpart F of part 107 of this chapter. In addition the 
person who signs the inspection report required by Sec.  180.417(b) of 
this subpart for such non-bulk tanks is not required to be registered. 
Although not required to register, a person who performs visual 
inspections or leakage tests or signs the inspection reports must have 
the knowledge and ability to perform such inspections and tests and must

[[Page 366]]

perform them as required by this subchapter.
    (d) A motor carrier or cargo tank owner who meets the requirements 
of paragraph (a) of this section may use an employee who is not a 
Registered Inspector to perform a portion of the pressure retest 
required by Sec.  180.407(g). External and internal visual inspections 
must be accomplished by a Registered Inspector, but the hydrostatic or 
pneumatic pressure test, as set forth in Sec.  180.407(g)(1)(viii) and 
(ix), respectively, may be done by an employee who is not a Registered 
Inspector provided that--
    (1) The employee is familiar with the cargo tank and is trained and 
experienced in the use of the inspection and testing equipment used;
    (2) The employer submits certification that such employee meets the 
qualification requirements to the Associate Administrator, Attn: (PHH-
32), Pipeline and Hazardous Materials Safety Administration, Department 
of Transportation, East Building, 1200 New Jersey Avenue, SE., 
Washington, DC 20590; and
    (3) The employer retains a copy of the tester's qualifications with 
the documents required by Sec.  180.417(b).

[Amdt. 180-2, 55 FR 37069, Sept. 7, 1990, as amended by Amdt. 180-3, 56 
FR 66287, Dec. 20, 1991; 57 FR 45466, Oct. 1, 1992; Amdt. 180-11, 62 FR 
1217, Jan. 8, 1997; 66 FR 45391, Aug. 28, 2001; 68 FR 19288, Apr. 18, 
2003; 70 FR 56100, Sept. 23, 2005; 72 FR 55697, Oct. 1, 2007]



Sec.  180.411  Acceptable results of tests and inspections.

    (a) Corroded or abraded areas. The minimum thickness may not be less 
than that prescribed in the applicable specification.
    (b) Dents, cuts, digs and gouges. For evaluation procedures, see CGA 
C-6 (IBR, see Sec.  171.7 of this subchapter).
    (1) For dents at welds or that include a weld, the maximum allowable 
depth is \1/2\ inch. For dents away from welds, the maximum allowable 
depth is \1/10\ of the greatest dimension of the dent, but in no case 
may the depth exceed one inch.
    (2) The minimum thickness remaining beneath a cut, dig, or gouge may 
not be less than that prescribed in the applicable specification.
    (c) Weld or structural defects. Any cargo tank with a weld defect 
such as a crack, pinhole, or incomplete fusion, or a structural defect 
must be taken out of hazardous materials service until repaired.
    (d) Leakage. All sources of leakage must be properly repaired prior 
to returning a tank to hazardous materials service.
    (e) Relief valves. Any pressure relief valve that fails to open and 
reclose at the prescribed pressure must be repaired or replaced.
    (f) Liner integrity. Any defect shown by the test must be properly 
repaired.
    (g) Pressure test. Any tank that fails to meet the acceptance 
criteria found in the individual specification that applies must be 
properly repaired.

[Amdt. 180-2, 54 FR 25032, June 12, 1989, as amended at 68 FR 75764, 
Dec. 31, 2003]



Sec.  180.413  Repair, modification, stretching, rebarrelling, or mounting 
of specification cargo tanks. 

    (a) General. Any repair, modification, stretching, rebarrelling, or 
mounting of a cargo tank must be performed in conformance with the 
requirements of this section.
    (1) Except as otherwise provided in this section, each repair, 
modification, stretching, or rebarrelling of a specification cargo tank 
must be performed by a repair facility holding a valid National Board 
Certificate of Authorization for use of the National Board ``R'' stamp 
and must be made in accordance with the edition of the National Board 
Inspection Code in effect at the time the work is performed.
    (i) Repairs, modifications, stretchings, and rebarrellings performed 
on non-ASME stamped specification cargo tanks may be performed by:
    (A) A cargo tank manufacturer holding a valid ASME Certificate of 
Authorization for the use of the ASME ``U'' stamp using the quality 
control procedures used to obtain the Certificate of Authorization; or
    (B) A repair facility holding a valid National Board Certificate of 
Authorization for use of the National Board ``R'' stamp using the 
quality control procedures used to obtain the Certificate of 
Authorization.

[[Page 367]]

    (ii) A repair, modification, stretching, or rebarrelling of a non-
ASME stamped cargo tank may be done without certification by an 
Authorized Inspector, completion of the R-1 form, or being stamped with 
the ``R'' stamp.
    (iii) A repair, as defined in Sec.  180.403, of a DOT specification 
cargo tank used for the transportation of hazardous materials in the 
United States may be performed by a facility in Canada in accordance 
with the Transport Canada TDG Regulations (IBR, see Sec.  171.7 of this 
subchapter) provided:
    (A) The facility holds a valid Certificate of Authorization from a 
provincial pressure vessel jurisdiction for repair;
    (B) The facility is registered in accordance with the Transport 
Canada TDG Regulations to repair the corresponding TC specification; and
    (C) All repairs are performed using the quality control procedures 
used to obtain the Certificate of Authorization.
    (2) Prior to each repair, modification, stretching, rebarrelling, or 
mounting, the cargo tank motor vehicle must be emptied of any hazardous 
material lading. In addition, cargo tank motor vehicles used to 
transport flammable or toxic lading must be sufficiently cleaned of 
residue and purged of vapors so any potential hazard is removed, 
including void spaces between double bulkheads, piping and vapor 
recovery systems.
    (3) Each person performing a repair, modification, stretching, 
rebarrelling or mounting of a DOT specification cargo tank must be 
registered in accordance with subpart F of part 107 of this chapter.
    (b) Repair. The suitability of each repair affecting the structural 
integrity or lading retention capability of the cargo tank must be 
determined by the testing required either in the applicable 
manufacturing specification or in Sec.  180.407(g)(1)(iv). Except for a 
repair performed by a facility in Canada in accordance with paragraph 
(a)(1)(iii) of this section, each repair of a cargo tank involving 
welding on the shell or head must be certified by a Registered 
Inspector. The following provisions apply to specific cargo tank 
repairs:
    (1) DOT 406, DOT 407, and DOT 412 cargo tanks must be repaired in 
accordance with the specification requirements in effect at the time of 
repair;
    (2) MC 300, MC 301, MC 302, MC 303, MC 305, and MC 306 cargo tanks 
must be repaired in accordance with either the most recent revision of 
the original specification or with the DOT 406 specification in effect 
at the time of repair;
    (3) MC 304 and MC 307 cargo tanks must be repaired in accordance 
with either the most recent revision of the original specification or 
with the DOT 407 specification in effect at the time of repair;
    (4) MC 310, MC 311, and MC 312 cargo tanks must be repaired in 
accordance with either the most recent revision of the original 
specification or with the DOT 412 specification in effect at the time of 
repair;
    (5) MC 338 cargo tanks must be repaired in accordance with the 
specification requirements in effect at the time of repair; and
    (6) MC 330 and MC 331 cargo tanks must be repaired in accordance 
with the repair procedures described in CGA Technical Bulletin TB-2 
(IBR, see Sec.  171.7 of this subchapter) and the National Board 
Inspection Code (IBR, see Sec.  171.7 of this subchapter). Each cargo 
tank having cracks or other defects requiring welded repairs must meet 
all inspection, test, and heat treatment requirements in Sec.  178.337-
16 of this subchapter in effect at the time of the repair, except that 
postweld heat treatment after minor weld repairs is not required. When a 
repair is made of defects revealed by the wet fluorescent magnetic 
particle inspection, including those repaired by grinding, the affected 
area of the cargo tank must again be examined by the wet fluorescent 
magnetic particle method after hydrostatic testing to assure that all 
defects have been removed.
    (c) Maintenance or replacement of piping, valves, hoses, or 
fittings. After each repair, maintenance or replacement of a pipe, 
valve, hose, or fitting on a cargo tank, that component must be 
installed in accordance with the provisions of the applicable 
specification before the cargo tank is returned to service.
    (1) After maintenance or replacement that does not involve welding 
on the

[[Page 368]]

cargo tank wall, the repaired or replaced piping, valve, hose, or 
fitting must be tested for leaks. This requirement is met when the 
piping, valve, hose, or fitting is tested after installation in 
accordance with Sec.  180.407(h)(1). A hose may be tested before or 
after installation on the cargo tank.
    (2) After repair or replacement of piping, valves, or fittings that 
involves welding on the cargo tank wall, the cargo tank must be pressure 
tested in accordance with the applicable manufacturing specification or 
Sec.  180.407(g)(1)(iv). In addition, the affected piping, valve, or 
fitting must be tested in accordance with paragraph (c)(1) of this 
section.
    (3) Hoses on cargo tanks in dedicated liquefied compressed gas, 
except carbon dioxide, service are excepted from these testing 
requirements, but must be tested in accordance with Sec.  180.416(f).
    (d) Modification, stretching, or rebarrelling. Modification, 
stretching or rebarrelling of a cargo tank motor vehicle must conform to 
the following provisions:
    (1) The design of the modified, stretched, or rebarrelled cargo tank 
motor vehicle must be certified in writing by a Design Certifying 
Engineer as meeting the structural integrity and accident damage 
protection requirements of the applicable specification.
    (2) Except as provided in paragraph (d)(2)(v) of this section, all 
new material and equipment affected by modification, stretching, or 
rebarrelling must meet the requirements of the specification in effect 
at the time such work is performed, and all applicable structural 
integrity requirements (Sec.  178.337-3, Sec.  178.338-3, or Sec.  
178.345-3 of this subchapter). The work must conform to the requirements 
of the applicable specification as follows:
    (i) For specification MC 300, MC 301, MC 302, MC 303, MC 305 and MC 
306 cargo tanks, the provisions of either specification MC 306 or DOT 
406 until August 31, 1995 and, thereafter to specification DOT 406 only;
    (ii) For specification MC 304 and MC 307 cargo tanks, the provisions 
of either specification MC 307 or DOT 407 until August 31, 1995 and, 
thereafter to specification DOT 407 only;
    (iii) For specification MC 310, MC 311, and MC 312 cargo tanks, the 
provisions of either specification MC 312 or DOT 412 until August 31, 
1995 and, thereafter to specification DOT 412 only;
    (iv) For specification MC 330 cargo tanks, the provisions of 
specification MC 331; and
    (v) For specification MC 338 cargo tanks, the provisions of 
specification MC 338. However, structural modifications to MC 338 cargo 
tanks authorized under Sec.  180.405(d) may conform to applicable 
provisions of the ASME Code instead of specification MC 338, provided 
the structural integrity of the modified cargo tank is at least 
equivalent to that of the original cargo tank.
    (3) The person performing the modification, stretching, or 
rebarrelling must:
    (i) Have knowledge of the original design concept, particularly with 
respect to structural design analysis, material and welding procedures.
    (ii) Assure compliance of the rebuilt cargo tank's structural 
integrity, venting, and accident damage protection with the applicable 
specification requirements.
    (iii) Assure compliance with all applicable Federal Motor Carrier 
Safety Regulations for all newly installed safety equipment.
    (iv) Assure the suitability of each modification, stretching and 
rebarrelling that affects the lading retention capability of the cargo 
tank by performing the tests required in the applicable specification or 
Sec.  180.407(g)(1)(iv).
    (v) Any modification that changes information displayed on the 
specification plate requires the installation of a supplemental 
specification plate, nameplate, or both containing the information that 
reflects the cargo tank as modified, stretched or rebarrelled. The plate 
must include the name of the person or facility doing the work, DOT 
registration number, date work is completed, retest information, and any 
other information that differs from the original plate. The supplemental 
plates must be installed immediately adjacent to the existing plate or 
plates.
    (vi) On a variable specification cargo tank, install a supplemental 
or new variable specification plate, and replace the specification 
listed on the

[[Page 369]]

original specification plate with the words ``see variable specification 
plate.''
    (4) A Registered Inspector must certify that the modified, 
stretched, or rebarrelled cargo tank conforms to the requirements of 
this section and the applicable specification by issuing a supplemental 
certificate of compliance. The registration number of the Registered 
Inspector must be entered on the certificate.
    (e) Mounting of cargo tanks. Mounting a cargo tank on a cargo tank 
motor vehicle must be:
    (1) Performed as required by paragraph (d)(2) of this section and 
certified by a Design Certifying Engineer if the mounting of a cargo 
tank on a motor vehicle chassis involves welding on the cargo tank head 
or shell or any change or modification of the methods of attachment; or
    (2) In accordance with the original specification for attachment to 
the chassis or the specification for attachment to the chassis in effect 
at the time of the mounting, and performed under the supervision of a 
Registered Inspector if the mounting of a cargo tank on a motor vehicle 
chassis does not involve welding on the cargo tank head or shell or a 
change or modification of the methods of attachment.
    (f) Records. Each owner of a cargo tank motor vehicle must retain at 
the owner's principal place of business all records of repair, 
modification, stretching, or rebarrelling, including notation of any 
tests conducted to verify the suitability of the repair, modification, 
stretching, or rebarrelling made to each cargo tank during the time the 
cargo tank motor vehicle is in service and for one year thereafter. 
Copies of these records must be retained by a motor carrier, if not the 
owner of the cargo tank motor vehicle, at its principal place of 
business during the period the cargo tank motor vehicle is in the 
carrier's service.

[68 FR 19288, Apr. 18, 2003; 68 FR 52372, Sept. 3, 2003, as amended at 
68 FR 75764, Dec. 31, 2003; 82 FR 15897, Mar. 30, 2017]



Sec.  180.415  Test and inspection markings.

    (a) Each cargo tank successfully completing the test and inspection 
requirements contained in Sec.  180.407 must be marked as specified in 
this section.
    (b) Each cargo tank must be durably and legibly marked, in English, 
with the date (month and year) and the type of test or inspection 
performed, subject to the following provisions:
    (1) The date must be readily identifiable with the applicable test 
or inspection.
    (2) The markings must be in letters and numbers at least 32 mm (1.25 
inches) high, near the specification plate or anywhere on the front 
head.
    (3) The type of test or inspection may be abbreviated as follows:
    (i) V for external visual inspection and test;
    (ii) I for internal visual inspection;
    (iii) P for pressure test;
    (iv) L for lining inspection;
    (v) T for thickness test; and
    (vi) K for leakage test for a cargo tank tested under Sec.  180.407, 
except Sec.  180.407(h)(2); and
    (vii) K-EPA27 for a cargo tank tested under Sec.  180.407(h)(2) 
after October 1, 2004.

    Examples to paragraph (b). The markings ``10-99 P, V, L'' represent 
that in October 1999 a cargo tank passed the prescribed pressure test, 
external visual inspection and test, and the lining inspection. The 
markings ``2-00 K-EPA27'' represent that in February 2000 a cargo tank 
passed the leakage test under Sec.  180.407(h)(2). The markings ``2-00 
K, K-EPA27'' represent that in February 2000 a cargo tank passed the 
leakage test under both Sec.  180.407(h)(1) and under EPA Method 27 in 
Sec.  180.407(h)(2).

    (c) For a cargo tank motor vehicle composed of multiple cargo tanks 
constructed to the same specification, which are tested and inspected at 
the same time, one set of test and inspection markings may be used to 
satisfy the requirements of this section. For a cargo tank motor vehicle 
composed of multiple cargo tanks constructed to different 
specifications, which are tested and inspected at different intervals, 
the test and inspection markings must appear in the order of the cargo 
tank's

[[Page 370]]

corresponding location, from front to rear.

[Amdt. 180-2, 56 FR 27879, June 17, 1991, as amended by Amdt. 180-3, 56 
FR 66287, Dec. 20, 1991; 57 FR 45466, Oct. 1, 1992; Amdt. 180-6, 59 FR 
49135, Sept. 26, 1994; Amdt. 180-10, 61 FR 51343, Oct. 1, 1996; 68 FR 
19290, Apr. 18, 2003; 68 FR 52372, Sept. 3, 2003]



Sec.  180.416  Discharge system inspection and maintenance program for 
cargo tanks transporting liquefied compressed gases. 

    (a) Applicability. This section is applicable to an operator using 
specification MC 330, MC 331, and nonspecification cargo tanks 
authorized under Sec.  173.315(k) of this subchapter for transportation 
of liquefied compressed gases other than carbon dioxide. Paragraphs (b), 
(c), (d)(1), (d)(5), (e), (f), and (g)(1) of this section, applicable to 
delivery hose assemblies, apply only to hose assemblies installed or 
carried on the cargo tank.
    (b) Hose identification. By July 1, 2000, the operator must assure 
that each delivery hose assembly is permanently marked with a unique 
identification number and maximum working pressure.
    (c) Post-delivery hose check. After each unloading, the operator 
must visually check that portion of the delivery hose assembly deployed 
during the unloading.
    (d) Monthly inspections and tests. (1) The operator must visually 
inspect each delivery hose assembly at least once each calendar month 
the delivery hose assembly is in service.
    (2) The operator must visually inspect the piping system at least 
once each calendar month the cargo tank is in service. The inspection 
must include fusible elements and all components of the piping system, 
including bolts, connections, and seals.
    (3) At least once each calendar month a cargo tank is in service, 
the operator must actuate all emergency discharge control devices 
designed to close the internal self-closing stop valve to assure that 
all linkages operate as designed. appendix A to this part outlines 
acceptable procedures that may be used for this test.
    (4) The operator of a cargo tank must check the internal self-
closing stop valve in the liquid discharge opening for leakage through 
the valve at least once each calendar month the cargo tank is in 
service. On cargo tanks equipped with a meter, the meter creep test as 
outlined in appendix B to this part or a test providing equivalent 
accuracy is acceptable. For cargo tanks that are not equipped with a 
meter, appendix B to this part outlines one acceptable method that may 
be used to check internal self-closing stop valves for closure.
    (5) The operator must note each inspection in a record. That record 
must include the inspection date, the name of the person performing the 
inspection, the hose assembly identification number, the manufacturer of 
the hose assembly, the date the hose was assembled and tested, and an 
indication that the delivery hose assembly and piping system passed or 
failed the tests and inspections. The operator must retain a copy of 
each test and inspection record at its principal place of business or 
where the vehicle is housed or maintained until the next test of the 
same type is successfully completed.
    (e) Annual hose leakage test. The owner of a delivery hose assembly 
that is not permanently attached to a cargo tank motor vehicle must 
ensure that the hose assembly is annually tested in accordance with 
Sec.  180.407(h)(4).
    (f) New or repaired delivery hose assemblies. Each operator of a 
cargo tank must ensure each new and repaired delivery hose assembly is 
tested at a minimum of 120 percent of the hose maximum working pressure.
    (1) The operator must visually examine the delivery hose assembly 
while it is under pressure.
    (2) Upon successful completion of the pressure test and inspection, 
the operator must assure that the delivery hose assembly is permanently 
marked with the month and year of the test.
    (3) After July 1, 2000, the operator must complete a record 
documenting the test and inspection, including the date, the signature 
of the inspector, the hose owner, the hose identification number, the 
date of original delivery hose assembly and test, notes of any defects 
observed and repairs made, and an indication that the delivery hose 
assembly passed or failed the tests and

[[Page 371]]

inspections. A copy of each test and inspection record must be retained 
by the operator at its principal place of business or where the vehicle 
is housed or maintained until the next test of the same type is 
successfully completed.
    (g) Rejection criteria. (1) No operator may use a delivery hose 
assembly determined to have any condition identified below for unloading 
liquefied compressed gases. An operator may remove and replace damaged 
sections or correct defects discovered. Repaired hose assemblies may be 
placed back in service if retested successfully in accordance with 
paragraph (f) of this section.
    (i) Damage to the hose cover that exposes the reinforcement.
    (ii) Wire braid reinforcement that has been kinked or flattened so 
as to permanently deform the wire braid.
    (iii) Soft spots when not under pressure, bulging under pressure, or 
loose outer covering.
    (iv) Damaged, slipping, or excessively worn hose couplings.
    (v) Loose or missing bolts or fastenings on bolted hose coupling 
assemblies.
    (2) No operator may use a cargo tank with a piping system found to 
have any condition identified in this paragraph (g)(2) for unloading 
liquefied compressed gases.
    (i) Any external leak identifiable without the use of instruments.
    (ii) Bolts that are loose, missing, or severely corroded.
    (iii) Manual stop valves that will not actuate.
    (iv) Rubber hose flexible connectors with any condition outlined in 
paragraph (g)(1) of this section.
    (v) Stainless steel flexible connectors with damaged reinforcement 
braid.
    (vi) Internal self-closing stop valves that fail to close or that 
permit leakage through the valve detectable without the use of 
instruments.
    (vii) Pipes or joints that are severely corroded.

[64 FR 28051, May 24, 1999, as amended at 78 FR 15330, Mar. 11, 2013]



Sec.  180.417  Reporting and record retention requirements.

    (a) Vehicle certification. (1) Each owner of a specification cargo 
tank must retain the manufacturer's certificate, the manufacturer's ASME 
U1A data report, where applicable, and related papers certifying that 
the specification cargo tank identified in the documents was 
manufactured and tested in accordance with the applicable specification. 
This would include any certification of emergency discharge control 
systems required by Sec.  173.315(n) of this subchapter or Sec.  
180.405(m). The owner must retain the documents throughout his ownership 
of the specification cargo tank and for one year thereafter. In the 
event of a change in ownership, the prior owner must retain non-fading 
photo copies of these documents for one year.
    (2) Each motor carrier who uses a specification cargo tank motor 
vehicle must obtain a copy of the manufacturer's certificate and related 
papers or the alternative report authorized by paragraph (a)(3)(i) or 
(ii) of this section and retain the documents as specified in this 
paragraph (a)(2). A motor carrier who is not the owner of a cargo tank 
motor vehicle must also retain a copy of the vehicle certification 
report for as long as the cargo tank motor vehicle is used by that 
carrier and for one year thereafter. The information required by this 
section must be maintained at the company's principal place of business 
or at the location where the vehicle is housed or maintained. The 
provisions of this section do not apply to a motor carrier who leases a 
cargo tank for less than 30 days.
    (3) DOT Specification cargo tanks--(i) Non-ASME Code stamped cargo 
tanks--If an owner does not have a manufacturer's certificate for a 
cargo tank and he wishes to certify it as a specification cargo tank, 
the owner must perform appropriate tests and inspections, under the 
direct supervision of a Registered Inspector, to determine if the cargo 
tank conforms with the applicable specification. Both the owner and the 
Registered Inspector must certify that the cargo tank fully conforms to 
the applicable specification. The owner must retain the certificate, as 
specified in this section.
    (ii) ASME Code Stamped cargo tanks. If the owner does not have the 
manufacturer's certificate required by the specification and the 
manufacturer's data report required by the ASME, the

[[Page 372]]

owner may contact the National Board for a copy of the manufacturer's 
data report, if the cargo tank was registered with the National Board, 
or copy the information contained on the cargo tank's identification and 
ASME Code plates. Additionally, both the owner and the Registered 
Inspector must certify that the cargo tank fully conforms to the 
specification. The owner must retain such documents, as specified in 
this section.
    (b) Test or inspection reporting. Each person performing a test or 
inspection as specified in Sec.  180.407 must prepare a written report, 
in English, in accordance with this paragraph.
    (1) Each test or inspection report must include the following 
information:
    (i) Owner's and manufacturer's unique serial number for the cargo 
tank;
    (ii) Name of cargo tank manufacturer;
    (iii) Cargo tank DOT or MC specification number;
    (iv) MAWP of the cargo tank;
    (v) Minimum thickness of the cargo tank shell and heads when the 
cargo tank is thickness tested in accordance with Sec.  180.407(d)(5), 
Sec.  180.407(e)(3), Sec.  180.407(f)(3), or Sec.  180.407(i);
    (vi) Indication of whether the cargo tank is lined, insulated, or 
both; and
    (vii) Indication of special service of the cargo tank (e.g., 
transports material corrosive to the tank, dedicated service, etc.)
    (2) Each test or inspection report must include the following 
specific information as appropriate for each individual type of test or 
inspection:
    (i) Type of test or inspection performed;
    (ii) Date of test or inspection (month and year);
    (iii) Listing of all items tested or inspected, including 
information about pressure relief devices that are removed, inspected 
and tested or replaced, when applicable (type of device, set to 
discharge pressure, pressure at which device opened, pressure at which 
device re-seated, and a statement of disposition of the device (e.g., 
reinstalled, repaired, or replaced)); information regarding the 
inspection of upper coupler assemblies, when applicable (visually 
examined in place, or removed for examination); and, information 
regarding leakage and pressure testing, when applicable (pneumatic or 
hydrostatic testing method, identification of the fluid used for the 
test, test pressure, and holding time of test);
    (iv) Location of defects found and method of repair;
    (v) ASME or National Board Certificate of Authorization number of 
facility performing repairs, if applicable;
    (vi) Name and address of person performing test;
    (vii) Registration number of the facility or person performing the 
test;
    (viii) Continued qualification statement, such as ``cargo tank meets 
the requirements of the DOT specification identified on this report'' or 
``cargo tank fails to meet the requirements of the DOT specification 
identified on this report'';
    (ix) DOT registration number of the registered inspector; and
    (x) Dated signature of the registered inspector and the cargo tank 
owner.
    (3) The owner and the motor carrier, if not the owner, must each 
retain a copy of the test and inspection reports until the next test or 
inspection of the same type is successfully completed. This requirement 
does not apply to a motor carrier leasing a cargo tank for fewer than 30 
days.
    (c) Additional requirements for Specification MC 330 and MC 331 
cargo tanks. (1) After completion of the pressure test specified in 
Sec.  180.407(g)(3), each motor carrier operating a Specification MC 330 
or MC 331 cargo tank in anhydrous ammonia, liquefied petroleum gas, or 
any other service that may cause stress corrosion cracking, must make a 
written report containing the following information:
    (i) Carrier's name, address of principal place of business, and 
telephone number;
    (ii) Complete identification plate data required by Specification MC 
330 or MC 331, including data required by ASME Code;
    (iii) Carrier's equipment number;
    (iv) A statement indicating whether or not the tank was stress 
relieved after fabrication;

[[Page 373]]

    (v) Name and address of the person performing the test and the date 
of the test;
    (vi) A statement of the nature and severity of any defects found. In 
particular, information must be furnished to indicate the location of 
defects detected, such as in weld, heat-affected zone, the liquid phase, 
the vapor phase, or the head-to-shell seam. If no defect or damage was 
discovered, that fact must be reported;
    (vii) A statement indicating the methods employed to make repairs, 
who made the repairs, and the date they were completed. Also, a 
statement of whether or not the tank was stress relieved after repairs 
and, if so, whether full or local stress relieving was performed;
    (viii) A statement of the disposition of the cargo tank, such as 
``cargo tank scrapped'' or ``cargo tank returned to service''; and
    (ix) A statement of whether or not the cargo tank is used in 
anhydrous ammonia, liquefied petroleum gas, or any other service that 
may cause stress corrosion cracking. Also, if the cargo tank has been 
used in anhydrous ammonia service since the last report, a statement 
indicating whether each shipment of ammonia was certified by its shipper 
as containing 0.2 percent water by weight.
    (2) A copy of the report must be retained by the carrier at its 
principal place of business during the period the cargo tank is in the 
carrier's service and for one year thereafter. Upon a written request 
to, and with the approval of, the Field Administrator, Regional Service 
Center, Federal Motor Carrier Safety Administration for the region in 
which a motor carrier has its principal place of business, the carrier 
may maintain the reports at a regional or terminal office.
    (3) The requirement in paragraph (c)(1) of this section does not 
apply to a motor carrier leasing a cargo tank for less than 30 days.
    (d) Supplying certificates and reports. Each person offering a DOT-
specification cargo tank for sale or lease must provide the purchaser or 
lessee a copy of the cargo tank certificate of compliance, records of 
repair, modification, stretching, or rebarrelling; and the most recent 
inspection and test reports made under this section. Copies of such 
reports must be provided to the lessee if the cargo tank is leased for 
more than 30 days.

[Amdt. 180-2, 54 FR 25032, June 12, 1989, as amended at 55 FR 21038, May 
22, 1990; 55 FR 37069, Sept. 7, 1990; 56 FR 27879, June 17, 1991; 58 FR 
12905, Mar. 8, 1993; Amdt. 180-2, 59 FR 1786, Jan. 12, 1994; Amdt. 180-
10, 61 FR 51343, Oct. 1, 1996; 63 FR 52850, Oct. 1, 1998; 64 FR 28052, 
May 24, 1999; 65 FR 50463, Aug. 18, 2000; 67 FR 61016, Sept. 27, 2002; 
68 FR 19290, Apr. 18, 2003; 68 FR 52372, Sept. 3, 2003; 69 FR 54047, 
Sept. 7, 2004; 70 FR 34077, June 13, 2005; 76 FR 43532, July 20, 2011; 
85 FR 75717, Nov. 25, 2020]



          Subpart F_Qualification and Maintenance of Tank Cars

    Source: Amdt. 180-8, 60 FR 49079, Sept. 21, 1995, unless otherwise 
noted.



Sec.  180.501  Applicability.

    (a) This subpart prescribes requirements, in addition to those 
contained in parts 107, 171, 172, 173, 174, and 179 of this subchapter, 
applicable to any person who manufactures, fabricates, marks, maintains, 
repairs, inspects, or services tank cars to ensure continuing 
qualification.
    (b) This subpart also establishes the minimum acceptable framework 
for an owner's qualification program for tank cars and components. 
Owners should follow this subpart in developing their written procedures 
(work instructions), as required under Sec.  179.7(d), for use by tank 
car facility employees. The owner's qualification program for each tank 
car, or a fleet of tank cars, must identify where to inspect, how to 
inspect, and the acceptance criteria. Alternative inspection and test 
procedures or intervals based on a damage-tolerance analysis or service 
reliability assessment must be approved by the Associate Administrator 
for Railroad Safety in accordance with 180.509(l). Tank car facilities 
must incorporate the owner's qualification program in their quality 
assurance program, as required under Sec.  179.7(a)(2), (b)(3), (b)(5), 
and (d).
    (c) Any person who performs a function prescribed in this part shall 
perform that function in accordance with this part.

[[Page 374]]

    (d) Where, in this subpart, a person is required to make documents 
available to FRA upon request, such request means that credentialed FRA 
personnel or an authorized representative of the Department may view the 
documents and make copies of them. The document owner's may seek 
confidential treatment of the documents presented. See Sec.  105.30.

[Amdt. 180-8, 60 FR 49079, Sept. 21, 1995, as amended by Amdt. 179-50, 
61 FR 33256, June 26, 1996; 77 FR 37986, June 25, 2012]



Sec.  180.503  Definitions.

    The following definitions and those contained in Sec. Sec.  171.8 
and 179.2 of this subchapter apply:
    Coating/lining owner means the person with the financial 
responsibility for purchasing and maintaining the integrity of the 
interior coating or lining.
    Corrosive to the tank or service equipment means a material 
identified in Appendix D of this part or a material when in contact with 
the inner shell of the tank or service equipment has a corrosion rate on 
steel greater than 2.5 milli-inch per year (mpy) (0.0025 inch per year).
    Defects mean abrasions; corrosion; cracks; dents; flaws in welds; 
distortions; erosion; missing, damaged, leaking or loose components and 
fasteners; and other conditions or imperfections that may make a tank 
car unsafe for transportation and/or require it to be removed from 
service.
    Design level of reliability and safety means the level of 
reliability and safety built into the tank car and, therefore, inherent 
in its specification, design, and manufacture.
    Inspection and test means a careful and critical examination of a 
tank car and its appurtenances performed by qualified personnel 
following the owner's qualified procedures.
    Interior heater system means a piping system located within the tank 
shell that uses a fluid medium to heat the lading for the purposes of 
unloading.
    Maintenance means upkeep, or preservation, including repairs 
necessary and proper to ensure an in-operation tank car's specification 
until its next qualification.
    Modification means any change to a tank car that affects the 
certificate of construction prescribed in Sec.  179.5, including an 
alteration prescribed in Sec.  179.6, or conversion.
    Objectively reasonable and articulable belief means a belief based 
on particularized and identifiable facts that provide an objective basis 
to believe or suspect that a tank car or a class or design of tank cars 
may be in an unsafe operating condition.
    Qualification, as relevant to a tank car, means the car and its 
components conforms to the specification to which it was designed, 
manufactured, or modified to the requirements of this subpart, to the 
applicable requirements of the AAR Specifications for Tank Cars (IBR, 
see Sec.  171.7 of this subchapter), and to the owner's acceptance 
criteria. Qualification is accomplished by careful and critical 
examination that verifies conformance using inspections and tests based 
on a written program approved by the tank car owner followed by a 
written representation of that conformance. A tank car that passes the 
appropriate tests for its specification, has a signed test report, is 
marked to denote this passage, and is considered qualified for hazardous 
materials transportation under this subchapter.

------------------------------------------------------------------------
                                       Tests and
        Qualification of              inspections     Sec.   180.509 (*)
------------------------------------------------------------------------
Tank............................  Visual Inspection.  d
                                  Structural          e
                                   Integrity
                                   Inspection.
                                  Thickness Test:     f
                                   Note 1.
                                  Safety System       h
                                   Inspection.
Service Equipment...............  Service Equipment.  k
Coating/lining..................  Internal Coatings   i
                                   and Linings.
------------------------------------------------------------------------

    Note 1: Subparagraph (f)(2) may require thickness tests at an 
interval different from the other items for qualification of the tank.

    Railworthy, Railworthiness for a tank car means that the tank, 
service equipment, safety systems, and all other components covered by 
this subchapter conform to the HMR, and are otherwise suitable for 
continued service and capable of performing their intended function 
until their next qualification.
    Reactive to the tank or service equipment means a material that, in 
contact with the inner shell of the tank, or with the service equipment, 
may react

[[Page 375]]

to produce heat, gases, and/or pressure which could substantially reduce 
the effectiveness of the packaging or the safety of its use.
    Reinforced tank shell butt weld means the portion of a butt weld 
covered by a reinforcing pad.
    Reinforcing pad means an attachment welded directly to the tank 
supporting major structural components for the purpose of preventing 
damage to the tank through fatigue, overstressing, denting, puncturing, 
or tearing.
    Reliability means the quantified ability of an item or structure to 
operate without failure for the specified period of its design life or 
until its next qualification.
    Representation means attesting through documenting, in writing or by 
marking on the tank (or jacket), that a tank car is qualified and 
railworthy. See also Sec. Sec.  180.511 and 180.517(b).
    Safety system means one or more of the following: Thermal protection 
systems, insulation systems, tank head puncture resistance systems, 
coupler vertical restraint systems, and systems used to protect 
discontinuities (e.g., skid protection and protective housings) as 
required under this subchapter.
    Service equipment means equipment used for loading and unloading 
(including an interior heating system), sampling, venting, vacuum 
relief, pressure relief, and measuring the amount of lading or the 
lading temperature.
    Service equipment owner means the party responsible for bearing the 
cost of the maintenance of the service equipment.
    Tank car owner means the person to whom a rail car's reporting marks 
are assigned, as listed in the Universal Machine Language Equipment 
Register (UMLER).
    Tank car tank means the shell, heads, tank shell and head weld 
joints, attachment welds, sumps, nozzles, flanges, and all other 
components welded thereto that are either in contact with the lading or 
contain the lading.
    Train consist means a written record of the contents and location of 
each rail car in a train.

[77 FR 37986, June 25, 2012, as amended at 81 FR 35546, June 2, 2016]



Sec.  180.505  Quality assurance program.

    The quality assurance program requirements of Sec.  179.7 of this 
subchapter apply.



Sec.  180.507  Qualification of tank cars.

    (a) Each tank car marked as meeting a ``DOT'' specification or any 
other tank car used for the transportation of a hazardous material must 
meet the requirements of this subchapter or the applicable specification 
to which the tank was constructed.
    (b)(1) Tank cars prescribed in the following table are no longer 
authorized for construction but may remain in hazardous materials 
service provided they conform to all applicable safety requirements of 
this subchapter:

                       Table 1 to Paragraph (b)(1)
------------------------------------------------------------------------
   Specification prescribed in the       Other specifications
         current regulations                   permitted          Notes
------------------------------------------------------------------------
105A200W.............................  105A100W................        1
105A200ALW...........................  105A100ALW..............        1
------------------------------------------------------------------------

    Note 1 to Table 1 to paragraph (b)(1): Tanks built as Specification 
DOT 105A100W or DOT 105A100ALW may be altered and converted to DOT 
105A200W and DOT 105A200ALW, respectively.
    (2) [Reserved]
    (3) Specification DOT-113A175W, DOT-113C60W, DOT-113D60W, and DOT-
113D120W tank cars may continue in use, but new construction is not 
authorized.
    (4) Class DOT 105A and 105S tank cars used to transport hydrogen 
chloride, refrigerated liquid under the terms of DOT-E 3992 may continue 
in service, but new construction is not authorized.
    (5) Specification DOT-103A-ALW, 103AW, 103ALW, 103ANW, 103BW, 103CW, 
103DW, 103EW, and 104W tank cars may continue in use, but new 
construction is not authorized.

[Amdt. 180-8, 60 FR 49079, Sept. 21, 1995, as amended at 68 FR 48572, 
Aug. 14, 2003; 77 FR 37987, June 25, 2012; 87 FR 79785, Dec. 27, 2022]



Sec.  180.509  Requirements for inspection and test of specification tank 
cars.

    (a) General. Each tank car owner must ensure that a tank car 
facility:
    (1) Inspects and tests each item according to the requirements 
specified in this section;

[[Page 376]]

    (2) Evaluates each item according to the acceptable results of 
inspections and tests specified in Sec.  180.511;
    (3) Marks each tank car as specified in Sec.  180.515 that is 
qualified to transport hazardous materials;
    (4) Prepares the documentation as required by Sec.  180.517 for each 
item qualified under this section. A copy of the documentation required 
by Sec.  180.517 must be sent to the owner as appropriate and according 
to the owner's instructions.
    (b) Conditions requiring qualification of tank cars. Without regard 
to the qualification compliance date requirements of any paragraph of 
this section, an owner of a tank car or an internal coating or lining 
must ensure an appropriate inspection and test according to the type of 
defect and the type of maintenance or repair performed if:
    (1) The tank car shows evidence of abrasion, corrosion, cracks, 
dents, distortions, defects in welds, or any other condition that may 
make the tank car unsafe for transportation,
    (2) The tank car was in an accident and shows evidence of damage to 
an extent that may adversely affect its capability to retain its 
contents or to otherwise remain railworthy.
    (3) The tank bears evidence of damage caused by fire. (4) The 
Associate Administrator for Railroad Safety, FRA, requires it based on 
the existence of an objectively reasonable and articulable belief that a 
tank car or a class or design of tank cars may be in an unsafe operating 
condition.
    (c) Frequency of inspection and tests. Each tank car shall have an 
inspection and test according to the requirements of this paragraph.
    (1) For Class 107 tank cars and tank cars of riveted construction, 
the tank car must have a hydrostatic pressure test and visual inspection 
conforming to the requirements in effect prior to July 1, 1996, for the 
tank specification.
    (2) For Class DOT 113 tank cars, see Sec.  173.319(e) of this 
subchapter.
    (3) Fusion welded tank cars must be inspected and tested to be 
qualified and maintained in accordance with the following table. All 
qualification requirements need not be done at the same time or at the 
same facility.

                                 Frequency of Qualification Inspection and Tests
----------------------------------------------------------------------------------------------------------------
        Section 180.509 (*)                           Description                         Maximum interval
----------------------------------------------------------------------------------------------------------------
D.................................  Visual inspection.............................  10 years.
E.................................  Structural integrity inspection...............  10 years.
F.................................  Thickness test................................  See Sec.   180.509(f).
H.................................  Safety Systems................................  10 years.
I.................................  Internal coating or lining (for materials       See Sec.   180.509(i).
                                     corrosive or reactive to the tank) (See
                                     definitions at Sec.   180.503).
J.................................  Leakage pressure test.........................  After reassembly.
K.................................  Service equipment (including pressure relief    See Sec.   180.509(k).
                                     device).
----------------------------------------------------------------------------------------------------------------

    (d) Visual inspection. At a minimum, each tank car facility must 
visually inspect the tank externally and internally as follows:
    (1) An internal inspection of the tank shell and heads for abrasion, 
corrosion, cracks, dents, distortions, defects in welds, or any other 
condition that makes the tank car unsafe for transportation, and except 
in the areas where insulation or a thermal protection system precludes 
it, an external inspection of the tank shell and heads for abrasion, 
corrosion, cracks, dents, distortions, defects in welds, or any other 
condition that makes the tank car unsafe for transportation, and for DOT 
115 class tank cars, an internal inspection of the inner container and 
external inspection of the outer shell and heads for defects in welds, 
or any other condition that may make the tank car unsafe for 
transportation;
    (2) When an internal coating or lining, head protection, insulation, 
or thermal protection is removed in part or in whole, the internal and 
external exposed surface of the tank must be visually inspected for 
defects in welds or any other condition that may make the tank car 
unsafe for transportation, and this inspection must precede any 
application or reapplication of a coating or lining;

[[Page 377]]

    (3) An inspection of the service equipment, including gaskets, for 
indications of corrosion and other conditions that may make the tank car 
unsafe for transportation;
    (4) An inspection for missing or loose bolts, nuts, or elements that 
may make the tank car unsafe for transportation;
    (5) An inspection of all closures on the tank car for conditions 
that may make the tank car unsafe for transportation, including an 
inspection of the protective housings for proper condition;
    (6) An inspection of excess flow valves with threaded seats for 
tightness; and
    (7) An inspection of the required markings on the tank car for 
legibility.
    (e) Structural integrity inspections and tests. (1) Each tank car 
owner must ensure the structural elements on the tank car qualify with 
the applicable requirements of this subchapter. At a minimum, the 
structural integrity inspection and test must include:
    (i) All transverse fillet welds greater than 0.64 cm (0.25 inch) 
within 121.92 cm (4 feet) of the bottom longitudinal centerline except 
body bolster pad attachment welds;
    (ii) The termination of longitudinal fillet welds greater than 0.64 
cm (0.25 inch) within 121.92 cm (4 feet) of the bottom longitudinal 
centerline; and
    (iii) The tank shell butt welds within 60.96 cm (2 feet) of the 
bottom longitudinal centerline, unless the tank car owner can determine 
by analysis (e.g., finite element analysis, damage-tolerance analysis, 
or service reliability assessment) that the structure will not develop 
defects that reduce the design level of safety and reliability or fail 
within its operational life or prior to the next required inspection. 
The owner must maintain all documentation used to make such 
determination at its principal place of business and make the data 
available to FRA or an authorized representative of the Department upon 
request.
    (2) For DOT 115 class tanks, paragraphs (e)(1)(i) through (iii) of 
this section apply only to the outer shell fillet welds and to the non-
reinforced exposed outer shell butt welds.
    (3) The inspection requirements of paragraph (e)(1)(iii) of this 
section do not apply to reinforced tank shell butt welds until the time 
of lining removal or application for tank cars with an internal lead, 
glass, or rubber lining.
    (4) Each tank car facility must inspect and test the elements 
identified in paragraph (e)(1) of this section by one or more of the 
following methods:
    (i) Dye penetrant testing (PT);
    (ii) Radiographic examination (RT);
    (iii) Magnetic particle testing (MT);
    (iv) Ultrasonic testing (UT); and
    (v) Direct, remote, or enhanced visual inspection, using, for 
example, magnifiers, fiberscopes, borescopes, and/or machine vision 
technology (VT).
    (f) Thickness tests. (1) The tank car owner must ensure that each 
tank car facility measures the thickness of the tank car shell, heads, 
sumps, protective housing (i.e., domes), and nozzles on each tank car by 
using a device capable of accurately measuring the thickness to within 
0.05 mm (0.002 inch).
    (2) The tank car owner must ensure that each tank car has a 
thickness test measurement:
    (i) At the time of an internal coating or lining application or 
replacement, or
    (ii) At least once every ten (10) years for a tank that does not 
have an internal coating or lining, or
    (iii) At least once every five (5) years for a tank that does not 
have an internal coating or lining when:
    (A) The tank is used to transport a material that is corrosive or 
reactive to the tank (see Appendix D of this part) or service equipment 
as defined Sec.  180.503, and
    (B) The remaining shell and head thickness is tested and determined 
to be at or below line C in Figure A of this paragraph.

[[Page 378]]

[GRAPHIC] [TIFF OMITTED] TR25JN12.000

Where:

A. As-built tank shell or head thickness with additional thickness.
B. Required minimum tank shell or head thickness after forming per part 
          179.
C. Inspection frequency adjustment point (design minimum shell or head 
          thickness, minus \1/2\ of the table value in paragraph (g) of 
          this section).
D. Condemning limit for general corrosion (required minimum shell or 
          head thickness, minus the value in paragraph (g) of this 
          section).
E. Condemning limit for localized corrosion (required minimum shell or 
          head thickness, minus the table value in paragraph (g) of this 
          section, minus 1.58 mm (\1/16\ inch)). See Note 1 in paragraph 
          (g) of this section for diameter limitations and minimum 
          separation distances.
F. Allowable shell or head thickness reduction (table value in paragraph 
          (g) of this section).
G. Additional thickness reduction for localized areas in paragraph (g) 
          of this section.

    (3) For a localized repair of an internal coating or lining where a 
material corrosive to the tank or service equipment as defined Sec.  
180.503 has contacted the tank, a qualified individual must verify the 
coating or lining's conformance with paragraph (g) of this section by 
measuring the shell or head in the area of the repair. The thickness 
test applies only to the non-lined or coated repaired area, and is not a 
qualification event. Modification of the tank stencil is not required.
    (4) Operation of a tank car below the condemning limit for general 
corrosion or the condemning limit for localized corrosion (as shown in 
Figure A of this section) is prohibited.
    (5) For sumps, protective housing (i.e., domes), nozzles, and nozzle 
reinforcing pads, the tank car owner must determine if any reduction in 
wall thickness affects the design levels of reliability and safety built 
into sump, protective housing, nozzle, or nozzle reinforcement. Each 
tank car owner must maintain at its principal place of business 
documentation describing the allowable thickness reductions for sumps, 
protective housings, and nozzles, and nozzle reinforcements. This 
documentation must be made available to FRA or an authorized 
representative of the Department upon request.
    (6) After repairs, alterations, conversions, modifications, or 
blasting of tank car that results in a reduction of the tank's 
thickness, and anytime a

[[Page 379]]

tank car coating or lining is removed, a qualified individual must 
measure the thickness of the tank in the area of reduced thickness to 
ensure that the thickness of the tank conforms to paragraph (g) of this 
section.
    (g) Service life thickness allowance. (1) A tank car found with a 
thickness below the required minimum thickness after forming for its 
specification, as stated in part 179 of this subchapter, may continue in 
service if any reduction in the required minimum thickness is not more 
than that provided in the following table:

                  Allowable Shell Thickness Reductions
------------------------------------------------------------------------
                                  Top shell and tank
    Marked tank test pressure            head            Bottom shell
------------------------------------------------------------------------
60 psig <200 psig...............  3.17 mm...........  1.58 mm.
                                  \1/8\ inch........  \1/16\ inch.
=200 psig............  0.79 mm...........  0.79 mm.
                                  \1/32\ inch.......  \1/32\ inch.
------------------------------------------------------------------------

    Note 1. A tank car owner may add an extra 1.58 mm (\1/16\ inch) to 
the values in the table for local reductions. Local reductions are those 
that do not exceed 20.32 linear centimeters (8 linear inches) measured 
at the longest diameter, and are separated from the other local 
reductions by at least 40.64 cm (16 inches).
    Note 2. Any reduction in the tank car shell thickness may not affect 
the structural strength of the tank car to the extent that the tank car 
no longer conforms to the applicable provisions of Section 6.2 of the 
AAR Specifications for Tank Cars (IBR, see Sec.  171.7 of this 
subchapter).
    Note 3. For DOT 115 class tank cars, shell thickness reductions 
apply only to the outer shell of the tank car. There is no shell or head 
thickness reduction authorized for the inner tank.

    (2) [Reserved]
    (h) Safety system inspections. Each tank car owner must ensure 
qualification of the tank car safety systems. However, inspections of 
foam or cork insulation systems are not required.
    (i) Internal coating and lining inspection and test. (1) At a 
minimum, the owner of an internal coating or lining applied to protect a 
tank used to transport a material that is corrosive or reactive to the 
tank must ensure an inspection adequate enough to detect defects or 
other conditions that could reduce the design level of reliability and 
safety of the tank is performed. In addition, the owner of a coating or 
lining of tank cars used to transport hazardous materials must ensure 
the lining complies with Sec.  173.24(b)(2) and (b)(3) of this 
subchapter.
    (2) The owner of the internal coating or lining must establish and 
maintain a record of the service life of the coating or lining and 
commodity combination, that is, the specific hazardous materials that 
were loaded into a tank and the coating or lining in place at the time 
of loading. The owner of the internal coating or lining must use its 
knowledge of the service life of each coating or lining and commodity 
combination to establish an appropriate inspection interval for that 
coating or lining and commodity combination. This interval must not 
exceed eight (8) years, unless the coating or lining owner can 
establish, document, and show that the service history or scientific 
analysis of the coating or lining and commodity pairing supports a 
longer inspection interval. The owner must maintain at its principal 
place of business a written procedure for collecting and documenting the 
performance of the coating or lining applied within the tank car for its 
service life. The internal coating or lining owner must provide this 
documentation, including inspection and test, repair, removal, and 
application procedures, to the FRA or car owner upon request. Further, 
the offeror must provide commodity information to the car owner and the 
owner of the internal coating or lining upon request.
    (3) The owner of the internal coating or lining must provide the 
test method and acceptance criteria to the tank car owner and to the 
person responsible for qualifying the coating or lining. The tank car 
facility inspecting and testing the internal coating or lining must 
follow the inspection and test procedure, including the acceptance 
requirements, established by the internal coating or lining owner.
    (j) Leakage pressure test. Unless the design of the service 
equipment arrangement precludes it (e.g., there is no fitting to 
pressurize the tank), each owner of a tank car must ensure that the 
tank, service equipment, and closures installed, replaced, or 
reinstalled on the tank car are leak tested. The test may be conducted 
with the lading

[[Page 380]]

in the tank. When the test pressure exceeds the start-to-discharge or 
burst pressure of a pressure relief device, the device must be rendered 
inoperative. The written procedures and test method for leak testing 
must ensure the sensitivity and reliability of the test method to 
prevent premature failure. This section does not apply to facilities 
that remove closures for the sole purpose of loading or unloading the 
lading (e.g., blind flanges, pipe plugs, etc.).
    (k) Service equipment inspection and test. (1) Each tank car owner 
must ensure the qualification of tank car service equipment at least 
once every ten (10) years. The tank car owner must analyze the service 
equipment inspection and test results for any given lading and, based on 
the analysis, adjust the inspection and test frequency to ensure that 
the design level of reliability and safety of the equipment is met. The 
owner must maintain at its principal place of business all supporting 
documentation used to make such analyses and inspection and test 
frequency adjustments. The supporting documentation must be made 
available to FRA or an authorized representative of the Department upon 
request.
    (2) Each tank car facility must qualify service equipment, including 
reclosing pressure relief devices and interior heater systems in 
accordance with the applicable provisions of Appendix D of the AAR 
Specifications for Tank Cars (IBR, see Sec.  171.7 of this subchapter).
    (l) Alternative inspection and test procedures. When approved by the 
Associate Administrator for Railroad Safety, FRA, a tank car owner, or a 
coating or lining owner may use an alternative inspection and test 
procedure or interval based on a damage-tolerance analysis (that must 
include a determination of the probable locations and modes of damage 
due to fatigue, corrosion, and accidental damage), or based on a service 
reliability assessment (that must be supported by analysis of 
systematically collected data) in lieu of the other requirements of this 
section.
    (m) Inspection and test compliance date for tank cars. (1) After 
July 1, 2000, each tank car with a metal jacket or with a thermal 
protection system shall have an inspection and test conforming to this 
section no later than the date the tank car requires a periodic 
hydrostatic pressure test (i.e., the marked due date on the tank car for 
the hydrostatic test).
    (2) After July 1, 1998, each tank car without a metal jacket shall 
have an inspection and test conforming to this section no later than the 
date the tank car requires a periodic hydrostatic pressure test (i.e., 
the marked due date on the tank car for the hydrostatic test).
    (3) For tank cars on a 20-year periodic hydrostatic pressure test 
interval (i.e., Class DOT 103W, 104W, 111A60W1, 111A100W1, and 111A100W3 
tank cars), the next inspection and test date is the midpoint between 
the compliance date in paragraph (l)(1) or (2) of this section and the 
remaining years until the tank would have had a hydrostatic pressure 
test.

[Amdt. 180-8, 60 FR 49079, Sept. 21, 1995, as amended by Amdt. 179-50, 
61 FR 33256, June 26, 1996; 62 FR 51561, Oct. 1, 1997; 63 FR 52851, Oct. 
1, 1998; 66 FR 45391, Aug. 28, 2001; 68 FR 75765, Dec. 31, 2003; 71 FR 
54398, Sept. 14, 2006; 77 FR 37987, June 25, 2012]



Sec.  180.511  Acceptable results of inspections and tests.

    Provided it conforms to other applicable requirements of this 
subchapter, a tank car is qualified for use if it successfully passes 
the inspections and tests set forth below conducted in accordance with 
this subpart. A representation of that qualification must consist of 
marking the tank in accordance with Sec.  180.515.
    (a) Visual inspection. A tank car successfully passes the visual 
inspection when the inspection shows no structural defect that may cause 
leakage from or failure of the tank before the next inspection and test 
interval.
    (b) Structural integrity inspection and test. A tank car 
successfully passes the structural integrity inspection and test when it 
shows no structural defect that may initiate cracks or propagate cracks 
and cause failure of the tank before the next inspection and test 
interval.
    (c) Service life shell thickness. A tank car successfully passes the 
service life shell thickness inspection when the

[[Page 381]]

tank shell and heads show no thickness reduction below that allowed in 
Sec.  180.509(g).
    (d) Safety system inspection. A tank car successfully passes the 
safety system inspection when each thermal protection system, tank head 
puncture resistance system, coupler vertical restraint system, and 
system used to protect discontinuities (e.g., breakage grooves on bottom 
outlets and protective housings) on the tank car conform to this 
subchapter and show no indication of a defect that may reduce 
reliability before the next inspection and test interval.
    (e) Lining and coating inspection. A tank car successfully passes 
the lining and coating inspection and test when the lining or coating 
conforms to the owner's acceptance criteria.
    (f) Leakage pressure test. A tank car successfully passes the 
leakage pressure test when all product piping, fittings and closures 
show no indication of leakage.
    (g) Hydrostatic test. A Class 107 tank car, the inner tank of a 
Class 115 tank car, or a riveted tank car successfully passes the 
hydrostatic test when it shows no leakage, distortion, excessive 
permanent expansion, or other evidence of weakness that might render the 
tank car unsafe for transportation service.
    (h) Service equipment. A tank car successfully passes the service 
equipment inspection and test when this equipment conforms to this 
subchapter and applicable provisions of Appendix D of the AAR 
Specifications for Tank Cars (IBR, see Sec.  171.7 of this subchapter), 
and shows no indication of a defect that may reduce reliability during 
the qualification interval.

[Amdt. 180-8, 60 FR 49079, Sept. 21, 1995, as amended by Amdt. 179-50, 
61 FR 33256, June 26, 1996; 66 FR 45187, Aug. 28, 2001; 77 FR 37990, 
June 25, 2012]



Sec.  180.513  Repairs, alterations, conversions, and modifications.

    (a) To work on tank cars, a tank car facility must comply with the 
applicable requirements of this subpart, the AAR Specifications for Tank 
Cars (IBR, see Sec.  171.7 of this subchapter), and the owner's 
requirements.
    (b) Responsibilities of Tank Car Facility. A tank car facility must 
obtain the permission of the equipment owner before performing work 
affecting alteration, conversion, repair, or qualification of the 
owner's equipment. For the purposes of qualification and maintenance, 
the tank car facility must use the written instructions furnished by the 
owner or have written confirmation from the owner allowing the use of 
written instructions furnished by the owner or have written confirmation 
from the owner allowing the use of written instructions furnished by 
another. A tank car facility must not use, copy distribute, forward or 
provide to another person the owner's confidential and proprietary 
written instructions, procedures, manuals, and records without the 
owner's permission. A tank car facility must report all work performed 
to the owner. The tank car facility must also report observed damage, 
deterioration, failed components, or non-compliant parts to the owner. A 
tank car facility must incorporate the owner's Quality Assurance Program 
into their own Quality Assurance Program.
    (c) Unless the exterior tank car shell or interior tank car jacket 
has a protective coating, after a repair that requires the complete 
removal of the tank car jacket, the exterior tank car shell and the 
interior tank car jacket must have a protective coating applied to 
prevent the deterioration of the tank shell and tank jacket. Previously 
applied coatings that still provide effective protection need not be 
covered over.
    (d) After repair, replacement, or qualification of tank car service 
equipment, the tank service equipment must successfully pass the leak 
test prescribed in Sec.  180.509(j).

[77 FR 37990, June 25, 2012]



Sec.  180.515  Markings.

    (a) When a tank car passes the required inspection and test with 
acceptable results, the tank car facility must mark the date of the 
inspection and test and due date of the next inspection and test 
qualified on the tank car in accordance with the applicable provisions 
of Appendix C of the AAR Specifications for Tank Cars (IBR, see Sec.  
171.7

[[Page 382]]

of this subchapter). When a tank car facility performs multiple 
inspections and tests at the same time, one date may be used to satisfy 
the requirements of this section. One date also may be shown when 
multiple inspections and tests have the same due date. Dates displayed 
on the ``consolidated stencil'' (see the applicable provisions of 
Appendix C of the AAR Specifications for Tank Cars) take precedence over 
dates modified, and not stenciled, pursuant to interval adjustments for 
service equipment, linings, and granted alternative inspection 
intervals.
    (b) Converted DOT 105, 109, 112, 114, or 120 class tank cars must 
have the new specification and conversion date permanently marked in 
letters and figures at least 0.95 cm (0.375 inch) high on the outside of 
the manway nozzle or the edge of the manway nozzle flange on the left 
side of the car. The marking may have the last numeral of the 
specification number omitted (e.g., ``DOT 111A100W'' instead of ``DOT 
111A100W1'').
    (c) When qualified within six months of installation and protected 
from deterioration, the test date marking of a reclosing pressure relief 
device is the installation date on the tank car.
    (d) The specification marking for DOT 113 tank cars built in 
accordance with the DOT 113C120W9 specification must display the last 
numeral of the specification number (i.e., ``DOT 113C120W9'').

[Amdt. 180-8, 60 FR 49079, Sept. 21, 1995, as amended by Amdt. 179-50, 
61 FR 33256, June 26, 1996; 63 FR 52851, Oct. 1, 1998; 66 FR 45391, Aug. 
28, 2001; 68 FR 75765, Dec. 31, 2003; 77 FR 37991, June 25, 2012; 85 FR 
45030, July 24, 2020]



Sec.  180.517  Reporting and record retention requirements.

    (a) Certification and representation. Each owner of a specification 
tank car must retain the certificate of construction (AAR Form 4-2) and 
related papers certifying that the manufacture of the specification tank 
car identified in the documents is in accordance with the applicable 
specification. The builder's signature on the certificate of 
construction and the marking of the tank car with the tank specification 
is the representation that all of the appropriate inspections and tests 
were successfully performed to qualify the tank for use. The owner must 
retain the documents throughout the period of ownership of the 
specification tank car and for one year thereafter. Upon a change of 
ownership, the applicable provisions prescribed in Section 1.3.15 of the 
AAR Specifications for Tank Cars (IBR, see Sec.  171.7 of this 
subchapter) apply. The builder of the car or a facility performing work 
on the car may retain copies of relevant records.
    (b) Inspection and test reporting. Each tank car that is inspected 
and tested as specified in Sec.  180.509 must have a written report, in 
English, prepared according to this paragraph. Marking the tank car with 
the specification (or retaining the specification marking on the tank) 
is the representation that all of the appropriate inspections and tests 
were performed and the results meet the tank car owner's acceptance 
criteria to qualify the car for continued use. The report may be created 
and retained electronically, but, upon request by FRA for a copy of the 
report, it must be made available in common readable form. The owner 
must retain a copy of the inspection and test reports until successfully 
completing the next inspection and test of the same type. The inspection 
and test report must include the following:
    (1) Type of inspection and test performed (a checklist is 
acceptable);
    (2) The results of each inspection and test performed;
    (3) Tank car reporting mark and number;
    (4) Tank car specification;
    (5) Inspection and test date (month and year);
    (6) Location and description of defects found and method used to 
repair each defect;
    (7) The name and address of the tank car facility and the name and 
signature of inspector; and
    (8) The unique code (station stencil) identifying the facility.

[Amdt. 180-2, 54 FR 25032, June 12, 1989, as amended at 68 FR 75765, 
Dec. 31, 2003; 77 FR 37991, June 25, 2012]

[[Page 383]]



Sec.  180.519  Periodic retest and inspection of tank cars other than  
single-unit tank car tanks.

    (a) General. Unless otherwise provided in this subpart, tanks 
designed to be removed from cars for filling and emptying and tanks 
built to a Class DOT 107A specification and their safety relief devices 
must be retested periodically as specified in Retest Table 1 of 
paragraph (b)(5) of this section. Retests may be made at any time during 
the calendar year the retest falls due.
    (b) Pressure test. (1) Each tank must be subjected to the specified 
hydrostatic pressure and its permanent expansion determined. Pressure 
must be maintained for 30 seconds and for as long as necessary to secure 
complete expansion of the tank. Before testing, the pressure gauge must 
be shown to be accurate within 1 percent at test measure. The expansion 
gauge must be shown to be accurate, at test pressure, to within 1 
percent. Expansion must be recorded in cubic cm. Permanent volumetric 
expansion may not exceed 10 percent of total volumetric expansion at 
test pressure and the tank must not leak or show evidence of distress.
    (2) Each tank, except tanks built to specification DOT 107A, must 
also be subjected to interior air pressure test of at least 100 psig 
under conditions favorable to detection of any leakage. No leaks may 
appear.
    (3) Safety relief valves must be retested by air or gas, must start-
to-discharge at or below the prescribed pressure and must be vapor tight 
at or above the prescribed pressure.
    (4) Rupture discs and fusible plugs must be removed from the tank 
and visually inspected.
    (5) Tanks must be retested as specified in Retest Table 1 of this 
paragraph (b)(5), and before returning to service after repairs 
involving welding or heat treatment:

                                                 Retest Table 1
----------------------------------------------------------------------------------------------------------------
                                     Retest interval--years   Minimum Retest pressure--   Pressure relief valve
                                   --------------------------           psig                 pressure--psig
                                                             ---------------------------------------------------
           Specification                           Pressure       Tank
                                        Tank        relief    hydrostatic    Tank air    Start-to-
                                                 devices \d\   expansion       test      discharge   Vapor tight
                                                                  \c\
----------------------------------------------------------------------------------------------------------------
DOT 27............................            5            2          500          100          375          300
106A500...........................            5            2          500          100          375          300
106A500X..........................            5            2          500          100          375          300
106A800...........................            5            2          800          100          600          480
106A800X..........................            5            2          800          100          600          480
106A800NCI........................            5            2          800          100          600          480
107A * * * *......................         \d\5         \a\2        (\b\)         None         None         None
110A500-W.........................            5            2          500          100          375          300
110A600-W.........................            5            2          600          100          500          360
110A800-W.........................            5            2          800          100          600          480
110A1000-W........................            5            2        1,000          100          750          600
BE-27.............................            5            2          500          100          375          300
----------------------------------------------------------------------------------------------------------------
Notes:
\a\ If DOT 107A * * * * tanks are used for transportation of flammable gases, one rupture disc from each car
  must be burst at the interval prescribed. The sample disc must burst at a pressure not exceeding the marked
  test pressure of the tank and not less than 70 percent of the marked test pressure. If the sample disc does
  not burst within the prescribed limits, all discs on the car must be replaced.
\b\ The hydrostatic expansion test pressure must at least equal the marked test pressure.
\c\ See Sec.   180.519(b)(1).
\d\ Safety relief valves of the spring-loaded type on tanks used exclusively for fluorinated hydrocarbons and
  mixtures thereof which are free from corroding components may be retested every 5 years.

    (6) The month and year of test, followed by a ``V'' if visually 
inspected as described in paragraph (c) of this section, must be plainly 
and permanently stamped into the metal of one head or chime of each tank 
with successful test results; for example, 01-90 for January 1990. On 
DOT 107A**** tanks, the date must be stamped into the metal of the 
marked end, except that if all tanks mounted on a car have been tested, 
the date may be stamped into the metal of a plate permanently applied to 
the bulkhead on the ``A'' end of the car. Dates of previous tests and 
all prescribed markings must be kept legible.

[[Page 384]]

    (c) Visual inspection. Tanks of Class DOT 106A and DOT 110A-W 
specifications (Sec. Sec.  179.300 and 179.301 of this subchapter) used 
exclusively for transporting fluorinated hydrocarbons and mixtures 
thereof, and that are free from corroding components, may be given a 
periodic complete internal and external visual inspection in place of 
the periodic hydrostatic retest. Visual inspections shall be made only 
by competent persons. The tank must be accepted or rejected in 
accordance with the criteria in CGA C-6 (IBR, see Sec.  171.7 of this 
subchapter).
    (d) Written records. The results of the pressure test and visual 
inspection must be recorded on a suitable data sheet. Completed copies 
of these reports must be retained by the owner and by the person 
performing the pressure test and visual inspection as long as the tank 
is in service. The information to be recorded and checked on these data 
sheets are: Date of test and inspection; DOT specification number; tank 
identification (registered symbol and serial number, date of manufacture 
and ownership symbol); type of protective coating (painted, etc., and 
statement as to need for refinishing or recoating); conditions checked 
(leakage, corrosion, gouges, dents or digs, broken or damaged chime or 
protective ring, fire, fire damage, internal condition); test pressure; 
results of tests; and disposition of tank (returned to service, returned 
to manufacturer for repair, or scrapped); and identification of the 
person conducting the retest or inspection.

[Amdt. 180-8, 60 FR 49079, Sept. 21, 1995, as amended by Amdt. 179-50, 
61 FR 33257, June 26, 1996; 65 FR 58633, Sept. 29, 2000; 66 FR 45187, 
45392, Aug. 28, 2001; 68 FR 75765, Dec. 31, 2003]



        Subpart G_Qualification and Maintenance of Portable Tanks

    Source: 66 FR 33453, June 21, 2001, unless otherwise noted.



Sec.  180.601  Applicability.

    This subpart prescribes requirements, in addition to those contained 
in parts 107, 171, 172, 173, and 178 of this subchapter, applicable to 
any person responsible for the continuing qualification, maintenance or 
periodic retesting of a portable tank.



Sec.  180.603  Qualification of portable tanks.

    (a) Each portable tank used for the transportation of hazardous 
materials must be an authorized packaging.
    (b) To qualify as an authorized packaging, each portable tank must 
conform to the requirements of this subchapter and the applicable design 
specification to which the portable tank was constructed.
    (c) The following portable tanks are authorized for use provided 
they conform to all applicable safety requirements of this subchapter: 
51, 56, 57, 60, IM 101, IM 102 and UN portable tanks.
    (d) A portable tank that also meets the definition of ``container'' 
in 49 CFR 450.3(a)(3) must conform to the requirements in parts 450 
through 453 of this title for compliance with Annex II of the Convention 
for Safe Containers (CSC).
    (e) Exemption portable tanks based on DOT 51 portable tanks. The 
owner of a portable tank constructed in accordance with and used under 
an exemption issued prior to August 31, 1996, which was in conformance 
with the requirements for Specification DOT 51 portable tanks with the 
exception of the location of fill and discharge outlets, shall examine 
the portable tank and its design to determine if it meets the outlet 
requirements in effect on October 1, 1996. If the owner determines that 
the portable tank is in compliance with all requirements of the DOT 51 
specification, the exemption number stenciled on the portable tank shall 
be removed and the specification plate (or a plate placed adjacent to 
the specification plate) shall be durably marked ``DOT 51-E*****'' 
(where ***** is to be replaced by the exemption number). During the 
period the portable tank is in service, and for one year thereafter, the 
owner of the portable tank must retain on file, at its principal place 
of business, a copy of the last exemption in effect.

[[Page 385]]



Sec.  180.605  Requirements for periodic testing, inspection, and repair 
of portable tanks.

    (a) A portable tank constructed in accordance with a DOT 
specification for which a test or inspection specified in this subpart 
has become due, must be tested or inspected prior to being returned for 
transportation.
    (b) Conditions requiring test and inspection of portable tanks. 
Without regard to any other test or inspection requirements, a 
Specification or UN portable tank must be tested and inspected in 
accordance with this section prior to further use if any of the 
following conditions exist:
    (1) The portable tank shows evidence of dents, corroded or abraded 
areas, leakage, or any other condition that might render it unsafe for 
transportation service.
    (2) The portable tank has been in an accident and has been damaged 
to an extent that may adversely affect its ability to retain the 
hazardous material.
    (3) The portable tank has been out of hazardous materials 
transportation service for a period of one year or more.
    (4) The portable tank has been modified from its original design 
specification.
    (5) The portable tank is in an unsafe operating condition.
    (c) Schedule for periodic inspections and tests. Each Specification 
portable tank must be tested and inspected in accordance with the 
following schedule:
    (1) Each IM or UN portable tank must be given an initial inspection 
and test before being placed into service, a periodic inspection and 
test at least once every 5 years, and an intermediate periodic 
inspection and test at least every 2.5 years following the initial 
inspection and the last 5 year periodic inspection and test.
    (2) Each Specification 51 portable tank must be given a periodic 
inspection and test at least once every five years.
    (3) Each Specification 56 or 57 portable tank must be given a 
periodic inspection and test at least once every 2.5 years.
    (4) Each Specification 60 portable tank must be given a periodic 
inspection and test at the end of the first 4-year period after the 
original test; at least once every 2 years thereafter up to a total of 
12 years of service; and at least once annually thereafter. Retesting is 
not required on a rubber-lined tank except before each relining.
    (d) Intermediate periodic inspection and test. For IM and UN 
portable tanks the intermediate 2.5 year periodic inspection and test 
must include at least an internal and external examination of the 
portable tank and its fittings taking into account the hazardous 
materials intended to be transported; a leakage test; and a test of the 
satisfactory operation of all service equipment. Sheathing, thermal 
insulation, etc. need only be removed to the extent required for 
reliable appraisal of the condition of the portable tank. For portable 
tanks intended for the transportation of a single hazardous material, 
the internal examination may be waived if it is leakage tested in 
accordance with the procedures in paragraph (h) of this section prior to 
each filling, or if approved by the Associate Administrator. Portable 
tanks used for dedicated transportation of refrigerated liquefied gases 
that are not fitted with inspection openings are excepted from the 
internal inspection requirement.
    (e) Periodic inspection and test. The 5 year periodic inspection and 
test must include an internal and external examination and, unless 
excepted, a pressure test as specified in this section. Sheathing, 
thermal insulation, etc. need only to be removed to the extent required 
for reliable appraisal of the condition of the portable tank. Except for 
DOT Specification 56 and 57 portable tanks, reclosing pressure relief 
devices must be removed from the tank and tested separately unless they 
can be tested while installed on the portable tank. For portable tanks 
where the shell and equipment have been pressure-tested separately, 
after assembly they must be subjected together to a leakage test and 
effectively tested and inspected for corrosion. Portable tanks used for 
the transportation of refrigerated, liquefied gases are excepted from 
the requirement for internal inspection and the hydraulic

[[Page 386]]

pressure test during the 5-year periodic inspection and test, if the 
portable tanks were pressure tested to a minimum test pressure of 1.3 
times the design pressure using an inert gas as prescribed in Sec.  
178.338-16(a) and (b) of this subchapter before putting the portable 
tank into service initially and after any exceptional inspections and 
tests specified in paragraph (f) of this section.
    (f) Exceptional inspection and test. The exceptional inspection and 
test is necessary when a portable tank shows evidence of damaged or 
corroded areas, or leakage, or other conditions that indicate a 
deficiency that could affect the integrity of the portable tank. The 
extent of the exceptional inspection and test must depend on the amount 
of damage or deterioration of the portable tank. It must include at 
least the inspection and a pressure test according to paragraph (e) of 
this section. Pressure relief devices need not be tested or replaced 
unless there is reason to believe the relief devices have been affected 
by the damage or deterioration.
    (g) Internal and external examination. The internal and external 
examinations must ensure that:
    (1) The shell is inspected for pitting, corrosion, or abrasions, 
dents, distortions, defects in welds or any other conditions, including 
leakage, that might render the portable tank unsafe for transportation. 
The wall thickness must be verified by appropriate measurement if this 
inspection indicates a reduction of wall thickness;
    (2) The piping, valves, and gaskets are inspected for corroded 
areas, defects, and other conditions, including leakage, that might 
render the portable tank unsafe for filling, discharge or 
transportation;
    (3) Devices for tightening manhole covers are operative and there is 
no leakage at manhole covers or gaskets;
    (4) Missing or loose bolts or nuts on any flanged connection or 
blank flange are replaced or tightened;
    (5) All emergency devices and valves are free from corrosion, 
distortion and any damage or defect that could prevent their normal 
operation. Remote closure devices and self-closing stop-valves must be 
operated to demonstrate proper operation;
    (6) Required markings on the portable tank are legible and in 
accordance with the applicable requirements; and
    (7) The framework, the supports and the arrangements for lifting the 
portable tank are in satisfactory condition.
    (h) Pressure test procedures for specification 51, 56, 57, 60, IM or 
UN portable tanks. (1) Each Specification 57 portable tank must be leak 
tested by a minimum sustained air pressure of at least 3 psig applied to 
the entire tank. Each Specification 51 or 56 portable tank must be 
tested by a minimum pressure (air or hydrostatic) of at least 2 psig or 
at least one and one-half times the design pressure (maximum allowable 
working pressure, or re-rated pressure) of the tank, whichever is 
greater. The leakage test for portable tanks used for refrigerated 
liquefied gas must be performed at 90% of MAWP. Leakage tests for all 
other portable tanks must be at a pressure of at least 25% of MAWP. 
During each air pressure test, the entire surface of all joints under 
pressure must be coated with or immersed in a solution of soap and 
water, heavy oil, or other material suitable for the purpose of 
detecting leaks. The pressure must be held for a period of time 
sufficiently long to assure detection of leaks, but in no case less than 
five minutes. During the air or hydrostatic test, relief devices may be 
removed, but all the closure fittings must be in place and the relief 
device openings plugged. Lagging need not be removed from a lagged tank 
if it is possible to maintain the required test pressure at constant 
temperature with the tank disconnected from the source of pressure.
    (2) Each Specification 60 portable tank must be retested by 
completely filling the tank with water or other liquid having a similar 
viscosity, the temperature of the liquid must not exceed 37.7 [deg]C 
(100 [deg]F) during the test, and applying a pressure of 60 psig. The 
portable tank must be capable of holding the prescribed pressure for at 
least 10 minutes without leakage, evidence of impending failure, or 
failure. All closures shall be in place while the test is made and the 
pressure shall be gauged at the top of the tank. Safety devices and/or 
vents shall be plugged during this test.

[[Page 387]]

    (3) Each Specification IM or UN portable tank, except for UN 
portable tanks used for non-refrigerated and refrigerated liquefied 
gases, and all piping, valves and accessories, except pressure relief 
devices, must be hydrostatically tested with water, or other liquid of 
similar density and viscosity, to a pressure not less than 150% of its 
maximum allowable working pressure. UN portable tanks used for the 
transportation of non-refrigerated liquefied gases must be 
hydrostatically tested with water, or other liquid of similar density 
and viscosity, to a pressure not less than 130% of its maximum allowable 
working pressure. UN portable tanks used for the transportation of 
refrigerated liquefied gases may be tested hydrostatically or 
pneumatically using an inert gas to a pressure not less than 1.3 times 
the design pressure. For pneumatic testing, due regard for protection of 
all personnel must be taken because of the potential hazard involved in 
such a test. The pneumatic test pressure in the portable tank must be 
reached by gradually increasing the pressure to one-half of the test 
pressure. Thereafter, the test pressure must be increased in steps of 
approximately one-tenth of the test pressure until the required test 
pressure has been reached. The pressure must then be reduced to a value 
equal to four-fifths of the test pressure and held for a sufficient time 
to permit inspection of the portable tank for leaks. The minimum test 
pressure for a portable tank is determined on the basis of the hazardous 
materials that are intended to be transported in the portable tanks. For 
liquid, solid and non-refrigerated liquefied gases, the minimum test 
pressure for specific hazardous materials are specified in the 
applicable T Codes assigned to a particular hazardous material in the 
Sec.  172.101 Table of this subchapter. While under pressure the tank 
shall be inspected for leakage, distortion, or any other condition which 
might render the tank unsafe for service. A portable tank fails to meet 
the requirements of the pressure test if, during the test, there is 
permanent distortion of the tank exceeding that permitted by the 
applicable specification; if there is any leakage; or if there are any 
deficiencies that would render the portable tank unsafe for 
transportation. Any portable tank that fails must be rejected and may 
not be used again for the transportation of a hazardous material unless 
the tank is adequately repaired, and, thereafter, a successful test is 
conducted in accordance with the requirements of this paragraph. An 
approval agency shall witness the hydrostatic or pneumatic test. Any 
damage or deficiency that might render the portable tank unsafe for 
service shall be repaired to the satisfaction of the witnessing approval 
agency. The repaired tank must be retested to the original pressure test 
requirements. Upon successful completion of the hydrostatic or pneumatic 
test, as applicable, the witnessing approval agency shall apply its 
name, identifying mark or identifying number in accordance with 
paragraph (k) of this section.
    (i) Rejection criteria. When evidence of any unsafe condition is 
discovered, the portable tank may not be returned to service until it 
has been repaired and the pressure test is repeated and passed.
    (j) Repair. The repair of a portable tank is authorized, provided 
such repairs are made in accordance with the requirements prescribed in 
the specification for the tank's original design and construction. In 
addition to any other provisions of the specification, no portable tank 
may be repaired so as to cause leakage or cracks or so as to increase 
the likelihood of leakage or cracks near areas of stress concentration 
due to cooling metal shrinkage in welding operations, sharp fillets, 
reversal of stresses, or otherwise. No field welding may be done except 
to non-pressure parts. Any cutting, burning or welding operations on the 
shell of an IM or UN portable tank must be done with the approval of the 
approval agency and be done in accordance with the requirements of this 
subchapter, taking into account the pressure vessel code used for the 
construction of the shell. A pressure test to the original test pressure 
must be performed after the work is completed.
    (k) Inspection and test markings. (1) Each IM or UN portable tank 
must be durably and legibly marked, in English, with the date (month and

[[Page 388]]

year) of the last pressure test, the identification markings of the 
approval agency witnessing the test, when required, and the date of the 
last visual inspection. The marking must be placed on or near the metal 
identification plate, in letters and numerals of not less than 3 mm 
(0.118 inches) high when on the metal identification plate, and 12 mm 
(0.47 inches) high when on the portable tank.
    (2) Each Specification DOT 51, 56, 57 or 60 portable tank must be 
durably and legibly marked, in English, with the date (month and year) 
of the most recent periodic retest. The marking must be placed on or 
near the metal certification plate and must be in accordance with Sec.  
178.3 of this subchapter. The letters and numerals must not be less than 
3 mm (0.118 inches) high when on the metal certification plate, and 12 
mm (0.47 inches) high when on the portable tank, except that a portable 
tank manufactured under a previously authorized specification may 
continue to be marked with smaller markings if originally authorized 
under that specification (for example, DOT Specification 57 portable 
tanks).
    (l) Record retention. (1) The owner of each portable tank or his 
authorized agent shall retain a written record of the date and results 
of all required inspections and tests, including an ASME manufacturer's 
date report, if applicable, and the name and address of the person 
performing the inspection or test, in accordance with the applicable 
specification. The manufacturer's data report, including a 
certificate(s) signed by the manufacturer, and the authorized design 
approval agency, as applicable, indicating compliance with the 
applicable specification of the portable tank, and related papers 
certifying that the portable tank was manufactured and tested in 
accordance with the applicable specification must be retained in the 
files of the owner, or his authorized agent, during the time that such 
portable tank is used for such service, except for Specifications 56 and 
57 portable tanks.
    (2) If the owner does not have the manufacturer's certificate 
required by the specification and the manufacturer's data report 
required by the ASME, the owner may contact the National Board for a 
copy of the manufacturer's data report, if the portable tank was 
registered with the National Board, or copy the information contained on 
the portable tanks specification plate and ASME Code data plates.

[Amdt. 180-2, 54 FR 25032, June 12, 1989, as amended at 67 FR 15744, 
Apr. 3, 2002; 68 FR 45042, July 31, 2003; 74 FR 53189, Oct. 16, 2009; 82 
FR 15897, Mar. 30, 2017; 83 FR 55811, Nov. 7, 2018; 87 FR 79785, Dec. 
27, 2022]





Sec. Appendix A to Part 180--Internal Self-closing Stop Valve Emergency 
               Closure Test for Liquefied Compressed Gases

    1. In performing this test, all internal self-closing stop valves 
must be opened. Each emergency discharge control remote actuator (on-
truck and off-truck) must be operated to ensure that each internal self-
closing stop valve's lever, piston, or other valve indicator has moved 
to the closed position.
    2. On pump-actuated pressure differential internal valves, the 
three-way toggle valve handle or its cable attachment must be activated 
to verify that the toggle handle moves to the closed position.

[64 FR 28052, May 24, 1999, as amended at 67 FR 15744, Apr. 3, 2002]



Sec. Appendix B to Part 180--Acceptable Internal Self-closing Stop Valve 
  Leakage Tests for Cargo Tanks Transporting Liquefied Compressed Gases

    For internal self-closing stop valve leakage testing, leakage is 
defined as any leakage through the internal self-closing valve or to the 
atmosphere that is detectable when the valve is in the closed position. 
On some valves this will require the closure of the pressure by-pass 
port.

                          (a) Meter Creep Test.

    1. An operator of a cargo tank equipped with a calibrated meter may 
check the internal self-closing stop valve for leakage through the valve 
seat using the meter as a flow measurement indicator. The test is 
initiated by starting the delivery process or returning product to the 
cargo tank through the delivery system. This may be performed at an 
idle. After the flow is established, the operator closes the internal 
self-closing stop valve and monitors the meter flow. The meter flow must 
stop within 30 seconds with no meter creep within 5 seconds after the 
meter stops.

[[Page 389]]

    2. On pump-actuated pressure differential internal self-closing stop 
valves, the valve must be closed with the remote actuator to assure that 
it is functioning. On other types of internal self-closing stop valves, 
the valve(s) may be closed using either the normal valve control or the 
discharge control system (e.g., remote).
    3. Rejection criteria: Any detectable meter creep within the first 
five seconds after initial meter stoppage.

               (b) Internal Self-Closing Stop Valve Test.

    An operator of a cargo tank that is not equipped with a meter may 
check the internal self-closing stop valve(s) for leakage as follows:
    1. The internal self-closing stop valve must be in the closed 
position.
    2. All of the material in the downstream piping must be evacuated, 
and the piping must be returned to atmospheric temperature and pressure.
    3. The outlet must be monitored for 30 seconds for detectable 
leakage.
    4. Rejection criteria. Any detectable leakage is considered 
unacceptable.

[64 FR 28052, May 24, 1999]



   Sec. Appendix C to Part 180--Eddy Current Examination With Visual 
 Inspection for DOT 3AL Cylinders Manufactured of Aluminum Alloy 6351-T6

    1. Examination Procedure. Each facility performing eddy current 
examination with visual inspection must develop, update, and maintain a 
written examination procedure applicable to the test equipment it uses 
to perform eddy current examinations.
    2. Visual examinations. Visual examinations of the neck and shoulder 
area of the cylinder must be conducted in accordance with CGA pamphlet 
C-6.1 (IBR; see Sec.  171.7 of this subchapter).
    3. Eddy Current Equipment. A reference ring and probe for each DOT-
3AL cylinder manufactured of aluminum alloy 6351-T6 to be inspected must 
be available at the examination facility. Eddy current equipment must be 
capable of accurately detecting the notches on the standard reference 
ring.
    4. Eddy Current Reference Ring. The reference ring must be produced 
to represent each cylinder to be tested. The reference ring must include 
artificial notches to simulate a neck crack. The size of the artificial 
notch (depth and length) must have a depth less than or equal to \1/3\ 
of the wall thickness of the neck and a length greater than or equal to 
two threads. The standard reference must have a drawing that includes 
the diameter of the ring, and depth and length of each notch.
    5. Condemnation Criteria. A cylinder must be condemned if the eddy 
current examination combined with visual examination reveals any crack 
in the neck or shoulder of 2 thread lengths or more.
    6. Examination equipment records. Records of eddy current inspection 
equipment shall contain the following information:
    (i) Equipment manufacturer, model number and serial number.
    (ii) Probe description and unique identification (e.g., serial 
number, part number, etc.).
    7. Eddy current examination reporting and record retention 
requirements. Daily records of eddy current examinations must be 
maintained by the person who performs the requalification until either 
the expiration of the requalification period or until the cylinder is 
again requalified, whichever occurs first. These records shall be made 
available for inspection by a representative of the Department on 
request. Eddy current examination records shall contain the following 
information:
    (i) Specification of each standard reference ring used to perform 
the eddy current examination.
    (ii) DOT specification or exemption number of the cylinder; 
manufacturer's name or symbol; owner's name or symbol, if present; 
serial number; and, date of manufacture.
    (iii) Name of test operator performing the eddy current examination.
    (iv) Date of eddy current examination.
    (vi) Acceptance/condemnation results (e.g., pass or fail).
    (vii) Retester identification number.
    8. Personnel Qualification Requirements. Each person who performs 
eddy current and visual examinations, and evaluates and certifies retest 
results must be certified by the employer that he/she has been properly 
trained and tested in the eddy current and visual examination 
procedures.
    9. Training Records. A record of current training must be maintained 
for each employee who performs eddy current and visual examinations in 
accordance with Sec.  172.704(d).

[71 FR 51129, Aug. 29, 2006]



 Sec. Appendix D to Part 180--Hazardous Materials Corrosive to Tanks or 
                            Service Equipment

    This list contains materials identified either by proper shipping 
name in 49 CFR 172.101 or shipped under an ``n.o.s.'' shipping 
description that, under certain conditions, can corrode carbon steel 
tanks or service equipment at a rate that may reduce the design level of 
reliability and safety of the tank or equipment to an unsafe level 
before the next qualification. Materials identified on this list are 
considered corrosive to the tank or service equipment.
    While every effort was made to identify materials deemed corrosive 
to the tank or

[[Page 390]]

service equipment, owners and operators are cautioned that this list may 
not be inclusive. Tank car owners and operators are reminded of their 
duty to ensure that no in-service tank will deteriorate below the 
specified minimum thickness requirements in this subchapter. See Sec.  
180.509(f)(3). In addition, FRA states a tank car owner must designate 
an internal coating or lining appropriately based on its knowledge of 
the chemical and not rely simply on this list. Regarding future 
thickness tests, this list may also be modified based on an analysis of 
the test results by the car owner, the Department of Transportation, or 
the Association of American Railroads' Tank Car Committee.

   Hazardous Materials Table Proper Shipping Names (See Sec.  172.101)

Acetic acid, glacial or Acetic acid solution
Aluminum chloride, solution
Arsenic acid, liquid
Arsenic acid, solid
Butyric acid
Ferric chloride, solution
Fertilizer ammoniating solution (Nitrogen fertilizer solution)
Fluoroboric acid
Fluorosilicic acid
Formaldehyde, solutions, flammable
Formaldehyde, solutions
Hydrobromic acid
Hydrochloric acid
Hydrochloric acid solution
Hydrofluoric acid and Sulfuric acid mixtures
Hydrofluoric acid
Hydrogen peroxide and peroxyacetic acid mixtures, stabilized
Hydrogen, peroxide, aqueous solutions
Hydrogen peroxide, stabilized or Hydrogen peroxide aqueous solutions, 
stabilized
Hypochlorite solutions
Nitric acid
Phenyl phosphorus dichloride
Phenyl phosphorus thiodichloride
Phosphoric acid solution
Phosphoric acid, solid
Phosphorus trichloride (Phosphorus chloride)
Sodium chlorate
Sodium chlorate, aqueous solution
Sodium hydrosulfide
Sulfur, molten
Sulfuric acid
Sulfuric acid, fuming
Sulfuric acid, spent
Zinc chloride, anhydrous
Zinc chloride, solution

          Materials Transported Under an ``N.O.S.'' Description

Benzoic acid (Environmentally hazardous substance, liquid, n.o.s., (RQ 
5,000 pounds)
Bisulphites, aqueous solution, n.o.s. (Ammonium bisulfide)
Black liquor (Corrosive liquids, n.o.s. (contains sulfuric acid))
Calcium lignosulfonate (not regulated under this subchapter)
Hexanoic acid (Corrosive liquids, n.o.s. (contains hexanoic acid))
Lignin liquor (not regulated under this subchapter)
Lithium chloride (not regulated under this subchapter)
Sodium polyacrylate (not regulated under this subchapter)
Titanium sulfate solution (Corrosive liquids, n.o.s. (contains sulfuric 
acid))
White liquor (not regulated under this subchapter)

[77 FR 37991, June 25, 2012]

                        PARTS 181	185 [RESERVED]

[[Page 391]]



                      SUBCHAPTER D_PIPELINE SAFETY



                        PARTS 186	189 [RESERVED]



PART 190_PIPELINE SAFETY ENFORCEMENT AND REGULATORY PROCEDURES--Table of 
                                 Contents



                            Subpart A_General

Sec.
190.1 Purpose and scope.
190.3 Definitions.
190.5 Service.
190.7 Subpoenas; witness fees.
190.9 Petitions for finding or approval.
190.11 Availability of informal guidance and interpretive assistance.

                          Subpart B_Enforcement

190.201 Purpose and scope.
190.203 Inspections and investigations.
190.205 Warnings.
190.206 Amendment of plans or procedures.
190.207 Notice of probable violation.
190.208 Response options.
190.209 Case file.
190.210 Separation of functions.
190.211 Hearing.
190.212 Presiding official, powers, and duties.
190.213 Final order.
190.215 Reserved.

                            Compliance Orders

190.217 Compliance orders generally.
190.219 Consent order.

                             Civil Penalties

190.221 Civil penalties generally.
190.223 Maximum penalties.
190.225 Assessment considerations.
190.227 Payment of penalty.

                           Criminal Penalties

190.229-190.231 [Reserved]

                             Specific Relief

190.233 Corrective action orders.
190.235 Injunctive action.
190.236 Emergency orders: Procedures for issuance and rescission.
190.237 Emergency orders: Petitions for review.
190.239 Safety orders.
190.241 Finality.
190.243 Petitions for reconsideration.

                     Subpart C_Criminal Enforcement

190.291 Criminal penalties generally.
190.293 Criminal referrals.

               Subpart D_Procedures for Adoption of Rules

190.301 Scope.
190.303 Delegations.
190.305 Regulatory dockets.
190.307 Records.
190.309 Where to file petitions.
190.311 General.
190.313 Initiation of rulemaking.
190.315 Contents of notices of proposed rulemaking.
190.317 Participation by interested persons.
190.319 Petitions for extension of time to comment.
190.321 Contents of written comments.
190.323 Consideration of comments received.
190.325 Additional rulemaking proceedings.
190.327 Hearings.
190.329 Adoption of final rules.
190.331 Petitions for rulemaking.
190.333 Processing of petition.
190.335 Petitions for reconsideration.
190.337 Proceedings on petitions for reconsideration.
190.338 Appeals.
190.339 Direct final rulemaking.
190.341 Special permits.
190.343 Information made available to the public and request for 
          protection of confidential commercial information.

               Subpart E_Cost Recovery for Design Reviews

190.401 Scope.
190.403 Applicability.
190.405 Notification.
190.407 Master Agreement.
190.409 Fee structure.
190.411 Procedures for billing and payment of fee.

    Authority: 33 U.S.C. 1321(b); 49 U.S.C. 60101 et seq.

    Source: 45 FR 20413, Mar. 27, 1980, unless otherwise noted.

    Editorial Note: Nomenclature changes to part 190 appear at 78 FR 
58908, Sept. 25, 2013.



                            Subpart A_General



Sec.  190.1  Purpose and scope.

    (a) This part prescribes procedures used by the Pipeline and 
Hazardous Materials Safety Administration in carrying out duties 
regarding pipeline safety under 49 U.S.C. 60101 et seq. (the pipeline 
safety laws) and 33 U.S.C. 1321 (the water pollution control laws).

[[Page 392]]

    (b) This subpart defines certain terms and prescribes procedures 
that are applicable to each proceeding described in this part.

[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-6, 61 FR 18512, 
Apr. 26, 1996; 70 FR 11137, Mar. 8, 2005; Amdt. 190-16, 78 FR 58908, 
Sept. 25, 2013]



Sec.  190.3  Definitions.

    As used in this part:
    Administrator means the Administrator, Pipeline and Hazardous 
Materials Safety Administration or his or her delegate.
    Associate Administrator means the Associate Administrator for 
Pipeline Safety, or his or her delegate.
    Chief Counsel means the Chief Counsel of PHMSA.
    Day means a 24-hour period ending at 11:59 p.m. Unless otherwise 
specified, a day refers to a calendar day.
    Emergency order means a written order issued in response to an 
imminent hazard imposing restrictions, prohibitions, or safety measures 
on owners and operators of gas or hazardous liquid pipeline facilities, 
without prior notice or an opportunity for a hearing.
    Formal hearing means a formal review in accordance with 5 U.S.C. 
554, conducted by an administrative law judge.
    Hearing means an informal conference or a proceeding for oral 
presentation. Unless otherwise specifically prescribed in this part, the 
use of ``hearing'' is not intended to require a hearing on the record in 
accordance with section 554 of title 5, U.S.C.
    Imminent hazard means the existence of a condition relating to a gas 
or hazardous liquid pipeline facility that presents a substantial 
likelihood that death, serious illness, severe personal injury, or a 
substantial endangerment to health, property, or the environment may 
occur before the reasonably foreseeable completion date of a formal 
proceeding begun to lessen the risk of such death, illness, injury or 
endangerment.
    New and novel technologies means any products, designs, materials, 
testing, construction, inspection, or operational procedures that are 
not addressed in 49 CFR parts 192, 193, or 195, due to technology or 
design advances and innovation for new construction. Technologies that 
are addressed in consensus standards that are incorporated by reference 
into parts 192, 193, and 195 are not ``new or novel technologies.''
    OPS means the Office of Pipeline Safety, which is part of the 
Pipeline and Hazardous Materials Safety Administration, U.S. Department 
of Transportation.
    Operator means any owner or operator.
    Person means any individual, firm, joint venture, partnership, 
corporation, association, State, municipality, cooperative association, 
or joint stock association, and includes any trustee, receiver, 
assignee, or personal representative thereof.
    Presiding Official means the person who conducts any hearing 
relating to civil penalty assessments, compliance orders, orders 
directing amendment, safety orders, or corrective action orders and who 
has the duties and powers set forth in Sec.  190.212.
    Regional Director means the head of any one of the Regional Offices 
of the Office of Pipeline Safety, or a designee appointed by the 
Regional Director. Regional Offices are located in Trenton, NJ (Eastern 
Region); Atlanta, Georgia (Southern Region); Kansas City, Missouri 
(Central Region); Houston, Texas (Southwest Region); and Lakewood, 
Colorado (Western Region).
    Respondent means a person upon whom OPS has served an enforcement 
action described in this part.
    PHMSA means the Pipeline and Hazardous Materials Safety 
Administration of the United States Department of Transportation.
    State means a State of the United States, the District of Columbia 
and the Commonwealth of Puerto Rico.

[Amdt. 190-6, 61 FR 18513, Apr. 26, 1996, as amended at 68 FR 11749, 
Mar. 12, 2003; 70 FR 11137, Mar. 8, 2005; Amdt. 190-15, 74 FR 62505, 
Nov. 30, 2009; Amdt. 190-16, 78 FR 58908, Sept. 25, 2013; Amdt. 190-18, 
81 FR 70985, Oct. 14, 2016; Amdt. 190-19, 82 FR 7995, Jan. 23, 2017; 
Amdt. 190-21, 84 FR 52026, Oct. 1, 2019]



Sec.  190.5  Service.

    (a) Each order, notice, or other document required to be served 
under this part, will be served personally, by certified mail, overnight 
courier, or electronic transmission by facsimile or

[[Page 393]]

other electronic means that includes reliable acknowledgement of actual 
receipt.
    (b) Service upon a person's duly authorized representative or agent 
constitutes service upon that person.
    (c) Service by certified mail or overnight courier is complete upon 
mailing. Service by electronic transmission is complete upon 
transmission and acknowledgement of receipt. An official receipt for the 
mailing from the U.S. Postal Service or overnight courier, or a 
facsimile or other electronic transmission confirmation, constitutes 
prima facie evidence of service.

[45 FR 20413, Mar. 27, 1980, as amended at 73 FR 16567, Mar. 28, 2008; 
Amdt. 190-16, 78 FR 58909, Sept. 25, 2013; Amdt. 190-18, 81 FR 70985, 
Oct. 14, 2016; Amdt. 190-21, 84 FR 52026, Oct. 1, 2019]



Sec.  190.7  Subpoenas; witness fees.

    (a) The Administrator, Chief Counsel, or the official designated by 
the Administrator to preside over a hearing convened in accordance with 
this part, may sign and issue subpoenas individually on his or her own 
initiative at any time, including pursuant to an inspection or 
investigation, or upon request and adequate showing by a participant to 
an enforcement proceeding that the information sought will materially 
advance the proceeding.
    (b) A subpoena may require the attendance of a witness, or the 
production of documentary or other tangible evidence in the possession 
or under the control of person served, or both.
    (c) A subpoena may be served personally by any person who is not an 
interested person and is not less than 18 years of age, or by certified 
mail.
    (d) Service of a subpoena upon the person named in the subpoena is 
achieved by delivering a copy of the subpoena to the person and by 
paying the fees for one day's attendance and mileage, as specified by 
paragraph (g) of this section. When a subpoena is issued at the instance 
of any officer or agency of the United States, fees and mileage need not 
be tendered at the time of service. Delivery of a copy of a subpoena and 
tender of the fees to a natural person may be made by handing them to 
the person, leaving them at the person's office with a person in charge, 
leaving them at the person's residence with a person of suitable age and 
discretion residing there, by mailing them by certified mail to the 
person at the last known address, or by any method whereby actual notice 
is given to the person and the fees are made available prior to the 
return date.
    (e) When the person to be served is not a natural person, delivery 
of a copy of the subpoena and tender of the fees may be achieved by 
handing them to a designated agent or representative for service, or to 
any officer, director, or agent in charge of any office of the person, 
or by mailing them by certified mail to that agent or representative and 
the fees are made available prior to the return date.
    (f) The original subpoena bearing a certificate of service shall be 
filed with the official having responsibility for the proceeding in 
connection with which the subpoena was issued.
    (g) A subpoenaed witness shall be paid the same fees and mileage as 
would be paid to a witness in a proceeding in the district courts of the 
United States. The witness fees and mileage shall be paid by the person 
at whose instance the subpoena was issued.
    (h) Notwithstanding the provisions of paragraph (g) of this section, 
and upon request, the witness fees and mileage may be paid by the PHMSA 
if the official who issued the subpoena determines on the basis of good 
cause shown, that:
    (1) The presence of the subpoenaed witness will materially advance 
the proceeding; and
    (2) The person at whose instance the subpoena was issued would 
suffer a serious hardship if required to pay the witness fees and 
mileage.
    (i) Any person to whom a subpoena is directed may, prior to the time 
specified therein for compliance, but in no event more than 10 days 
after the date of service of such subpoena, apply to the official who 
issued the subpoena, or if the person is unavailable, to the 
Administrator to quash or modify the subpoena. The application shall 
contain a brief statement of the reasons relied upon in support of the 
action sought therein. The Administrator, or

[[Page 394]]

this issuing official, as the case may be, may:
    (1) Deny the application;
    (2) Quash or modify the subpoena; or
    (3) Condition a grant or denial of the application to quash or 
modify the subpoena upon the satisfaction of certain just and reasonable 
requirements. The denial may be summary.
    (j) Upon refusal to obey a subpoena served upon any person under the 
provisions of this section, the PHMSA may request the Attorney General 
to seek the aid of the U. S. District Court for any District in which 
the person is found to compel that person, after notice, to appear and 
give testimony, or to appear and produce the subpoenaed documents before 
the PHMSA, or both.

[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-6, 61 FR 18513, 
Apr. 26, 1996; Amdt. 190-7, 63 FR 7722, Feb. 17, 1998; 70 FR 11137, Mar. 
8, 2005; Amdt. 190-16, 78 FR 58909, Sept. 25, 2013]



Sec.  190.9  Petitions for finding or approval.

    (a) In circumstances where a rule contained in parts 192, 193 and 
195 of this chapter authorizes the Administrator to make a finding or 
approval, an operator may petition the Administrator for such a finding 
or approval.
    (b) Each petition must refer to the rule authorizing the action 
sought and contain information or arguments that justify the action. 
Unless otherwise specified, no public proceeding is held on a petition 
before it is granted or denied. After a petition is received, the 
Administrator or participating state agency notifies the petitioner of 
the disposition of the petition or, if the request requires more 
extensive consideration or additional information or comments are 
requested and delay is expected, of the date by which action will be 
taken.
    (1) For operators seeking a finding or approval involving intrastate 
pipeline transportation, petitions must be sent to:
    (i) The State agency certified to participate under 49 U.S.C. 60105.
    (ii) Where there is no state agency certified to participate, the 
Administrator, Pipeline and Hazardous Materials Safety Administration, 
1200 New Jersey Avenue, SE, Washington, DC 20590.
    (2) For operators seeking a finding or approval involving interstate 
pipeline transportation, petitions must be sent to the Administrator, 
Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey 
Avenue, SE, Washington, DC 20590.
    (c) All petitions must be received at least 90 days prior to the 
date by which the operator requests the finding or approval to be made.
    (d) The Administrator will make all findings or approvals of 
petitions initiated under this section. A participating state agency 
receiving petitions initiated under this section shall provide the 
Administrator a written recommendation as to the disposition of any 
petition received by them. Where the Administrator does not reverse or 
modify a recommendation made by a state agency within 10 business days 
of its receipt, the recommended disposition shall constitute the 
Administrator's decision on the petition.

[Amdt. 190-5, 59 FR 17280, Apr. 12, 1994, as amended by Amdt. 190-6, 61 
FR 18513, Apr. 26, 1996; 70 FR 11137, Mar. 8, 2005; 73 FR 16566, Mar. 
28, 2008]



Sec.  190.11  Availability of informal guidance and interpretive assistance.

    (a) Availability of telephonic and Internet assistance. PHMSA has 
established a Web site and a telephone line to OPS headquarters where 
information on and advice about compliance with the pipeline safety 
regulations specified in 49 CFR parts 190-199 is available. The Web site 
and telephone line are staffed by personnel from PHMSA's OPS from 9:00 
a.m. through 5:00 p.m., Eastern Time, Monday through Friday, with the 
exception of Federal holidays. When the lines are not staffed, 
individuals may leave a recorded voicemail message or post a message on 
the OPS Web site. The telephone number for the OPS information line is 
(202) 366-4595 and the OPS Web site can be accessed via the Internet at 
http://phmsa.dot.gov/pipeline.
    (b) Availability of written interpretations. A written regulatory 
interpretation, response to a question, or an opinion concerning a 
pipeline safety issue may be obtained by submitting a

[[Page 395]]

written request to the Office of Pipeline Safety (PHP-30), PHMSA, U.S. 
Department of Transportation, 1200 New Jersey Avenue SE., Washington, DC 
20590-0001. The requestor must include his or her return address and 
should also include a daytime telephone number. Written requests should 
be submitted at least 120 days before the time the requestor needs a 
response.

[Amdt. 190-16, 78 FR 58909, Sept. 25, 2013]



                          Subpart B_Enforcement



Sec.  190.201  Purpose and scope.

    (a) This subpart describes the enforcement authority and sanctions 
exercised by the Associate Administrator for achieving and maintaining 
pipeline safety and compliance under 49 U.S.C. 60101 et seq., 33 U.S.C. 
1321(j), and any regulation or order issued thereunder. It also 
prescribes the procedures governing the exercise of that authority and 
the imposition of those sanctions.
    (b) A person who is the subject of action pursuant to this subpart 
may be represented by legal counsel at all stages of the proceeding.

[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-6, 61 FR 18513, 
Apr. 26, 1996; Amdt. 190-16, 78 FR 58909, Sept. 25, 2013]



Sec.  190.203  Inspections and investigations.

    (a) Officers, employees, or agents authorized by the Associate 
Administrator for Pipeline Safety, PHMSA, upon presenting appropriate 
credentials, are authorized to enter upon, inspect, and examine, at 
reasonable times and in a reasonable manner, the records and properties 
of persons to the extent such records and properties are relevant to 
determining the compliance of such persons with the requirements of 49 
U.S.C. 60101 et seq., or regulations or orders issued thereunder.
    (b) Inspections are ordinarily conducted pursuant to one of the 
following:
    (1) Routine scheduling by the Regional Director of the Region in 
which the facility is located;
    (2) A complaint received from a member of the public;
    (3) Information obtained from a previous inspection;
    (4) Report from a State Agency participating in the Federal Program 
under 49 U.S.C. 60105;
    (5) Pipeline accident or incident; or
    (6) Whenever deemed appropriate by the Associate Administrator.
    (c) If the Associate Administrator or Regional Director believes 
that further information is needed to determine appropriate action, the 
Associate Administrator or Regional Director may notify the pipeline 
operator in writing that the operator is required to provide specific 
information within 30 days from the time the notification is received by 
the operator, unless otherwise specified in the notification. The 
notification must provide a reasonable description of the specific 
information required. An operator may request an extension of time to 
respond by providing a written justification as to why such an extension 
is necessary and proposing an alternative submission date. A request for 
an extension may ask for the deadline to be stayed while the extension 
is considered. General statements of hardship are not acceptable bases 
for requesting an extension.
    (d) To the extent necessary to carry out the responsibilities under 
49 U.S.C. 60101 et seq., the Administrator, or the Associate 
Administrator, may require testing of portions of pipeline facilities 
that have been involved in, or affected by, an accident. However, before 
exercising this authority, the Administrator, or the Associate 
Administrator, shall make every effort to negotiate a mutually 
acceptable plan with the owner of those facilities and, where 
appropriate, the National Transportation Safety Board for performing the 
testing.
    (e) If a representative of the U.S. Department of Transportation 
inspects or investigates an accident or incident involving a pipeline 
facility, the operator must make available to the representative all 
records and information that pertain to the event in any way, including 
integrity management plans and test results. The operator must provide 
all reasonable assistance in the investigation. Any person who obstructs 
an inspection or investigation by taking actions that were known or 
reasonably should have been known to

[[Page 396]]

prevent, hinder, or impede an investigation without good cause will be 
subject to administrative civil penalties under this subpart.
    (f) When OPS determines that the information obtained from an 
inspection or from other appropriate sources warrants further action, 
OPS may initiate one or more of the enforcement proceedings prescribed 
in this subpart.

[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-3, 56 FR 31090, 
July 9, 1991; Amdt. 190-6, 61 FR 18513, Apr. 26, 1996; Amdt. 190-7, 61 
FR 27792, June 3, 1996; Amdt. 190-7, 63 FR 7722, Feb. 17, 1998; 70 FR 
11137, Mar. 8, 2005; Amdt. 190-16, 78 FR 58909, Sept. 25, 2013]



Sec.  190.205  Warnings.

    Upon determining that a probable violation of 49 U.S.C. 60101 et 
seq., 33 U.S.C. 1321(j), or any regulation or order issued thereunder 
has occurred, the Associate Administrator or a Regional Director may 
issue a written warning notifying the operator of the probable violation 
and advising the operator to correct it or be subject to potential 
enforcement action in the future. The operator may submit a response to 
a warning, but is not required to. An adjudication under this subpart to 
determine whether a violation occurred is not conducted for warnings.

[Amdt. 190-16, 78 FR 58909, Sept. 25, 2013]



Sec.  190.206  Amendment of plans or procedures.

    (a) A Regional Director begins a proceeding to determine whether an 
operator's plans or procedures required under parts 192, 193, 195, and 
199 of this subchapter are inadequate to assure safe operation of a 
pipeline facility by issuing a notice of amendment. The notice will 
specify the alleged inadequacies and the proposed revisions of the plans 
or procedures and provide an opportunity to respond. The notice will 
allow the operator 30 days following receipt of the notice to submit 
written comments, revised procedures, or a request for a hearing under 
Sec.  190.211.
    (b) After considering all material presented in writing or at the 
hearing, if applicable, the Associate Administrator determines whether 
the plans or procedures are inadequate as alleged. The Associate 
Administrator issues an order directing amendment of the plans or 
procedures if they are inadequate, or withdraws the notice if they are 
not. In determining the adequacy of an operator's plans or procedures, 
the Associate Administrator may consider:
    (1) Relevant pipeline safety data;
    (2) Whether the plans or procedures are appropriate for the 
particular type of pipeline transportation or facility, and for the 
location of the facility;
    (3) The reasonableness of the plans or procedures; and
    (4) The extent to which the plans or procedures contribute to public 
safety.
    (c) An order directing amendment of an operator's plans or 
procedures prescribed in this section may be in addition to, or in 
conjunction with, other appropriate enforcement actions prescribed in 
this subpart.

[Amdt. 190-16, 78 FR 58910, Sept. 25, 2013]



Sec.  190.207  Notice of probable violation.

    (a) Except as otherwise provided by this subpart, a Regional 
Director begins an enforcement proceeding by serving a notice of 
probable violation on a person charging that person with a probable 
violation of 49 U.S.C. 60101 et seq., 33 U.S.C. 1321(j), or any 
regulation or order issued thereunder.
    (b) A notice of probable violation issued under this section shall 
include:
    (1) Statement of the provisions of the laws, regulations or orders 
which the respondent is alleged to have violated and a statement of the 
evidence upon which the allegations are based;
    (2) Notice of response options available to the respondent under 
Sec.  190.208;
    (3) If a civil penalty is proposed under Sec.  190.221, the amount 
of the proposed civil penalty and the maximum civil penalty for which 
respondent is liable under law; and
    (4) If a compliance order is proposed under Sec.  190.217, a 
statement of the remedial action being sought in the form of a proposed 
compliance order.
    (c) The Regional Director may amend a notice of probable violation 
at any time prior to issuance of a final order under Sec.  190.213. If 
an amendment includes any new material allegations of fact, proposes an 
increased civil penalty amount, or proposes new or additional remedial 
action under Sec.  190.217,

[[Page 397]]

the respondent will have the opportunity to respond under Sec.  190.208.

[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-6, 61 FR 18513, 
Apr. 26, 1996; Amdt. 190-16, 78 FR 58910, Sept. 25, 2013]



Sec.  190.208  Response options.

    Within 30 days of receipt of a notice of probable violation, the 
respondent must answer the Regional Director who issued the notice in 
the following manner:
    (a) When the notice contains a proposed civil penalty--
    (1) If the respondent is not contesting an allegation of probable 
violation, pay the proposed civil penalty as provided in Sec.  190.227 
and advise the Regional Director of the payment. The payment authorizes 
the Associate Administrator to make a finding of violation and to issue 
a final order under Sec.  190.213;
    (2) If the respondent is not contesting an allegation of probable 
violation but wishes to submit a written explanation, information, or 
other materials the respondent believes may warrant mitigation or 
elimination of the proposed civil penalty, the respondent may submit 
such materials. This authorizes the Associate Administrator to make a 
finding of violation and to issue a final order under Sec.  190.213;
    (3) If the respondent is contesting one or more allegations of 
probable violation but is not requesting a hearing under Sec.  190.211, 
the respondent may submit a written response in answer to the 
allegations; or
    (4) The respondent may request a hearing under Sec.  190.211.
    (b) When the notice contains a proposed compliance order--
    (1) If the respondent is not contesting an allegation of probable 
violation, agree to the proposed compliance order. This authorizes the 
Associate Administrator to make a finding of violation and to issue a 
final order under Sec.  190.213;
    (2) Request the execution of a consent order under Sec.  190.219;
    (3) If the respondent is contesting one or more of the allegations 
of probable violation or compliance terms, but is not requesting a 
hearing under Sec.  190.211, the respondent may object to the proposed 
compliance order and submit written explanations, information, or other 
materials in answer to the allegations in the notice of probable 
violation; or
    (4) The respondent may request a hearing under Sec.  190.211.
    (c) Before or after responding in accordance with paragraph (a) of 
this section or, when applicable paragraph (b) of this section, the 
respondent may request a copy of the violation report from the Regional 
Director as set forth in Sec.  190.209. The Regional Director will 
provide the violation report to the respondent within five business days 
of receiving a request.
    (d) Failure to respond in accordance with paragraph (a) of this 
section or, when applicable paragraph (b) of this section, constitutes a 
waiver of the right to contest the allegations in the notice of probable 
violation and authorizes the Associate Administrator, without further 
notice to the respondent, to find the facts as alleged in the notice of 
probable violation and to issue a final order under Sec.  190.213.
    (e) All materials submitted by operators in response to enforcement 
actions may be placed on publicly accessible Web sites. A respondent 
seeking confidential treatment under 5 U.S.C. 552(b) for any portion of 
its responsive materials must provide a second copy of such materials 
along with the complete original document. A respondent may redact the 
portions it believes qualify for confidential treatment in the second 
copy but must provide a written explanation for each redaction.

[Amdt. 190-16, 78 FR 58910, Sept. 25, 2013]



Sec.  190.209  Case file.

    (a) The case file, as defined in this section, is available to the 
respondent in all enforcement proceedings conducted under this subpart.
    (b) The case file of an enforcement proceeding consists of the 
following:
    (1) In cases commenced under Sec.  190.206, the notice of amendment 
and the relevant procedures;
    (2) In cases commenced under Sec.  190.207, the notice of probable 
violation and the violation report;
    (3) In cases commenced under Sec.  190.233, the corrective action 
order or notice of proposed corrective action order and the data report, 
if one is prepared;

[[Page 398]]

    (4) In cases commenced under Sec.  190.239, the notice of proposed 
safety order;
    (5) Any documents and other material submitted by the respondent in 
response to the enforcement action;
    (6) In cases involving a hearing, any material submitted during and 
after the hearing as set forth in Sec.  190.211; and
    (7) The Regional Director's written evaluation of response material 
submitted by the respondent and recommendation for final action, if one 
is prepared.

[Amdt. 190-16, 78 FR 58910, Sept. 25, 2013]



Sec.  190.210  Separation of functions.

    (a) General. An agency employee who assists in the investigation or 
prosecution of an enforcement case may not participate in the decision 
of that case or a factually related one, but may participate as a 
witness or counsel at a hearing as set forth in this subpart. Likewise, 
an agency employee who prepares a decision in an enforcement case may 
not have served in an investigative or prosecutorial capacity in that 
case or a factually related one.
    (b) Prohibition on ex parte communications. A party to an 
enforcement proceeding, including the respondent, its representative, or 
an agency employee having served in an investigative or prosecutorial 
capacity in the proceeding, may not communicate privately with the 
Associate Administrator, Presiding Official, or attorney drafting the 
recommended decision concerning information that is relevant to the 
questions to be decided in the proceeding. A party may communicate with 
the Presiding Official regarding administrative or procedural issues, 
such as for scheduling a hearing.

[Amdt. 190-16, 78 FR 58911, Sept. 25, 2013]



Sec.  190.211  Hearing.

    (a) General. This section applies to hearings conducted under this 
part relating to civil penalty assessments, compliance orders, orders 
directing amendment, safety orders, and corrective action orders. The 
Presiding Official will convene hearings conducted under this section.
    (b) Hearing request and statement of issues. A request for a hearing 
must be accompanied by a statement of the issues that the respondent 
intends to raise at the hearing. The issues may relate to the 
allegations in the notice, the proposed corrective action, or the 
proposed civil penalty amount. A respondent's failure to specify an 
issue may result in waiver of the respondent's right to raise that issue 
at the hearing. The respondent's request must also indicate whether or 
not the respondent will be represented by counsel at the hearing. The 
respondent may withdraw a request for a hearing in writing and provide a 
written response.
    (c) Telephonic and in-person hearings. A telephone hearing will be 
held if the amount of the proposed civil penalty or the cost of the 
proposed corrective action is less than $25,000, unless the respondent 
or OPS submits a written request for an in-person hearing. In-person 
hearings will normally be held at the office of the appropriate OPS 
Region. Hearings may be held by video teleconference if the necessary 
equipment is available to all parties.
    (d) Pre-hearing submissions. If OPS or the respondent intends to 
introduce material, including records, documents, and other exhibits not 
already in the case file, the material must be submitted to the 
Presiding Official and the other party at least 10 days prior to the 
date of the hearing, unless the Presiding Official sets a different 
deadline or waives the deadline for good cause.
    (e) Conduct of the hearing. The hearing is conducted informally 
without strict adherence to rules of evidence. The Presiding Official 
regulates the course of the hearing and gives each party an opportunity 
to offer facts, statements, explanations, documents, testimony or other 
evidence that is relevant and material to the issues under 
consideration. The parties may call witnesses on their own behalf and 
examine the evidence and witnesses presented by the other party. After 
the evidence in the case has been presented, the Presiding Official will 
permit reasonable discussion of the issues under consideration.
    (f) Written transcripts. If a respondent elects to transcribe a 
hearing, the respondent must make arrangements

[[Page 399]]

with a court reporter at cost to the respondent and submit a complete 
copy of the transcript for the case file. The respondent must notify the 
Presiding Official in advance if it intends to transcribe a hearing.
    (g) Post-hearing submission. The respondent and OPS may request an 
opportunity to submit further written material after the hearing for 
inclusion in the record. The Presiding Official will allow a reasonable 
time for the submission of the material and will specify the submission 
date. If the material is not submitted within the time prescribed, the 
case will proceed to final action without the material.
    (h) Preparation of decision. After consideration of the case file, 
the Presiding Official prepares a recommended decision in the case, 
which is then forwarded to the Associate Administrator for issuance of a 
final order.

[Amdt. 190-16, 78 FR 58911, Sept. 25, 2013]



Sec.  190.212  Presiding official, powers, and duties.

    (a) General. The Presiding Official for a hearing conducted under 
Sec.  190.211 is an attorney on the staff of the Deputy Chief Counsel 
who is not engaged in any investigative or prosecutorial functions, such 
as the issuance of notices under this subpart. If the designated 
Presiding Official is unavailable, the Deputy Chief Counsel may delegate 
the powers and duties specified in this section to another attorney in 
the Office of Chief Counsel who is not engaged in any investigative or 
prosecutorial functions under this subpart.
    (b) Time and place of the hearing. The Presiding Official will set 
the date, time and location of the hearing. To the extent practicable, 
the Presiding Official will accommodate the parties' schedules when 
setting the hearing. Reasonable notice of the hearing will be provided 
to all parties.
    (c) Powers and duties of Presiding Official. The Presiding Official 
will conduct a fair and impartial hearing and take all action necessary 
to avoid delay in the disposition of the proceeding and maintain order. 
The Presiding Official has all powers necessary to achieve those ends, 
including, but not limited to the power to:
    (1) Regulate the course of the hearing and conduct of the parties 
and their counsel;
    (2) Receive evidence and inquire into the relevant and material 
facts;
    (3) Require the submission of documents and other information;
    (4) Direct that documents or briefs relate to issues raised during 
the course of the hearing;
    (5) Set the date for filing documents, briefs, and other items;
    (6) Prepare a recommended decision; and
    (7) Exercise the authority necessary to carry out the 
responsibilities of the Presiding Official under this subpart.

[Amdt. 190-16, 78 FR 58911, Sept. 25, 2013]



Sec.  190.213  Final order.

    (a) In an enforcement proceeding commenced under Sec.  190.207, an 
attorney from the Office of Chief Counsel prepares a recommended 
decision after expiration of the 30-day response period prescribed in 
Sec.  190.208. If a hearing is held, the Presiding Official prepares the 
recommended decision as set forth in Sec.  190.211. The recommended 
decision is forwarded to the Associate Administrator who considers the 
case file and issues a final order. The final order includes--
    (1) A statement of findings and determinations on all material 
issues, including a determination as to whether each alleged violation 
has been proved;
    (2) If a civil penalty is assessed, the amount of the penalty and 
the procedures for payment of the penalty, provided that the assessed 
civil penalty may not exceed the penalty proposed in the notice of 
probable violation; and
    (3) If a compliance order is issued, a statement of the actions 
required to be taken by the respondent and the time by which such 
actions must be accomplished.
    (b) In cases where a substantial delay is expected in the issuance 
of a final order, notice of that fact and the date by which it is 
expected that action will be taken is provided to the respondent upon 
request and whenever practicable.

[Amdt. 190-16, 78 FR 58911, Sept. 25, 2013]

[[Page 400]]



Sec.  190.215  [Reserved]

                            Compliance Orders



Sec.  190.217  Compliance orders generally.

    When a Regional Director has reason to believe that a person is 
engaging in conduct that violates 49 U.S.C. 60101 et seq., 33 U.S.C. 
1321(j), or any regulation or order issued thereunder, and if the nature 
of the violation and the public interest so warrant, the Regional 
Director may initiate proceedings under Sec. Sec.  190.207 through 
190.213 to determine the nature and extent of the violations and for the 
issuance of an order directing compliance.

[Amdt. 190-16, 78 FR 58912, Sept. 25, 2013]



Sec.  190.219  Consent order.

    (a) At any time prior to the issuance of a compliance order under 
Sec.  190.217, a corrective action order under Sec.  190.233, or a 
safety order under Sec.  190.239, the Regional Director and the 
respondent may agree to resolve the case by execution of a consent 
agreement and order, which may be jointly executed by the parties and 
issued by the Associate Administrator. Upon execution, the consent order 
is considered a final order under Sec.  190.213.
    (b) A consent order executed under paragraph (a) of this section 
shall include:
    (1) An admission by the respondent of all jurisdictional facts;
    (2) An express waiver of further procedural steps and of all right 
to seek judicial review or otherwise challenge or contest the validity 
of that order;
    (3) An acknowledgement that the notice of probable violation may be 
used to construe the terms of the consent order; and
    (4) A statement of the actions required of the respondent and the 
time by which such actions shall be accomplished.
    (c) Prior to the execution of a consent agreement and order arising 
out of a corrective action order under Sec.  190.233, the Associate 
Administrator will notify any appropriate State official in accordance 
with 49 U.S.C. 60112(c).

[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-6, 61 FR 18514, 
Apr. 26, 1996; Amdt. 190-16, 78 FR 58912, Sept. 25, 2013]

                             Civil Penalties



Sec.  190.221  Civil penalties generally.

    When a Regional Director has reason to believe that a person has 
committed an act violating 49 U.S.C. 60101 et seq., 33 U.S.C. 1321(j), 
or any regulation or order issued thereunder, the Regional Director may 
initiate proceedings under Sec. Sec.  190.207 through 190.213 to 
determine the nature and extent of the violations and appropriate civil 
penalty.

[Amdt. 190-16, 78 FR 58912, Sept. 25, 2013]



Sec.  190.223  Maximum penalties.

    (a) Any person found to have violated a provision of 49 U.S.C. 
60101, et seq., or any regulation in 49 CFR parts 190 through 199, or 
order issued pursuant to 49 U.S.C. 60101, et seq. or 49 CFR part 190, is 
subject to an administrative civil penalty not to exceed $257,664 for 
each violation for each day the violation continues, with a maximum 
administrative civil penalty not to exceed $2,576,627 for any related 
series of violations.
    (b) Any person found to have violated a provision of 33 U.S.C. 
1321(j), or any regulation or order issued thereunder, is subject to an 
administrative civil penalty under 33 U.S.C. 1321(b)(6), as adjusted by 
40 CFR 19.4.
    (c) Any person found to have violated any standard or order under 49 
U.S.C. 60103 is subject to an administrative civil penalty not to exceed 
$94,128, which may be in addition to other penalties to which such 
person may be subject under paragraph (a) of this section.
    (d) Any person who is determined to have violated any standard or 
order under 49 U.S.C. 60129 is subject to an administrative civil 
penalty not to exceed $1,496, which may be in addition to other 
penalties to which such person may be subject under paragraph (a) of 
this section.
    (e) Separate penalties for violating a regulation prescribed under 
this subchapter and for violating an order issued under Sec. Sec.  
190.206, 190.213, 190.233,

[[Page 401]]

or 190.239 may not be imposed under this section if both violations are 
based on the same act.

[Amdt. 190-16, 78 FR 58912, Sept. 25, 2013, as amended at 81 FR 42566, 
June 30, 2016; Amdt. 190-17, 82 FR 19328, Apr. 27, 2017; 84 FR 37071, 
July 31, 2019; 86 FR 1756, Jan 11, 2021; 86 FR 23252, May 3, 2021; 87 FR 
15866, Mar. 21, 2022; 88 FR 1125, Jan. 6, 2023]



Sec.  190.225  Assessment considerations.

    In determining the amount of a civil penalty under this part,
    (a) The Associate Administrator will consider:
    (1) The nature, circumstances and gravity of the violation, 
including adverse impact on the environment;
    (2) The degree of the respondent's culpability;
    (3) The respondent's history of prior offenses;
    (4) Any good faith by the respondent in attempting to achieve 
compliance;
    (5) The effect on the respondent's ability to continue in business; 
and
    (b) The Associate Administrator may consider:
    (1) The economic benefit gained from violation, if readily 
ascertainable, without any reduction because of subsequent damages; and
    (2) Such other matters as justice may require.

[Amdt. 190-16, 78 FR 58912, Sept. 25, 2013]



Sec.  190.227  Payment of penalty.

    (a) Except for payments exceeding $10,000, payment of a civil 
penalty proposed or assessed under this subpart may be made by certified 
check or money order (containing the CPF Number for the case), payable 
to ``U.S. Department of Transportation,'' to the Federal Aviation 
Administration, Mike Monroney Aeronautical Center, Financial Operations 
Division (AMZ-341), P.O. Box 25770, Oklahoma City, OK 73125, or by wire 
transfer through the Federal Reserve Communications System (Fedwire) to 
the account of the U.S. Treasury, or via https://www.pay.gov. Payments 
exceeding $10,000 must be made by wire transfer.
    (b) Payment of a civil penalty assessed in a final order issued 
under Sec.  190.213 or affirmed in a decision on a petition for 
reconsideration must be made within 20 days after receipt of the final 
order or decision. Failure to do so will result in the initiation of 
collection action, including the accrual of interest and penalties, in 
accordance with 31 U.S.C. 3717 and 49 CFR part 89.

[Amdt. 190-7, 61 FR 27792, June 3, 1996, as amended at 70 FR 11138, Mar. 
8, 2005; 73 FR 16567, Mar. 28, 2008; Amdt. 190-16, 78 FR 58912, Sept. 
25, 2013]



Sec. Sec.  190.229-190.231  [Reserved]

                             Specific Relief



Sec.  190.233  Corrective action orders.

    (a) Generally. Except as provided by paragraph (b) of this section, 
if the Associate Administrator finds, after reasonable notice and 
opportunity for hearing in accord with paragraph (c) of this section, a 
particular pipeline facility is or would be hazardous to life, property, 
or the environment, the Associate Administrator may issue an order 
pursuant to this section requiring the operator of the facility to take 
corrective action. Corrective action may include suspended or restricted 
use of the facility, physical inspection, testing, repair, replacement, 
or other appropriate action.
    (b) Waiver of notice and expedited review. The Associate 
Administrator may waive the requirement for notice and opportunity for 
hearing under paragraph (a) of this section before issuing an order 
whenever the Associate Administrator determines that the failure to do 
so would result in the likelihood of serious harm to life, property, or 
the environment. When an order is issued under this paragraph, a 
respondent that contests the order may obtain expedited review of the 
order either by answering in writing to the order within 10 days of 
receipt or requesting a hearing under Sec.  190.211 to be held as soon 
as practicable in accordance with paragraph (c)(2) of this section. For 
purposes of this section, the term ``expedited review'' is defined as 
the process for making a prompt determination of whether the order 
should remain in effect or be amended or terminated. The expedited 
review of an order issued under this paragraph will be complete upon 
issuance of such determination.
    (c) Notice and hearing:

[[Page 402]]

    (1) Written notice that OPS intends to issue an order under this 
section will be served upon the owner or operator of an alleged 
hazardous facility in accordance with Sec.  190.5. The notice must 
allege the existence of a hazardous facility and state the facts and 
circumstances supporting the issuance of a corrective action order. The 
notice must provide the owner or operator with an opportunity to respond 
within 10 days of receipt.
    (2) An owner or operator that elects to exercise its opportunity for 
a hearing under this section must notify the Associate Administrator of 
that election in writing within 10 days of receipt of the notice 
provided under paragraph (c)(1) of this section, or the order under 
paragraph (b) of this section when applicable. The absence of such 
written notification waives an owner or operator's opportunity for a 
hearing.
    (3) At any time after issuance of a notice or order under this 
section, the respondent may request a copy of the case file as set forth 
in Sec.  190.209.
    (4) A hearing under this section is conducted pursuant to Sec.  
190.211. The hearing should be held within 15 days of receipt of the 
respondent's request for a hearing.
    (5) After conclusion of a hearing under this section, the Presiding 
Official submits a recommended decision to the Associate Administrator 
as to whether or not the facility is or would be hazardous to life, 
property, or the environment, and if necessary, requiring expeditious 
corrective action. If a notice or order is contested in writing without 
a hearing, an attorney from the Office of Chief Counsel prepares the 
recommended decision. The recommended decision should be submitted to 
the Associate Administrator within five business days after conclusion 
of the hearing or after receipt of the respondent's written objection if 
no hearing is held. Upon receipt of the recommendation, the Associate 
Administrator will proceed in accordance with paragraphs (d) through (h) 
of this section. If the Associate Administrator finds the facility is or 
would be hazardous to life, property, or the environment, the Associate 
Administrator issues a corrective action order in accordance with this 
section, or confirms (or amends) the corrective action order issued 
under paragraph (b) of this section. If the Associate Administrator does 
not find the facility is or would be hazardous to life, property, or the 
environment, the Associate Administrator withdraws the notice or 
terminates the order issued under paragraph (b) of this section, and 
promptly notifies the operator in writing by service as prescribed in 
Sec.  190.5.
    (d) The Associate Administrator may find a pipeline facility to be 
hazardous under paragraph (a) of this section:
    (1) If under the facts and circumstances the Associate Administrator 
determines the particular facility is hazardous to life, property, or 
the environment; or
    (2) If the pipeline facility or a component thereof has been 
constructed or operated with any equipment, material, or technique which 
the Associate Administrator determines is hazardous to life, property, 
or the environment, unless the operator involved demonstrates to the 
satisfaction of the Associate Administrator that, under the particular 
facts and circumstances involved, such equipment, material, or technique 
is not hazardous.
    (e) In making a determination under paragraph (d) of this section, 
the Associate Administrator shall consider, if relevant:
    (1) The characteristics of the pipe and other equipment used in the 
pipeline facility involved, including its age, manufacturer, physical 
properties (including its resistance to corrosion and deterioration), 
and the method of its manufacture, construction or assembly;
    (2) The nature of the materials transported by such facility 
(including their corrosive and deteriorative qualities), the sequence in 
which such materials are transported, and the pressure required for such 
transportation;
    (3) The characteristics of the geographical areas in which the 
pipeline facility is located, in particular the climatic and geologic 
conditions (including soil characteristics) associated with such areas, 
and the population density and population and growth patterns of such 
areas;
    (4) Any recommendation of the National Transportation Safety Board

[[Page 403]]

issued in connection with any investigation conducted by the Board; and
    (5) Such other factors as the Associate Administrator may consider 
appropriate.
    (f) A corrective action order shall contain the following 
information:
    (1) A finding that the pipeline facility is or would be hazardous to 
life, property, or the environment.
    (2) The relevant facts which form the basis of that finding.
    (3) The legal basis for the order.
    (4) The nature and description of any particular corrective action 
required of the respondent.
    (5) The date by which the required corrective action must be taken 
or completed and, where appropriate, the duration of the order.
    (6) If the opportunity for a hearing was waived pursuant to 
paragraph (b) of this section, a statement that an opportunity for a 
hearing will be available at a particular time and location after 
issuance of the order.
    (g) The Associate Administrator will terminate a corrective action 
order whenever the Associate Administrator determines that the facility 
is no longer hazardous to life, property, or the environment. If 
appropriate, however, a notice of probable violation may be issued under 
Sec.  190.207.
    (h) At any time after a corrective action order issued under this 
section has become effective, the Associate Administrator may request 
the Attorney General to bring an action for appropriate relief in 
accordance with Sec.  190.235.
    (i) Upon petition by the Attorney General, the District Courts of 
the United States shall have jurisdiction to enforce orders issued under 
this section by appropriate means.

[70 FR 11138, Mar. 8, 2005, as amended by Amdt. 190-16, 78 FR 58912, 
Sept. 25, 2013]



Sec.  190.235  Civil actions generally.

    Whenever it appears to the Associate Administrator that a person has 
engaged, is engaged, or is about to engage in any act or practice 
constituting a violation of any provision of 49 U.S.C. 60101 et seq., or 
any regulations issued thereunder, the Administrator, or the person to 
whom the authority has been delegated, may request the Attorney General 
to bring an action in the appropriate U.S. District Court for such 
relief as is necessary or appropriate, including mandatory or 
prohibitive injunctive relief, interim equitable relief, civil 
penalties, and punitive damages as provided under 49 U.S.C. 60120 and 49 
U.S.C. 5123.

[70 FR 11139, Mar. 8, 2005]



Sec.  190.236  Emergency orders: Procedures for issuance and rescision.

    (a) Determination of imminent hazard. When the Administrator 
determines that an unsafe condition or practice, or a combination of 
unsafe conditions and practices, constitutes or is causing an imminent 
hazard, as defined in Sec.  190.3, the Administrator may issue or impose 
an emergency order, without advance notice or an opportunity for a 
hearing, but only to the extent necessary to abate the imminent hazard. 
The order will contain a written description of:
    (1) The violation, condition, or practice that constitutes or is 
causing the imminent hazard;
    (2) Those entities subject to the order;
    (3) The restrictions, prohibitions, or safety measures imposed;
    (4) The standards and procedures for obtaining relief from the 
order;
    (5) How the order is tailored to abate the imminent hazard and the 
reasons the authorities under 49 U.S.C. 60112 and 60117(l) are 
insufficient to do so; and
    (6) How the considerations listed in paragraph (c) of this section 
were taken into
    account.
    (b) Consultation. In considering the factors under paragraph (c) of 
this section, the Administrator shall consult, as the Administrator 
determines appropriate, with appropriate Federal agencies, State 
agencies, and other entities knowledgeable in pipeline safety or 
operations.
    (c) Considerations. Prior to issuing an emergency order, the 
Administrator shall consider the following, as appropriate:
    (1) The impact of the emergency order on public health and safety;
    (2) The impact, if any, of the emergency order on the national or 
regional economy or national security;

[[Page 404]]

    (3) The impact of the emergency order on the ability of owners and 
operators of pipeline facilities to maintain reliability and continuity 
of service to customers; and
    (4) The results of any consultations with appropriate Federal 
agencies, State agencies, and other entities knowledgeable in pipeline 
safety or operations.
    (d) Service. The Administrator will provide service of emergency 
orders in accordance with Sec.  190.5 to all operators of gas and 
hazardous liquid pipeline facilities that the Administrator reasonably 
expects to be affected by the emergency order. In addition, the 
Administrator will publish emergency orders in the Federal Register and 
post them on the PHMSA website as soon as practicable upon issuance. 
Publication in the Federal Register will serve as general notice of an 
emergency order. Each emergency order must contain information 
specifying how pipeline operators and owners may respond to the 
emergency order, filing procedures, and service requirements, including 
the address of DOT Docket Operations and the names and addresses of all 
persons to be served if a petition for review is filed.
    (e) Rescission. If an emergency order has been in effect for more 
than 365 days, the Administrator will make an assessment regarding 
whether the unsafe condition or practice, or combination of unsafe 
conditions and practices, constituting or causing an imminent hazard, as 
defined in Sec.  190.3, continues to exist. If the imminent hazard does 
not continue to exist, the Administrator will rescind the emergency 
order and follow the service procedures set forth in Sec.  190.236(d). 
If the imminent hazard underlying the emergency order continues to 
exist, PHMSA will initiate a rulemaking action as soon as practicable.

[Amdt. 190-21, 84 FR 52027, Oct. 1, 2019]



Sec.  190.237  Emergency orders: Petitions for review.

    (a) Requirements. A pipeline owner or operator that is subject to 
and aggrieved by an emergency order may petition the Administrator for 
review to determine whether the order will remain in place, be modified, 
or be terminated. A petition for review must:
    (1) Be in writing;
    (2) State with particularity each part of the emergency order that 
is sought to be modified or terminated and include all information, 
evidence and arguments in support thereof;
    (3) State whether the petitioner requests a formal hearing in 
accordance with 5 U.S.C. 554, and, if so, any material facts in dispute; 
and,
    (4) Be filed and served in accordance with paragraph (h) of this 
section.
    (b) Modification of petitions. A petitioner may modify its petition 
for review to provide new information that materially affects the review 
proceeding and that is timely submitted. Where the petitioner has not 
requested a formal hearing, the Associate Administrator will make the 
determination whether to accept the new information. Where a case has 
been assigned for a formal hearing, the presiding administrative law 
judge will determine whether to accept the new information.
    (c) Response to the petition for review. An attorney designated by 
the Office of Chief Counsel may file and serve, in accordance with 
paragraph (h) of this section, a response to the petition, including 
appropriate pleadings, within five calendar days of receipt of the 
petition by the Chief Counsel.
    (d) Associate Administrator's responsibilities.--(1) Formal hearing 
requested. Upon receipt of a petition for review that includes a formal 
hearing request under this section, the Associate Administrator will, 
within three days after receipt of the petition, assign the petition to 
the Office of Hearings, DOT, for a formal hearing.
    (2) No formal hearing requested. Upon receipt of a petition for 
review that does not include a formal hearing request, the Associate 
Administrator will issue an administrative decision on the merits within 
30 days of receipt of the petition for review. The Associate 
Administrator's decision constitutes the agency's final decision.
    (3) Consolidation. If the Associate Administrator receives more than 
one petition for review and they share common issues of law or fact, the 
Associate Administrator may consolidate the petitions for the purpose of 
complying

[[Page 405]]

with this section, provided such consolidation occurs prior to the 
commencement of a formal hearing. The Associate Administrator may 
reassign a petition that does not request a formal hearing to the Office 
of Hearings, DOT, provided the petition otherwise meets the requirements 
for consolidation. If the Associate Administrator has consolidated 
multiple petitions that do not request a formal hearing, he may de-
consolidate such petitions if there has been a change in circumstances 
that, in his discretion, warrant separation for the purpose of rendering 
a final decision.
    (e) Formal Hearings. Formal hearings must be conducted by an 
administrative law judge assigned by the chief administrative law judge 
of the Office of Hearings, DOT. The administrative law judge may:
    (1) Administer oaths and affirmations;
    (2) Issue subpoenas as provided by the appropriate statutes and 
agency regulations (e.g., 49 U.S.C. 60117 and 49 CFR 190.7);
    (3) Adopt the relevant Federal Rules of Civil Procedure for the 
United States District Courts for the procedures governing the hearings, 
when appropriate;
    (4) Adopt the relevant Federal Rules of Evidence for United States 
Courts and Magistrates for the submission of evidence, when appropriate;
    (5) Take or cause depositions to be taken;
    (6) Examine witnesses at the hearing;
    (7) Rule on offers of proof and receive relevant evidence;
    (8) Convene, recess, adjourn or otherwise regulate the course of the 
hearing;
    (9) Hold conferences for settlement, simplification of the issues, 
or any other proper purpose; and
    (10) Take any other action authorized by or consistent with the 
provisions of this part and permitted by law that may expedite the 
hearing or aid in the disposition of an issue raised.
    (f) Parties. The petitioner may appear and be heard in person or by 
an authorized representative. PHMSA will be represented by an attorney 
designated by the Office of Chief Counsel.
    (g) Burden of proof. Except in the case of an affirmative defense, 
PHMSA shall bear the burden of proving, by a preponderance of the 
evidence, the validity of an emergency order in a proceeding under this 
section by a preponderance of the evidence. A party asserting an 
affirmative defense shall bear the burden of proving, by a preponderance 
of the evidence, the affirmative defense in a proceeding under this 
section.
    (h) Filing and service. (1) Each petition, pleading, motion, notice, 
order, or other document submitted in connection with an emergency order 
issued under this section must be filed (commercially delivered or 
submitted electronically) with: U.S. Department of Transportation, 
Docket Operations, M-30, West Building Ground Floor, Room W12-140, 1200 
New Jersey Avenue SE, Washington, DC 20590. All documents filed will be 
published on the Department's docket management website, http://
www.regulations.gov. The emergency order must state the above filing 
requirements and the address of DOT Docket Operations.
    (2) Each document filed in accordance with paragraph (h)(1) of this 
section must be concurrently served upon the following persons:
    (i) Associate Administrator for Pipeline Safety, OPS, Pipeline and 
Hazardous Materials Safety Administration, U.S. Department of 
Transportation, 1200 New Jersey Avenue SE, East Building, Washington, DC 
20590;
    (ii) Chief Counsel, PHC, Pipeline and Hazardous Materials Safety 
Administration, U.S. Department of Transportation, 1200 New Jersey 
Avenue SE, East Building, Washington, DC 20590 (facsimile: 202-366-
7041); and
    (iii) If the petition for review requests a formal hearing, the 
Chief Administrative Law Judge, U.S. Department of Transportation, 
Office of Hearings, 1200 New Jersey Ave SE, c/o Mail Center (E11-310), 
Washington, DC 20590 (facsimile: 202-366-7536).
    (3) Service must be made in accordance with Sec.  190.5 of this 
part. The emergency order must state all relevant service requirements 
and list the persons to be served and may be updated as necessary.

[[Page 406]]

    (4) Certificate of service. Each order, pleading, motion, notice, or 
other document must be accompanied by a certificate of service 
specifying the manner in which and the date on which service was made.
    (5) If applicable, service upon a person's duly authorized 
representative, agent for service, or an organization's president or 
chief executive officer constitutes service upon that person.
    (i) Report and recommendation. The administrative law judge must 
issue a report and recommendation to the Associate Administrator at the 
close of the record. The report and recommendation must:
    (1) Contain findings of fact and conclusions of law and the grounds 
for the decision, based on the material issues of fact or law presented 
on the record;
    (2) Be served on the parties to the proceeding; and
    (3) Be issued no later than 25 days after receipt of the petition 
for review by the Associate Administrator.
    (j) Petition for reconsideration. (1) A petitioner aggrieved by the 
administrative law judge's report and recommendation may file a petition 
for reconsideration with the Associate Administrator. The petition for 
reconsideration must be filed:
    (i) Not more than five days after the administrative law judge has 
issued a report and recommendation under paragraph (i) of this section, 
provided such report and recommendation is issued 20 days or less after 
the petition for review was filed with PHMSA; or
    (ii) Not more than two days after the administrative law judge has 
issued his or her report and recommendation under paragraph (h) of this 
section, where such report and recommendation are issued more than 20 
days after the petition for review was filed with PHMSA.
    (2) The Associate Administrator must issue a decision on a petition 
for reconsideration no later than 30 days after receipt of the petition 
for review. Such decision constitutes final agency action on a petition 
for review.
    (k) Judicial review. (1) After the issuance of a final agency 
decision pursuant to paragraphs (d)(2) or (j)(2) of this section, or the 
issuance of a written determination by the Administrator pursuant to 
paragraph (l) of this section, a pipeline owner or operator subject to 
and aggrieved by an emergency order issued under Sec.  190.236 may seek 
judicial review of the order in the appropriate district court of the 
United States. The filing of an action seeking judicial review does not 
stay or modify the force and effect of the agency's final decision under 
paragraphs (d)(2) or (j)(3) of this section, or the written 
determination under paragraph (l) of this section, unless stayed or 
modified by the Administrator.
    (l) Expiration of order. (1) No petition for review filed: If no 
petition for review is filed challenging the emergency order, then the 
emergency order shall remain in effect until PHMSA determines, in 
writing, that the imminent hazard no longer exists or the order is 
terminated by a court of competent jurisdiction.
    (2) Petition for review filed and decision rendered within 30 days. 
If the Associate Administrator renders a final decision upon a petition 
for review within 30 days of its receipt by PHMSA, any elements of the 
emergency order upheld or modified by the decision shall remain in 
effect until PHMSA determines, in writing, that the imminent hazard no 
longer exists or the order is terminated by a court of competent 
jurisdiction.
    (3) Petition for review filed but no decision rendered within 30 
days. If the Associate Administrator has not reached a decision on the 
petition for review within 30 days of receipt of the petition for 
review, the emergency order will cease to be effective unless the 
Administrator determines, in writing, that the imminent hazard providing 
a basis for the emergency order continues to exist.
    (m) Time. In computing any period of time prescribed by this section 
or an order or report and recommendation issued by an administrative law 
judge under this section, the day of filing of a petition for review or 
of any other act, event or default from which the designated period of 
time begins to run will not be included. The last day of the period so 
computed will be included, unless it is a Saturday, Sunday, or Federal 
holiday, in which event the period runs until end of the next day

[[Page 407]]

which is not one of the aforementioned days.

[Amdt. 190-21, 84 FR 52027, Oct. 1, 2019]



Sec.  190.239  Safety orders.

    (a) When may PHMSA issue a safety order? If the Associate 
Administrator finds, after notice and an opportunity for hearing under 
paragraph (b) of this section, that a particular pipeline facility has a 
condition or conditions that pose a pipeline integrity risk to public 
safety, property, or the environment, the Associate Administrator may 
issue an order requiring the operator of the facility to take necessary 
corrective action. Such action may include physical inspection, testing, 
repair or other appropriate action to remedy the identified risk 
condition.
    (b) How is an operator notified of the proposed issuance of a safety 
order and what are its responses options? (1) Notice of proposed safety 
order. PHMSA will serve written notice of a proposed safety order under 
Sec.  190.5 to an operator of the pipeline facility. The notice will 
allege the existence of a condition that poses a pipeline integrity risk 
to public safety, property, or the environment, and state the facts and 
circumstances that support issuing a safety order for the specified 
pipeline or portion thereof. The notice will also specify proposed 
testing, evaluations, integrity assessment, or other actions to be taken 
by the operator and may propose that the operator submit a work plan and 
schedule to address the conditions identified in the notice. The notice 
will also provide the operator with its response options, including 
procedures for requesting informal consultation and a hearing. An 
operator receiving a notice will have 30 days to respond to the PHMSA 
official who issued the notice.
    (2) Informal consultation. Upon timely request by the operator, 
PHMSA will provide an opportunity for informal consultation concerning 
the proposed safety order. Such informal consultation shall commence 
within 30 days, provided that PHMSA may extend this time by request or 
otherwise for good cause. Informal consultation provides an opportunity 
for the respondent to explain the circumstances associated with the risk 
condition(s) identified in the notice and, where appropriate, to present 
a proposal for corrective action, without prejudice to the operator's 
position in any subsequent hearing. If the respondent and Regional 
Director agree within 30 days of the informal consultation on a plan for 
the operator to address each risk condition, they may enter into a 
written consent agreement and the Associate Administrator may issue a 
consent order incorporating the terms of the agreement. If a consent 
agreement is reached, no further hearing will be provided in the matter 
and any pending hearing request will be considered withdrawn. If a 
consent agreement is not reached within 30 days of the informal 
consultation (or if informal consultation is not requested), the 
Associate Administrator may proceed under paragraphs (b)(3) through (5) 
of this section. If PHMSA subsequently determines that an operator has 
failed to comply with the terms of a consent order, PHMSA may obtain any 
administrative or judicial remedies available under 49 U.S.C. 60101 et 
seq. and this part. If a consent agreement is not reached, any 
admissions made by the operator during the informal consultation shall 
be excluded from the record in any subsequent hearing. Nothing in this 
paragraph (b) precludes PHMSA from terminating the informal consultation 
process if it has reason to believe that the operator is not engaging in 
good faith discussions or otherwise concludes that further consultation 
would not be productive or in the public interest.
    (3) Hearing. An operator receiving a notice of proposed safety order 
may contest the notice, or any portion thereof, by filing a written 
request for a hearing within 30 days following receipt of the notice or 
within 10 days following the conclusion of informal consultation that 
did not result in a consent agreement, as applicable. In the absence of 
a timely request for a hearing, the Associate Administrator may issue a 
safety order in the form of the proposed order in accordance with 
paragraphs (c) through (g) of this section.
    (4) Conduct of hearing. An attorney from the Office of Chief 
Counsel, will serve as the Presiding Official in a hearing under this 
section. The hearing

[[Page 408]]

will be conducted informally, without strict adherence to formal rules 
of evidence in accordance with Sec.  190.211. The respondent may submit 
any relevant information or materials, call witnesses, and present 
arguments on the issue of whether a safety order should be issued to 
address the alleged presence of a condition that poses a pipeline 
integrity risk to public safety, property, or the environment.
    (5) Post-hearing action. Following a hearing under this section, the 
Presiding Official will submit a recommendation to the Associate 
Administrator concerning issuance of a final safety order. Upon receipt 
of the recommendation, the Associate Administrator may proceed under 
paragraphs (c) through (g) of this section. If the Associate 
Administrator finds the facility to have a condition that poses a 
pipeline integrity risk to public safety, property, or the environment, 
the Associate Administrator will issue a safety order under this 
section. If the Associate Administrator does not find that the facility 
has such a condition, or concludes that a safety order is otherwise not 
warranted, the Associate Administrator will withdraw the notice and 
promptly notify the operator in writing by service as prescribed in 
Sec.  190.5. Nothing in this subsection precludes PHMSA and the operator 
from entering into a consent agreement at any time before a safety order 
is issued.
    (6) Termination of safety order. Once all remedial actions set forth 
in the safety order and associated work plans are completed, as 
determined by PHMSA, the Associate Administrator will notify the 
operator that the safety order has been lifted. The Associate 
Administrator shall suspend or terminate a safety order whenever the 
Associate Administrator determines that the pipeline facility no longer 
has a condition or conditions that pose a pipeline integrity risk to 
public safety, property, or the environment.
    (c) How is the determination made that a pipeline facility has a 
condition that poses an integrity risk? The Associate Administrator may 
find a pipeline facility to have a condition that poses a pipeline 
integrity risk to public safety, property, or the environment under 
paragraph (a) of this section:
    (1) If under the facts and circumstances the Associate Administrator 
determines the particular facility has such a condition; or
    (2) If the pipeline facility or a component thereof has been 
constructed or operated with any equipment, material, or technique with 
a history of being susceptible to failure when used in pipeline service, 
unless the operator involved demonstrates that such equipment, material, 
or technique is not susceptible to failure given the manner it is being 
used for a particular facility.
    (d) What factors must PHMSA consider in making a determination that 
a risk condition is present? In making a determination under paragraph 
(c) of this section, the Associate Administrator shall consider, if 
relevant:
    (1) The characteristics of the pipe and other equipment used in the 
pipeline facility involved, including its age, manufacturer, physical 
properties (including its resistance to corrosion and deterioration), 
and the method of its manufacture, construction or assembly;
    (2) The nature of the materials transported by such facility 
(including their corrosive and deteriorative qualities), the sequence in 
which such materials are transported, and the pressure required for such 
transportation;
    (3) The characteristics of the geographical areas where the pipeline 
facility is located, in particular the climatic and geologic conditions 
(including soil characteristics) associated with such areas;
    (4) For hazardous liquid pipelines, the proximity of the pipeline to 
an unusually sensitive area;
    (5) The population density and growth patterns of the area in which 
the pipeline facility is located;
    (6) Any relevant recommendation of the National Transportation 
Safety Board issued in connection with any investigation conducted by 
the Board;
    (7) The likelihood that the condition will impair the serviceability 
of the pipeline;
    (8) The likelihood that the condition will worsen over time; and

[[Page 409]]

    (9) The likelihood that the condition is present or could develop on 
other areas of the pipeline.
    (e) What information will be included in a safety order? A safety 
order shall contain the following:
    (1) A finding that the pipeline facility has a condition that poses 
a pipeline integrity risk to public safety, property, or the 
environment;
    (2) The relevant facts which form the basis of that finding;
    (3) The legal basis for the order;
    (4) The nature and description of any particular corrective actions 
to be required of the operator; and
    (5) The date(s) by which the required corrective actions must be 
taken or completed and, where appropriate, the duration of the order.
    (f) Can PHMSA take other enforcement actions on the affected 
facilities? Nothing in this section precludes PHMSA from issuing a 
Notice of Probable Violation under Sec.  190.207 or taking other 
enforcement action if noncompliance is identified at the facilities that 
are the subject of a safety order proceeding.
    (g) May I petition for reconsideration of a safety order? Yes, a 
petition for reconsideration may be submitted in accordance with Sec.  
190.243.

[73 FR 16567, Mar. 28, 2008, as amended at 74 FR 2893, Jan. 16, 2009; 
Amdt. 190-16, 78 FR 58913, Sept. 25, 2013]



Sec.  190.241  Finality.

    Except as otherwise provided by Sec.  190.243, an order directing 
amendment issued under Sec.  190.206, a final order issued under Sec.  
190.213, a corrective action order issued under Sec.  190.233, or a 
safety order issued under Sec.  190.239 is considered final 
administrative action on that enforcement proceeding.

[Amdt. 190-16, 78 FR 58913, Sept. 25, 2013]



Sec.  190.243  Petitions for reconsideration.

    (a) A respondent may petition the Associate Administrator for 
reconsideration of an order directing amendment of plans or procedures 
issued under Sec.  190.206, a final order issued under Sec.  190.213, or 
a safety order issued under Sec.  190.239. The written petition must be 
received no later than 20 days after receipt of the order by the 
respondent. A copy of the petition must be provided to the Chief Counsel 
of the Pipeline and Hazardous Materials Safety Administration, East 
Building, 2nd Floor, Mail Stop E26-105, 1200 New Jersey Ave. SE., 
Washington, DC 20590 or by email to [email protected]. Petitions 
received after that time will not be considered. The petition must 
contain a brief statement of the complaint and an explanation as to why 
the order should be reconsidered.
    (b) If the respondent requests the consideration of additional facts 
or arguments, the respondent must submit the reasons why they were not 
presented prior to issuance of the final order.
    (c) The filing of a petition under this section stays the payment of 
any civil penalty assessed. However, unless the Associate Administrator 
otherwise provides, the order, including any required corrective action, 
is not stayed.
    (d) The Associate Administrator may grant or deny, in whole or in 
part, any petition for reconsideration without further proceedings. If 
the Associate Administrator reconsiders an order under this section, a 
final decision on reconsideration may be issued without further 
proceedings, or, in the alternative, additional information, data, and 
comment may be requested by the Associate Administrator, as deemed 
appropriate.
    (e) It is the policy of the Associate Administrator to expeditiously 
issue notice of the action taken on a petition for reconsideration. In 
cases where a substantial delay is expected, notice of that fact and the 
date by which it is expected that action will be taken is provided to 
the respondent upon request and whenever practicable.
    (f) If the Associate Administrator reconsiders an order under this 
section, the decision on reconsideration is the final administrative 
action on that enforcement proceeding.
    (g) Any application for judicial review must be filed no later than 
89 days after the issuance of the decision in accordance with 49 U.S.C. 
60119(a).
    (h) Judicial review of agency action under 49 U.S.C. 60119(a) will 
apply the standards of review established in 5 U.S.C. 706.

[Amdt. 190-16, 78 FR 58913, Sept. 25, 2013]

[[Page 410]]



                     Subpart C_Criminal Enforcement

    Source: Amdt. 190-16, 78 FR 58914, Sept. 25, 2013, unless otherwise 
noted.



Sec.  190.291  Criminal penalties generally.

    (a) Any person who willfully and knowingly violates a provision of 
49 U.S.C. 60101 et seq. or any regulation or order issued thereunder 
will upon conviction be subject to a fine under title 18, United States 
Code, and imprisonment for not more than five years, or both, for each 
offense.
    (b) Any person who willfully and knowingly injures or destroys, or 
attempts to injure or destroy, any interstate transmission facility, any 
interstate pipeline facility, or any intrastate pipeline facility used 
in interstate or foreign commerce or in any activity affecting 
interstate or foreign commerce (as those terms are defined in 49 U.S.C. 
60101 et seq.) will, upon conviction, be subject to a fine under title 
18, United States Code, imprisonment for a term not to exceed 20 years, 
or both, for each offense.
    (c) Any person who willfully and knowingly defaces, damages, 
removes, or destroys any pipeline sign, right-of-way marker, or marine 
buoy required by 49 U.S.C. 60101 et seq. or any regulation or order 
issued thereunder will, upon conviction, be subject to a fine under 
title 18, United States Code, imprisonment for a term not to exceed 1 
year, or both, for each offense.
    (d) Any person who willfully and knowingly engages in excavation 
activity without first using an available one-call notification system 
to establish the location of underground facilities in the excavation 
area; or without considering location information or markings 
established by a pipeline facility operator; and
    (1) Subsequently damages a pipeline facility resulting in death, 
serious bodily harm, or property damage exceeding $50,000;
    (2) Subsequently damages a pipeline facility and knows or has reason 
to know of the damage but fails to promptly report the damage to the 
operator and to the appropriate authorities; or
    (3) Subsequently damages a hazardous liquid pipeline facility that 
results in the release of more than 50 barrels of product; will, upon 
conviction, be subject to a fine under title 18, United States Code, 
imprisonment for a term not to exceed 5 years, or both, for each 
offense.
    (e) No person shall be subject to criminal penalties under paragraph 
(a) of this section for violation of any regulation and the violation of 
any order issued under Sec. Sec.  190.217, 190.219 or 190.291 if both 
violations are based on the same act.



Sec.  190.293  Criminal referrals.

    (a) If a PHMSA employee becomes aware of any actual or possible 
activity subject to criminal penalties under Sec.  190.291, the employee 
must report it to the Office of Chief Counsel, Pipeline and Hazardous 
Materials Safety Administration, and to the employee's supervisor. The 
Chief Counsel may refer the report to the Associate Administrator to 
investigate. If appropriate, the Chief Counsel shall refer the report to 
the Office of Inspector General, or other law enforcement as appropriate 
(with notification to the Office of Inspector General as soon as 
possible).
    (b) A PHMSA employee also has the option of making a direct referral 
to the Office of Inspector General (OIG), either by directly contacting 
an OIG investigator, or via the OIG hotline at 800-424-9071, at https://
www.oig.dot.gov/hotline, by email at [email protected], or by mail to 
the Office of Inspector General, 1200 New Jersey Ave. SE, West Bldg. 7th 
Floor, Washington, DC 20590.

[87 FR 28781, May 11, 2022]



               Subpart D_Procedures for Adoption of Rules

    Source: Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, unless otherwise 
noted.



Sec.  190.301  Scope.

    This subpart prescribes general rulemaking procedures for the issue, 
amendment, and repeal of Pipeline Safety Program regulations of the 
Pipeline and Hazardous Materials Safety Administration of the Department 
of Transportation.

[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, as amended at 70 FR 11137, 
Mar. 8, 2005]

[[Page 411]]



Sec.  190.303  Delegations.

    For the purposes of this subpart, Administrator means the 
Administrator, Pipeline and Hazardous Materials Safety Administration, 
or his or her delegate.

[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, as amended at 70 FR 11137, 
Mar. 8, 2005]



Sec.  190.305  Regulatory dockets.

    (a) Information and data considered relevant by the Administrator 
relating to rulemaking actions, including notices of proposed 
rulemaking; comments received in response to notices; petitions for 
rulemaking and reconsideration; denials of petitions for rulemaking and 
reconsideration; records of additional rulemaking proceedings under 
Sec.  190.325; and final regulations are maintained by the Pipeline and 
Hazardous Materials Safety Administration at 1200 New Jersey Avenue, SE, 
Washington, D.C. 20590-0001.
    (b) Once a public docket is established, docketed material may be 
accessed at http://www.regulations.gov. Public comments also may be 
submitted at http://www.regulations.gov. Comment submissions must 
identify the docket number. You may also examine public docket material 
at the offices of the Docket Operations Facility (M-30), U.S. Department 
of Transportation, West Building, First Floor, Room W12-140, 1200 New 
Jersey Avenue, SE., Washington, DC 20590. You may obtain a copy during 
normal business hours, excluding Federal holidays, for a fee, with the 
exception of material which the Administrator of PHMSA determines should 
be withheld from public disclosure under 5 U.S.C. 552(b) or any other 
applicable statutory provision.

[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, as amended at 70 FR 11137, 
11139, Mar. 8, 2005; 73 FR 16566, Mar. 28, 2008; 73 FR 16568, Mar. 28, 
2008]



Sec.  190.307  Records.

    Records of the Pipeline and Hazardous Materials Safety 
Administration relating to rulemaking proceedings are available for 
inspection as provided in section 552(b) of title 5, United States Code, 
and part 7 of the Regulations of the Office of the Secretary of 
Transportation (part 7 of this title).

[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, as amended at 70 FR 11137, 
Mar. 8, 2005]



Sec.  190.309  Where to file petitions.

    Petitions for extension of time to comment submitted under Sec.  
190.319, petitions for hearings submitted under Sec.  190.327, petitions 
for rulemaking submitted under Sec.  190.331, and petitions for 
reconsideration submitted under Sec.  190.335 must be submitted to: 
Administrator, Pipeline and Hazardous Materials Safety Administration, 
U.S. Department of Transportation, 1200 New Jersey Avenue, SE, 
Washington, D.C. 20590-0001.

[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, as amended at 70 FR 11137, 
Mar. 8, 2005; 73 FR 16566, Mar. 28, 2008]



Sec.  190.311  General.

    Unless the Administrator, for good cause, finds that notice is 
impracticable, unnecessary, or contrary to the public interest, and 
incorporates that finding and a brief statement of the reasons for it in 
the rule, a notice of proposed rulemaking is issued and interested 
persons are invited to participate in the rulemaking proceedings with 
respect to each substantive rule.



Sec.  190.313  Initiation of rulemaking.

    The Administrator initiates rulemaking on his or her own motion; 
however, in so doing, the Administrator may use discretion to consider 
the recommendations of other agencies of the United States or of other 
interested persons including those of any technical advisory body 
established by statute for that purpose.



Sec.  190.315  Contents of notices of proposed rulemaking.

    (a) Each notice of proposed rulemaking is published in the Federal 
Register, unless all persons subject to it are named and are personally 
served with a copy of it.
    (b) Each notice, whether published in the Federal Register or 
personally served, includes:
    (1) A statement of the time, place, and nature of the proposed 
rulemaking proceeding;

[[Page 412]]

    (2) A reference to the authority under which it is issued;
    (3) A description of the subjects and issues involved or the 
substance and terms of the proposed regulation;
    (4) A statement of the time within which written comments must be 
submitted; and
    (5) A statement of how and to what extent interested persons may 
participate in the proceeding.



Sec.  190.317  Participation by interested persons.

    (a) Any interested person may participate in rulemaking proceedings 
by submitting comments in writing containing information, views or 
arguments in accordance with instructions for participation in the 
rulemaking document.
    (b) The Administrator may invite any interested person to 
participate in the rulemaking proceedings described in Sec.  190.325.
    (c) For the purposes of this subpart, an interested person includes 
any Federal or State government agency or any political subdivision of a 
State.



Sec.  190.319  Petitions for extension of time to comment.

    A petition for extension of the time to submit comments must be 
submitted to PHMSA in accordance with Sec.  190.309 and received by 
PHMSA not later than 10 days before expiration of the time stated in the 
notice. The filing of the petition does not automatically extend the 
time for petitioner's comments. A petition is granted only if the 
petitioner shows good cause for the extension, and if the extension is 
consistent with the public interest. If an extension is granted, it is 
granted to all persons, and it is published in the Federal Register.

[Amdt. 190-16, 78 FR 58914, Sept. 25, 2013]



Sec.  190.321  Contents of written comments.

    All written comments must be in English. Any interested person 
should submit as part of written comments all material considered 
relevant to any statement of fact. Incorporation of material by 
reference should be avoided; however, where necessary, such incorporated 
material must be identified by document title and page.

[Amdt. 190-16, 78 FR 58914, Sept. 25, 2013]



Sec.  190.323  Consideration of comments received.

    All timely comments and the recommendations of any technical 
advisory body established by statute for the purpose of reviewing the 
proposed rule concerned are considered before final action is taken on a 
rulemaking proposal. Late filed comments are considered so far as 
practicable.



Sec.  190.325  Additional rulemaking proceedings.

    The Administrator may initiate any further rulemaking proceedings 
that the Administrator finds necessary or desirable. For example, 
interested persons may be invited to make oral arguments, to participate 
in conferences between the Administrator or the Administrator's 
representative and interested persons, at which minutes of the 
conference are kept, to appear at informal hearings presided over by 
officials designated by the Administrator at which a transcript of 
minutes are kept, or participate in any other proceeding to assure 
informed administrative action and to protect the public interest.



Sec.  190.327  Hearings.

    (a) If a notice of proposed rulemaking does not provide for a 
hearing, any interested person may petition the Administrator for an 
informal hearing. The petition must be received by the Administrator not 
later than 20 days before expiration of the time stated in the notice. 
The filing of the petition does not automatically result in the 
scheduling of a hearing. A petition is granted only if the petitioner 
shows good cause for a hearing. If a petition for a hearing is granted, 
notice of the hearing is published in the Federal Register.
    (b) Sections 556 and 557 of title 5, United States Code, do not 
apply to hearings held under this subpart. Unless otherwise specified, 
hearings held under this subpart are informal, non-adversarial fact-
finding proceedings, at which there are no formal pleadings or adverse 
parties. Any regulation issued in a case in which an informal hearing

[[Page 413]]

is held is not necessarily based exclusively on the record of the 
hearing.
    (c) The Administrator designates a representative to conduct any 
hearing held under this subpart. The Chief Counsel designates a member 
of his or her staff to serve as legal officer at the hearing.

[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996. Redesignated and amended by 
Amdt. 190-16, 78 FR 58914, Sept. 25, 2013]



Sec.  190.329  Adoption of final rules.

    Final rules are prepared by representatives of the Office of 
Pipeline Safety and the Office of the Chief Counsel. The regulation is 
then submitted to the Administrator for consideration. If the 
Administrator adopts the regulation, it is published in the Federal 
Register, unless all persons subject to it are named and are personally 
served with a copy of it.



Sec.  190.331  Petitions for rulemaking.

    (a) Any interested person may petition the Associate Administrator 
for Pipeline Safety to establish, amend, or repeal a substantive 
regulation, or may petition the Chief Counsel to establish, amend, or 
repeal a procedural regulation.
    (b) Each petition filed under this section must--
    (1) Summarize the proposed action and explain its purpose;
    (2) State the text of the proposed rule or amendment, or specify the 
rule proposed to be repealed;
    (3) Explain the petitioner's interest in the proposed action and the 
interest of any party the petitioner represents; and
    (4) Provide information and arguments that support the proposed 
action, including relevant technical, scientific or other data as 
available to the petitioner, and any specific known cases that 
illustrate the need for the proposed action.
    (c) If the potential impact of the proposed action is substantial, 
and information and data related to that impact are available to the 
petitioner, the Associate Administrator or the Chief Counsel may request 
the petitioner to provide--
    (1) The costs and benefits to society and identifiable groups within 
society, quantifiable and otherwise;
    (2) The direct effects (including preemption effects) of the 
proposed action on States, on the relationship between the Federal 
Government and the States, and on the distribution of power and 
responsibilities among the various levels of government;
    (3) The regulatory burden on small businesses, small organizations 
and small governmental jurisdictions;
    (4) The recordkeeping and reporting requirements and to whom they 
would apply; and
    (5) Impacts on the quality of the natural and social environments.
    (d) The Associate Administrator or Chief Counsel may return a 
petition that does not comply with the requirements of this section, 
accompanied by a written statement indicating the deficiencies in the 
petition.



Sec.  190.333  Processing of petition.

    (a) General. Unless the Associate Administrator or the Chief Counsel 
otherwise specifies, no public hearing, argument, or other proceeding is 
held directly on a petition before its disposition under this section.
    (b) Grants. If the Associate Administrator or the Chief Counsel 
determines that the petition contains adequate justification, he or she 
initiates rulemaking action under this subpart.
    (c) Denials. If the Associate Administrator or the Chief Counsel 
determines that the petition does not justify rulemaking, the petition 
is denied.
    (d) Notification. The Associate Administrator or the Chief Counsel 
will notify a petitioner, in writing, of the decision to grant or deny a 
petition for rulemaking.



Sec.  190.335  Petitions for reconsideration.

    (a) Except as provided in Sec.  190.339(d), any interested person 
may petition the Associate Administrator for reconsideration of any 
regulation issued under this subpart, or may petition the Chief Counsel 
for reconsideration of any procedural regulation issued under this 
subpart and contained in this subpart. The petition must be received not 
later than 30 days after publication of the

[[Page 414]]

rule in the Federal Register. Petitions filed after that time will be 
considered as petitions filed under Sec.  190.331. The petition must 
contain a brief statement of the complaint and an explanation as to why 
compliance with the rule is not practicable, is unreasonable, or is not 
in the public interest.
    (b) If the petitioner requests the consideration of additional 
facts, the petitioner must state the reason they were not presented to 
the Associate Administrator or the Chief Counsel within the prescribed 
time.
    (c) The Associate Administrator or the Chief Counsel does not 
consider repetitious petitions.
    (d) Unless the Associate Administrator or the Chief Counsel 
otherwise provides, the filing of a petition under this section does not 
stay the effectiveness of the rule.

[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996. Redesignated and amended by 
Amdt. 190-16, 78 FR 58914, Sept. 25, 2013]



Sec.  190.337  Proceedings on petitions for reconsideration.

    (a) The Associate Administrator or the Chief Counsel may grant or 
deny, in whole or in part, any petition for reconsideration without 
further proceedings, except where a grant of the petition would result 
in issuance of a new final rule. In the event that the Associate 
Administrator or the Chief Counsel determines to reconsider any 
regulation, a final decision on reconsideration may be issued without 
further proceedings, or an opportunity to submit comment or information 
and data as deemed appropriate, may be provided. Whenever the Associate 
Administrator or the Chief Counsel determines that a petition should be 
granted or denied, the Office of the Chief Counsel prepares a notice of 
the grant or denial of a petition for reconsideration, for issuance to 
the petitioner, and the Associate Administrator or the Chief Counsel 
issues it to the petitioner. The Associate Administrator or the Chief 
Counsel may consolidate petitions relating to the same rules.
    (b) It is the policy of the Associate Administrator or the Chief 
Counsel to issue notice of the action taken on a petition for 
reconsideration within 90 days after the date on which the regulation in 
question is published in the Federal Register, unless it is found 
impracticable to take action within that time. In cases where it is so 
found and the delay beyond that period is expected to be substantial, 
notice of that fact and the date by which it is expected that action 
will be taken is issued to the petitioner and published in the Federal 
Register.



Sec.  190.338  Appeals.

    (a) Any interested person may appeal a denial of the Associate 
Administrator or the Chief Counsel, issued under Sec.  190.333 or Sec.  
190.337, to the Administrator.
    (b) An appeal must be received within 20 days of service of written 
notice to petitioner of the Associate Administrator's or the Chief 
Counsel's decision, or within 20 days from the date of publication of 
the decision in the Federal Register, and should set forth the contested 
aspects of the decision as well as any new arguments or information.
    (c) Unless the Administrator otherwise provides, the filing of an 
appeal under this section does not stay the effectiveness of any rule.

[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996. Redesignated and amended by 
Amdt. 190-16, 78 FR 58914, Sept. 25, 2013]



Sec.  190.339  Direct final rulemaking.

    (a) Where practicable, the Administrator will use direct final 
rulemaking to issue the following types of rules:
    (1) Minor, substantive changes to regulations;
    (2) Incorporation by reference of the latest edition of technical or 
industry standards;
    (3) Extensions of compliance dates; and
    (4) Other noncontroversial rules where the Administrator determines 
that use of direct final rulemaking is in the public interest, and that 
a regulation is unlikely to result in adverse comment.
    (b) The direct final rule will state an effective date. The direct 
final rule will also state that unless an adverse comment or notice of 
intent to file an adverse comment is received within the specified 
comment period, generally 60 days after publication of the direct final 
rule in the Federal Register,

[[Page 415]]

the Administrator will issue a confirmation document, generally within 
15 days after the close of the comment period, advising the public that 
the direct final rule will either become effective on the date stated in 
the direct final rule or at least 30 days after the publication date of 
the confirmation document, whichever is later.
    (c) For purposes of this section, an adverse comment is one which 
explains why the rule would be inappropriate, including a challenge to 
the rule's underlying premise or approach, or would be ineffective or 
unacceptable without a change. Comments that are frivolous or 
insubstantial will not be considered adverse under this procedure. A 
comment recommending a rule change in addition to the rule will not be 
considered an adverse comment, unless the commenter states why the rule 
would be ineffective without the additional change.
    (d) Only parties who filed comments to a direct final rule issued 
under this section may petition under Sec.  190.335 for reconsideration 
of that direct final rule.
    (e) If an adverse comment or notice of intent to file an adverse 
comment is received, a timely document will be published in the Federal 
Register advising the public and withdrawing the direct final rule in 
whole or in part. The Administrator may then incorporate the adverse 
comment into a subsequent direct final rule or may publish a notice of 
proposed rulemaking. A notice of proposed rulemaking will provide an 
opportunity for public comment, generally a minimum of 60 days, and will 
be processed in accordance with Sec. Sec.  190.311-190.329.



Sec.  190.341  Special permits.

    (a) What is a special permit? A special permit is an order by which 
PHMSA waives compliance with one or more of the Federal pipeline safety 
regulations under the standards set forth in 49 U.S.C. 60118(c) and 
subject to conditions set forth in the order. A special permit is issued 
to a pipeline operator (or prospective operator) for specified 
facilities that are or, absent waiver, would be subject to the 
regulation.
    (b) How do I apply for a special permit? Applications for special 
permits must be submitted at least 120 days before the requested 
effective date using any of the following methods:
    (1) Direct fax to PHMSA at: 202-366-4566; or
    (2) Mail, express mail, or overnight courier to the Associate 
Administrator for Pipeline Safety, Pipeline and Hazardous Materials 
Safety Administration, 1200 New Jersey Avenue, SE., East Building, 
Washington, DC 20590.
    (c) What information must be contained in the application? 
Applications must contain the following information:
    (1) The name, mailing address, and telephone number of the applicant 
and whether the applicant is an operator;
    (2) A detailed description of the pipeline facilities for which the 
special permit is sought, including:
    (i) The beginning and ending points of the pipeline mileage to be 
covered and the Counties and States in which it is located;
    (ii) Whether the pipeline is interstate or intrastate and a general 
description of the right-of-way including proximity of the affected 
segments to populated areas and unusually sensitive areas;
    (iii) Relevant pipeline design and construction information 
including the year of installation, the material, grade, diameter, wall 
thickness, and coating type; and
    (iv) Relevant operating information including operating pressure, 
leak history, and most recent testing or assessment results;
    (3) A list of the specific regulation(s) from which the applicant 
seeks relief;
    (4) An explanation of the unique circumstances that the applicant 
believes make the applicability of that regulation or standard (or 
portion thereof) unnecessary or inappropriate for its facility;
    (5) A description of any measures or activities the applicant 
proposes to undertake as an alternative to compliance with the relevant 
regulation, including an explanation of how such measures will mitigate 
any safety or environmental risks;
    (6) A description of any positive or negative impacts on affected 
stakeholders and a statement indicating how operating the pipeline 
pursuant to a special permit would be in the public interest;

[[Page 416]]

    (7) A certification that operation of the applicant's pipeline under 
the requested special permit would not be inconsistent with pipeline 
safety;
    (8) Any other information PHMSA may need to process the application 
including environmental analysis where necessary.
    (d) How does PHMSA handle special permit applications?--(1) Public 
notice. Upon receipt of an application or renewal of a special permit, 
PHMSA will provide notice to the public of its intent to consider the 
application and invite comment. In addition, PHMSA may consult with 
other Federal agencies before granting or denying an application or 
renewal on matters that PHMSA believes may have significance for 
proceedings under their areas of responsibility.
    (2) Grants, renewals, and denials. If the Associate Administrator 
determines that the application complies with the requirements of this 
section and that the waiver of the relevant regulation or standard is 
not inconsistent with pipeline safety, the Associate Administrator may 
grant the application, in whole or in part, for a period of time from 
the date granted. Conditions may be imposed on the grant if the 
Associate Administrator concludes they are necessary to assure safety, 
environmental protection, or are otherwise in the public interest. If 
the Associate Administrator determines that the application does not 
comply with the requirements of this section or that a waiver is not 
justified, the application will be denied. Whenever the Associate 
Administrator grants or denies an application, notice of the decision 
will be provided to the applicant. PHMSA will post all special permits 
on its Web site at http://www.phmsa.dot.gov/.
    (e) How does PHMSA handle special permit renewals? (1) The grantee 
of the special permit must apply for a renewal of the permit 180 days 
prior to the permit expiration.
    (2) If, at least 180 days before an existing special permit expires 
the holder files an application for renewal that is complete and 
conforms to the requirements of this section, the special permit will 
not expire until final administrative action on the application for 
renewal has been taken:
    (i) Direct fax to PHMSA at: 202-366-4566; or
    (ii) Express mail, or overnight courier to the Associate 
Administrator for Pipeline Safety, Pipeline and Hazardous Materials 
Safety Administration, 1200 New Jersey Avenue SE., Washington, DC 20590.
    (f) What information must be included in the renewal application? 
(1) The renewal application must include a copy of the original special 
permit, the docket number on the special permit, and the following 
information as applicable:
    (i) A summary report in accordance with the requirements of the 
original special permit including verification that the grantee's 
operations and maintenance plan (O&M Plan) is consistent with the 
conditions of the special permit;
    (ii) Name, mailing address and telephone number of the special 
permit grantee;
    (iii) Location of special permit--areas on the pipeline where the 
special permit is applicable including: Diameter, mile posts, county, 
and state;
    (iv) Applicable usage of the special permit--original and future; 
and
    (v) Data for the special permit segment and area identified in the 
special permit as needing additional inspections to include, as 
applicable:
    (A) Pipe attributes: Pipe diameter, wall thickness, grade, seam 
type; and pipe coating including girth weld coating;
    (B) Operating Pressure: Maximum allowable operating pressure (MAOP); 
class location (including boundaries on aerial photography);
    (C) High Consequence Areas (HCAs): HCA boundaries on aerial 
photography;
    (D) Material Properties: Pipeline material documentation for all 
pipe, fittings, flanges, and any other facilities included in the 
special permit. Material documentation must include: Yield strength, 
tensile strength, chemical composition, wall thickness, and seam type;
    (E) Test Pressure: Hydrostatic test pressure and date including 
pressure and temperature charts and logs and any known test failures or 
leaks;
    (F) In-line inspection (ILI): Summary of ILI survey results from all 
ILI tools

[[Page 417]]

used on the special permit segments during the previous five years or 
latest ILI survey result;
    (G) Integrity Data and Integration: The following information, as 
applicable, for the past five (5) years: Hydrostatic test pressure 
including any known test failures or leaks; casings(any shorts); any in-
service ruptures or leaks; close interval survey (CIS) surveys; depth of 
cover surveys; rectifier readings; test point survey readings; 
alternating current/direct current (AC/DC) interference surveys; pipe 
coating surveys; pipe coating and anomaly evaluations from pipe 
excavations; stress corrosion cracking (SCC), selective seam weld 
corrosion (SSWC) and hard spot excavations and findings; and pipe 
exposures from encroachments;
    (H) In-service: Any in-service ruptures or leaks including repair 
type and failure investigation findings; and
    (I) Aerial Photography: Special permit segment and special permit 
inspection area, if applicable.
    (2) PHMSA may request additional operational, integrity or 
environmental assessment information prior to granting any request for 
special permit renewal.
    (3) The existing special permit will remain in effect until PHMSA 
acts on the application for renewal by granting or denying the request.
    (g) Can a special permit be requested on an emergency basis? Yes. 
PHMSA may grant an application for an emergency special permit without 
notice and comment or hearing if the Associate Administrator determines 
that such action is in the public interest, is not inconsistent with 
pipeline safety, and is necessary to address an actual or impending 
emergency involving pipeline transportation. For purposes of this 
section, an emergency event may be local, regional, or national in scope 
and includes significant fuel supply disruptions and natural or manmade 
disasters such as hurricanes, floods, earthquakes, terrorist acts, 
biological outbreaks, releases of dangerous radiological, chemical, or 
biological materials, war-related activities, or other similar events. 
PHMSA will determine on a case-by-case basis what duration is necessary 
to address the emergency. However, as required by statute, no emergency 
special permit may be issued for a period of more than 60 days. Each 
emergency special permit will automatically expire on the date specified 
in the permit. Emergency special permits may be renewed upon application 
to PHMSA only after notice and opportunity for a hearing on the renewal.
    (h) How do I apply for an emergency special permit? Applications for 
emergency special permits may be submitted to PHMSA using any of the 
following methods:
    (1) Direct fax to the Crisis Management Center at: 202-366-3768;
    (2) Direct e-mail to PHMSA at: phmsa.pipeline-
[email protected]; or
    (3) Express mail/overnight courier to the Associate Administrator 
for Pipeline Safety, Pipeline and Hazardous Materials Safety 
Administration, 1200 New Jersey Avenue, SE., East Building, Washington, 
DC 20590.
    (i) What must be contained in an application for an emergency 
special permit? In addition to the information required under paragraph 
(c) of this section, applications for emergency special permits must 
include:
    (1) An explanation of the actual or impending emergency and how the 
applicant is affected;
    (2) A citation of the regulations that are implicated and the 
specific reasons the permit is necessary to address the emergency (e.g., 
lack of accessibility, damaged equipment, insufficient manpower);
    (3) A statement indicating how operating the pipeline pursuant to an 
emergency special permit is in the public interest (e.g., continuity of 
service, service restoration);
    (4) A description of any proposed alternatives to compliance with 
the regulation (e.g., additional inspections and tests, shortened 
reassessment intervals); and
    (5) A description of any measures to be taken after the emergency 
situation or permit expires--whichever comes first--to confirm long-term 
operational reliability of the pipeline facility.

    Note to paragraph (g): If PHMSA determines that handling of the 
application on an emergency basis is not warranted, PHMSA

[[Page 418]]

will notify the applicant and process the application under normal 
special permit procedures of this section.

    (j) In what circumstances will PHMSA revoke, suspend, or modify a 
special permit? (1) PHMSA may revoke, suspend, or modify a special 
permit on a finding that:
    (i) Intervening changes in Federal law mandate revocation, 
suspension, or modification of the special permit;
    (ii) Based on a material change in conditions or circumstances, 
continued adherence to the terms of the special permit would be 
inconsistent with safety;
    (iii) The application contained inaccurate or incomplete 
information, and the special permit would not have been granted had the 
application been accurate and complete;
    (iv) The application contained deliberately inaccurate or incomplete 
information; or
    (v) The holder has failed to comply with any material term or 
condition of the special permit.
    (2) Except as provided in paragraph (h)(3) of this section, before a 
special permit is modified, suspended or revoked, PHMSA will notify the 
holder in writing of the proposed action and the reasons for it, and 
provide an opportunity to show cause why the proposed action should not 
be taken.
    (i) The holder may file a written response that shows cause why the 
proposed action should not be taken within 30 days of receipt of notice 
of the proposed action.
    (ii) After considering the holder's written response, or after 30 
days have passed without response since receipt of the notice, PHMSA 
will notify the holder in writing of the final decision with a brief 
statement of reasons.
    (3) If necessary to avoid a risk of significant harm to persons, 
property, or the environment, PHMSA may in the notification declare the 
proposed action immediately effective.
    (4) Unless otherwise specified, the terms and conditions of a 
corrective action order, compliance order, or other order applicable to 
a pipeline facility covered by a special permit will take precedence 
over the terms of the special permit.
    (5) A special permit holder may seek reconsideration of a decision 
under paragraph (h) of this section as provided in paragraph (i) of this 
section.
    (k) Can a denial of a request for a special permit or a revocation 
of an existing special permit be appealed? Reconsideration of the denial 
of an application for a special permit or a revocation of an existing 
special permit may be sought by petition to the Associate Administrator. 
Petitions for reconsideration must be received by PHMSA within 20 
calendar days of the notice of the grant or denial and must contain a 
brief statement of the issue and an explanation of why the petitioner 
believes that the decision being appealed is not in the public interest. 
The Associate Administrator may grant or deny, in whole or in part, any 
petition for reconsideration without further proceedings. The Associate 
Administrator's decision is the final administrative action.
    (l) Are documents related to an application for a special permit 
available for public inspection? Documents related to an application, 
including the application itself, are available for public inspection on 
regulations.gov or the Docket Operations Facility to the extent such 
documents do not include information exempt from public disclosure under 
5 U.S.C. 552(b). Applicants may request confidential treatment under 
part 7 of this title.
    (m) Am I subject to enforcement action for non-compliance with the 
terms and conditions of a special permit? Yes. PHMSA inspects for 
compliance with the terms and conditions of special permits and if a 
probable violation is identified, PHMSA will initiate one or more of the 
enforcement actions under subpart B of this part.

[73 FR 16568, Mar. 28, 2008, as amended at 74 FR 2893, Jan. 16, 2009; 
Amdt. 190-16, 78 FR 58914, Sept. 25, 2013; Amdt. 190-19, 82 FR 7995, 
Jan. 23, 2017]



Sec.  190.343  Information made available to the public and request for 
protection of confidential commercial information.

    When you submit information to PHMSA during a rulemaking proceeding, 
as part of your application for special permit or renewal, or for any

[[Page 419]]

other reason, we may make that information publicly available unless you 
ask that we keep the information confidential.
    (a) Asking for protection of confidential commercial information. 
You may ask us to give confidential treatment to information you give to 
the agency by taking the following steps:
    (1) Mark ``confidential'' on each page of the original document you 
would like to keep confidential.
    (2) Send us, along with the original document, a second copy of the 
original document with the confidential commercial information deleted.
    (3) Explain why the information you are submitting is confidential 
commercial information.
    (b) PHMSA decision. PHMSA will treat as confidential the information 
that you submitted in accordance with this section, unless we notify you 
otherwise. If PHMSA decides to disclose the information, PHMSA will 
review your request to protect confidential commercial information under 
the criteria set forth in the Freedom of Information Act (FOIA), 5 
U.S.C. 552, including following the consultation procedures set out in 
the Departmental FOIA regulations, 49 CFR 7.29. If PHMSA decides to 
disclose the information over your objections, we will notify you in 
writing at least five business days before the intended disclosure date.

[Amdt. 190-19, 82 FR 7995, Jan. 23, 2017]



               Subpart E_Cost Recovery for Design Reviews

    Source: Amdt. 190-19, 82 FR 7996, Jan. 23, 2017, unless otherwise 
noted.



Sec.  190.401  Scope.

    If PHMSA conducts a facility design and/or construction safety 
review or inspection in connection with a proposal to construct, expand, 
or operate a gas, hazardous liquid or carbon dioxide pipeline facility, 
or a liquefied natural gas facility that meets the applicability 
requirements in Sec.  190.403, PHMSA may require the applicant proposing 
the project to pay the costs incurred by PHMSA relating to such review, 
including the cost of design and construction safety reviews or 
inspections.



Sec.  190.403  Applicability.

    The following paragraph specifies which projects will be subject to 
the cost recovery requirements of this section.
    (a) This section applies to any project that--
    (1) Has design and construction costs totaling at least 
$2,500,000,000, as periodically adjusted by PHMSA, to take into account 
increases in the Consumer Price Index for all urban consumers published 
by the Department of Labor, based on--
    (i) The cost estimate provided to the Federal Energy Regulatory 
Commission in an application for a certificate of public convenience and 
necessity for a gas pipeline facility or an application for 
authorization for a liquefied natural gas pipeline facility; or
    (ii) A good faith estimate developed by the applicant proposing a 
hazardous liquid or carbon dioxide pipeline facility and submitted to 
the Associate Administrator. The good faith estimate for design and 
construction costs must include all of the applicable cost items 
contained in the Federal Energy Regulatory Commission application 
referenced in Sec.  190.403(a)(1)(i) for a gas or LNG facility. In 
addition, an applicant must take into account all survey, design, 
material, permitting, right-of way acquisition, construction, testing, 
commissioning, start-up, construction financing, environmental 
protection, inspection, material transportation, sales tax, project 
contingency, and all other applicable costs, including all segments, 
facilities, and multi-year phases of the project;
    (2) Uses new or novel technologies or design, as defined in Sec.  
190.3.
    (b) The Associate Administrator may not collect design safety review 
fees under this section and 49 U.S.C. 60301 for the same design safety 
review.
    (c) The Associate Administrator, after receipt of the design 
specifications, construction plans and procedures, and related 
materials, determines if cost recovery is necessary. The Associate 
Administrator's determination is based on the amount of

[[Page 420]]

PHMSA resources needed to ensure safety and environmental protection.



Sec.  190.405  Notification.

    For any new pipeline facility construction project in which PHMSA 
will conduct a design review, the applicant proposing the project must 
notify PHMSA and provide the design specifications, construction plans 
and procedures, project schedule and related materials at least 120 days 
prior to the commencement of any of the following activities: Route 
surveys for construction, material manufacturing, offsite facility 
fabrications, construction equipment move-in activities, onsite or 
offsite fabrications, personnel support facility construction, and any 
offsite or onsite facility construction. To the maximum extent 
practicable, but not later than 90 days after receiving such design 
specifications, construction plans and procedures, and related 
materials, PHMSA will provide written comments, feedback, and guidance 
on the project.



Sec.  190.407  Master Agreement.

    PHMSA and the applicant will enter into an agreement within 60 days 
after PHMSA received notification from the applicant provided in Sec.  
190.405, outlining PHMSA's recovery of the costs associated with the 
facility design safety review.
    (a) A Master Agreement, at a minimum, includes:
    (1) Itemized list of direct costs to be recovered by PHMSA;
    (2) Scope of work for conducting the facility design safety review 
and an estimated total cost;
    (3) Description of the method of periodic billing, payment, and 
auditing of cost recovery fees;
    (4) Minimum account balance which the applicant must maintain with 
PHMSA at all times;
    (5) Provisions for reconciling differences between total amount 
billed and the final cost of the design review, including provisions for 
returning any excess payments to the applicant at the conclusion of the 
project;
    (6) A principal point of contact for both PHMSA and the applicant; 
and
    (7) Provisions for terminating the agreement.
    (8) A project reimbursement cost schedule based upon the project 
timing and scope.
    (b) [Reserved]



Sec.  190.409  Fee structure.

    The fee charged is based on the direct costs that PHMSA incurs in 
conducting the facility design safety review (including construction 
review and inspections), and will be based only on costs necessary for 
conducting the facility design safety review. ``Necessary for'' means 
that but for the facility design safety review, the costs would not have 
been incurred and that the costs cover only those activities and items 
without which the facility design safety review cannot be completed.
    (a) Costs qualifying for cost recovery include, but are not limited 
to--
    (1) Personnel costs based upon total cost to PHMSA;
    (2) Travel, lodging and subsistence;
    (3) Vehicle mileage;
    (4) Other direct services, materials and supplies;
    (5) Other direct costs as may be specified in the Master Agreement.
    (b) [Reserved]



Sec.  190.411  Procedures for billing and payment of fee.

    All PHMSA cost calculations for billing purposes are determined from 
the best available PHMSA records.
    (a) PHMSA bills an applicant for cost recovery fees as specified in 
the Master Agreement, but the applicant will not be billed more 
frequently than quarterly.
    (1) PHMSA will itemize cost recovery bills in sufficient detail to 
allow independent verification of calculations.
    (2) [Reserved]
    (b) PHMSA will monitor the applicant's account balance. Should the 
account balance fall below the required minimum balance specified in the 
Master Agreement, PHMSA may request at any time the applicant submit 
payment within 30 days to maintain the minimum balance.
    (c) PHMSA will provide an updated estimate of costs to the applicant 
on or near October 1st of each calendar year.
    (d) Payment of cost recovery fees is due within 30 days of issuance 
of a bill

[[Page 421]]

for the fees. If payment is not made within 30 days, PHMSA may charge an 
annual rate of interest (as set by the Department of Treasury's 
Statutory Debt Collection Authorities) on any outstanding debt, as 
specified in the Master Agreement.
    (e) Payment of the cost recovery fee by the applicant does not 
obligate or prevent PHMSA from taking any particular action during 
safety inspections on the project.



PART 191_TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE; ANNUAL,  
         INCIDENT, AND OTHER REPORTING--Table of Contents



Sec.
191.1 Scope.
191.3 Definitions.
191.5 Immediate notice of certain incidents.
191.7 Report submission requirements.
191.9 Distribution system: Incident report.
191.11 Distribution system: Annual report.
191.12 [Reserved]
191.13 Distribution systems reporting transmission pipelines; 
          transmission or gathering systems reporting distribution 
          pipelines.
191.15 Transmission systems; gathering systems; liquefied natural gas 
          facilities; and underground natural gas storage facilities: 
          Incident report.
191.17 Transmission systems; gathering systems; liquefied natural gas 
          facilities; and underground natural gas storage facilities: 
          Annual report.
191.21 OMB control number assigned to information collection.
191.22 National Registry of Operators.
191.23 Reporting safety-related conditions.
191.25 Filing safety-related condition reports.
191.29 National Pipeline Mapping System.

    Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5121, 60101 et. seq., and 
49 CFR 1.97.



Sec.  191.1  Scope.

    (a) This part prescribes requirements for the reporting of 
incidents, safety-related conditions, annual pipeline summary data, 
National Operator Registry information, and other miscellaneous 
conditions by operators of underground natural gas storage facilities 
and natural gas pipeline facilities located in the United States or 
Puerto Rico, including underground natural gas storage facilities and 
pipelines within the limits of the Outer Continental Shelf as that term 
is defined in the Outer Continental Shelf Lands Act (43 U.S.C. 1331). 
This part applies to offshore gathering lines (except as provided in 
paragraph (b) of this section) and to onshore gathering lines, including 
Type R gathering lines as determined in Sec.  192.8 of this chapter.
    (b) This part does not apply to--
    (1) Offshore gathering of gas in State waters upstream from the 
outlet flange of each facility where hydrocarbons are produced or where 
produced hydrocarbons are first separated, dehydrated, or otherwise 
processed, whichever facility is farther downstream;
    (2) Pipelines on the Outer Continental Shelf (OCS) that are 
producer-operated and cross into State waters without first connecting 
to a transporting operator's facility on the OCS, upstream (generally 
seaward) of the last valve on the last production facility on the OCS. 
Safety equipment protecting PHMSA-regulated pipeline segments is not 
excluded. Producing operators for those pipeline segments upstream of 
the last valve of the last production facility on the OCS may petition 
the Administrator, or designee, for approval to operate under Pipeline 
and Hazardous Materials Safety Administration (PHMSA) regulations 
governing pipeline design, construction, operation, and maintenance 
under 49 CFR 190.9; or
    (3) Pipelines on the Outer Continental Shelf upstream of the point 
at which operating responsibility transfers from a producing operator to 
a transporting operator.
    (c) Sections 191.22(b) and (c) and 191.23 do not apply to the 
onshore gathering of gas--
    (1) Through a pipeline that operates at less than 0 psig (0 kPa);
    (2) Through a pipeline that is not a regulated onshore gathering 
pipeline; or

[[Page 422]]

    (3) Within inlets of the Gulf of Mexico, except for the requirements 
in Sec.  192.612 of this chapter.

[Amdt. 191-5, 49 FR 18960, May 3, 1984, as amended by Amdt. 191-6, 53 FR 
24949, July 1, 1988; Amdt. 191-11, 61 FR 27793, June 3, 1996; Amdt. 191-
12, 62 FR 61695, Nov. 19, 1997; Amdt. 191-15, 68 FR 46111, Aug. 5, 2003; 
70 FR 11139, Mar. 8, 2005; 75 FR 72904, Nov. 26, 2010; Amdt. 191-24, 81 
FR 91871, Dec. 19, 2016; Amdt. 191-27, 85 FR 8124, Feb. 12, 2020; Amdt. 
191-30, 86 FR 63294, Nov. 15, 2021]



Sec.  191.3  Definitions.

    As used in this part and the PHMSA Forms referenced in this part--
    Administrator means the Administrator, Pipeline and Hazardous 
Materials Safety Administration or his or her delegate
    Confirmed Discovery means when it can be reasonably determined, 
based on information available to the operator at the time a reportable 
event has occurred, even if only based on a preliminary evaluation.
    Gas means natural gas, flammable gas, or gas which is toxic or 
corrosive;
    Incident means any of the following events:
    (1) An event that involves a release of gas from a pipeline, gas 
from an underground natural gas storage facility (UNGSF), liquefied 
natural gas, liquefied petroleum gas, refrigerant gas, or gas from an 
LNG facility, and that results in one or more of the following 
consequences:
    (i) A death, or personal injury necessitating in-patient 
hospitalization;
    (ii) Estimated property damage of $122,000 or more, including loss 
to the operator and others, or both, but excluding the cost of gas lost. 
For adjustments for inflation observed in calendar year 2021 onwards, 
changes to the reporting threshold will be posted on PHMSA's website. 
These changes will be determined in accordance with the procedures in 
appendix A to part 191.
    (iii) Unintentional estimated gas loss of three million cubic feet 
or more.
    (2) An event that results in an emergency shutdown of an LNG 
facility or a UNGSF. Activation of an emergency shutdown system for 
reasons other than an actual emergency within the facility does not 
constitute an incident.
    (3) An event that is significant in the judgment of the operator, 
even though it did not meet the criteria of paragraph (1) or (2) of this 
definition.
    LNG facility means a liquefied natural gas facility as defined in 
Sec.  193.2007 of part 193 of this chapter;
    Master Meter System means a pipeline system for distributing gas 
within, but not limited to, a definable area, such as a mobile home 
park, housing project, or apartment complex, where the operator 
purchases metered gas from an outside source for resale through a gas 
distribution pipeline system. The gas distribution pipeline system 
supplies the ultimate consumer who either purchases the gas directly 
through a meter or by other means, such as by rents;
    Municipality means a city, county, or any other political 
subdivision of a State;
    Offshore means beyond the line of ordinary low water along that 
portion of the coast of the United States that is in direct contact with 
the open seas and beyond the line marking the seaward limit of inland 
waters;
    Operator means a person who engages in the transportation of gas;
    Outer Continental Shelf means all submerged lands lying seaward and 
outside the area of lands beneath navigable waters as defined in Section 
2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil 
and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Person means any individual, firm, joint venture, partnership, 
corporation, association, State, municipality, cooperative association, 
or joint stock association, and includes any trustee, receiver, 
assignee, or personal representative thereof;
    Pipeline or Pipeline System means all parts of those physical 
facilities through which gas moves in transportation, including, but not 
limited to, pipe, valves, and other appurtenance attached to pipe, 
compressor units, metering stations, regulator stations, delivery 
stations, holders, and fabricated assemblies.

[[Page 423]]

    Regulated onshore gathering means a Type A, Type B, or Type C gas 
gathering pipeline system as determined in Sec.  192.8 of this chapter.
    Reporting-regulated gathering means a Type R gathering line as 
determined in Sec.  192.8 of this chapter. A Type R gathering line is 
subject only to this part.
    State includes each of the several States, the District of Columbia, 
and the Commonwealth of Puerto Rico;
    Transportation of gas means the gathering, transmission, or 
distribution of gas by pipeline, or the storage of gas in or affecting 
interstate or foreign commerce.
    Underground natural gas storage facility (UNGSF) means an 
underground natural gas storage facility or UNGSF as defined in Sec.  
192.3 of this chapter.

[35 FR 320, Jan. 8, 1970, as amended by Amdt. 191-5, 49 FR 18960, May 3, 
1984; Amdt. 191-10, 61 FR 18516, Apr. 26, 1996; Amdt. 191-12, 62 FR 
61695, Nov. 19, 1997; 68 FR 11749, Mar. 12, 2003; 70 FR 11139, Mar. 8, 
2005; 75 FR 72905, Nov. 26, 2010; Amdt. 191-24, 81 FR 91871, Dec. 19, 
2016; Amdt. 191-25, 82 FR 7997, Jan. 23, 2017; Amdt. 191-27, 85 FR 8125, 
Feb. 12, 2020; 86 FR 2237, Jan. 11, 2021; Amdt. 191-30, 86 FR 63295, 
Nov. 15, 2021]



Sec.  191.5  Immediate notice of certain incidents.

    (a) At the earliest practicable moment following discovery, but no 
later than one hour after confirmed discovery, each operator must give 
notice in accordance with paragraph (b) of this section of each incident 
as defined in Sec.  191.3.
    (b) Each notice required by paragraph (a) of this section must be 
made to the National Response Center either by telephone to 800-424-8802 
(in Washington, DC, 202 267-2675) or electronically at http://
www.nrc.uscg.mil and must include the following information:
    (1) Names of operator and person making report and their telephone 
numbers.
    (2) The location of the incident.
    (3) The time of the incident.
    (4) The number of fatalities and personal injuries, if any.
    (5) All other significant facts that are known by the operator that 
are relevant to the cause of the incident or extent of the damages.
    (c) Within 48 hours after the confirmed discovery of an incident, to 
the extent practicable, an operator must revise or confirm its initial 
telephonic notice required in paragraph (b) of this section with an 
estimate of the amount of product released, an estimate of the number of 
fatalities and injuries, and all other significant facts that are known 
by the operator that are relevant to the cause of the incident or extent 
of the damages. If there are no changes or revisions to the initial 
report, the operator must confirm the estimates in its initial report.

[Amdt. 191-4, 47 FR 32720, July 29, 1982, as amended by Amdt. 191-5, 49 
FR 18960, May 3, 1984; Amdt. 191-8, 54 FR 40878, Oct. 4, 1989; 75 FR 
72905, Nov. 26, 2010; Amdt. 191-25, 82 FR 7997, Jan. 23, 2017]



Sec.  191.7  Report submission requirements.

    (a) General. Except as provided in paragraphs (b) and (e) of this 
section, an operator must submit each report required by this part 
electronically to the Pipeline and Hazardous Materials Safety 
Administration at http://portal.phmsa.dot.gov/pipeline unless an 
alternative reporting method is authorized in accordance with paragraph 
(d) of this section.
    (b) Exceptions: An operator is not required to submit a safety-
related condition report (Sec.  191.25) electronically.
    (c) Safety-related conditions. An operator must submit concurrently 
to the applicable State agency a safety-related condition report 
required by Sec.  191.23 for intrastate pipeline transportation or when 
the State agency acts as an agent of the Secretary with respect to 
interstate transmission facilities.
    (d) Alternative Reporting Method. If electronic reporting imposes an 
undue burden and hardship, an operator may submit a written request for 
an alternative reporting method to the Information Resources Manager, 
Office of Pipeline Safety, Pipeline and Hazardous Materials Safety 
Administration, PHP-20, 1200 New Jersey Avenue, SE, Washington DC 20590. 
The request must describe the undue burden and hardship. PHMSA will 
review the request and may authorize, in writing, an

[[Page 424]]

alternative reporting method. An authorization will state the period for 
which it is valid, which may be indefinite. An operator must contact 
PHMSA at 202-366-8075, or electronically to 
[email protected] or make arrangements for submitting 
a report that is due after a request for alternative reporting is 
submitted but before an authorization or denial is received.
    (e) National Pipeline Mapping System (NPMS). An operator must 
provide the NPMS data to the address identified in the NPMS Operator 
Standards manual available at www.npms.phmsa.dot.gov or by contacting 
the PHMSA Geographic Information Systems Manager at (202) 366-4595.

[75 FR 72905, Nov. 26, 2010, as amended at by Amdt. 191-23, 80 FR 12777, 
Mar. 11, 2015]



Sec.  191.9  Distribution system: Incident report.

    (a) Except as provided in paragraph (c) of this section, each 
operator of a distribution pipeline system shall submit Department of 
Transportation Form RSPA F 7100.1 as soon as practicable but not more 
than 30 days after detection of an incident required to be reported 
under Sec.  191.5.
    (b) When additional relevant information is obtained after the 
report is submitted under paragraph (a) of this section, the operator 
shall make supplementary reports as deemed necessary with a clear 
reference by date and subject to the original report.
    (c) Master meter operators are not required to submit an incident 
report as required by this section.

[Amdt. 191-5, 49 FR 18960, May 3, 1984, as amended at 75 FR 72905, Nov. 
26, 2010]



Sec.  191.11  Distribution system: Annual report.

    (a) General. Except as provided in paragraph (b) of this section, 
each operator of a distribution pipeline system must submit an annual 
report for that system on DOT Form PHMSA F 7100.1-1. This report must be 
submitted each year, not later than March 15, for the preceding calendar 
year.
    (b) Not required. The annual report requirement in this section does 
not apply to a master meter system, a petroleum gas system that serves 
fewer than 100 customers from a single source, or an individual service 
line directly connected to a production pipeline or a gathering line 
other than a regulated gathering line as determined in Sec.  192.8.

[75 FR 72905, Nov. 26, 2010, as amended at 86 FR 2237, Jan. 11, 2021]



Sec.  191.12  [Reserved]



Sec.  191.13  Distribution systems reporting transmission pipelines; 
transmission or gathering systems reporting distribution pipelines.

    Each operator, primarily engaged in gas distribution, who also 
operates gas transmission or gathering pipelines shall submit separate 
reports for these pipelines as required by Sec. Sec.  191.15 and 191.17. 
Each operator, primarily engaged in gas transmission or gathering, who 
also operates gas distribution pipelines shall submit separate reports 
for these pipelines as required by Sec. Sec.  191.9 and 191.11.

[Amdt. 191-5, 49 FR 18961, May 3, 1984]



Sec.  191.15  Transmission systems; gathering systems; liquefied natural 
gas facilities; and underground natural gas storage facilities: Incident 
report.

    (a) Pipeline systems--(1) Transmission, offshore gathering, or 
regulated onshore gathering. Each operator of a transmission, offshore 
gathering, or a regulated onshore gathering pipeline system must submit 
Department of Transportation (DOT) Form PHMSA F 7100.2 as soon as 
practicable but not more than 30 days after detection of an incident 
required to be reported under Sec.  191.5.
    (2) Reporting-regulated gathering. Each operator of a reporting-
regulated gathering pipeline system must submit DOT Form PHMSA F 7100.2-
2 as soon as practicable but not more than 30 days after detection of an 
incident required to be reported under Sec.  191.5 that occurs after May 
16, 2022.
    (b) LNG. Each operator of a liquefied natural gas plant or facility 
must submit DOT Form PHMSA F 7100.3 as soon as practicable but not more 
than 30

[[Page 425]]

days after detection of an incident required to be reported under Sec.  
191.5 of this part.
    (c) Underground natural gas storage facility. Each operator of a 
UNGSF must submit DOT Form PHMSA F7100.2 as soon as practicable but not 
more than 30 days after the detection of an incident required to be 
reported under Sec.  191.5.
    (d) Supplemental report. Where additional related information is 
obtained after an operator submits a report under paragraph (a), (b), or 
(c) of this section, the operator must make a supplemental report as 
soon as practicable, with a clear reference by date to the original 
report.

[75 FR 72905, Nov. 26, 2010; as amended by Amdt. 191-24, 81 FR 91871, 
Dec. 19, 2016; Amdt. 191-27, 85 FR 8125, Feb. 12, 2020; Amdt. 191-30, 86 
FR 63295, Nov. 15, 2021; 87 FR 35677, June 13, 2022]



Sec.  191.17  Transmission systems; gathering systems; liquefied natural  
gas facilities; and underground natural gas storage facilities: Annual 
report.

    (a) Pipeline systems--(1) Transmission, offshore gathering, or 
regulated onshore gathering. Each operator of a transmission, offshore 
gathering, or regulated onshore gathering pipeline system must submit an 
annual report for that system on DOT Form PHMSA F 7100.2-1. This report 
must be submitted each year, not later than March 15, for the preceding 
calendar year.
    (2) Type R gathering. Beginning with an initial annual report 
submitted in March 2023 for the 2022 calendar year, each operator of a 
reporting-regulated gas gathering pipeline system must submit an annual 
report for that system on DOT Form PHMSA F 7100.2-3. This report must be 
submitted each year, not later than March 15, for the preceding calendar 
year.
    (b) LNG. Each operator of a liquefied natural gas facility must 
submit an annual report for that system on DOT Form PHMSA 7100.3-1 This 
report must be submitted each year, not later than March 15, for the 
preceding calendar year, except that for the 2010 reporting year the 
report must be submitted by June 15, 2011.
    (c) Underground natural gas storage facility. Each operator of a 
UNGSF must submit an annual report through DOT Form PHMSA 7100.4-1. This 
report must be submitted each year, no later than March 15, for the 
preceding calendar year.

[75 FR 72905, Nov. 26, 2010, as amended by Amdt. 191-24, 81 FR 91871, 
Dec. 19, 2016; Amdt. 191-27, 85 FR 8125, Feb. 12, 2020; Amdt. 191-30, 86 
FR 63295, Nov. 15, 2021; 87 FR 35677. June 13, 2022]



Sec.  191.21  OMB control number assigned to information collection.

    This section displays the control number assigned by the Office of 
Management and Budget (OMB) to the information collection requirements 
in this part. The Paperwork Reduction Act requires agencies to display a 
current control number assigned by the Director of OMB for each agency 
information collection requirement.

                                          OMB Control Number 2137-0522
----------------------------------------------------------------------------------------------------------------
Section of 49 CFR part 191 where
           identified                                                Form No.
----------------------------------------------------------------------------------------------------------------
191.5...........................  Telephonic.
191.9...........................  PHMSA 7100.1, PHMSA 7100.3.
191.11..........................  PHMSA 7100.1-1, PHMSA 7100.3-1.
191.12..........................  PHMSA 7100.1-2.
191.15..........................  PHMSA 7100.2, PHMSA 7100.3.
191.17..........................  PHMSA 7100.2-1, PHMSA 7100.3-1.PHMSA 7100.4-1.
191.22..........................  PHMSA 1000.1, PHMSA 1000.2.
----------------------------------------------------------------------------------------------------------------


[75 FR 72905, Nov. 26, 2010, as amended by Amdt. 191-24, 81 FR 91871, 
Dec. 19, 2016]



Sec.  191.22  National Registry of Operators.

    (a) OPID request. Effective January 1, 2012, each operator of a gas 
pipeline, gas pipeline facility, UNGSF, LNG

[[Page 426]]

plant, or LNG facility must obtain from PHMSA an Operator Identification 
Number (OPID). An OPID is assigned to an operator for the pipeline, 
pipeline facility, or pipeline system for which the operator has primary 
responsibility. To obtain an OPID, an operator must submit an OPID 
Assignment Request DOT Form PHMSA F 1000.1 through the National Registry 
of Operators in accordance with Sec.  191.7.
    (b) OPID validation. An operator who has already been assigned one 
or more OPIDs by January 1, 2011, must validate the information 
associated with each OPID through the National Registry of Operators at 
https://portal.phmsa .dot.gov, and correct that information as 
necessary, no later than June 30, 2012.
    (c) Changes. Each operator of a gas pipeline, gas pipeline facility, 
UNGSF, LNG plant, or LNG facility must notify PHMSA electronically 
through the National Registry of Operators at https://
portal.phmsa.dot.gov of certain events.
    (1) An operator must notify PHMSA of any of the following events not 
later than 60 days before the event occurs:
    (i) Construction of any planned rehabilitation, replacement, 
modification, upgrade, uprate, or update of a facility, other than a 
section of line pipe, that costs $10 million or more. If 60-day notice 
is not feasible because of an emergency, an operator must notify PHMSA 
as soon as practicable;
    (ii) Construction of 10 or more miles of a new pipeline;
    (iii) Construction of a new LNG plant, LNG facility, or UNGSF;
    (iv) Maintenance of a UNGSF that involves the plugging or 
abandonment of a well, or that requires a workover rig and costs 
$200,000 or more for an individual well, including its wellhead. If 60-
days' notice is not feasible due to an emergency, an operator must 
promptly respond to the emergency and notify PHMSA as soon as 
practicable;
    (v) Reversal of product flow direction when the reversal is expected 
to last more than 30 days. This notification is not required for 
pipeline systems already designed for bi-directional flow; or
    (vi) A pipeline converted for service under Sec.  192.14 of this 
chapter, or a change in commodity as reported on the annual report as 
required by Sec.  191.17.
    (2) An operator must notify PHMSA of any of the following events not 
later than 60 days after the event occurs:
    (i) A change in the primary entity responsible (i.e., with an 
assigned OPID) for managing or administering a safety program required 
by this part covering pipeline facilities operated under multiple OPIDs;
    (ii) A change in the name of the operator;
    (iii) A change in the entity (e.g., company, municipality) 
responsible for an existing pipeline, pipeline segment, pipeline 
facility, UNGSF, or LNG facility;
    (iv) The acquisition or divestiture of 50 or more miles of a 
pipeline or pipeline system subject to part 192 of this subchapter; or
    (v) The acquisition or divestiture of an existing UNGSF, or an LNG 
plant or LNG facility subject to part 193 of this subchapter.
    (d) Reporting. An operator must use the OPID issued by PHMSA for all 
reporting requirements covered under this subchapter and for submissions 
to the National Pipeline Mapping System.

[Amdt. 191-27, 85 FR 8125, Feb. 12, 2020, as amended by Amdt. 191-28, 85 
FR 44478, July 23, 2020]



Sec.  191.23  Reporting safety-related conditions.

    (a) Except as provided in paragraph (b) of this section, each 
operator shall report in accordance with Sec.  191.25 the existence of 
any of the following safety-related conditions involving facilities in 
service:
    (1) In the case of a pipeline (other than an LNG facility) that 
operates at a hoop stress of 20% or more of its specified minimum yield 
strength, general corrosion that has reduced the wall thickness to less 
than that required for the maximum allowable operating pressure, and 
localized corrosion pitting to a degree where leakage might result.
    (2) In the case of a UNGSF, general corrosion that has reduced the 
wall thickness of any metal component to less than that required for the 
well's

[[Page 427]]

maximum operating pressure, or localized corrosion pitting to a degree 
where leakage might result.
    (3) Unintended movement or abnormal loading by environmental causes, 
such as an earthquake, landslide, or flood, that impairs the 
serviceability of a pipeline or the structural integrity or reliability 
of a UNGSF or LNG facility that contains, controls, or processes gas or 
LNG.
    (4) Any crack or other material defect that impairs the structural 
integrity or reliability of a UNGSF or an LNG facility that contains, 
controls, or processes gas or LNG.
    (5) Any material defect or physical damage that impairs the 
serviceability of a pipeline that operates at a hoop stress of 20% or 
more of its specified minimum yield strength, or the serviceability or 
the structural integrity of a UNGSF.
    (6) Any malfunction or operating error that causes the pressure--
plus the margin (build-up) allowed for operation of pressure limiting or 
control devices--to exceed either the maximum allowable operating 
pressure of a distribution or gathering line, the maximum well allowable 
operating pressure of an underground natural gas storage facility, or 
the maximum allowable working pressure of an LNG facility that contains 
or processes gas or LNG.
    (7) A leak in a pipeline, UNGSF, or LNG facility containing or 
processing gas or LNG that constitutes an emergency.
    (8) Inner tank leakage, ineffective insulation, or frost heave that 
impairs the structural integrity of an LNG storage tank.
    (9) Any safety-related condition that could lead to an imminent 
hazard and causes (either directly or indirectly by remedial action of 
the operator), for purposes other than abandonment, a 20% or more 
reduction in operating pressure or shutdown of operation of a pipeline, 
UNGSF, or an LNG facility that contains or processes gas or LNG.
    (10) For transmission pipelines only, each exceedance of the maximum 
allowable operating pressure that exceeds the margin (build-up) allowed 
for operation of pressure-limiting or control devices as specified in 
the applicable requirements of Sec. Sec.  192.201, 192.620(e), and 
192.739. The reporting requirement of this paragraph (a)(10) is not 
applicable to gathering lines, distribution lines, LNG facilities, or 
underground natural gas storage facilities (See paragraph (a)(6) of this 
section).
    (11) Any malfunction or operating error that causes the pressure of 
a UNGSF using a salt cavern for natural gas storage to fall below its 
minimum allowable operating pressure, as defined by the facility's State 
or Federal operating permit or certificate, whichever pressure is 
higher.
    (b) A report is not required for any safety-related condition that--
    (1) Exists on a master meter system, a reporting-regulated gathering 
pipeline, a Type C gas gathering pipeline with an outside diameter of 
12.75 inches or less, a Type C gas gathering pipeline covered by the 
exception in Sec.  192.9(f)(1) of this subchapter and therefore not 
required to comply with Sec.  192.9(e)(2)(ii), or a customer-owned 
service line;
    (2) Is an incident or results in an incident before the deadline for 
filing the safety-related condition report;
    (3) Exists on a pipeline (other than an UNGSF or an LNG facility) 
that is more than 220 yards (200 meters) from any building intended for 
human occupancy or outdoor place of assembly, except that reports are 
required for conditions within the right-of-way of an active railroad, 
paved road, street, or highway; or
    (4) Is corrected by repair or replacement in accordance with 
applicable safety standards before the deadline for filing the safety-
related condition report. Notwithstanding this exception, a report must 
be filed for:
    (i) Conditions under paragraph (a)(1) of this section, unless the 
condition is localized corrosion pitting on an effectively coated and 
cathodically protected pipeline; and
    (ii) Any condition under paragraph (a)(10) of this section.
    (5) Exists on an UNGSF, where a well or wellhead is isolated, 
allowing the reservoir or cavern and all other components of the 
facility to continue to

[[Page 428]]

operate normally and without pressure restriction.

[Amdt. 191-26, 84 FR 52242, Oct. 1, 2019; Amdt. 191-27, 85 FR 8125, Feb. 
12, 2020; Amdt. 191-31, 192-131, 87 FR 26299, May 4, 2022]



Sec.  191.25  Filing safety-related condition reports.

    (a) Each report of a safety-related condition under Sec.  
191.23(a)(1) through (9) must be filed (received by the Associate 
Administrator) in writing within 5 working days (not including Saturday, 
Sunday, or Federal holidays) after the day a representative of an 
operator first determines that the condition exists, but not later than 
10 working days after the day a representative of an operator discovers 
the condition. Separate conditions may be described in a single report 
if they are closely related. Reporting methods and report requirements 
are described in paragraph (c) of this section.
    (b) Each report of a maximum allowable operating pressure exceedance 
meeting the requirements of criteria in Sec.  191.23(a)(10) for a gas 
transmission pipeline must be filed (received by the Associate 
Administrator) in writing within 5 calendar days of the exceedance using 
the reporting methods and report requirements described in paragraph (c) 
of this section.
    (c) Reports must be filed by email to 
[email protected] or by facsimile to (202) 366-7128. 
For a report made pursuant to Sec.  191.23(a)(1) through (9), the report 
must be headed ``Safety-Related Condition Report.'' For a report made 
pursuant to Sec.  191.23(a)(10), the report must be headed ``Maximum 
Allowable Operating Pressure Exceedances.'' All reports must provide the 
following information:
    (1) Name, principal address, and operator identification number 
(OPID) of the operator.
    (2) Date of report.
    (3) Name, job title, and business telephone number of person 
submitting the report.
    (4) Name, job title, and business telephone number of person who 
determined that the condition exists.
    (5) Date condition was discovered and date condition was first 
determined to exist.
    (6) Location of condition, with reference to the State (and town, 
city, or county) or offshore site, and as appropriate, nearest street 
address, offshore platform, survey station number, milepost, landmark, 
or name of pipeline.
    (7) Description of the condition, including circumstances leading to 
its discovery, any significant effects of the condition on safety, and 
the name of the commodity transported or stored.
    (8) The corrective action taken (including reduction of pressure or 
shutdown) before the report is submitted and the planned follow-up or 
future corrective action, including the anticipated schedule for 
starting and concluding such action.

[Amdt. 191-26, 84 FR 52242, Oct. 1, 2019]



Sec.  191.29  National Pipeline Mapping System.

    (a) Each operator of a gas transmission pipeline or liquefied 
natural gas facility must provide the following geospatial data to PHMSA 
for that pipeline or facility:
    (1) Geospatial data, attributes, metadata and transmittal letter 
appropriate for use in the National Pipeline Mapping System. Acceptable 
formats and additional information are specified in the NPMS Operator 
Standards Manual available at www.npms.phmsa.dot.gov or by contacting 
the PHMSA Geographic Information Systems Manager at (202) 366-4595.
    (2) The name of and address for the operator.
    (3) The name and contact information of a pipeline company employee, 
to be displayed on a public Web site, who will serve as a contact for 
questions from the general public about the operator's NPMS data.
    (b) The information required in paragraph (a) of this section must 
be submitted each year, on or before March 15, representing assets as of 
December 31 of the previous year. If no changes have occurred since the 
previous year's submission, the operator must comply with the guidance 
provided in the NPMS Operator Standards manual available at 
www.npms.phmsa.dot.gov or contact the PHMSA Geographic Information 
Systems Manager at (202) 366-4595.

[[Page 429]]

    (c) This section does not apply to gathering pipelines.

[Amdt. 191-23, 80 FR 12777, Mar. 11, 2015, as amended by Amdt. 191-30, 
86 FR 63295, Nov. 15, 2021]



    Sec. Appendix A to Part 191--Procedure for Determining Reporting 
                                Threshold

                  I. Property Damage Threshold Formula

    Each year after calendar year 2021, the Administrator will publish a 
notice on PHMSA's website announcing the updates to the property damage 
threshold criterion that will take effect on July 1 of that year and 
will remain in effect until the June 30 of the next year. The property 
damage threshold used in the definition of an Incident at Sec.  191.3 
shall be determined in accordance with the following formula:
[GRAPHIC] [TIFF OMITTED] TR11JA21.019

Where:

Tr is the revised damage threshold,
Tp is the previous damage threshold,
CPIr is the average Consumer Price Indices for all Urban Consumers (CPI-
          U) published by the Bureau of Labor Statistics each month 
          during the most recent complete calendar year, and
CPIp is the average CPI-U for the calendar year used to establish the 
          previous property damage criteria.

[86 FR 2237, Jan. 11, 2021]



PART 192_TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM 
           FEDERAL SAFETY STANDARDS--Table of Contents



                            Subpart A_General

Sec.
192.1 What is the scope of this part?
192.3 Definitions.
192.5 Class locations.
192.7 What documents are incorporated by reference partly or wholly in 
          this part?
192.8 How are onshore gathering pipelines and regulated onshore 
          gathering pipelines determined?
192.9 What requirements apply to gathering pipelines?
192.10 Outer continental shelf pipelines.
192.11 Petroleum gas systems.
192.12 Underground natural gas storage facilities.
192.13 What general requirements apply to pipelines regulated under this 
          part?
192.14 Conversion to service subject to this part.
192.15 Rules of regulatory construction.
192.16 Customer notification.
192.18 How to notify PHMSA.

                           Subpart B_Materials

192.51 Scope.
192.53 General.
192.55 Steel pipe.
192.57 [Reserved]
192.59 Plastic pipe.
192.61 [Reserved]
192.63 Marking of materials.
192.65 Transportation of pipe.
192.67 Records: Material properties.
192.69 Storage and handling of plastic pipe and associated components.

                          Subpart C_Pipe Design

192.101 Scope.
192.103 General.
192.105 Design formula for steel pipe.
192.107 Yield strength (S) for steel pipe.
192.109 Nominal wall thickness (t) for steel pipe.
192.111 Design factor (F) for steel pipe.
192.112 Additional design requirements for steel pipe using alternative 
          maximum allowable operating pressure.
192.113 Longitudinal joint factor (E) for steel pipe.
192.115 Temperature derating factor (T) for steel pipe.
192.117-192.119 [Reserved]
192.121 Design of plastic pipe.
192.123 Design limitations for plastic pipe.
192.125 Design of copper pipe.
192.127 Records: Pipe design.

                 Subpart D_Design of Pipeline Components

192.141 Scope.
192.143 General requirements.
192.144 Qualifying metallic components.
192.145 Valves.
192.147 Flanges and flange accessories.
192.149 Standard fittings.

[[Page 430]]

192.150 Passage of internal inspection devices.
192.151 Tapping.
192.153 Components fabricated by welding.
192.155 Welded branch connections.
192.157 Extruded outlets.
192.159 Flexibility.
192.161 Supports and anchors.
192.163 Compressor stations: Design and construction.
192.165 Compressor stations: Liquid removal.
192.167 Compressor stations: Emergency shutdown.
192.169 Compressor stations: Pressure limiting devices.
192.171 Compressor stations: Additional safety equipment.
192.173 Compressor stations: Ventilation.
192.175 Pipe-type and bottle-type holders.
192.177 Additional provisions for bottle-type holders.
192.179 Transmission line valves.
192.181 Distribution line valves.
192.183 Vaults: Structural design requirements.
192.185 Vaults: Accessibility.
192.187 Vaults: Sealing, venting, and ventilation.
192.189 Vaults: Drainage and waterproofing.
192.191 [Reserved]
192.193 Valve installation in plastic pipe.
192.195 Protection against accidental overpressuring.
192.197 Control of the pressure of gas delivered from high-pressure 
          distribution systems.
192.199 Requirements for design of pressure relief and limiting devices.
192.201 Required capacity of pressure relieving and limiting stations.
192.203 Instrument, control, and sampling pipe and components.
192.204 Risers installed after January 22, 2019.
192.205 Records: Pipeline components.

                 Subpart E_Welding of Steel in Pipelines

192.221 Scope.
192.225 Welding procedures.
192.227 Qualification of welders and welding operators.
192.229 Limitations on welders and welding operators.
192.229 Limitations on welders.
192.231 Protection from weather.
192.233 Miter joints.
192.235 Preparation for welding.
192.241 Inspection and test of welds.
192.243 Nondestructive testing.
192.245 Repair or removal of defects.

          Subpart F_Joining of Materials Other Than by Welding

192.271 Scope.
192.273 General.
192.275 Cast iron pipe.
192.277 Ductile iron pipe.
192.279 Copper pipe.
192.281 Plastic pipe.
192.283 Plastic pipe: Qualifying joining procedures.
192.285 Plastic pipe: Qualifying persons to make joints.
192.287 Plastic pipe: Inspection of joints.

 Subpart G_General Construction Requirements for Transmission Lines and 
                                  Mains

192.301 Scope.
192.303 Compliance with specifications or standards.
192.305 Inspection: General.
192.307 Inspection of materials.
192.309 Repair of steel pipe.
192.311 Repair of plastic pipe.
192.313 Bends and elbows.
192.315 Wrinkle bends in steel pipe.
192.317 Protection from hazards.
192.319 Installation of pipe in a ditch.
192.321 Installation of plastic pipe.
192.323 Casing.
192.325 Underground clearance.
192.327 Cover.
192.328 Additional construction requirements for steel pipe using 
          alternative maximum allowable operating pressure.
192.329 Installation of plastic pipelines by trenchless excavation.

    Subpart H_Customer Meters, Service Regulators, and Service Lines

192.351 Scope.
192.353 Customer meters and regulators: Location.
192.355 Customer meters and regulators: Protection from damage.
192.357 Customer meters and regulators: Installation.
192.359 Customer meter installations: Operating pressure.
192.361 Service lines: Installation.
192.363 Service lines: Valve requirements.
192.365 Service lines: Location of valves.
192.367 Service lines: General requirements for connections to main 
          piping.
192.369 Service lines: Connections to cast iron or ductile iron mains.
192.371 Service lines: Steel.
192.373 Service lines: Cast iron and ductile iron.
192.375 Service lines: Plastic.
192.376 Installation of plastic service lines by trenchless excavation.
192.377 Service lines: Copper.
192.379 New service lines not in use.
192.381 Service lines: Excess flow valve performance standards.
192.383 Excess flow valve installation.
192.385 Manual service line shut-off valve installation.

[[Page 431]]

              Subpart I_Requirements for Corrosion Control

192.451 Scope.
192.452 How does this subpart apply to converted pipelines and regulated 
          onshore gathering pipelines?
192.453 General.
192.455 External corrosion control: Buried or submerged pipelines 
          installed after July 31, 1971.
192.457 External corrosion control: Buried or submerged pipelines 
          installed before August 1, 1971.
192.459 External corrosion control: Examination of buried pipeline when 
          exposed.
192.461 External corrosion control: Protective coating.
192.463 External corrosion control: Cathodic protection.
192.465 External corrosion control: Monitoring and remediation.
192.467 External corrosion control: Electrical isolation.
192.469 External corrosion control: Test stations.
192.471 External corrosion control: Test leads.
192.473 External corrosion control: Interference currents.
192.475 Internal corrosion control: General.
192.476 Internal corrosion control: Design and construction of 
          transmission line.
192.477 Internal corrosion control: Monitoring.
192.478 Internal corrosion control: Onshore transmission monitoring and 
          mitigation.
192.479 Atmospheric corrosion control: General.
192.481 Atmospheric corrosion control: Monitoring.
192.483 Remedial measures: General.
192.485 Remedial measures: Transmission lines.
192.487 Remedial measures: Distribution lines other than cast iron or 
          ductile iron lines.
192.489 Remedial measures: Cast iron and ductile iron pipelines.
192.490 Direct assessment.
192.491 Corrosion control records.
192.493 In-line inspection of pipelines.

                       Subpart J_Test Requirements

192.501 Scope.
192.503 General requirements.
192.505 Strength test requirements for steel pipeline to operate at a 
          hoop stress of 30 percent or more of SMYS.
192.506 Transmission lines: Spike hydrostatic pressure test.
192.507 Test requirements for pipelines to operate at a hoop stress less 
          than 30 percent of SMYS and at or above 100 p.s.i. (689 kPa) 
          gage.
192.509 Test requirements for pipelines to operate below 100 p.s.i. (689 
          kPa) gage.
192.511 Test requirements for service lines.
192.513 Test requirements for plastic pipelines.
192.515 Environmental protection and safety requirements.
192.517 Records.

                           Subpart K_Uprating

192.551 Scope.
192.553 General requirements.
192.555 Uprating to a pressure that will produce a hoop stress of 30 
          percent or more of SMYS in steel pipelines.
192.557 Uprating: Steel pipelines to a pressure that will produce a hoop 
          stress less than 30 percent of SMYS; plastic, cast iron, and 
          ductile iron pipelines.

                          Subpart L_Operations

192.601 Scope.
192.603 General provisions.
192.605 Procedural manual for operations, maintenance, and emergencies.
192.607 Verification of pipeline material properties and attributes: 
          Onshore steel transmission pipelines.
192.609 Change in class location: Required study.
192.610 Change in class location: Change in valve spacing.
192.611 Change in class location: Confirmation or revision of maximum 
          allowable operating pressure.
192.612 Underwater inspection and reburial of pipelines in the Gulf of 
          Mexico and its inlets.
192.613 Continuing surveillance.
192.614 Damage prevention program.
192.615 Emergency plans.
192.616 Public awareness.
192.617 Investigation of failures and incidents.
192.619 What is the maximum allowable operating pressure for steel or 
          plastic pipelines?
192.620 Alternative maximum allowable operating pressure for certain 
          steel pipelines.
192.621 Maximum allowable operating pressure: High-pressure distribution 
          systems.
192.623 Maximum and minimum allowable operating pressure; Low-pressure 
          distribution systems.
192.624 Maximum allowable operating pressure reconfirmation: Onshore 
          steel transmission pipelines.
192.625 Odorization of gas.
192.627 Tapping pipelines under pressure.
192.629 Purging of pipelines.
192.631 Control room management.
192.632 Engineering critical assessment for maximum allowable operating 
          pressure reconfirmation: Onshore steel transmission pipelines.

[[Page 432]]

192.634 Transmission lines: Onshore valve shut-off for rupture 
          mitigation.
192.635 Notification of potential rupture.
192.636 Transmission lines: Response to a rupture; capabilities of 
          rupture-mitigation valves (RMVs) or alternative equivalent 
          technologies.

                          Subpart M_Maintenance

192.701 Scope.
192.703 General.
192.705 Transmission lines: Patrolling.
192.706 Transmission lines: Leakage surveys.
192.707 Line markers for mains and transmission lines.
192.709 Transmission lines: Record keeping.
192.710 Transmission lines: Assessments outside of high consequence 
          areas.
192.711 Transmission lines: General requirements for repair procedures.
192.712 Analysis of predicted failure pressure and critical strain 
          level.
192.713 Transmission lines: Permanent field repair of imperfections and 
          damages.
192.714 Transmission lines: Repair criteria for onshore transmission 
          pipelines.
192.715 Transmission lines: Permanent field repair of welds.
192.717 Transmission lines: Permanent field repair of leaks.
192.719 Transmission lines: Testing of repairs.
192.720 Distribution systems: Leak repair.
192.721 Distribution systems: Patrolling.
192.723 Distribution systems: Leakage surveys.
192.725 Test requirements for reinstating service lines.
192.727 Abandonment or deactivation of facilities.
192.731 Compressor stations: Inspection and testing of relief devices.
192.735 Compressor stations: Storage of combustible materials.
192.736 Compressor stations: Gas detection.
192.739 Pressure limiting and regulating stations: Inspection and 
          testing.
192.740 Pressure regulating, limiting, and overpressure protection--
          Individual service lines directly connected to regulated 
          gathering or transmission pipelines.
192.741 Pressure limiting and regulating stations: Telemetering or 
          recording gauges.
192.743 Pressure limiting and regulating stations: Capacity of relief 
          devices.
192.745 Valve maintenance: Transmission lines.
192.747 Valve maintenance: Distribution systems.
192.749 Vault maintenance.
192.750 Launcher and receiver safety.
192.751 Prevention of accidental ignition.
192.753 Caulked bell and spigot joints.
192.755 Protecting cast-iron pipelines.
192.756 Joining plastic pipe by heat fusion; equipment maintenance and 
          calibration.

              Subpart N_Qualification of Pipeline Personnel

192.801 Scope.
192.803 Definitions.
192.805 Qualification Program.
192.807 Recordkeeping.
192.809 General.

        Subpart O_Gas Transmission Pipeline Integrity Management

192.901 What do the regulations in this subpart cover?
192.903 What definitions apply to this subpart?
192.905 How does an operator identify a high consequence area?
192.907 What must an operator do to implement this subpart?
192.909 How can an operator change its integrity management program?
192.911 What are the elements of an integrity management program?
192.913 When may an operator deviate its program from certain 
          requirements of this subpart?
192.915 What knowledge and training must personnel have to carry out an 
          integrity management program?
192.917 How does an operator identify potential threats to pipeline 
          integrity and use the threat identification in its integrity 
          program?
192.919 What must be in the baseline assessment plan?
192.921 How is the baseline assessment to be conducted?
192.923 How is direct assessment used and for what threats?
192.925 What are the requirements for using External Corrosion Direct 
          Assessment (ECDA)?
192.927 What are the requirements for using Internal Corrosion Direct 
          Assessment (ICDA)?
192.929 What are the requirements for using Direct Assessment for Stress 
          Corrosion Cracking?
192.931 How may Confirmatory Direct Assessment (CDA) be used?
192.933 What actions must be taken to address integrity issues?
192.935 What additional preventive and mitigative measures must an 
          operator take?
192.937 What is a continual process of evaluation and assessment to 
          maintain a pipeline's integrity?
192.939 What are the required reassessment intervals?
192.941 What is a low stress reassessment?
192.943 When can an operator deviate from these reassessment intervals?

[[Page 433]]

192.945 What methods must an operator use to measure program 
          effectiveness?
192.947 What records must an operator keep?
192.949 [Reserved]
192.951 Where does an operator file a report?

      Subpart P_Gas Distribution Pipeline Integrity Management (IM)

192.1001 What definitions apply to this subpart?
192.1003 What do the regulations in this subpart cover?
192.1005 What must a gas distribution operator (other than a small LPG 
          operator) do to implement this subpart?
192.1007 What are the required elements of an integrity management plan?
192.1009 [Reserved]
192.1011 What records must an operator keep?
192.1013 When may an operator deviate from required periodic inspections 
          of this part?
192.1015 What must a small LPG operator do to implement this subpart?

Appendix A to Part 192 [Reserved]
Appendix B to Part 192--Qualification of Pipe and Components
Appendix C to Part 192--Qualification of Welders for Low Stress Level 
          Pipe
Appendix D to Part 192--Criteria for Cathodic Protection and 
          Determination of Measurements
Appendix E to Part 192--Guidance on Determining High Consequence Areas 
          and on Carrying out Requirements in the Integrity Management 
          Rule
Appendix F to Part 192--Criteria for Conducting Integrity Assessments 
          Using Guided Wave Ultrasonic Testing (GWUT)

    Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et. seq., and 
49 CFR 1.97.

    Source: 35 FR 13257, Aug. 19, 1970, unless otherwise noted.

    Editorial Note: Nomenclature changes to part 192 appear at 71 FR 
33406, June 9, 2006.



                            Subpart A_General



Sec.  192.1  What is the scope of this part?

    (a) This part prescribes minimum safety requirements for pipeline 
facilities and the transportation of gas, including pipeline facilities 
and the transportation of gas within the limits of the outer continental 
shelf as that term is defined in the Outer Continental Shelf Lands Act 
(43 U.S.C. 1331).
    (b) This part does not apply to--
    (1) Offshore gathering of gas in State waters upstream from the 
outlet flange of each facility where hydrocarbons are produced or where 
produced hydrocarbons are first separated, dehydrated, or otherwise 
processed, whichever facility is farther downstream;
    (2) Pipelines on the Outer Continental Shelf (OCS) that are 
producer-operated and cross into State waters without first connecting 
to a transporting operator's facility on the OCS, upstream (generally 
seaward) of the last valve on the last production facility on the OCS. 
Safety equipment protecting PHMSA-regulated pipeline segments is not 
excluded. Producing operators for those pipeline segments upstream of 
the last valve of the last production facility on the OCS may petition 
the Administrator, or designee, for approval to operate under PHMSA 
regulations governing pipeline design, construction, operation, and 
maintenance under 49 CFR 190.9;
    (3) Pipelines on the Outer Continental Shelf upstream of the point 
at which operating responsibility transfers from a producing operator to 
a transporting operator;
    (4) Onshore gathering of gas--
    (i) Through a pipeline that operates at less than 0 psig (0 kPa);
    (ii) Through a pipeline that is not a regulated onshore gathering 
line (as determined in Sec.  192.8); and
    (iii) Within inlets of the Gulf of Mexico, except for the 
requirements in Sec.  192.612; or
    (5) Any pipeline system that transports only petroleum gas or 
petroleum gas/air mixtures to--
    (i) Fewer than 10 customers, if no portion of the system is located 
in a public place; or
    (ii) A single customer, if the system is located entirely on the 
customer's premises (no matter if a portion of the system is located in 
a public place).

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34605, 
Aug. 16, 1976; Amdt. 192-67, 56 FR 63771, Dec. 5, 1991; Amdt. 192-78, 61 
FR 28782, June 6, 1996; Amdt. 192-81, 62 FR 61695, Nov. 19, 1997; Amdt. 
192-92, 68 FR 46112, Aug. 5, 2003; 70 FR 11139, Mar. 8, 2005; Amdt. 192-
102, 71 FR 13301, Mar. 15, 2006; Amdt. 192-103, 72 FR 4656, Feb. 1, 
2007]



Sec.  192.3  Definitions.

    As used in this part:

[[Page 434]]

    Abandoned means permanently removed from service.
    Active corrosion means continuing corrosion that, unless controlled, 
could result in a condition that is detrimental to public safety.
    Administrator means the Administrator, Pipeline and Hazardous 
Materials Safety Administration or his or her delegate.
    Alarm means an audible or visible means of indicating to the 
controller that equipment or processes are outside operator-defined, 
safety-related parameters.
    Close interval survey means a series of closely and properly spaced 
pipe-to-electrolyte potential measurements taken over the pipe to assess 
the adequacy of cathodic protection or to identify locations where a 
current may be leaving the pipeline that may cause corrosion and for the 
purpose of quantifying voltage (IR) drops other than those across the 
structure electrolyte boundary, such as when performed as a current 
interrupted, depolarized, or native survey.
    Composite materials means materials used to make pipe or components 
manufactured with a combination of either steel and/or plastic and with 
a reinforcing material to maintain its circumferential or longitudinal 
strength.
    Control room means an operations center staffed by personnel charged 
with the responsibility for remotely monitoring and controlling a 
pipeline facility.
    Controller means a qualified individual who remotely monitors and 
controls the safety-related operations of a pipeline facility via a 
SCADA system from a control room, and who has operational authority and 
accountability for the remote operational functions of the pipeline 
facility.
    Customer meter means the meter that measures the transfer of gas 
from an operator to a consumer.
    Distribution center means the initial point where gas enters piping 
used primarily to deliver gas to customers who purchase it for 
consumption, as opposed to customers who purchase it for resale, for 
example:
    (1) At a metering location;
    (2) A pressure reduction location; or
    (3) Where there is a reduction in the volume of gas, such as a 
lateral off a transmission line.
    Distribution line means a pipeline other than a gathering or 
transmission line.
    Dry gas or dry natural gas means gas above its dew point and without 
condensed liquids.
    Electrical survey means a series of closely spaced pipe-to-soil 
readings over pipelines which are subsequently analyzed to identify 
locations where a corrosive current is leaving the pipeline.
    Engineering critical assessment (ECA) means a documented analytical 
procedure based on fracture mechanics principles, relevant material 
properties (mechanical and fracture resistance properties), operating 
history, operational environment, in-service degradation, possible 
failure mechanisms, initial and final defect sizes, and usage of future 
operating and maintenance procedures to determine the maximum tolerable 
sizes for imperfections based upon the pipeline segment maximum 
allowable operating pressure.
    Entirely replaced onshore transmission pipeline segments means, for 
the purposes of Sec. Sec.  192.179 and 192.634, where 2 or more miles, 
in the aggregate, of onshore transmission pipeline have been replaced 
within any 5 contiguous miles of pipeline within any 24-month period. 
This definition does not apply to any gathering line.
    Exposed underwater pipeline means an underwater pipeline where the 
top of the pipe protrudes above the underwater natural bottom (as 
determined by recognized and generally accepted practices) in waters 
less than 15 feet (4.6 meters) deep, as measured from mean low water.
    Gas means natural gas, flammable gas, or gas which is toxic or 
corrosive.
    Gathering line means a pipeline that transports gas from a current 
production facility to a transmission line or main.
    Gulf of Mexico and its inlets means the waters from the mean high 
water mark of the coast of the Gulf of Mexico and its inlets open to the 
sea (excluding rivers, tidal marshes, lakes, and canals) seaward to 
include the territorial sea and Outer Continental Shelf to a

[[Page 435]]

depth of 15 feet (4.6 meters), as measured from the mean low water.
    Hard spot means an area on steel pipe material with a minimum 
dimension greater than two inches (50.8 mm) in any direction and 
hardness greater than or equal to Rockwell 35 HRC (Brinell 327 HB or 
Vickers 345 HV10).
    Hazard to navigation means, for the purposes of this part, a 
pipeline where the top of the pipe is less than 12 inches (305 
millimeters) below the underwater natural bottom (as determined by 
recognized and generally accepted practices) in waters less than 15 feet 
(4.6 meters) deep, as measured from the mean low water.
    High-pressure distribution system means a distribution system in 
which the gas pressure in the main is higher than the pressure provided 
to the customer.
    In-line inspection (ILI) means an inspection of a pipeline from the 
interior of the pipe using an inspection tool also called intelligent or 
smart pigging. This definition includes tethered and self-propelled 
inspection tools.
    In-line inspection tool or instrumented internal inspection device 
means an instrumented device or vehicle that uses a non-destructive 
testing technique to inspect the pipeline from the inside in order to 
identify and characterize flaws to analyze pipeline integrity; also 
known as an intelligent or smart pig.
    Line section means a continuous run of transmission line between 
adjacent compressor stations, between a compressor station and storage 
facilities, between a compressor station and a block valve, or between 
adjacent block valves.
    Listed specification means a specification listed in section I of 
appendix B of this part.
    Low-pressure distribution system means a distribution system in 
which the gas pressure in the main is substantially the same as the 
pressure provided to the customer.
    Main means a distribution line that serves as a common source of 
supply for more than one service line.
    Maximum actual operating pressure means the maximum pressure that 
occurs during normal operations over a period of 1 year.
    Maximum allowable operating pressure (MAOP) means the maximum 
pressure at which a pipeline or segment of a pipeline may be operated 
under this part.
    Moderate consequence area means:
    (1) An onshore area that is within a potential impact circle, as 
defined in Sec.  192.903, containing either:
    (i) Five or more buildings intended for human occupancy; or
    (ii) Any portion of the paved surface, including shoulders, of a 
designated interstate, other freeway, or expressway, as well as any 
other principal arterial roadway with 4 or more lanes, as defined in the 
Federal Highway Administration's Highway Functional Classification 
Concepts, Criteria and Procedures, Section 3.1 (see: https://
www.fhwa.dot.gov/planning/processes/statewide/related/
highway_functional_classifications/fcauab.pdf), and that does not meet 
the definition of high consequence area, as defined in Sec.  192.903.
    (2) The length of the moderate consequence area extends axially 
along the length of the pipeline from the outermost edge of the first 
potential impact circle containing either 5 or more buildings intended 
for human occupancy; or any portion of the paved surface, including 
shoulders, of any designated interstate, freeway, or expressway, as well 
as any other principal arterial roadway with 4 or more lanes, to the 
outermost edge of the last contiguous potential impact circle that 
contains either 5 or more buildings intended for human occupancy, or any 
portion of the paved surface, including shoulders, of any designated 
interstate, freeway, or expressway, as well as any other principal 
arterial roadway with 4 or more lanes.
    Municipality means a city, county, or any other political 
subdivision of a State.
    Notification of potential rupture means the notification to, or 
observation by, an operator of indicia identified in Sec.  192.635 of a 
potential unintentional or uncontrolled release of a large volume of gas 
from a pipeline. This definition does not apply to any gathering line.
    Offshore means beyond the line of ordinary low water along that 
portion of the coast of the United States that is

[[Page 436]]

in direct contact with the open seas and beyond the line marking the 
seaward limit of inland waters.
    Operator means a person who engages in the transportation of gas.
    Outer Continental Shelf means all submerged lands lying seaward and 
outside the area of lands beneath navigable waters as defined in Section 
2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil 
and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Person means any individual, firm, joint venture, partnership, 
corporation, association, State, municipality, cooperative association, 
or joint stock association, and including any trustee, receiver, 
assignee, or personal representative thereof.
    Petroleum gas means propane, propylene, butane, (normal butane or 
isobutanes), and butylene (including isomers), or mixtures composed 
predominantly of these gases, having a vapor pressure not exceeding 208 
psi (1434 kPa) gage at 100 [deg]F (38 [deg]C).
    Pipe means any pipe or tubing used in the transportation of gas, 
including pipe-type holders.
    Pipeline means all parts of those physical facilities through which 
gas moves in transportation, including pipe, valves, and other 
appurtenance attached to pipe, compressor units, metering stations, 
regulator stations, delivery stations, holders, and fabricated 
assemblies.
    Pipeline environment includes soil resistivity (high or low), soil 
moisture (wet or dry), soil contaminants that may promote corrosive 
activity, and other known conditions that could affect the probability 
of active corrosion.
    Pipeline facility means new and existing pipelines, rights-of-way, 
and any equipment, facility, or building used in the transportation of 
gas or in the treatment of gas during the course of transportation.
    Rupture-mitigation valve (RMV) means an automatic shut-off valve 
(ASV) or a remote-control valve (RCV) that a pipeline operator uses to 
minimize the volume of gas released from the pipeline and to mitigate 
the consequences of a rupture. This definition does not apply to any 
gathering line.
    Service line means a distribution line that transports gas from a 
common source of supply to an individual customer, to two adjacent or 
adjoining residential or small commercial customers, or to multiple 
residential or small commercial customers served through a meter header 
or manifold. A service line ends at the outlet of the customer meter or 
at the connection to a customer's piping, whichever is further 
downstream, or at the connection to customer piping if there is no 
meter.
    Service regulator means the device on a service line that controls 
the pressure of gas delivered from a higher pressure to the pressure 
provided to the customer. A service regulator may serve one customer or 
multiple customers through a meter header or manifold.
    SMYS means specified minimum yield strength is:
    (1) For steel pipe manufactured in accordance with a listed 
specification, the yield strength specified as a minimum in that 
specification; or
    (2) For steel pipe manufactured in accordance with an unknown or 
unlisted specification, the yield strength determined in accordance with 
Sec.  192.107(b).
    State means each of the several States, the District of Columbia, 
and the Commonwealth of Puerto Rico.
    Supervisory Control and Data Acquisition (SCADA) system means a 
computer-based system or systems used by a controller in a control room 
that collects and displays information about a pipeline facility and may 
have the ability to send commands back to the pipeline facility.
    Transmission line means a pipeline or connected series of pipelines, 
other than a gathering line, that:
    (1) Transports gas from a gathering pipeline or storage facility to 
a distribution center, storage facility, or large volume customer that 
is not down-stream from a distribution center;
    (2) Has an MAOP of 20 percent or more of SMYS;
    (3) Transports gas within a storage field; or
    (4) Is voluntarily designated by the operator as a transmission 
pipeline.
    Note 1 to transmission line. A large volume customer may receive 
similar

[[Page 437]]

volumes of gas as a distribution center, and includes factories, power 
plants, and institutional users of gas.
    Transportation of gas means the gathering, transmission, or 
distribution of gas by pipeline or the storage of gas, in or affecting 
interstate or foreign commerce.
    Underground natural gas storage facility (UNGSF) means a gas 
pipeline facility that stores natural gas underground incidental to the 
transportation of natural gas, including:
    (1)(i) A depleted hydrocarbon reservoir;
    (ii) An aquifer reservoir; or
    (iii) A solution-mined salt cavern.
    (2) In addition to the reservoir or cavern, a UNGSF includes 
injection, withdrawal, monitoring, and observation wells; wellbores and 
downhole components; wellheads and associated wellhead piping; wing-
valve assemblies that isolate the wellhead from connected piping beyond 
the wing-valve assemblies; and any other equipment, facility, right-of-
way, or building used in the underground storage of natural gas.
    Weak link means a device or method used when pulling polyethylene 
pipe, typically through methods such as horizontal directional drilling, 
to ensure that damage will not occur to the pipeline by exceeding the 
maximum tensile stresses allowed.
    Welder means a person who performs manual or semi-automatic welding.
    Welding operator means a person who operates machine or automatic 
welding equipment.
    Wrinkle bend means a bend in the pipe that:
    (1) Was formed in the field during construction such that the inside 
radius of the bend has one or more ripples with:
    (i) An amplitude greater than or equal to 1.5 times the wall 
thickness of the pipe, measured from peak to valley of the ripple; or
    (ii) With ripples less than 1.5 times the wall thickness of the pipe 
and with a wrinkle length (peak to peak) to wrinkle height (peak to 
valley) ratio under 12.
    (2)(i) If the length of the wrinkle bend cannot be reliably 
determined, then wrinkle bend means a bend in the pipe where (h/D)*100 
exceeds 2 when S is less than 37,000 psi (255 MPa), where (h/D)*100 
exceeds (47000--S)/10,000 +1 for psi [(324--S)/69 +1 for MPa] when S is 
greater than 37,000 psi (255 MPa) but less than 47,000 psi (324 MPa), 
and where (h/D)*100 exceeds 1 when S is 47,000 psi (324 MPa) or more.
    (ii) Where:

    (A) D = Outside diameter of the pipe, in. (mm);
    (B) h = Crest-to-trough height of the ripple, in. (mm); and
    (C) S = Maximum operating hoop stress, psi (S/145, MPa).

[Amdt. 192-13, 38 FR 9084, Apr. 10, 1973]

    Editorial Note: For Federal Register citations affecting Sec.  
192.3, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.govinfo.gov.



Sec.  192.5  Class locations.

    (a) This section classifies pipeline locations for purposes of this 
part. The following criteria apply to classifications under this 
section.
    (1) A ``class location unit'' is an onshore area that extends 220 
yards (200 meters) on either side of the centerline of any continuous 1- 
mile (1.6 kilometers) length of pipeline.
    (2) Each separate dwelling unit in a multiple dwelling unit building 
is counted as a separate building intended for human occupancy.
    (b) Except as provided in paragraph (c) of this section, pipeline 
locations are classified as follows:
    (1) A Class 1 location is:
    (i) An offshore area; or
    (ii) Any class location unit that has 10 or fewer buildings intended 
for human occupancy.
    (2) A Class 2 location is any class location unit that has more than 
10 but fewer than 46 buildings intended for human occupancy.
    (3) A Class 3 location is:
    (i) Any class location unit that has 46 or more buildings intended 
for human occupancy; or
    (ii) An area where the pipeline lies within 100 yards (91 meters) of 
either a building or a small, well-defined outside area (such as a 
playground, recreation area, outdoor theater, or other place of public 
assembly) that is occupied by 20 or more persons on at least

[[Page 438]]

5 days a week for 10 weeks in any 12-month period. (The days and weeks 
need not be consecutive.)
    (4) A Class 4 location is any class location unit where buildings 
with four or more stories above ground are prevalent.
    (c) The length of Class locations 2, 3, and 4 may be adjusted as 
follows:
    (1) A Class 4 location ends 220 yards (200 meters) from the nearest 
building with four or more stories above ground.
    (2) When a cluster of buildings intended for human occupancy 
requires a Class 2 or 3 location, the class location ends 220 yards (200 
meters) from the nearest building in the cluster.
    (d) An operator must have records that document the current class 
location of each gas transmission pipeline segment and that demonstrate 
how the operator determined each current class location in accordance 
with this section.

[Amdt. 192-78, 61 FR 28783, June 6, 1996; 61 FR 35139, July 5, 1996, as 
amended by Amdt. 192-85, 63 FR 37502, July 13, 1998; Amdt. 192-125, 84 
FR 52243, Oct. 1, 2019; Amdt. 192-127, 85 FR 40134, July 6, 2020]



Sec.  192.7  What documents are incorporated by reference partly or wholly 
in this part?

    (a) Certain material is incorporated by reference into this part 
with the approval of the Director of the Federal Register under 5 U.S.C. 
552(a) and 1 CFR part 51. All approved material is available for 
inspection at the Office of Pipeline Safety, Pipeline and Hazardous 
Materials Safety Administration, 1200 New Jersey Avenue SE, Washington, 
DC 20590, 202-366-4046, https://www.phmsa.dot.gov/pipeline/regs, and at 
the National Archives and Records Administration (NARA). For information 
on the availability of this material at NARA, email 
[email protected], or go to www.archives.gov/federal-register/cfr/
ibr-locations.html. It is also available from the sources in the 
following paragraphs of this section.
    (b) American Petroleum Institute (API), 200 Massachusetts Ave. NW, 
Suite 1100, Washington, DC 20001, and phone: 202-682-8000, website: 
https://www.api.org/.
    (1) API Recommended Practice 5L1, ``Recommended Practice for 
Railroad Transportation of Line Pipe,'' 7th edition, September 2009, 
(API RP 5L1), IBR approved for Sec.  192.65(a).
    (2) API Recommended Practice 5LT, ``Recommended Practice for Truck 
Transportation of Line Pipe,'' First edition, March 2012, (API RP 5LT), 
IBR approved for Sec.  192.65(c).
    (3) API Recommended Practice 5LW, ``Recommended Practice for 
Transportation of Line Pipe on Barges and Marine Vessels,'' 3rd edition, 
September 2009, (API RP 5LW), IBR approved for Sec.  192.65(b).
    (4) API Recommended Practice 80, ``Guidelines for the Definition of 
Onshore Gas Gathering Lines,'' 1st edition, April 2000, (API RP 80), IBR 
approved for Sec.  192.8(a).
    (5) API Recommended Practice 1162, ``Public Awareness Programs for 
Pipeline Operators,'' 1st edition, December 2003, (API RP 1162), IBR 
approved for Sec.  192.616(a), (b), and (c).
    (6) API Recommended Practice 1165, ``Recommended Practice for 
Pipeline SCADA Displays,'' First edition, January 2007, (API RP 1165), 
IBR approved for Sec.  192.631(c).
    (7) API Specification 5L, ``Specification for Line Pipe,'' 45th 
edition, effective July 1, 2013, (API Spec 5L), IBR approved for 
Sec. Sec.  192.55(e); 192.112(a), (b), (d), (e); 192.113; and Item I, 
Appendix B to Part 192.
    (8) ANSI/API Specification 6D, ``Specification for Pipeline 
Valves,''23rd edition, effective October 1, 2008, including Errata 1 
(June 2008), Errata2 (/November 2008), Errata 3 (February 2009), Errata 
4 (April 2010), Errata 5 (November 2010), Errata 6 (August 2011) 
Addendum 1 (October 2009), Addendum 2 (August 2011), and Addendum 3 
(October 2012), (ANSI/API Spec 6D), IBR approved for Sec.  192.145(a).
    (9) API Standard 1104, ``Welding of Pipelines and Related 
Facilities,'' 20th edition, October 2005, including errata/addendum 
(July 2007) and errata 2 (2008), (API Std 1104), IBR approved for 
Sec. Sec.  192.225(a); 192.227(a); 192.229(b) and (c); 192.241(c); and 
Item II, Appendix B.
    (10) API Recommended Practice 1170, ``Design and Operation of 
Solution-mined Salt Caverns Used for Natural

[[Page 439]]

Gas Storage,'' First edition, July 2015 (API RP 1170), IBR approved for 
Sec.  192.12.
    (11) API Recommended Practice 1171, ``Functional Integrity of 
Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer 
Reservoirs,'' First edition, September 2015, (API RP 1171), IBR approved 
for Sec.  192.12.
    (12) API STANDARD 1163, ``In-Line Inspection Systems 
Qualification,'' Second edition, April 2013, Reaffirmed August 2018, 
(API STD 1163), IBR approved for Sec.  192.493.
    (c) ASME International (ASME), Three Park Avenue, New York, NY 
10016, 800-843-2763 (U.S./Canada), http://www.asme.org/.
    (1) ASME/ANSI B16.1-2005, ``Gray Iron Pipe Flanges and Flanged 
Fittings: (Classes 25, 125, and 250),'' August 31, 2006, (ASME/ANSI 
B16.1), IBR approved for Sec.  192.147(c).
    (2) ASME/ANSI B16.5-2003, ``Pipe Flanges and Flanged Fittings,'' 
October 2004, (ASME/ANSI B16.5), IBR approved for Sec. Sec.  192.147(a), 
192.279, and 192.607(f).
    (3) ASME B16.40-2008, ``Manually Operated Thermoplastic Gas Shutoffs 
and Valves in Gas Distribution Systems,'' March 18, 2008, approved by 
ANSI, (ASME B16.40-2008), IBR approved for Item I, Appendix B to Part 
192.
    (4) ASME/ANSI B31G-1991 (Reaffirmed 2004), ``Manual for Determining 
the Remaining Strength of Corroded Pipelines,'' 2004, (ASME/ANSI B31G), 
IBR approved for Sec. Sec.  192.485(c), 192.632(a), 192.712(b), and 
192.933(a).
    (5) ASME/ANSI B31.8-2007, ``Gas Transmission and Distribution Piping 
Systems,'' November 30, 2007, (ASME/ANSI B31.8), IBR approved for 
Sec. Sec.  192.112(b) and 192.619(a).
    (6) ASME/ANSI B31.8S-2004, ``Supplement to B31.8 on Managing System 
Integrity of Gas Pipelines,'' approved January 14, 2005, (ASME/ANSI 
B31.8S), IBR approved for Sec. Sec.  192.13(d); 192.714(c) and (d); 
192.903 note to potential impact radius; 192.907 introductory text and 
(b); 192.911 introductory text, (i), and (k) through (m); 192.913(a) 
through (c); 192.917(a) through (e); 192.921(a); 192.923(b); 192.925(b); 
192.927(b) and (c); 192.929(b); 192.933(c) and (d); 192.935(a) and (b); 
192.937(c); 192.939(a); and 192.945(a).
    (7) [Reserved]
    (8) ASME Boiler & Pressure Vessel Code, Section VIII, Division 1 
``Rules for Construction of Pressure Vessels,'' 2007 edition, July 1, 
2007, (ASME BPVC, Section VIII, Division 1), IBR approved for Sec. Sec.  
192.153(a), (b), (d); and 192.165(b).
    (9) ASME Boiler & Pressure Vessel Code, Section VIII, Division 2 
``Alternate Rules, Rules for Construction of Pressure Vessels,'' 2007 
edition, July 1, 2007, (ASME BPVC, Section VIII, Division 2), IBR 
approved for Sec. Sec.  192.153(b), (d); and 192.165(b).
    (10) ASME Boiler & Pressure Vessel Code, Section IX: ``Qualification 
Standard for Welding and Brazing Procedures, Welders, Brazers, and 
Welding and Brazing Operators,'' 2007 edition, July 1, 2007, ASME BPVC, 
Section IX, IBR approved for Sec. Sec.  192.225(a); 192.227(a); and Item 
II, Appendix B to Part 192.
    (d) American Society for Nondestructive Testing (ASNT), P.O. Box 
28518, 1711 Arlingate Lane, Columbus, OH 43228, phone: 800-222-2768, 
website: https://www.asnt.org/.
    (1) ANSI/ASNT ILI-PQ-2005(2010), ``In-line Inspection Personnel 
Qualification and Certification,'' Reapproved October 11, 2010, (ANSI/
ASNT ILI-PQ), IBR approved for Sec.  192.493.
    (2) [Reserved]
    (e) ASTM International (formerly American Society for Testing and 
Materials), 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA 
19428, phone: (610) 832-9585, website: http://astm.org.
    (1) ASTM A53/A53M-10, ``Standard Specification for Pipe, Steel, 
Black and Hot-Dipped, Zinc-Coated, Welded and Seamless,'' approved 
October 1, 2010, (ASTM A53/A53M), IBR approved for Sec.  192.113; and 
Item II, Appendix B to Part 192.
    (2) ASTM A106/A106M-10, ``Standard Specification for Seamless Carbon 
Steel Pipe for High-Temperature Service,'' approved October 1, 2010, 
(ASTM A106/A106M), IBR approved for Sec.  192.113; and Item I, Appendix 
B to Part 192.
    (3) ASTM A333/A333M-11, ``Standard Specification for Seamless and 
Welded Steel Pipe for Low-Temperature Service,'' approved April 1, 2011, 
(ASTM A333/A333M), IBR approved for Sec.  192.113; and Item I, Appendix 
B to Part 192.
    (4) ASTM A372/A372M-10, ``Standard Specification for Carbon and 
Alloy

[[Page 440]]

Steel Forgings for Thin-Walled Pressure Vessels,'' approved October 1, 
2010, (ASTM A372/A372M), IBR approved for Sec.  192.177(b).
    (5) ASTM A381-96 (reapproved 2005), ``Standard Specification for 
Metal-Arc Welded Steel Pipe for Use with High-Pressure Transmission 
Systems,'' approved October 1, 2005, (ASTM A381), IBR approved for Sec.  
192.113; and Item I, Appendix B to Part 192.
    (6) ASTM A578/A578M-96 (reapproved 2001), ``Standard Specification 
for Straight-Beam Ultrasonic Examination of Plain and Clad Steel Plates 
for Special Applications,'' (ASTM A578/A578M), IBR approved for Sec.  
192.112(c).
    (7) ASTM A671/A671M-10, ``Standard Specification for Electric-
Fusion-Welded Steel Pipe for Atmospheric and Lower Temperatures,'' 
approved April 1, 2010, (ASTM A671/A671M), IBR approved for Sec.  
192.113; and Item I, Appendix B to Part 192.
    (8) ASTM A672/A672M-09, ``Standard Specification for Electric-
Fusion-Welded Steel Pipe for High-Pressure Service at Moderate 
Temperatures,'' approved October 1, 2009, (ASTM A672/672M), IBR approved 
for Sec.  192.113 and Item I, Appendix B to Part 192.
    (9) ASTM A691/A691M-09, ``Standard Specification for Carbon and 
Alloy Steel Pipe, Electric-Fusion-Welded for High-Pressure Service at 
High Temperatures,'' approved October 1, 2009, (ASTM A691/A691M), IBR 
approved for Sec.  192.113 and Item I, Appendix B to Part 192.
    (10) ASTM D638-03, ``Standard Test Method for Tensile Properties of 
Plastics,'' 2003, (ASTM D638), IBR approved for Sec.  192.283(a) and 
(b).
    (11) ASTM D2513-18a, ``Standard Specification for Polyethylene (PE) 
Gas Pressure Pipe, Tubing, and Fittings,'' approved August 1, 2018, 
(ASTM D2513), IBR approved for Item I, Appendix B to Part 192.
    (12) ASTM D2517-00, ``Standard Specification for Reinforced Epoxy 
Resin Gas Pressure Pipe and Fittings,'' (ASTM D 2517), IBR approved for 
Sec. Sec.  192.191(a); 192.281(d); 192.283(a); and Item I, Appendix B to 
Part 192.
    (13) ASTM D2564-12, ``Standard Specification for Solvent Cements for 
Poly (Vinyl Chloride) (PVC) Plastic Piping Systems,'' Aug. 1, 2012, 
(ASTM D2564-12), IBR approved for Sec.  192.281(b)(2).
    (14) ASTM F1055-98 (Reapproved 2006), ``Standard Specification for 
Electrofusion Type Polyethylene Fittings for Outside Diameter Controlled 
Polyethylene Pipe and Tubing,'' March 1, 2006, (ASTM F1055-98 (2006)), 
IBR approved for Sec.  192.283(a), Item I, Appendix B to Part 192.
    (15) ASTM F1924-12, ``Standard Specification for Plastic Mechanical 
Fittings for Use on Outside Diameter Controlled Polyethylene Gas 
Distribution Pipe and Tubing,'' April 1, 2012, (ASTM F1924-12), IBR 
approved for Item I, Appendix B to Part 192.
    (16) ASTM F1948-12, ``Standard Specification for Metallic Mechanical 
Fittings for Use on Outside Diameter Controlled Thermoplastic Gas 
Distribution Pipe and Tubing,'' April 1, 2012, (ASTM F1948-12), IBR 
approved for Item I, Appendix B to Part 192.
    (17) ASTM F1973-13, ``Standard Specification for Factory Assembled 
Anodeless Risers and Transition Fittings in Polyethylene (PE) and 
Polyamide 11 (PA11) and Polyamide 12 (PA12) Fuel Gas Distribution 
Systems,'' May 1, 2013, (ASTM F1973-13), IBR approved for Sec.  
192.204(b); and Item I, Appendix B to Part 192.
    (18) ASTM F2145-13, ``Standard Specification for Polyamide 11 (PA 
11) and Polyamide 12 (PA12) Mechanical Fittings for Use on Outside 
Diameter Controlled Polyamide 11 and Polyamide 12 Pipe and Tubing,'' May 
1, 2013, (ASTM F2145-13), IBR approved for Item I, Appendix B to Part 
192.
    (19) ASTM F 2600-09, ``Standard Specification for Electrofusion Type 
Polyamide-11 Fittings for Outside Diameter Controlled Polyamide-11 Pipe 
and Tubing,'' April 1, 2009, (ASTM F 2600-09), IBR approved for Item I, 
Appendix B to Part 192.
    (20) ASTM F2620-19, ``Standard Practice for Heat Fusion Joining of 
Polyethylene Pipe and Fittings,'' approved February 1, 2019, (ASTM 
F2620), IBR approved for Sec. Sec.  192.281(c) and 192.285(b).
    (21) ASTM F2767-12, ``Specification for Electrofusion Type 
Polyamide-12 Fittings for Outside Diameter Controlled Polyamide-12 Pipe 
and Tubing for Gas Distribution,'' Oct. 15, 2012,

[[Page 441]]

(ASTM F2767-12), IBR approved for Item I, Appendix B to Part 192.
    (22) ASTM F2785-12, ``Standard Specification for Polyamide 12 Gas 
Pressure Pipe, Tubing, and Fittings,'' Aug. 1, 2012, (ASTM F2785-12), 
IBR approved for Item I, Appendix B to Part 192.
    (23) ASTM F2817-10, ``Standard Specification for Poly (Vinyl 
Chloride) (PVC) Gas Pressure Pipe and Fittings for Maintenance or 
Repair,'' Feb. 1, 2010, (ASTM F2817-10), IBR approved for Item I, 
Appendix B to Part 192.
    (24) ASTM F2945-12a ``Standard Specification for Polyamide 11 Gas 
Pressure Pipe, Tubing, and Fittings,'' Nov. 27, 2012, (ASTM F2945-12a), 
IBR approved for Item I, Appendix B to Part 192.
    (f) Gas Technology Institute (GTI), formerly the Gas Research 
Institute (GRI)), 1700 S. Mount Prospect Road, Des Plaines, IL 60018, 
phone: 847-768-0500, Web site: www.gastechnology.org.
    (1) GRI 02/0057 (2002) ``Internal Corrosion Direct Assessment of Gas 
Transmission Pipelines Methodology,'' (GRI 02/0057), IBR approved for 
Sec.  192.927(c).
    (2) [Reserved]
    (g) Manufacturers Standardization Society of the Valve and Fittings 
Industry, Inc. (MSS), 127 Park St. NE., Vienna, VA 22180, phone: 703-
281-6613, Web site: http://www.mss-hq.org/.
    (1) MSS SP-44-2010, Standard Practice, ``Steel Pipeline Flanges,'' 
2010 edition, (including Errata (May 20, 2011)), (MSS SP-44), IBR 
approved for Sec.  192.147(a).
    (2) [Reserved]
    (h) NACE International (NACE), 1440 South Creek Drive, Houston, TX 
77084: phone: 281-228-6223 or 800-797-6223, Web site: http://
www.nace.org/Publications/.
    (1) NACE Standard Practice 0102-2010, ``In-Line Inspection of 
Pipelines,'' Revised 2010-03-13, (NACE SP0102), IBR approved for 
Sec. Sec.  192.150(a) and 192.493.
    (2) NACE SP0204-2008, Standard Practice, ``Stress Corrosion Cracking 
(SCC) Direct Assessment Methodology,'' reaffirmed September 18, 2008, 
(NACE SP0204); IBR approved for Sec. Sec.  192.923(b); 192.929(b) 
introductory text, (b)(1) through (3), (b)(5) introductory text, and 
(b)(5)(i).
    (3) NACE SP0206-2006, Standard Practice, ``Internal Corrosion Direct 
Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas 
(DG-ICDA),'' approved December 1, 2006, (NACE SP0206), IBR approved for 
Sec. Sec.  192.923(b); 192.927(b), (c) introductory text, and (c)(1) 
through (4).
    (4) ANSI/NACE SP0502-2010, Standard Practice, ``Pipeline External 
Corrosion Direct Assessment Methodology,'' revised June 24, 2010, (NACE 
SP0502), IBR approved for Sec. Sec.  192.319(f); 192.461(h); 192.923(b); 
192.925(b); 192.931(d); 192.935(b); and 192.939(a).
    (i) National Fire Protection Association (NFPA), 1 Batterymarch 
Park, Quincy, Massachusetts 02169, phone: 1 617 984-7275, Web site: 
http://www.nfpa.org/.
    (1) NFPA-30 (2012), ``Flammable and Combustible Liquids Code,'' 2012 
edition, June 20, 2011, including Errata 30-12-1 (September 27, 2011) 
and Errata 30-12-2 (November 14, 2011), (NFPA-30), IBR approved for 
Sec.  192.735(b).
    (2) NFPA-58 (2004), ``Liquefied Petroleum Gas Code (LP-Gas Code),'' 
(NFPA-58), IBR approved for Sec.  192.11(a), (b), and (c).
    (3) NFPA-59 (2004), ``Utility LP-Gas Plant Code,'' (NFPA-59), IBR 
approved for Sec.  192.11(a), (b); and (c).
    (4) NFPA-70 (2011), ``National Electrical Code,'' 2011 edition, 
issued August 5, 2010, (NFPA-70), IBR approved for Sec. Sec.  
192.163(e); and 192.189(c).
    (j) Pipeline Research Council International, Inc. (PRCI), c/o 
Technical Toolboxes, 3801 Kirby Drive, Suite 520, P.O. Box 980550, 
Houston, TX 77098, phone: 713-630-0505, toll free: 866-866-6766, Web 
site: http://www.ttoolboxes.com/. (Contract number PR-3-805.)
    (1) AGA, Pipeline Research Committee Project, PR-3-805, ``A Modified 
Criterion for Evaluating the Remaining Strength of Corroded Pipe,'' 
(December 22, 1989), (PRCI PR-3-805 (R-STRENG)), IBR approved for 
Sec. Sec.  192.485(c); 192.632(a); 192.712(b); 192.933(a) and (d).
    (2) [Reserved]
    (k) Plastics Pipe Institute, Inc. (PPI), 105 Decker Court, Suite 825 
Irving TX 75062, phone: 469-499-1044, http://www.plasticpipe.org/.
    (1) PPI TR-3/2012, HDB/HDS/PDB/SDB/MRS/CRS, Policies, ``Policies and 
Procedures for Developing Hydrostatic Design Basis (HDB), Hydrostatic 
Design Stresses (HDS), Pressure Design Basis (PDB), Strength Design 
Basis

[[Page 442]]

(SDB), Minimum Required Strength (MRS) Ratings, and Categorized Required 
Strength (CRS) for Thermoplastic Piping Materials or Pipe,'' updated 
November 2012, (PPI TR-3/2012), IBR approved for Sec.  192.121.
    (2) PPI TR-4, HDB/HDS/SDB/MRS, Listed Materials, ``PPI Listing of 
Hydrostatic Design Basis (HDB), Hydrostatic Design Stress (HDS), 
Strength Design Basis (SDB), Pressure Design Basis (PDB) and Minimum 
Required Strength (MRS) Rating For Thermoplastic Piping Materials or 
Pipe,'' updated March, 2011, (PPI TR-4/2012), IBR approved for Sec.  
192.121.

[35 FR 13257, Aug. 19, 1970]

    Editorial Note: For Federal Register citations affecting Sec.  
192.7, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.govinfo.gov.



Sec.  192.8  How are onshore gathering pipelines and regulated onshore 
gathering pipelines determined?

    (a) An operator must use API RP 80 (incorporated by reference, see 
Sec.  192.7), to determine if an onshore pipeline (or part of a 
connected series of pipelines) is an onshore gathering line. The 
determination is subject to the limitations listed below. After making 
this determination, an operator must determine if the onshore gathering 
line is a regulated onshore gathering line under paragraph (b) of this 
section.
    (1) The beginning of gathering, under section 2.2(a)(1) of API RP 
80, may not extend beyond the furthermost downstream point in a 
production operation as defined in section 2.3 of API RP 80. This 
furthermost downstream point does not include equipment that can be used 
in either production or transportation, such as separators or 
dehydrators, unless that equipment is involved in the processes of 
``production and preparation for transportation or delivery of 
hydrocarbon gas'' within the meaning of ``production operation.''
    (2) The endpoint of gathering, under section 2.2(a)(1)(A) of API RP 
80, may not extend beyond the first downstream natural gas processing 
plant, unless the operator can demonstrate, using sound engineering 
principles, that gathering extends to a further downstream plant.
    (3) If the endpoint of gathering, under section 2.2(a)(1)(C) of API 
RP 80, is determined by the commingling of gas from separate production 
fields, the fields may not be more than 50 miles from each other, unless 
the Administrator finds a longer separation distance is justified in a 
particular case (see 49 CFR Sec.  190.9).
    (4) The endpoint of gathering, under section 2.2(a)(1)(D) of API RP 
80, may not extend beyond the furthermost downstream compressor used to 
increase gathering line pressure for delivery to another pipeline.
    (5) For new, replaced, relocated, or otherwise changed gas gathering 
pipelines installed after May 16, 2022, the endpoint of gathering under 
sections 2.2(a)(1)(E) and 2.2.1.2.6 of API RP 80 (incorporated by 
reference, see Sec.  192.7)--also known as ``incidental gathering''--may 
not be used if the pipeline terminates 10 or more miles downstream from 
the furthermost downstream endpoint as defined in paragraphs 
2.2(a)(1)(A) through (a)(1)(D) of API RP 80 (incorporated by reference, 
see Sec.  192.7) and this section. If an ``incidental gathering'' 
pipeline is 10 miles or more in length, the entire portion of the 
pipeline that is designated as an incidental gathering line under 
2.2(a)(1)(E) and 2.2.1.2.6 of API RP 80 shall be classified as a 
transmission pipeline subject to all applicable regulations in this 
chapter for transmission pipelines.
    (b) Each operator must determine and maintain for the life of the 
pipeline records documenting the methodology by which it calculated the 
beginning and end points of each onshore gathering pipeline it operates, 
as described in the second column of table 1 to paragraph (c)(2) of this 
section, by:
    (1) November 16, 2022, or before the pipeline is placed into 
operation, whichever is later; or
    (2) An alternative deadline approved by the Pipeline and Hazardous 
Materials Safety Administration (PHMSA). The operator must notify PHMSA 
and State or local pipeline safety authorities, as applicable, no later 
than 90

[[Page 443]]

days in advance of the deadline in paragraph (b)(1) of this section. The 
notification must be made in accordance with Sec.  192.18 and must 
include the following information:
    (i) Description of the affected facilities and operating 
environment;
    (ii) Justification for an alternative compliance deadline; and
    (iii) Proposed alternative deadline.
    (c) For purposes of part 191 of this chapter and Sec.  192.9, the 
term ``regulated onshore gathering pipeline'' means:
    (1) Each Type A, Type B, or Type C onshore gathering pipeline (or 
segment of onshore gathering pipeline) with a feature described in the 
second column of table 1 to paragraph (c)(2) of this section that lies 
in an area described in the third column; and
    (2) As applicable, additional lengths of pipeline described in the 
fourth column to provide a safety buffer:

                       Table 1 to Paragraph (c)(2)
------------------------------------------------------------------------
                                                            Additional
        Type              Feature            Area         safety buffer
------------------------------------------------------------------------
A..................  --Metallic and    Class 2, 3, or 4  None.
                      the MAOP          location (see
                      produces a hoop   Sec.   192.5).
                      stress of 20
                      percent or more
                      of SMYS.
                     --If the stress
                      level is
                      unknown, an
                      operator must
                      determine the
                      stress level
                      according to
                      the applicable
                      provisions in
                      subpart C of
                      this part.
                     --Non-metallic
                      and the MAOP is
                      more than 125
                      psig (862 kPa).
B..................  --Metallic and    Area 1. Class 3,  If the
                      the MAOP          or 4 location.    gathering
                      produces a hoop  Area 2. An area    pipeline is in
                      stress of less    within a Class    Area 2(b) or
                      than 20 percent   2 location the    2(c), the
                      of SMYS. If the   operator          additional
                      stress level is   determines by     lengths of
                      unknown, an       using any of      line extend
                      operator must     the following     upstream and
                      determine the     three methods:.   downstream
                      stress level     (a) A Class 2      from the area
                      according to      location;.        to a point
                      the applicable   (b) An area        where the line
                      provisions in     extending 150     is at least
                      subpart C of      feet (45.7 m)     150 feet (45.7
                      this part.        on each side of   m) from the
                     --Non-metallic     the centerline    nearest
                      and the MAOP is   of any            dwelling in
                      125 psig (862     continuous 1      the area.
                      kPa) or less.     mile (1.6 km)    However, if a
                                        of pipeline and   cluster of
                                        including more    dwellings in
                                        than 10 but       Area 2(b) or
                                        fewer than 46     2(c) qualifies
                                        dwellings; or.    a pipeline as
                                       (c) An area        Type B, the
                                        extending 150     Type B
                                        feet (45.7 m)     classification
                                        on each side of   ends 150 feet
                                        the centerline    (45.7 m) from
                                        of any            the nearest
                                        continuous 1000   dwelling in
                                        feet (305 m) of   the cluster.
                                        pipeline and
                                        including 5 or
                                        more dwellings.
C..................  Outside diameter  Class 1 location  None.
                      greater than or
                      equal to 8.625
                      inches and any
                      of the
                      following:
                     --Metallic and
                      the MAOP
                      produces a hoop
                      stress of 20
                      percent or more
                      of SMYS;.
                     --If the stress
                      level is
                      unknown,
                      segment is
                      metallic and
                      the MAOP is
                      more than 125
                      psig (862 kPa);
                      or.
                     --Non-metallic
                      and the MAOP is
                      more than 125
                      psig (862 kPa).
R..................  --All other       Class 1 and       None.
                      onshore           Class 2
                      gathering lines.  locations.
------------------------------------------------------------------------

    (3) A Type R gathering line is subject to reporting requirements 
under part 191 of this chapter but is not a regulated onshore gathering 
line under this part.
    (4) For the purpose of identifying Type C lines in table 1 to 
paragraph (c)(2) of this section, if an operator has not calculated MAOP 
consistent with the methods at Sec.  192.619(a) or (c)(1), the operator 
must either:
    (i) Calculate MAOP consistent with the methods at Sec.  192.619(a) 
or (c)(1); or

[[Page 444]]

    (ii) Use as a substitute for MAOP the highest operating pressure to 
which the segment was subjected during the preceding 5 operating years.

[Amdt. 192-102, 71 FR 13302, Mar. 15, 2006, as amended by Amdt. 192-129, 
86 FR 63295, Nov. 15, 2021; Amdt. 192-131, 87 FR 26299, May 4, 2022]



Sec.  192.9  What requirements apply to gathering pipelines?

    (a) Requirements. An operator of a gathering line must follow the 
safety requirements of this part as prescribed by this section.
    (b) Offshore lines. An operator of an offshore gathering line must 
comply with requirements of this part applicable to transmission lines, 
except the requirements in Sec. Sec.  192.13(d), 192.150, 192.285(e), 
192.319(d) through (g), 192.461(f) through (i), 192.465(d) and (f), 
192.473(c), 192.478, 192.485(c), 192.493, 192.506, 192.607, 192.613(c), 
192.619(e), 192.624, 192.710, 192.712, and 192.714, and in subpart O of 
this part. Further, operators of offshore gathering lines are exempt 
from the requirements of Sec. Sec.  192.617(b) through (d) and 192.635. 
Lastly, operators of offshore gathering lines are exempt from the 
requirements of Sec.  192.615 (but an operator of an offshore gathering 
line must comply with the requirements of 49 CFR 192.615, effective as 
of October 4, 2022).
    (c) Type A lines. An operator of a Type A regulated onshore 
gathering line must comply with the requirements of this part applicable 
to transmission lines, except the requirements in Sec. Sec.  192.13(d), 
192.150, 192.285(e), 192.319(d) through (g), 192.461(f) through (i), 
192.465(d) and (f), 192.473(c), 192.478, 192.485(c) 192.493, 192.506, 
192.607, 192.613(c), 192.619(e), 192.624, 192.710, 192.712, and 192.714, 
and in subpart O of this part. However, an operator of a Type A 
regulated onshore gathering line in a Class 2 location may demonstrate 
compliance with subpart N of this part by describing the processes it 
uses to determine the qualification of persons performing operations and 
maintenance tasks. Further, operators of Type A regulated onshore 
gathering lines are exempt from the requirements of Sec. Sec.  
192.179(e) through (g), 192.610, 192.617(b) through (d), 192.634, 
192.635, 192.636, and 192.745(c) through (f). Lastly, operators of Type 
A regulated onshore gathering lines are exempt from the requirements of 
Sec.  192.615 (but an operator of a Type A regulated onshore gathering 
line must comply with the requirements of 49 CFR 192.615, effective as 
of October 4, 2022).
    (d) Type B lines. An operator of a Type B regulated onshore 
gathering line must comply with the following requirements:
    (1) If a line is new, replaced, relocated, or otherwise changed, the 
design, installation, construction, initial inspection, and initial 
testing must be in accordance with requirements of this part applicable 
to transmission lines. Compliance with Sec. Sec.  192.67, 192.127, 
192.179(e) and (f), 192.205, 192.227(c), 192.285(e), 192.319(d) through 
(g), 192.506, 192.634, and 192.636 is not required;
    (2) If the pipeline is metallic, control corrosion according to 
requirements of subpart I of this part applicable to transmission lines, 
except the requirements in Sec. Sec.  192.461(f) through (i), 192.465(d) 
and (f), 192.473(c), 192.478, 192.485(c), and 192.493;
    (3) If the pipeline contains plastic pipe or components, the 
operator must comply with all applicable requirements of this part for 
plastic pipe components;
    (4) Carry out a damage prevention program under Sec.  192.614;
    (5) Establish a public education program under Sec.  192.616;
    (6) Establish the MAOP of the line under Sec.  192.619(a), (b), and 
(c);
    (7) Install and maintain line markers according to the requirements 
for transmission lines in Sec.  192.707; and
    (8) Conduct leakage surveys in accordance with the requirements for 
transmission lines in Sec.  192.706, using leak-detection equipment, and 
promptly repair hazardous leaks in accordance with Sec.  192.703(c).
    (e) Type C lines. The requirements for Type C gathering lines are as 
follows.
    (1) An operator of a Type C onshore gathering line with an outside 
diameter greater than or equal to 8.625 inches must comply with the 
following requirements:
    (i) Except as provided in paragraph (h) of this section for pipe and 
components made with composite materials, the design, installation, 
construction,

[[Page 445]]

initial inspection, and initial testing of a new, replaced, relocated, 
or otherwise changed Type C gathering line, must be done in accordance 
with the requirements in subparts B through G and J of this part 
applicable to transmission lines. Compliance with Sec. Sec.  192.67, 
192.127, 192.179(e) and (f), 192.205, 192.227(c), 192.285(e), 192.319(d) 
through (g), 192.506, 192.634, and 192.636 is not required;
    (ii) If the pipeline is metallic, control corrosion according to 
requirements of subpart I of this part applicable to transmission lines, 
except the requirements in Sec. Sec.  192.461(f) through (i), 192.465(d) 
and (f), 192.473(c), 192.478, 192.485(c), and 192.493;
    (iii) Carry out a damage prevention program under Sec.  192.614;
    (iv) Develop and implement procedures for emergency plans in 
accordance with the requirements of 49 CFR 192.615, effective as of 
October 4, 2022;
    (v) Develop and implement a written public awareness program in 
accordance with Sec.  192.616;
    (vi) Install and maintain line markers according to the requirements 
for transmission lines in Sec.  192.707; and
    (vii) Conduct leakage surveys in accordance with the requirements 
for transmission lines in Sec.  192.706 using leak-detection equipment, 
and promptly repair hazardous leaks in accordance with Sec.  192.703(c).
    (2) An operator of a Type C onshore gathering line with an outside 
diameter greater than 12.75 inches must comply with the requirements in 
paragraph (e)(1) of this section and the following:
    (i) If the pipeline contains plastic pipe, the operator must comply 
with all applicable requirements of this part for plastic pipe or 
components. This does not include pipe and components made of composite 
materials that incorporate plastic in the design; and
    (ii) Establish the MAOP of the pipeline under Sec.  192.619(a) or 
(c) and maintain records used to establish the MAOP for the life of the 
pipeline.
    (f) Exceptions. (1) Compliance with paragraphs (e)(1)(ii), (v), 
(vi), and (vii) and (e)(2)(i) and (ii) of this section is not required 
for pipeline segments that are 16 inches or less in outside diameter if 
one of the following criteria are met:
    (i) Method 1. The segment is not located within a potential impact 
circle containing a building intended for human occupancy or other 
impacted site. The potential impact circle must be calculated as 
specified in Sec.  192.903, except that a factor of 0.73 must be used 
instead of 0.69. The MAOP used in this calculation must be determined 
and documented in accordance with paragraph (e)(2)(ii) of this section.
    (ii) Method 2. The segment is not located within a class location 
unit (see Sec.  192.5) containing a building intended for human 
occupancy or other impacted site.
    (2) Paragraph (e)(1)(i) of this section is not applicable to 
pipeline segments 40 feet or shorter in length that are replaced, 
relocated, or changed on a pipeline existing on or before May 16, 2022.
    (3) For purposes of this section, the term ``building intended for 
human occupancy or other impacted site'' means any of the following:
    (i) Any building that may be occupied by humans, including homes, 
office buildings factories, outside recreation areas, plant facilities, 
etc.;
    (ii) A small, well-defined outside area (such as a playground, 
recreation area, outdoor theater, or other place of public assembly) 
that is occupied by 20 or more persons on at least 5 days a week for 10 
weeks in any 12-month period (the days and weeks need not be 
consecutive); or
    (iii) Any portion of the paved surface, including shoulders, of a 
designated interstate, other freeway, or expressway, as well as any 
other principal arterial roadway with 4 or more lanes.
    (g) Compliance deadlines. An operator of a regulated onshore 
gathering line must comply with the following deadlines, as applicable.
    (1) An operator of a new, replaced, relocated, or otherwise changed 
line must be in compliance with the applicable requirements of this 
section by the date the line goes into service, unless an exception in 
Sec.  192.13 applies.
    (2) If a Type A or Type B regulated onshore gathering pipeline 
existing on April 14, 2006, was not previously subject to this part, an 
operator has until the date stated in the second column to comply with 
the applicable requirement for the pipeline listed in the first

[[Page 446]]

column, unless the Administrator finds a later deadline is justified in 
a particular case:

------------------------------------------------------------------------
                Requirement                      Compliance deadline
------------------------------------------------------------------------
(i) Control corrosion according to          April 15, 2009.
 requirements for transmission lines in
 subpart I of this part.
(ii) Carry out a damage prevention program  October 15, 2007.
 under Sec.   192.614.
(iii) Establish MAOP under Sec.   192.619.  October 15, 2007.
(iv) Install and maintain line markers      April 15, 2008.
 under Sec.   192.707.
(v) Establish a public education program    April 15, 2008.
 under Sec.   192.616.
(vi) Other provisions of this part as       April 15, 2009.
 required by paragraph (c) of this section
 for Type A lines.
------------------------------------------------------------------------

    (3) If, after April 14, 2006, a change in class location or increase 
in dwelling density causes an onshore gathering pipeline to become a 
Type A or Type B regulated onshore gathering line, the operator has 1 
year for Type B lines and 2 years for Type A lines after the pipeline 
becomes a regulated onshore gathering pipeline to comply with this 
section.
    (4) If a Type C gathering pipeline existing on or before May 16, 
2022, was not previously subject to this part, an operator must comply 
with the applicable requirements of this section, except for paragraph 
(h) of this section, on or before:
    (i) May 16, 2023; or
    (ii) An alternative deadline approved by PHMSA. The operator must 
notify PHMSA and State or local pipeline safety authorities, as 
applicable, no later than 90 days in advance of the deadline in 
paragraph (b)(1) of this section. The notification must be made in 
accordance with Sec.  192.18 and must include a description of the 
affected facilities and operating environment, the proposed alternative 
deadline for each affected requirement, the justification for each 
alternative compliance deadline, and actions the operator will take to 
ensure the safety of affected facilities.
    (5) If, after May 16, 2022, a change in class location, an increase 
in dwelling density, or an increase in MAOP causes a pipeline to become 
a Type C gathering pipeline, or causes a Type C gathering pipeline to 
become subject to additional Type C requirements (see paragraph (f) of 
this section), the operator has 1 year after the pipeline becomes 
subject to the additional requirements to comply with this section.
    (h) Composite materials. Pipe and components made with composite 
materials not otherwise authorized for use under this part may be used 
on Type C gathering pipelines if the following requirements are met:
    (1) Steel and plastic pipe and components must meet the 
installation, construction, initial inspection, and initial testing 
requirements in subparts B though G and J of this part applicable to 
transmission lines.
    (2) Operators must notify PHMSA in accordance with Sec.  192.18 at 
least 90 days prior to installing new or replacement pipe or components 
made of composite materials otherwise not authorized for use under this 
part in a Type C gathering pipeline. The notifications required by this 
section must include a detailed description of the pipeline facilities 
in which pipe or components made of composite materials would be used, 
including:
    (i) The beginning and end points (stationing by footage and mileage 
with latitude and longitude coordinates) of the pipeline segment 
containing composite pipeline material and the counties and States in 
which it is located;
    (ii) A general description of the right-of-way including high 
consequence areas, as defined in Sec.  192.905;
    (iii) Relevant pipeline design and construction information 
including the year of installation, the specific composite material, 
diameter, wall thickness, and any manufacturing and construction 
specifications for the pipeline;
    (iv) Relevant operating information, including MAOP, leak and 
failure history, and the most recent pressure test

[[Page 447]]

(identification of the actual pipe tested, minimum and maximum test 
pressure, duration of test, any leaks and any test logs and charts) or 
assessment results;
    (v) An explanation of the circumstances that the operator believes 
make the use of composite pipeline material appropriate and how the 
design, construction, operations, and maintenance will mitigate safety 
and environmental risks;
    (vi) An explanation of procedures and tests that will be conducted 
periodically over the life of the composite pipeline material to 
document that its strength is being maintained;
    (vii) Operations and maintenance procedures that will be applied to 
the alternative materials. These include procedures that will be used to 
evaluate and remediate anomalies and how the operator will determine 
safe operating pressures for composite pipe when defects are found;
    (viii) An explanation of how the use of composite pipeline material 
would be in the public interest; and
    (ix) A certification signed by a vice president (or equivalent or 
higher officer) of the operator's company that operation of the 
applicant's pipeline using composite pipeline material would be 
consistent with pipeline safety.
    (3) Repairs or replacements using materials authorized under this 
part do not require notification under this section.

[Amdt. 192-102, 71 FR 13301, Mar. 15, 2006, as amended by Amdt. 192-120, 
80 FR 12777, Mar. 11, 2015; Amdt. 192-124, 83 FR 58716, Nov. 20, 2018; 
Amdt. 192-125, 84 FR 52244, Oct. 1, 2019; Amdt. 192-129, 86 FR 63296, 
Nov. 15, 2021; Amdt. 192-130, 87 FR 20982, Apr. 8, 2022; Amdt. 192-132, 
87 FR 52268, Aug. 24, 2022; Amdt. 192-134, 88 FR 50060, Aug. 1, 2023]



Sec.  192.10  Outer continental shelf pipelines.

    Operators of transportation pipelines on the Outer Continental Shelf 
(as defined in the Outer Continental Shelf Lands Act; 43 U.S.C. 1331) 
must identify on all their respective pipelines the specific points at 
which operating responsibility transfers to a producing operator. For 
those instances in which the transfer points are not identifiable by a 
durable marking, each operator will have until September 15, 1998 to 
identify the transfer points. If it is not practicable to durably mark a 
transfer point and the transfer point is located above water, the 
operator must depict the transfer point on a schematic located near the 
transfer point. If a transfer point is located subsea, then the operator 
must identify the transfer point on a schematic which must be maintained 
at the nearest upstream facility and provided to PHMSA upon request. For 
those cases in which adjoining operators have not agreed on a transfer 
point by September 15, 1998 the Regional Director and the MMS Regional 
Supervisor will make a joint determination of the transfer point.

[Amdt. 192-81, 62 FR 61695, Nov. 19, 1997, as amended at 70 FR 11139, 
Mar. 8, 2005]



Sec.  192.11  Petroleum gas systems.

    (a) Each plant that supplies petroleum gas by pipeline to a natural 
gas distribution system must meet the requirements of this part and NFPA 
58 and NFPA 59 (incorporated by reference, see Sec.  192.7).
    (b) Each pipeline system subject to this part that transports only 
petroleum gas or petroleum gas/air mixtures must meet the requirements 
of this part and of ANSI/NFPA 58 and 59.
    (c) In the event of a conflict between this part and NFPA 58 and 
NFPA 59 (incorporated by reference, see Sec.  192.7), NFPA 58 and NFPA 
59 prevail.

[Amdt. 192-78, 61 FR 28783, June 6, 1996, as amended by Amdt. 192-119, 
80 FR 180, Jan. 5, 2015; 80 FR 46847, Aug. 6, 2015]



Sec.  192.12  Underground natural gas storage facilities.

    Underground natural gas storage facilities (UNGSFs), as defined in 
Sec.  192.3, are not subject to any requirements of this part aside from 
this section.
    (a) Salt cavern UNGSFs. (1) Each UNGSF that uses a solution-mined 
salt cavern for natural gas storage and was constructed after March 13, 
2020, must meet all the provisions of API RP 1170 (incorporated by 
reference, see Sec.  192.7), the provisions of section 8 of API RP 1171 
(incorporated by reference, see Sec.  192.7) that are applicable to the 
physical characteristics and operations of a solution-mined salt cavern 
UNGSF,

[[Page 448]]

and paragraphs (c) and (d) of this section prior to commencing 
operations.
    (2) Each UNGSF that uses a solution-mined salt cavern for natural 
gas storage and was constructed between July 18, 2017, and March 13, 
2020, must meet all the provisions of API RP 1170 (incorporated by 
reference, see Sec.  192.7) and paragraph (c) of this section prior to 
commencing operations, and must meet all the provisions of section 8 of 
API RP 1171 (incorporated by reference, see Sec.  192.7) that are 
applicable to the physical characteristics and operations of a solution-
mined salt cavern UNGSF, and paragraph (d) of this section, by March 13, 
2021.
    (3) Each UNGSF that uses a solution-mined salt cavern for natural 
gas storage and was constructed on or before July 18, 2017, must meet 
the provisions of API RP 1170 (incorporated by reference, see Sec.  
192.7), sections 9, 10, and 11, and paragraph (c) of this section, by 
January 18, 2018, and must meet all provisions of section 8 of API RP 
1171 (incorporated by reference, see Sec.  192.7) that are applicable to 
the physical characteristics and operations of a solution-mined salt 
cavern UNGSF, and paragraph (d) of this section, by March 13, 2021.
    (b) Depleted hydrocarbon and aquifer reservoir UNGSFs. (1) Each 
UNGSF that uses a depleted hydrocarbon reservoir or an aquifer reservoir 
for natural gas storage and was constructed after July 18, 2017, must 
meet all provisions of API RP 1171 (incorporated by reference, see Sec.  
192.7), and paragraphs (c) and (d) of this section, prior to commencing 
operations.
    (2) Each UNGSF that uses a depleted hydrocarbon reservoir or an 
aquifer reservoir for natural gas storage and was constructed on or 
before July 18, 2017, must meet the provisions of API RP 1171 
(incorporated by reference, see Sec.  192.7), sections 8, 9, 10, and 11, 
and paragraph (c) of this section, by January 18, 2018, and must meet 
all provisions of paragraph (d) of this section by March 13, 2021.
    (c) Procedural manuals. Each operator of a UNGSF must prepare and 
follow for each facility one or more manuals of written procedures for 
conducting operations, maintenance, and emergency preparedness and 
response activities under paragraphs (a) and (b) of this section. Each 
operator must keep records necessary to administer such procedures and 
review and update these manuals at intervals not exceeding 15 months, 
but at least once each calendar year. Each operator must keep the 
appropriate parts of these manuals accessible at locations where UNGSF 
work is being performed. Each operator must have written procedures in 
place before commencing operations or beginning an activity not yet 
implemented.
    (d) Integrity management program--(1) Integrity management program 
elements. The integrity management program for each UNGSF under this 
paragraph (d) must consist, at a minimum, of a framework developed under 
API RP 1171 (incorporated by reference, see Sec.  192.7), section 8 
(``Risk Management for Gas Storage Operations''), and that also 
describes how relevant decisions will be made and by whom. An operator 
must make continual improvements to the program and its execution. The 
integrity management program must include the following elements:
    (i) A plan for developing and implementing each program element to 
meet the requirements of this section;
    (ii) An outline of the procedures to be developed;
    (iii) The roles and responsibilities of UNGSF staff assigned to 
develop and implement the procedures required by this paragraph (d);
    (iv) A plan for how staff will be trained in awareness and 
application of the procedures required by this paragraph (d);
    (v) Timelines for implementing each program element, including the 
risk analysis and baseline risk assessments; and
    (vi) A plan for how to incorporate information gained from 
experience into the integrity management program on a continuous basis.
    (2) Integrity management baseline risk-assessment intervals. No 
later than March 13, 2024, each UNGSF operator must complete the 
baseline risk assessments of all reservoirs and caverns, and at least 
40% of the baseline risk assessments for each of its UNGSF wells 
(including wellhead assemblies), beginning with the highest-risk wells, 
as

[[Page 449]]

identified by the risk analysis process. No later than March 13, 2027, 
an operator must complete baseline risk assessments on all its wells 
(including wellhead assemblies). Operators may use prior risk 
assessments for a well as a baseline (or part of the baseline) risk 
assessment in implementing its initial integrity management program, so 
long as the prior assessments meet the requirements of API RP 1171 
(incorporated by reference, see Sec.  192.7), section 8, and continue to 
be relevant and valid for the current operating and environmental 
conditions. When evaluating prior risk-assessment results, operators 
must account for the growth and effects of indicated defects since the 
time the assessment was performed.
    (3) Integrity management re-assessment intervals. The operator must 
determine the appropriate interval for risk assessments under API RP 
1171 (incorporated by reference, see Sec.  192.7), subsection 8.7.1, and 
this paragraph (d) for each reservoir, cavern, and well, using the 
results from earlier assessments and updated risk analyses. The re-
assessment interval for each reservoir, cavern, and well must not exceed 
seven years from the date of the baseline assessment for each reservoir, 
cavern, and well.
    (4) Integrity management procedures and recordkeeping. Each UNGSF 
operator must establish and follow written procedures to carry out its 
integrity management program under API RP 1171 (incorporated by 
reference, see Sec.  192.7), section 8 (``Risk Management for Gas 
Storage Operations''), and this paragraph (d). The operator must also 
maintain, for the useful life of the UNGSF, records that demonstrate 
compliance with the requirements of this paragraph (d). This includes 
records developed and used in support of any identification, 
calculation, amendment, modification, justification, deviation, and 
determination made, and any action taken to implement and evaluate any 
integrity management program element.

[Amdt. 192-126, 85 FR 8126, Feb. 12, 2020]



Sec.  192.13  What general requirements apply to pipelines regulated under 
this part?

    (a) No person may operate a segment of pipeline listed in the first 
column of paragraph (a)(3) of this section that is readied for service 
after the date in the second column, unless:
    (1) The pipeline has been designed, installed, constructed, 
initially inspected, and initially tested in accordance with this part; 
or
    (2) The pipeline qualifies for use under this part according to the 
requirements in Sec.  192.14.
    (3) The compliance deadlines are as follows:

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
(i) Offshore gathering pipeline...........  July 31, 1977.
(ii) Regulated onshore gathering pipeline   March 15, 2007.
 to which this part did not apply until
 April 14, 2006.
(iii) Regulated onshore gathering pipeline  May 16, 2023.
 to which this part did not apply until
 May 16, 2022.
(iv) All other pipelines..................  March 12, 1971.
------------------------------------------------------------------------

    (b) No person may operate a segment of pipeline listed in the first 
column of this paragraph (b) that is replaced, relocated, or otherwise 
changed after the date in the second column of this paragraph (b), 
unless the replacement, relocation or change has been made according to 
the requirements in this part.

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
(1) Offshore gathering pipeline...........  July 31, 1977.
(2) Regulated onshore gathering pipeline    March 15, 2007.
 to which this part did not apply until
 April 14, 2006.
(3) Regulated onshore gathering pipeline    May 16, 2023.
 to which this part did not apply until
 May 16, 2022.
(4) All other pipelines...................  November 12, 1970.
------------------------------------------------------------------------

    (c) Each operator shall maintain, modify as appropriate, and follow 
the plans, procedures, and programs that it is required to establish 
under this part.
    (d) Each operator of an onshore gas transmission pipeline must 
evaluate and mitigate, as necessary, significant changes that pose a 
risk to safety or the environment through a management of change 
process. Each operator of an onshore gas transmission pipeline must 
develop and follow a management of change process, as outlined in ASME/
ANSI B31.8S, section 11 (incorporated by reference, see Sec.  192.7), 
that

[[Page 450]]

addresses technical, design, physical, environmental, procedural, 
operational, maintenance, and organizational changes to the pipeline or 
processes, whether permanent or temporary. A management of change 
process must include the following: reason for change, authority for 
approving changes, analysis of implications, acquisition of required 
work permits, documentation, communication of change to affected 
parties, time limitations, and qualification of staff. For pipeline 
segments other than those covered in subpart O of this part, this 
management of change process must be implemented by February 26, 2024. 
The requirements of this paragraph (d) do not apply to gas gathering 
pipelines. Operators may request an extension of up to 1 year by 
submitting a notification to PHMSA at least 90 days before February 26, 
2024, in accordance with Sec.  192.18. The notification must include a 
reasonable and technically justified basis, an up-to-date plan for 
completing all actions required by this section, the reason for the 
requested extension, current safety or mitigation status of the pipeline 
segment, the proposed completion date, and any needed temporary safety 
measures to mitigate the impact on safety.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34605, 
Aug. 16, 1976; Amdt. 192-30, 42 FR 60148, Nov. 25, 1977; Amdt. 192-102, 
71 FR 13303, Mar. 15, 2006; Amdt. 192-129, 86 FR 63298, Nov. 15, 2021; 
Amdt. 192-132, 87 FR 52268, Aug. 24, 2022]



Sec.  192.14  Conversion to service subject to this part.

    (a) A steel pipeline previously used in service not subject to this 
part qualifies for use under this part if the operator prepares and 
follows a written procedure to carry out the following requirements:
    (1) The design, construction, operation, and maintenance history of 
the pipeline must be reviewed and, where sufficient historical records 
are not available, appropriate tests must be performed to determine if 
the pipeline is in a satisfactory condition for safe operation.
    (2) The pipeline right-of-way, all aboveground segments of the 
pipeline, and appropriately selected underground segments must be 
visually inspected for physical defects and operating conditions which 
reasonably could be expected to impair the strength or tightness of the 
pipeline.
    (3) All known unsafe defects and conditions must be corrected in 
accordance with this part.
    (4) The pipeline must be tested in accordance with subpart J of this 
part to substantiate the maximum allowable operating pressure permitted 
by subpart L of this part.
    (b) Each operator must keep for the life of the pipeline a record of 
the investigations, tests, repairs, replacements, and alterations made 
under the requirements of paragraph (a) of this section.
    (c) An operator converting a pipeline from service not previously 
covered by this part must notify PHMSA 60 days before the conversion 
occurs as required by Sec.  191.22 of this chapter.

[Amdt. 192-30, 42 FR 60148, Nov. 25, 1977, as amended by Amdt. 192-123, 
82 FR 7997, Jan. 23, 2017]



Sec.  192.15  Rules of regulatory construction.

    (a) As used in this part:
    Includes means including but not limited to.
    May means ``is permitted to'' or ``is authorized to''.
    May not means ``is not permitted to'' or ``is not authorized to''.
    Shall is used in the mandatory and imperative sense.
    (b) In this part:
    (1) Words importing the singular include the plural;
    (2) Words importing the plural include the singular; and
    (3) Words importing the masculine gender include the feminine.



Sec.  192.16  Customer notification.

    (a) This section applies to each operator of a service line who does 
not maintain the customer's buried piping up to entry of the first 
building downstream, or, if the customer's buried piping does not enter 
a building, up to the principal gas utilization equipment or the first 
fence (or wall) that surrounds that equipment. For the purpose of this 
section, ``customer's buried piping'' does not include branch lines

[[Page 451]]

that serve yard lanterns, pool heaters, or other types of secondary 
equipment. Also, ``maintain'' means monitor for corrosion according to 
Sec.  192.465 if the customer's buried piping is metallic, survey for 
leaks according to Sec.  192.723, and if an unsafe condition is found, 
shut off the flow of gas, advise the customer of the need to repair the 
unsafe condition, or repair the unsafe condition.
    (b) Each operator shall notify each customer once in writing of the 
following information:
    (1) The operator does not maintain the customer's buried piping.
    (2) If the customer's buried piping is not maintained, it may be 
subject to the potential hazards of corrosion and leakage.
    (3) Buried gas piping should be--
    (i) Periodically inspected for leaks;
    (ii) Periodically inspected for corrosion if the piping is metallic; 
and
    (iii) Repaired if any unsafe condition is discovered.
    (4) When excavating near buried gas piping, the piping should be 
located in advance, and the excavation done by hand.
    (5) The operator (if applicable), plumbing contractors, and heating 
contractors can assist in locating, inspecting, and repairing the 
customer's buried piping.
    (c) Each operator shall notify each customer not later than August 
14, 1996, or 90 days after the customer first receives gas at a 
particular location, whichever is later. However, operators of master 
meter systems may continuously post a general notice in a prominent 
location frequented by customers.
    (d) Each operator must make the following records available for 
inspection by the Administrator or a State agency participating under 49 
U.S.C. 60105 or 60106:
    (1) A copy of the notice currently in use; and
    (2) Evidence that notices have been sent to customers within the 
previous 3 years.

[Amdt. 192-74, 60 FR 41828, Aug. 14, 1995, as amended by Amdt. 192-74A, 
60 FR 63451, Dec. 11, 1995; Amdt. 192-83, 63 FR 7723, Feb. 17, 1998]



Sec.  192.18  How to notify PHMSA.

    (a) An operator must provide any notification required by this part 
by--
    (1) Sending the notification by electronic mail to 
[email protected]; or
    (2) Sending the notification by mail to ATTN: Information Resources 
Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New 
Jersey Ave. SE, Washington, DC 20590.
    (b) An operator must also notify the appropriate State or local 
pipeline safety authority when an applicable pipeline segment is located 
in a State where OPS has an interstate agent agreement, or an intrastate 
applicable pipeline segment is regulated by that State.
    (c) Unless otherwise specified, if an operator submits, pursuant to 
Sec.  192.8, Sec.  192.9, Sec.  192.13, Sec.  192.179, Sec.  192.319, 
Sec.  192.461, Sec.  192.506, Sec.  192.607, Sec.  192.619, Sec.  
192.624, Sec.  192.632, Sec.  192.634, Sec.  192.636, Sec.  192.710, 
Sec.  192.712, Sec.  192.714, Sec.  192.745, Sec.  192.917, Sec.  
192.921, Sec.  192.927, Sec.  192.933, or Sec.  192.937, a notification 
for use of a different integrity assessment method, analytical method, 
compliance period, sampling approach, pipeline material, or technique 
(e.g., ``other technology'' or ``alternative equivalent technology'') 
than otherwise prescribed in those sections, that notification must be 
submitted to PHMSA for review at least 90 days in advance of using the 
other method, approach, compliance timeline, or technique. An operator 
may proceed to use the other method, approach, compliance timeline, or 
technique 91 days after submitting the notification unless it receives a 
letter from the Associate Administrator for Pipeline Safety informing 
the operator that PHMSA objects to the proposal or that PHMSA requires 
additional time and/or more information to conduct its review.

[Amdt. 192-125, 84 FR 52244, Oct. 1, 2019, as amended by Amdt. 192-129, 
86 FR 63298, Nov. 15, 2021; Amdt. 192-130, 87 FR 20982, Apr. 8, 2022; 
Amdt. 192-132, 87 FR 52268, Aug. 24, 2022]

[[Page 452]]



                           Subpart B_Materials



Sec.  192.51  Scope.

    This subpart prescribes minimum requirements for the selection and 
qualification of pipe and components for use in pipelines.



Sec.  192.53  General.

    Materials for pipe and components must be:
    (a) Able to maintain the structural integrity of the pipeline under 
temperature and other environmental conditions that may be anticipated;
    (b) Chemically compatible with any gas that they transport and with 
any other material in the pipeline with which they are in contact; and
    (c) Qualified in accordance with the applicable requirements of this 
subpart.



Sec.  192.55  Steel pipe.

    (a) New steel pipe is qualified for use under this part if:
    (1) It was manufactured in accordance with a listed specification;
    (2) It meets the requirements of--
    (i) Section II of appendix B to this part; or
    (ii) If it was manufactured before November 12, 1970, either section 
II or III of appendix B to this part; or
    (3) It is used in accordance with paragraph (c) or (d) of this 
section.
    (b) Used steel pipe is qualified for use under this part if:
    (1) It was manufactured in accordance with a listed specification 
and it meets the requirements of paragraph II-C of appendix B to this 
part;
    (2) It meets the requirements of:
    (i) Section II of appendix B to this part; or
    (ii) If it was manufactured before November 12, 1970, either section 
II or III of appendix B to this part;
    (3) It has been used in an existing line of the same or higher 
pressure and meets the requirements of paragraph II-C of appendix B to 
this part; or
    (4) It is used in accordance with paragraph (c) of this section.
    (c) New or used steel pipe may be used at a pressure resulting in a 
hoop stress of less than 6,000 p.s.i. (41 MPa) where no close coiling or 
close bending is to be done, if visual examination indicates that the 
pipe is in good condition and that it is free of split seams and other 
defects that would cause leakage. If it is to be welded, steel pipe that 
has not been manufactured to a listed specification must also pass the 
weldability tests prescribed in paragraph II-B of appendix B to this 
part.
    (d) Steel pipe that has not been previously used may be used as 
replacement pipe in a segment of pipeline if it has been manufactured 
prior to November 12, 1970, in accordance with the same specification as 
the pipe used in constructing that segment of pipeline.
    (e) New steel pipe that has been cold expanded must comply with the 
mandatory provisions of API Spec 5L (incorporated by reference, see 
Sec.  192.7).

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 191-1, 35 FR 17660, 
Nov. 17, 1970; Amdt. 192-12, 38 FR 4761, Feb. 22, 1973; Amdt. 192-51, 51 
FR 15335, Apr. 23, 1986; 58 FR 14521, Mar. 18, 1993; Amdt. 192-85, 63 FR 
37502, July 13, 1998; Amdt. 192-119, 80 FR 180, Jan. 5, 2015; 80 FR 
46847, Aug. 6, 2015]



Sec.  192.57  [Reserved]



Sec.  192.59  Plastic pipe.

    (a) New plastic pipe is qualified for use under this part if:
    (1) It is manufactured in accordance with a listed specification;
    (2) It is resistant to chemicals with which contact may be 
anticipated; and
    (3) It is free of visible defects.
    (b) Used plastic pipe is qualified for use under this part if:
    (1) It was manufactured in accordance with a listed specification;
    (2) It is resistant to chemicals with which contact may be 
anticipated;
    (3) It has been used only in gas service;
    (4) Its dimensions are still within the tolerances of the 
specification to which it was manufactured; and
    (5) It is free of visible defects.
    (c) For the purpose of paragraphs (a)(1) and (b)(1) of this section, 
where pipe of a diameter included in a listed specification is 
impractical to use, pipe of a diameter between the sizes included in a 
listed specification may be used if it:
    (1) Meets the strength and design criteria required of pipe included 
in that listed specification; and

[[Page 453]]

    (2) Is manufactured from plastic compounds which meet the criteria 
for material required of pipe included in that listed specification.
    (d) Rework and/or regrind material is not allowed in plastic pipe 
produced after March 6, 2015 used under this part.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-19, 40 FR 10472, 
Mar. 6, 1975; Amdt. 192-58, 53 FR 1635, Jan. 21, 1988; Amdt. 192-119, 80 
FR 180, Jan. 5, 2015; Amdt. 192-124, 83 FR 58716, Nov. 20, 2018]



Sec.  192.61  [Reserved]



Sec.  192.63  Marking of materials.

    (a) Except as provided in paragraph (d) and (e) of this section, 
each valve, fitting, length of pipe, and other component must be marked 
as prescribed in the specification or standard to which it was 
manufactured.
    (b) Surfaces of pipe and components that are subject to stress from 
internal pressure may not be field die stamped.
    (c) If any item is marked by die stamping, the die must have blunt 
or rounded edges that will minimize stress concentrations.
    (d) Paragraph (a) of this section does not apply to items 
manufactured before November 12, 1970, that meet all of the following:
    (1) The item is identifiable as to type, manufacturer, and model.
    (2) Specifications or standards giving pressure, temperature, and 
other appropriate criteria for the use of items are readily available.
    (e) All plastic pipe and components must also meet the following 
requirements:
    (1) All markings on plastic pipe prescribed in the listed 
specification and the requirements of paragraph (e)(2) of this section 
must be repeated at intervals not exceeding two feet.
    (2) Plastic pipe and components manufactured after December 31, 2019 
must be marked in accordance with the listed specification.
    (3) All physical markings on plastic pipelines prescribed in the 
listed specification and paragraph (e)(2) of this section must be 
legible until the time of installation.

[Amdt. 192-1, 35 FR 17660, Nov. 17, 1970, as amended by Amdt. 192-31, 43 
FR 883, Apr. 3, 1978; Amdt. 192-61, 53 FR 36793, Sept. 22, 1988; Amdt. 
192-62, 54 FR 5627, Feb. 6, 1989; Amdt. 192-61A, 54 FR 32642, Aug. 9, 
1989; 58 FR 14521, Mar. 18, 1993; Amdt. 192-76, 61 FR 26122, May 24, 
1996; 61 FR 36826, July 15, 1996; Amdt. 192-114, 75 FR 48603, Aug. 11, 
2010; Amdt. 192-119, 80 FR 180, Jan. 5, 2015; Amdt. 192-124, 83 FR 
58716, Nov. 20, 2018]



Sec.  192.65  Transportation of pipe.

    (a) Railroad. In a pipeline to be operated at a hoop stress of 20 
percent or more of SMYS, an operator may not install pipe having an 
outer diameter to wall thickness of 70 to 1, or more, that is 
transported by railroad unless the transportation is performed by API RP 
5L1 (incorporated by reference, see Sec.  192.7).
    (b) Ship or barge. In a pipeline to be operated at a hoop stress of 
20 percent or more of SMYS, an operator may not use pipe having an outer 
diameter to wall thickness ratio of 70 to 1, or more, that is 
transported by ship or barge on both inland and marine waterways unless 
the transportation is performed in accordance with API RP 5LW 
(incorporated by reference, see Sec.  192.7).
    (c) Truck. In a pipeline to be operated at a hoop stress of 20 
percent or more of SMYS, an operator may not use pipe having an outer 
diameter to wall thickness ratio of 70 to 1, or more, that is 
transported by truck unless the transportation is performed in 
accordance with API RP 5LT (incorporated by reference, see Sec.  192.7).

[Amdt. 192-114, 75 FR 48603, Aug. 11, 2010, as amended by Amdt. 192-119, 
80 FR 180, Jan. 5, 2015; Amdt. 192-120, 80 FR 12777, Mar. 11, 2015]



Sec.  192.67  Records: Material properties.

    (a) For steel transmission pipelines installed after [July 1, 2020, 
an operator must collect or make, and retain for the life of the 
pipeline, records that document the physical characteristics of the 
pipeline, including diameter, yield strength, ultimate tensile strength, 
wall thickness, seam type, and chemical composition of materials for 
pipe in accordance with Sec. Sec.  192.53 and 192.55. Records must 
include tests, inspections, and attributes required by

[[Page 454]]

the manufacturing specifications applicable at the time the pipe was 
manufactured or installed.
    (b) For steel transmission pipelines installed on or before July 1, 
2020], if operators have records that document tests, inspections, and 
attributes required by the manufacturing specifications applicable at 
the time the pipe was manufactured or installed, including diameter, 
yield strength, ultimate tensile strength, wall thickness, seam type, 
and chemical composition in accordance with Sec. Sec.  192.53 and 
192.55, operators must retain such records for the life of the pipeline.
    (c) For steel transmission pipeline segments installed on or before 
July 1, 2020], if an operator does not have records necessary to 
establish the MAOP of a pipeline segment, the operator may be subject to 
the requirements of Sec.  192.624 according to the terms of that 
section.

[Amdt. 192-125, 84 FR 52244, Oct. 1, 2019]



Sec.  192.69  Storage and handling of plastic pipe and associated 
components.

    Each operator must have and follow written procedures for the 
storage and handling of plastic pipe and associated components that meet 
the applicable listed specifications.

[83 FR 58716, Nov. 20, 2018. Redesignated by Amdt. 192-125, 84 FR 52244, 
Oct. 1, 2019]



                          Subpart C_Pipe Design



Sec.  192.101  Scope.

    This subpart prescribes the minimum requirements for the design of 
pipe.



Sec.  192.103  General.

    Pipe must be designed with sufficient wall thickness, or must be 
installed with adequate protection, to withstand anticipated external 
pressures and loads that will be imposed on the pipe after installation.



Sec.  192.105  Design formula for steel pipe.

    (a) The design pressure for steel pipe is determined in accordance 
with the following formula:

P = (2 St/D) x F x E x T

P = Design pressure in pounds per square inch (kPa) gauge.
S = Yield strength in pounds per square inch (kPa) determined in 
          accordance with Sec.  192.107.
D = Nominal outside diameter of the pipe in inches (millimeters).
t = Nominal wall thickness of the pipe in inches (millimeters). If this 
          is unknown, it is determined in accordance with Sec.  192.109. 
          Additional wall thickness required for concurrent external 
          loads in accordance with Sec.  192.103 may not be included in 
          computing design pressure.
F = Design factor determined in accordance with Sec.  192.111.
E = Longitudinal joint factor determined in accordance with Sec.  
          192.113.
T = Temperature derating factor determined in accordance with Sec.  
          192.115.

    (b) If steel pipe that has been subjected to cold expansion to meet 
the SMYS is subsequently heated, other than by welding or stress 
relieving as a part of welding, the design pressure is limited to 75 
percent of the pressure determined under paragraph (a) of this section 
if the temperature of the pipe exceeds 900 [deg]F (482 [deg]C) at any 
time or is held above 600 [deg]F (316 [deg]C) for more than 1 hour.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-47, 49 FR 7569, 
Mar. 1, 1984; Amdt. 192-85, 63 FR 37502, July 13, 1998]



Sec.  192.107  Yield strength (S) for steel pipe.

    (a) For pipe that is manufactured in accordance with a specification 
listed in section I of appendix B of this part, the yield strength to be 
used in the design formula in Sec.  192.105 is the SMYS stated in the 
listed specification, if that value is known.
    (b) For pipe that is manufactured in accordance with a specification 
not listed in section I of appendix B to this part or whose 
specification or tensile properties are unknown, the yield strength to 
be used in the design formula in Sec.  192.105 is one of the following:
    (1) If the pipe is tensile tested in accordance with section II-D of 
appendix B to this part, the lower of the following:
    (i) 80 percent of the average yield strength determined by the 
tensile tests.
    (ii) The lowest yield strength determined by the tensile tests.

[[Page 455]]

    (2) If the pipe is not tensile tested as provided in paragraph 
(b)(1) of this section, 24,000 p.s.i. (165 MPa).

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR 28783, 
June 6, 1996; Amdt. 192-83, 63 FR 7723, Feb. 17, 1998; Amdt. 192-85, 63 
FR 37502, July 13, 1998]



Sec.  192.109  Nominal wall thickness (t) for steel pipe.

    (a) If the nominal wall thickness for steel pipe is not known, it is 
determined by measuring the thickness of each piece of pipe at quarter 
points on one end.
    (b) However, if the pipe is of uniform grade, size, and thickness 
and there are more than 10 lengths, only 10 percent of the individual 
lengths, but not less than 10 lengths, need be measured. The thickness 
of the lengths that are not measured must be verified by applying a 
gauge set to the minimum thickness found by the measurement. The nominal 
wall thickness to be used in the design formula in Sec.  192.105 is the 
next wall thickness found in commercial specifications that is below the 
average of all the measurements taken. However, the nominal wall 
thickness used may not be more than 1.14 times the smallest measurement 
taken on pipe less than 20 inches (508 millimeters) in outside diameter, 
nor more than 1.11 times the smallest measurement taken on pipe 20 
inches (508 millimeters) or more in outside diameter.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37502, 
July 13, 1998]



Sec.  192.111  Design factor (F) for steel pipe.

    (a) Except as otherwise provided in paragraphs (b), (c), and (d) of 
this section, the design factor to be used in the design formula in 
Sec.  192.105 is determined in accordance with the following table:

------------------------------------------------------------------------
                                                                Design
                       Class location                         factor (F)
------------------------------------------------------------------------
1...........................................................        0.72
2...........................................................        0.60
3...........................................................        0.50
4...........................................................        0.40
------------------------------------------------------------------------

    (b) A design factor of 0.60 or less must be used in the design 
formula in Sec.  192.105 for steel pipe in Class 1 locations that:
    (1) Crosses the right-of-way of an unimproved public road, without a 
casing;
    (2) Crosses without a casing, or makes a parallel encroachment on, 
the right-of-way of either a hard surfaced road, a highway, a public 
street, or a railroad;
    (3) Is supported by a vehicular, pedestrian, railroad, or pipeline 
bridge; or
    (4) Is used in a fabricated assembly, (including separators, 
mainline valve assemblies, cross-connections, and river crossing 
headers) or is used within five pipe diameters in any direction from the 
last fitting of a fabricated assembly, other than a transition piece or 
an elbow used in place of a pipe bend which is not associated with a 
fabricated assembly.
    (c) For Class 2 locations, a design factor of 0.50, or less, must be 
used in the design formula in Sec.  192.105 for uncased steel pipe that 
crosses the right-of-way of a hard surfaced road, a highway, a public 
street, or a railroad.
    (d) For Class 1 and Class 2 locations, a design factor of 0.50, or 
less, must be used in the design formula in Sec.  192.105 for--
    (1) Steel pipe in a compressor station, regulating station, or 
measuring station; and
    (2) Steel pipe, including a pipe riser, on a platform located 
offshore or in inland navigable waters.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34605, 
Aug. 16, 1976]



Sec.  192.112  Additional design requirements for steel pipe using 
alternative maximum allowable operating pressure.

    For a new or existing pipeline segment to be eligible for operation 
at the alternative maximum allowable operating pressure (MAOP) 
calculated under Sec.  192.620, a segment must meet the following 
additional design requirements. Records for alternative MAOP must be 
maintained, for the useful life of the pipeline, demonstrating 
compliance with these requirements:

[[Page 456]]



------------------------------------------------------------------------
                                    The pipeline segment must meet these
   To address this design issue:          additional requirements:
------------------------------------------------------------------------
(a) General standards for the       (1) The plate, skelp, or coil used
 steel pipe.                         for the pipe must be micro-alloyed,
                                     fine grain, fully killed,
                                     continuously cast steel with
                                     calcium treatment.
                                    (2) The carbon equivalents of the
                                     steel used for pipe must not exceed
                                     0.25 percent by weight, as
                                     calculated by the Ito-Bessyo
                                     formula (Pcm formula) or 0.43
                                     percent by weight, as calculated by
                                     the International Institute of
                                     Welding (IIW) formula.
                                    (3) The ratio of the specified
                                     outside diameter of the pipe to the
                                     specified wall thickness must be
                                     less than 100. The wall thickness
                                     or other mitigative measures must
                                     prevent denting and ovality
                                     anomalies during construction,
                                     strength testing and anticipated
                                     operational stresses.
                                    (4) The pipe must be manufactured
                                     using API Spec 5L, product
                                     specification level 2 (incorporated
                                     by reference, see Sec.   192.7) for
                                     maximum operating pressures and
                                     minimum and maximum operating
                                     temperatures and other requirements
                                     under this section.
(b) Fracture control..............  (1) The toughness properties for
                                     pipe must address the potential for
                                     initiation, propagation and arrest
                                     of fractures in accordance with:
                                    (i) API Spec 5L (incorporated by
                                     reference, see Sec.   192.7); or
                                    (ii) American Society of Mechanical
                                     Engineers (ASME) B31.8
                                     (incorporated by reference, see
                                     Sec.   192.7); and
                                    (iii) Any correction factors needed
                                     to address pipe grades, pressures,
                                     temperatures, or gas compositions
                                     not expressly addressed in API Spec
                                     5L , product specification level 2
                                     or ASME B31.8 (incorporated by
                                     reference, see Sec.   192.7).
                                    (2) Fracture control must:
                                    (i) Ensure resistance to fracture
                                     initiation while addressing the
                                     full range of operating
                                     temperatures, pressures, gas
                                     compositions, pipe grade and
                                     operating stress levels, including
                                     maximum pressures and minimum
                                     temperatures for shut-in
                                     conditions, that the pipeline is
                                     expected to experience. If these
                                     parameters change during operation
                                     of the pipeline such that they are
                                     outside the bounds of what was
                                     considered in the design
                                     evaluation, the evaluation must be
                                     reviewed and updated to assure
                                     continued resistance to fracture
                                     initiation over the operating life
                                     of the pipeline;
                                    (ii) Address adjustments to
                                     toughness of pipe for each grade
                                     used and the decompression behavior
                                     of the gas at operating parameters;
                                    (iii) Ensure at least 99 percent
                                     probability of fracture arrest
                                     within eight pipe lengths with a
                                     probability of not less than 90
                                     percent within five pipe lengths;
                                     and
                                    (iv) Include fracture toughness
                                     testing that is equivalent to that
                                     described in supplementary
                                     requirements SR5A, SR5B, and SR6 of
                                     API Specification 5L (incorporated
                                     by reference, see Sec.   192.7) and
                                     ensures ductile fracture and arrest
                                     with the following exceptions:
                                    (A) The results of the Charpy impact
                                     test prescribed in SR5A must
                                     indicate at least 80 percent
                                     minimum shear area for any single
                                     test on each heat of steel; and
                                    (B) The results of the drop weight
                                     test prescribed in SR6 must
                                     indicate 80 percent average shear
                                     area with a minimum single test
                                     result of 60 percent shear area for
                                     any steel test samples. The test
                                     results must ensure a ductile
                                     fracture and arrest.
                                    (3) If it is not physically possible
                                     to achieve the pipeline toughness
                                     properties of paragraphs (b)(1) and
                                     (2) of this section, additional
                                     design features, such as mechanical
                                     or composite crack arrestors and/or
                                     heavier walled pipe of proper
                                     design and spacing, must be used to
                                     ensure fracture arrest as described
                                     in paragraph (b)(2)(iii) of this
                                     section.
(c) Plate/coil quality control....  (1) There must be an internal
                                     quality management program at all
                                     mills involved in producing steel,
                                     plate, coil, skelp, and/or rolling
                                     pipe to be operated at alternative
                                     MAOP. These programs must be
                                     structured to eliminate or detect
                                     defects and inclusions affecting
                                     pipe quality.
                                    (2) A mill inspection program or
                                     internal quality management program
                                     must include (i) and either (ii) or
                                     (iii):
                                    (i) An ultrasonic test of the ends
                                     and at least 35 percent of the
                                     surface of the plate/coil or pipe
                                     to identify imperfections that
                                     impair serviceability such as
                                     laminations, cracks, and
                                     inclusions. At least 95 percent of
                                     the lengths of pipe manufactured
                                     must be tested. For all pipelines
                                     designed after December 22, 2008,
                                     the test must be done in accordance
                                     with ASTM A578/A578M Level B, or
                                     API Spec 5L Paragraph 7.8.10
                                     (incorporated by reference, see
                                     Sec.   192.7) or equivalent method,
                                     and either
                                    (ii) A macro etch test or other
                                     equivalent method to identify
                                     inclusions that may form centerline
                                     segregation during the continuous
                                     casting process. Use of sulfur
                                     prints is not an equivalent method.
                                     The test must be carried out on the
                                     first or second slab of each
                                     sequence graded with an acceptance
                                     criteria of one or two on the
                                     Mannesmann scale or equivalent; or
                                    (iii) A quality assurance monitoring
                                     program implemented by the operator
                                     that includes audits of: (a) all
                                     steelmaking and casting facilities,
                                     (b) quality control plans and
                                     manufacturing procedure
                                     specifications, (c) equipment
                                     maintenance and records of
                                     conformance, (d) applicable casting
                                     superheat and speeds, and (e)
                                     centerline segregation monitoring
                                     records to ensure mitigation of
                                     centerline segregation during the
                                     continuous casting process.
(d) Seam quality control..........  (1) There must be a quality
                                     assurance program for pipe seam
                                     welds to assure tensile strength
                                     provided in API Spec 5L
                                     (incorporated by reference, see
                                     Sec.   192.7) for appropriate
                                     grades.
                                    (2) There must be a hardness test,
                                     using Vickers (Hv10) hardness test
                                     method or equivalent test method,
                                     to assure a maximum hardness of 280
                                     Vickers of the following:
                                    (i) A cross section of the weld seam
                                     of one pipe from each heat plus one
                                     pipe from each welding line per
                                     day; and
                                    (ii) For each sample cross section,
                                     a minimum of 13 readings (three for
                                     each heat affected zone, three in
                                     the weld metal, and two in each
                                     section of pipe base metal).
                                    (3) All of the seams must be
                                     ultrasonically tested after cold
                                     expansion and mill hydrostatic
                                     testing.

[[Page 457]]

 
(e) Mill hydrostatic test.........  (1) All pipe to be used in a new
                                     pipeline segment installed after
                                     October 1, 2015, must be
                                     hydrostatically tested at the mill
                                     at a test pressure corresponding to
                                     a hoop stress of 95 percent SMYS
                                     for 10 seconds.
                                    (2) Pipe in operation prior to
                                     December 22, 2008, must have been
                                     hydrostatically tested at the mill
                                     at a test pressure corresponding to
                                     a hoop stress of 90 percent SMYS
                                     for 10 seconds.
                                    (3) Pipe in operation on or after
                                     December 22, 2008, but before
                                     October 1, 2015, must have been
                                     hydrostatically tested at the mill
                                     at a test pressure corresponding to
                                     a hoop stress of 95 percent SMYS
                                     for 10 seconds. The test pressure
                                     may include a combination of
                                     internal test pressure and the
                                     allowance for end loading stresses
                                     imposed by the pipe mill
                                     hydrostatic testing equipment as
                                     allowed by ``ANSI/API Spec 5L''
                                     (incorporated by reference, see
                                     Sec.   192.7).
(f) Coating.......................  (1) The pipe must be protected
                                     against external corrosion by a non-
                                     shielding coating.
                                    (2) Coating on pipe used for
                                     trenchless installation must be non-
                                     shielding and resist abrasions and
                                     other damage possible during
                                     installation.
                                    (3) A quality assurance inspection
                                     and testing program for the coating
                                     must cover the surface quality of
                                     the bare pipe, surface cleanliness
                                     and chlorides, blast cleaning,
                                     application temperature control,
                                     adhesion, cathodic disbondment,
                                     moisture permeation, bending,
                                     coating thickness, holiday
                                     detection, and repair.
(g) Fittings and flanges..........  (1) There must be certification
                                     records of flanges, factory
                                     induction bends and factory weld
                                     ells. Certification must address
                                     material properties such as
                                     chemistry, minimum yield strength
                                     and minimum wall thickness to meet
                                     design conditions.
                                    (2) If the carbon equivalents of
                                     flanges, bends and ells are greater
                                     than 0.42 percent by weight, the
                                     qualified welding procedures must
                                     include a pre-heat procedure.
                                    (3) Valves, flanges and fittings
                                     must be rated based upon the
                                     required specification rating class
                                     for the alternative MAOP.
(h) Compressor stations...........  (1) A compressor station must be
                                     designed to limit the temperature
                                     of the nearest downstream segment
                                     operating at alternative MAOP to a
                                     maximum of 120 degrees Fahrenheit
                                     (49 degrees Celsius) or the higher
                                     temperature allowed in paragraph
                                     (h)(2) of this section unless a
                                     long-term coating integrity
                                     monitoring program is implemented
                                     in accordance with paragraph (h)(3)
                                     of this section.
                                    (2) If research, testing and field
                                     monitoring tests demonstrate that
                                     the coating type being used will
                                     withstand a higher temperature in
                                     long-term operations, the
                                     compressor station may be designed
                                     to limit downstream piping to that
                                     higher temperature. Test results
                                     and acceptance criteria addressing
                                     coating adhesion, cathodic
                                     disbondment, and coating condition
                                     must be provided to each PHMSA
                                     pipeline safety regional office
                                     where the pipeline is in service at
                                     least 60 days prior to operating
                                     above 120 degrees Fahrenheit (49
                                     degrees Celsius). An operator must
                                     also notify a State pipeline safety
                                     authority when the pipeline is
                                     located in a State where PHMSA has
                                     an interstate agent agreement, or
                                     an intrastate pipeline is regulated
                                     by that State.
                                    (3) Pipeline segments operating at
                                     alternative MAOP may operate at
                                     temperatures above 120 degrees
                                     Fahrenheit (49 degrees Celsius) if
                                     the operator implements a long-term
                                     coating integrity monitoring
                                     program. The monitoring program
                                     must include examinations using
                                     direct current voltage gradient
                                     (DCVG), alternating current voltage
                                     gradient (ACVG), or an equivalent
                                     method of monitoring coating
                                     integrity. An operator must specify
                                     the periodicity at which these
                                     examinations occur and criteria for
                                     repairing identified indications.
                                     An operator must submit its long-
                                     term coating integrity monitoring
                                     program to each PHMSA pipeline
                                     safety regional office in which the
                                     pipeline is located for review
                                     before the pipeline segments may be
                                     operated at temperatures in excess
                                     of 120 degrees Fahrenheit (49
                                     degrees Celsius). An operator must
                                     also notify a State pipeline safety
                                     authority when the pipeline is
                                     located in a State where PHMSA has
                                     an interstate agent agreement, or
                                     an intrastate pipeline is regulated
                                     by that State.
------------------------------------------------------------------------


[73 FR 62175, Oct. 17, 2008, as amended by Amdt. 192-111, 74 FR 62505, 
Nov. 30, 2009; Amdt. 192-119, 80 FR 180, Jan. 5, 2015; Amdt. 192-120, 80 
FR 12777, Mar. 11, 2015]



Sec.  192.113  Longitudinal joint factor (E) for steel pipe.

    The longitudinal joint factor to be used in the design formula in 
Sec.  192.105 is determined in accordance with the following table:

------------------------------------------------------------------------
                                                          Longitudinal
         Specification                Pipe class        joint factor (E)
------------------------------------------------------------------------
ASTM A 53/A53M.................  Seamless............               1.00
                                 Electric resistance                1.00
                                  welded.
                                 Furnace butt welded.                .60
ASTM A 106.....................  Seamless............               1.00
ASTM A 333/A 333M..............  Seamless............               1.00
                                 Electric resistance                1.00
                                  welded.
ASTM A 381.....................  Double submerged arc               1.00
                                  welded.

[[Page 458]]

 
ASTM A 671.....................  Electric-fusion-                   1.00
                                  welded.
ASTM A 672.....................  Electric-fusion-                   1.00
                                  welded.
ASTM A 691.....................  Electric-fusion-                   1.00
                                  welded.
API Spec 5L....................  Seamless............               1.00
                                 Electric resistance                1.00
                                  welded.
                                 Electric flash                     1.00
                                  welded.
                                 Submerged arc welded               1.00
                                 Furnace butt welded.                .60
Other..........................  Pipe over 4 inches                  .80
                                  (102 millimeters).
Other..........................  Pipe 4 inches (102                  .60
                                  millimeters) or
                                  less.
------------------------------------------------------------------------


If the type of longitudinal joint cannot be determined, the joint factor 
to be used must not exceed that designated for ``Other.''

[Amdt. 192-37, 46 FR 10159, Feb. 2, 1981, as amended by Amdt. 192-51, 51 
FR 15335, Apr. 23, 1986; Amdt. 192-62, 54 FR 5627, Feb. 6, 1989; 58 FR 
14521, Mar. 18, 1993; Amdt. 192-85, 63 FR 37502, July 13, 1998; Amdt. 
192-94, 69 FR 32894, June 14, 2004; Amdt. 192-119, 80 FR 180, Jan. 5, 
2015]



Sec.  192.115  Temperature derating factor (T) for steel pipe.

    The temperature derating factor to be used in the design formula in 
Sec.  192.105 is determined as follows:

------------------------------------------------------------------------
                                                          Temperature
   Gas temperature in degrees Fahrenheit (Celsius)      derating factor
                                                              (T)
------------------------------------------------------------------------
250 [deg]F (121 [deg]C) or less......................              1.000
300 [deg]F (149 [deg]C)..............................              0.967
350 [deg]F (177 [deg]C)..............................              0.933
400 [deg]F (204 [deg]C)..............................              0.900
450 [deg]F (232 [deg]C)..............................              0.867
------------------------------------------------------------------------


For intermediate gas temperatures, the derating factor is determined by 
interpolation.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37502, 
July 13, 1998]



Sec. Sec.  192.117-192.119  [Reserved]



Sec.  192.121  Design of plastic pipe.

    (a) Design pressure. The design pressure for plastic pipe is 
determined in accordance with either of the following formulas:
[GRAPHIC] [TIFF OMITTED] TR20NO18.000

P = Design pressure, gage, psi (kPa).
S = For thermoplastic pipe, the hydrostatic design basis (HDB) is 
          determined in accordance with the listed specification at a 
          temperature equal to 73 [deg]F (23 [deg]C), 100 [deg]F (38 
          [deg]C), 120 [deg]F (49 [deg]C), or 140 [deg]F (60 [deg]C). In 
          the absence of an HDB established at the specified 
          temperature, the HDB of a higher temperature may be used in 
          determining a design pressure rating at the specified 
          temperature by arithmetic interpolation using the procedure in 
          Part D.2 of PPI TR-3/2012, (incorporated by reference, see 
          Sec.  192.7). For reinforced thermosetting plastic pipe, 
          11,000 psig (75,842 kPa).
t = Specified wall thickness, inches (mm).
D = Specified outside diameter, inches (mm).
SDR = Standard dimension ratio, the ratio of the average specified 
          outside diameter to the minimum specified wall thickness, 
          corresponding to a value from a common numbering system that 
          was derived from the American National Standards Institute 
          (ANSI) preferred number series 10.
DF = Design Factor, a maximum of 0.32 unless otherwise specified for a 
          particular material in this section


[[Page 459]]


    (b) General requirements for plastic pipe and components. (1) Except 
as provided in paragraphs (c) through (f) of this section, the design 
pressure for plastic pipe may not exceed a gauge pressure of 100 psig 
(689 kPa) for pipe used in:
    (i) Distribution systems; or
    (ii) Transmission lines in Class 3 and 4 locations.
    (2) Plastic pipe may not be used where operating temperatures of the 
pipe will be:
    (i) Below -20 [deg]F (-29 [deg]C), or below -40 [deg]F (-40 [deg]C) 
if all pipe and pipeline components whose operating temperature will be 
below -20 [deg]F (-29 [deg]C) have a temperature rating by the 
manufacturer consistent with that operating temperature; or
    (ii) Above the temperature at which the HDB used in the design 
formula under this section is determined.
    (3) Unless specified for a particular material in this section, the 
wall thickness of plastic pipe may not be less than 0.062 inches (1.57 
millimeters).
    (4) All plastic pipe must have a listed HDB in accordance with PPI 
TR-4/2012 (incorporated by reference, see Sec.  192.7).
    (c) Polyethylene (PE) pipe requirements. (1) For PE pipe produced 
after July 14, 2004, but before January 22, 2019, a design pressure of 
up to 125 psig may be used, provided:
    (i) The material designation code is PE2406 or PE3408.
    (ii) The pipe has a nominal size (Iron Pipe Size (IPS) or Copper 
Tubing Size (CTS)) of 12 inches or less (above nominal pipe size of 12 
inches, the design pressure is limited to 100 psig); and
    (iii) The wall thickness is not less than 0.062 inches (1.57 
millimeters).
    (2) For PE pipe produced on or after January 22, 2019, a DF of 0.40 
may be used in the design formula, provided:
    (i) The design pressure does not exceed 125 psig;
    (ii) The material designation code is PE2708 or PE4710;
    (iii) The pipe has a nominal size (IPS or CTS) of 24 inches or less; 
and
    (iv) The wall thickness for a given outside diameter is not less 
than that listed in table 1 to this paragraph (c)(2)(iv).

                     Table 1 to Paragraph (c)(2)(iv)
------------------------------------------------------------------------
             PE pipe: minimum wall thickness and SDR values
-------------------------------------------------------------------------
                                           Minimum wall
           Pipe size (inches)                thickness     Corresponding
                                             (inches)      SDR (values)
------------------------------------------------------------------------
\1/2\[sec] CTS..........................           0.090               7
\1/2\[sec] IPS..........................           0.090             9.3
\3/4\[sec] CTS..........................           0.090             9.7
\3/4\[sec] IPS..........................           0.095              11
1[sec] CTS..............................           0.099              11
1[sec] IPS..............................           0.119              11
1 \1/4\[sec] IPS........................           0.151              11
1 \1/2\[sec] IPS........................           0.173              11
2[sec]..................................           0.216              11
3[sec]..................................           0.259            13.5
4[sec]..................................           0.265              17
6[sec]..................................           0.315              21
8[sec]..................................           0.411              21
10[sec].................................           0.512              21
12[sec].................................           0.607              21
16[sec].................................           0.762              21
18[sec].................................           0.857              21
20[sec].................................           0.952              21
22[sec].................................           1.048              21
24[sec].................................           1.143              21
------------------------------------------------------------------------

    (d) Polyamide (PA-11) pipe requirements. (1) For PA-11 pipe produced 
after January 23, 2009, but before January 22, 2019, a DF of 0.40 may be 
used in the design formula, provided:
    (i) The design pressure does not exceed 200 psig;
    (ii) The material designation code is PA32312 or PA32316;
    (iii) The pipe has a nominal size (IPS or CTS) of 4 inches or less; 
and

[[Page 460]]

    (iv) The pipe has a standard dimension ratio of SDR-11 or less 
(i.e., thicker wall pipe).
    (2) For PA-11 pipe produced on or after January 22, 2019, a DF of 
0.40 may be used in the design formula, provided:
    (i) The design pressure does not exceed 250 psig;
    (ii) The material designation code is PA32316;
    (iii) The pipe has a nominal size (IPS or CTS) of 6 inches or less; 
and
    (iv) The minimum wall thickness for a given outside diameter is not 
less than that listed in table 2 to paragraph (d)(2)(iv):

                     Table 2 to Paragraph (d)(2)(iv)
------------------------------------------------------------------------
            PA-11 pipe: minimum wall thickness and SDR values
-------------------------------------------------------------------------
                                           Minimum wall
           Pipe size (inches)                thickness     Corresponding
                                             (inches)      SDR (values)
------------------------------------------------------------------------
\1/2\[sec] CTS..........................           0.090             7.0
\1/2\[sec] IPS..........................           0.090             9.3
\3/4\[sec] CTS..........................           0.090             9.7
\3/4\[sec] IPS..........................           0.095              11
1[sec] CTS..............................           0.099              11
1[sec] IPS..............................           0.119              11
1 \1/4\ IPS.............................           0.151              11
1 \1/2\[sec] IPS........................           0.173              11
2[sec] IPS..............................           0.216              11
3[sec] IPS..............................           0.259            13.5
4[sec] IPS..............................           0.333            13.5
6[sec] IPS..............................           0.491            13.5
------------------------------------------------------------------------

    (e) Polyamide (PA-12) pipe requirements. For PA-12 pipe produced 
after January 22, 2019, a DF of 0.40 may be used in the design formula, 
provided:
    (1) The design pressure does not exceed 250 psig;
    (2) The material designation code is PA42316;
    (3) The pipe has a nominal size (IPS or CTS) of 6 inches or less; 
and
    (4) The minimum wall thickness for a given outside diameter is not 
less than that listed in table 3 to paragraph (e)(4).

                       Table 3 to Paragraph (e)(4)
------------------------------------------------------------------------
            PA-12 pipe: minimum wall thickness and SDR values
-------------------------------------------------------------------------
                                           Minimum wall
           Pipe size (inches)                thickness     Corresponding
                                             (inches)      SDR (values)
------------------------------------------------------------------------
\1/2\[sec] CTS..........................           0.090               7
\1/2\[sec] IPS..........................           0.090             9.3
\3/4\[sec] CTS..........................           0.090             9.7
\3/4\[sec] IPS..........................           0.095              11
1[sec] CTS..............................           0.099              11
1[sec] IPS..............................           0.119              11
1 \1/4\[sec] IPS........................           0.151              11
1 \1/2\[sec] IPS........................           0.173              11
2[sec] IPS..............................           0.216              11
3[sec] IPS..............................           0.259            13.5
4[sec] IPS..............................           0.333            13.5
6[sec] IPS..............................           0.491            13.5
------------------------------------------------------------------------

    (f) Reinforced thermosetting plastic pipe requirements. (1) 
Reinforced thermosetting plastic pipe may not be used at operating 
temperatures above 150 [deg]F (66 [deg]C).
    (2) The wall thickness for reinforced thermosetting plastic pipe may 
not be less than that listed in the following table:

[[Page 461]]



------------------------------------------------------------------------
                                                           Minimum wall
                                                           thickness in
          Nominal size in inches (millimeters)                inches
                                                          (millimeters)
------------------------------------------------------------------------
2 (51).................................................     0.060 (1.52)
3 (76).................................................     0.060 (1.52)
4 (102)................................................     0.070 (1.78)
6 (152)................................................     0.100 (2.54)
------------------------------------------------------------------------


[Amdt. 192-124, 83 FR 58716, Nov. 20, 2018, as amended at 86 FR 2238, 
Jan. 11, 2021]



Sec.  192.123  [Reserved]



Sec.  192.125  Design of copper pipe.

    (a) Copper pipe used in mains must have a minimum wall thickness of 
0.065 inches (1.65 millimeters) and must be hard drawn.
    (b) Copper pipe used in service lines must have wall thickness not 
less than that indicated in the following table:

------------------------------------------------------------------------
                                        Wall thickness inch (millimeter)
Standard size inch   Nominal O.D. inch ---------------------------------
   (millimeter)        (millimeter)         Nominal         Tolerance
------------------------------------------------------------------------
    \1/2\ (13)           .625 (16)       .040 (1.06)     .0035 (.0889)
    \5/8\ (16)           .750 (19)       .042 (1.07)     .0035 (.0889)
    \3/4\ (19)           .875 (22)       .045 (1.14)       .004 (.102)
        1 (25)          1.125 (29)       .050 (1.27)       .004 (.102)
   1\1/4\ (32)          1.375 (35)       .055 (1.40)     .0045 (.1143)
   1\1/2\ (38)          1.625 (41)       .060 (1.52)     .0045 (.1143)
------------------------------------------------------------------------

    (c) Copper pipe used in mains and service lines may not be used at 
pressures in excess of 100 p.s.i. (689 kPa) gage.
    (d) Copper pipe that does not have an internal corrosion resistant 
lining may not be used to carry gas that has an average hydrogen sulfide 
content of more than 0.3 grains/100 ft\3\ (6.9/m\3\) under standard 
conditions. Standard conditions refers to 60 [deg]F and 14.7 psia (15.6 
[deg]C and one atmosphere) of gas.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5628, 
Feb. 6, 1989; Amdt. 192-85, 63 FR 37502, July 13, 1998]



Sec.  192.127  Records: Pipe design.

    (a) For steel transmission pipelines installed after July 1, 2020], 
an operator must collect or make, and retain for the life of the 
pipeline, records documenting that the pipe is designed to withstand 
anticipated external pressures and loads in accordance with Sec.  
192.103 and documenting that the determination of design pressure for 
the pipe is made in accordance with Sec.  192.105.
    (b) For steel transmission pipelines installed on or before July 1, 
2020, if operators have records documenting pipe design and the 
determination of design pressure in accordance with Sec. Sec.  192.103 
and 192.105, operators must retain such records for the life of the 
pipeline.
    (c) For steel transmission pipeline segments installed on or before 
July 1, 2020, if an operator does not have records necessary to 
establish the MAOP of a pipeline segment, the operator may be subject to 
the requirements of Sec.  192.624 according to the terms of that 
section.

[Amdt. 192-125, 84 FR 52244, Oct. 1, 2019]



                 Subpart D_Design of Pipeline Components



Sec.  192.141  Scope.

    This subpart prescribes minimum requirements for the design and 
installation of pipeline components and facilities. In addition, it 
prescribes requirements relating to protection against accidental 
overpressuring.



Sec.  192.143  General requirements.

    (a) Each component of a pipeline must be able to withstand operating 
pressures and other anticipated loadings without impairment of its 
serviceability with unit stresses equivalent to those allowed for 
comparable material in pipe in the same location and kind of service. 
However, if design based upon unit stresses is impractical for a 
particular component, design may be based upon a pressure rating 
established by the manufacturer by pressure testing that component or a 
prototype of the component.
    (b) The design and installation of pipeline components and 
facilities must meet applicable requirements for corrosion control found 
in subpart I of this part.
    (c) Except for excess flow valves, each plastic pipeline component 
installed after January 22, 2019 must be able to withstand operating 
pressures and other anticipated loads in accordance with a listed 
specification.

[Amdt. 48, 49 FR 19824, May 10, 1984, as amended at 72 FR 20059, Apr. 
23, 2007; Amdt. 192-124, 83 FR 58717, Nov. 20, 2018]

[[Page 462]]



Sec.  192.144  Qualifying metallic components.

    Notwithstanding any requirement of this subpart which incorporates 
by reference an edition of a document listed in Sec.  192.7 or Appendix 
B of this part, a metallic component manufactured in accordance with any 
other edition of that document is qualified for use under this part if--
    (a) It can be shown through visual inspection of the cleaned 
component that no defect exists which might impair the strength or 
tightness of the component; and
    (b) The edition of the document under which the component was 
manufactured has equal or more stringent requirements for the following 
as an edition of that document currently or previously listed in Sec.  
192.7 or appendix B of this part:
    (1) Pressure testing;
    (2) Materials; and
    (3) Pressure and temperature ratings.

[Amdt. 192-45, 48 FR 30639, July 5, 1983, as amended by Amdt. 192-94, 69 
FR 32894, June 14, 2004]



Sec.  192.145  Valves.

    (a) Except for cast iron and plastic valves, each valve must meet 
the minimum requirements of ANSI/API Spec 6D (incorporated by reference, 
see Sec.  192.7), or to a national or international standard that 
provides an equivalent performance level. A valve may not be used under 
operating conditions that exceed the applicable pressure-temperature 
ratings contained in those requirements.
    (b) Each cast iron and plastic valve must comply with the following:
    (1) The valve must have a maximum service pressure rating for 
temperatures that equal or exceed the maximum service temperature.
    (2) The valve must be tested as part of the manufacturing, as 
follows:
    (i) With the valve in the fully open position, the shell must be 
tested with no leakage to a pressure at least 1.5 times the maximum 
service rating.
    (ii) After the shell test, the seat must be tested to a pressure not 
less than 1.5 times the maximum service pressure rating. Except for 
swing check valves, test pressure during the seat test must be applied 
successively on each side of the closed valve with the opposite side 
open. No visible leakage is permitted.
    (iii) After the last pressure test is completed, the valve must be 
operated through its full travel to demonstrate freedom from 
interference.
    (c) Each valve must be able to meet the anticipated operating 
conditions.
    (d) No valve having shell (body, bonnet, cover, and/or end flange) 
components made of ductile iron may be used at pressures exceeding 80 
percent of the pressure ratings for comparable steel valves at their 
listed temperature. However, a valve having shell components made of 
ductile iron may be used at pressures up to 80 percent of the pressure 
ratings for comparable steel valves at their listed temperature, if:
    (1) The temperature-adjusted service pressure does not exceed 1,000 
p.s.i. (7 Mpa) gage; and
    (2) Welding is not used on any ductile iron component in the 
fabrication of the valve shells or their assembly.
    (e) No valve having shell (body, bonnet, cover, and/or end flange) 
components made of cast iron, malleable iron, or ductile iron may be 
used in the gas pipe components of compressor stations.
    (f) Except for excess flow valves, plastic valves installed after 
January 22, 2019, must meet the minimum requirements of a listed 
specification. A valve may not be used under operating conditions that 
exceed the applicable pressure and temperature ratings contained in the 
listed specification.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5628, 
Feb. 6, 1989; Amdt. 192-85, 63 FR 37502, July 13, 1998; Amdt. 192-94, 69 
FR 32894, June 14, 2004; Amdt. 192-114, 75 FR 48603, Aug. 11, 2010; 
Amdt. 192-119, 80 FR 181, Jan. 5, 2015; Amdt. 192-124, 83 FR 58717, Nov. 
20, 2018]



Sec.  192.147  Flanges and flange accessories.

    (a) Each flange or flange accessory (other than cast iron) must meet 
the minimum requirements of ASME/ANSI B 16.5 and MSS SP-44 (incorporated 
by reference, see Sec.  192.7), or the equivalent.
    (b) Each flange assembly must be able to withstand the maximum 
pressure at which the pipeline is to be operated and to maintain its 
physical and

[[Page 463]]

chemical properties at any temperature to which it is anticipated that 
it might be subjected in service.
    (c) Each flange on a flanged joint in cast iron pipe must conform in 
dimensions, drilling, face and gasket design to ASME/ANSI B16.1 
(incorporated by reference, see Sec.  192.7)and be cast integrally with 
the pipe, valve, or fitting.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5628, 
Feb. 6, 1989; 58 FR 14521, Mar. 18, 1993; Amdt. 192-119, 80 FR 181, Jan. 
5, 2015]



Sec.  192.149  Standard fittings.

    (a) The minimum metal thickness of threaded fittings may not be less 
than specified for the pressures and temperatures in the applicable 
standards referenced in this part, or their equivalent.
    (b) Each steel butt-welding fitting must have pressure and 
temperature ratings based on stresses for pipe of the same or equivalent 
material. The actual bursting strength of the fitting must at least 
equal the computed bursting strength of pipe of the designated material 
and wall thickness, as determined by a prototype that was tested to at 
least the pressure required for the pipeline to which it is being added.
    (c) Plastic fittings installed after January 22, 2019, must meet a 
listed specification.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-124, 83 FR 58718, 
Nov. 20, 2018]



Sec.  192.150  Passage of internal inspection devices.

    (a) Except as provided in paragraphs (b) and (c) of this section, 
each new transmission line and each replacement of line pipe, valve, 
fitting, or other line component in a transmission line, must be 
designed and constructed to accommodate the passage of instrumented 
internal inspection devices in accordance with NACE SP0102, section 7 
(incorporated by reference, see Sec.  192.7).
    (b) This section does not apply to: (1) Manifolds;
    (2) Station piping such as at compressor stations, meter stations, 
or regulator stations;
    (3) Piping associated with storage facilities, other than a 
continuous run of transmission line between a compressor station and 
storage facilities;
    (4) Cross-overs;
    (5) Sizes of pipe for which an instrumented internal inspection 
device is not commercially available;
    (6) Transmission lines, operated in conjunction with a distribution 
system which are installed in Class 4 locations;
    (7) Offshore transmission lines, except transmission lines 10\3/4\ 
inches (273 millimeters) or more in outside diameter on which 
construction begins after December 28, 2005, that run from platform to 
platform or platform to shore unless--
    (i) Platform space or configuration is incompatible with launching 
or retrieving instrumented internal inspection devices; or
    (ii) If the design includes taps for lateral connections, the 
operator can demonstrate, based on investigation or experience, that 
there is no reasonably practical alternative under the design 
circumstances to the use of a tap that will obstruct the passage of 
instrumented internal inspection devices;
    (8) Gathering lines; and
    (9) Other piping that, under Sec.  190.9 of this chapter, the 
Administrator finds in a particular case would be impracticable to 
design and construct to accommodate the passage of instrumented internal 
inspection devices.
    (c) An operator encountering emergencies, construction time 
constraints or other unforeseen construction problems need not construct 
a new or replacement segment of a transmission line to meet paragraph 
(a) of this section, if the operator determines and documents why an 
impracticability prohibits compliance with paragraph (a) of this 
section. Within 30 days after discovering the emergency or construction 
problem the operator must petition, under Sec.  190.9 of this chapter, 
for approval that design and construction to accommodate passage of 
instrumented internal inspection devices would be impracticable. If the 
petition is denied, within 1 year after the date of the notice of the 
denial, the operator must modify that segment to allow

[[Page 464]]

passage of instrumented internal inspection devices.

[Amdt. 192-72, 59 FR 17281, Apr. 12, 1994, as amended by Amdt. 192-85, 
63 FR 37502, July 13, 1998; Amdt. 192-97, 69 FR 36029, June 28, 2004; 
Amdt. 192-125, 84 FR 52244, Oct. 1, 2019; Amdt. 192-129, 86 FR 63298, 
Nov. 15, 2021]



Sec.  192.151  Tapping.

    (a) Each mechanical fitting used to make a hot tap must be designed 
for at least the operating pressure of the pipeline.
    (b) Where a ductile iron pipe is tapped, the extent of full-thread 
engagement and the need for the use of outside-sealing service 
connections, tapping saddles, or other fixtures must be determined by 
service conditions.
    (c) Where a threaded tap is made in cast iron or ductile iron pipe, 
the diameter of the tapped hole may not be more than 25 percent of the 
nominal diameter of the pipe unless the pipe is reinforced, except that
    (1) Existing taps may be used for replacement service, if they are 
free of cracks and have good threads; and
    (2) A 1\1/4\-inch (32 millimeters) tap may be made in a 4-inch (102 
millimeters) cast iron or ductile iron pipe, without reinforcement.

However, in areas where climate, soil, and service conditions may create 
unusual external stresses on cast iron pipe, unreinforced taps may be 
used only on 6-inch (152 millimeters) or larger pipe.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37502, 
July 13, 1998]



Sec.  192.153  Components fabricated by welding.

    (a) Except for branch connections and assemblies of standard pipe 
and fittings joined by circumferential welds, the design pressure of 
each component fabricated by welding, whose strength cannot be 
determined, must be established in accordance with paragraph UG-101 of 
the ASME Boiler and Pressure Vessel Code (BPVC) (Section VIII, Division 
1) (incorporated by reference, see Sec.  192.7).
    (b) Each prefabricated unit that uses plate and longitudinal seams 
must be designed, constructed, and tested in accordance with the ASME 
BPVC (Rules for Construction of Pressure Vessels as defined in either 
Section VIII, Division 1 or Section VIII, Division 2; incorporated by 
reference, see Sec.  192.7), except for the following:
    (1) Regularly manufactured butt-welding fittings.
    (2) Pipe that has been produced and tested under a specification 
listed in appendix B to this part.
    (3) Partial assemblies such as split rings or collars.
    (4) Prefabricated units that the manufacturer certifies have been 
tested to at least twice the maximum pressure to which they will be 
subjected under the anticipated operating conditions.
    (c) Orange-peel bull plugs and orange-peel swages may not be used on 
pipelines that are to operate at a hoop stress of 20 percent or more of 
the SMYS of the pipe.
    (d) Except for flat closures designed in accordance with the ASME 
BPVC (Section VIII, Division 1 or 2), flat closures and fish tails may 
not be used on pipe that either operates at 100 p.s.i. (689 kPa) gage or 
more, or is more than 3 inches in (76 millimeters) nominal diameter.
    (e) The test requirements for a prefabricated unit or pressure 
vessel, defined for this paragraph as components with a design pressure 
established in accordance with paragraph (a) or paragraph (b) of this 
section are as follows.
    (1) A prefabricated unit or pressure vessel installed after July 14, 
2004 is not subject to the strength testing requirements at Sec.  
192.505(b) provided the component has been tested in accordance with 
paragraph (a) or paragraph (b) of this section and with a test factor of 
at least 1.3 times MAOP.
    (2) A prefabricated unit or pressure vessel must be tested for a 
duration specified as follows:
    (i) A prefabricated unit or pressure vessel installed after July 14, 
2004, but before October 1, 2021 is exempt from Sec. Sec.  192.505(c) 
and (d) and 192.507(c) provided it has been tested for a duration 
consistent with the ASME BPVC requirements referenced in paragraph (a) 
or (b) of this section.
    (ii) A prefabricated unit or pressure vessel installed on or after 
October 1, 2021 must be tested for the duration specified in either 
Sec.  192.505(c) or (d), Sec.  192.507(c), or Sec.  192.509(a), 
whichever is

[[Page 465]]

applicable for the pipeline in which the component is being installed.
    (3) For any prefabricated unit or pressure vessel permanently or 
temporarily installed on a pipeline facility, an operator must either:
    (i) Test the prefabricated unit or pressure vessel in accordance 
with this section and Subpart J of this part after it has been placed on 
its support structure at its final installation location. The test may 
be performed before or after it has been tied-in to the pipeline. Test 
records that meet Sec.  192.517(a) must be kept for the operational life 
of the prefabricated unit or pressure vessel; or
    (ii) For a prefabricated unit or pressure vessel that is pressure 
tested prior to installation or where a manufacturer's pressure test is 
used in accordance with paragraph (e) of this section, inspect the 
prefabricated unit or pressure vessel after it has been placed on its 
support structure at its final installation location and confirm that 
the prefabricated unit or pressure vessel was not damaged during any 
prior operation, transportation, or installation into the pipeline. The 
inspection procedure and documented inspection must include visual 
inspection for vessel damage, including, at a minimum, inlets, outlets, 
and lifting locations. Injurious defects that are an integrity threat 
may include dents, gouges, bending, corrosion, and cracking. This 
inspection must be performed prior to operation but may be performed 
either before or after it has been tied-in to the pipeline. If injurious 
defects that are an integrity threat are found, the prefabricated unit 
or pressure vessel must be either non-destructively tested, re-pressure 
tested, or remediated in accordance with applicable part 192 
requirements for a fabricated unit or with the applicable ASME BPVC 
requirements referenced in paragraphs (a) or (b) of this section. Test, 
inspection, and repair records for the fabricated unit or pressure 
vessel must be kept for the operational life of the component. Test 
records must meet the requirements in Sec.  192.517(a).
    (4) An initial pressure test from the prefabricated unit or pressure 
vessel manufacturer may be used to meet the requirements of this section 
with the following conditions:
    (i) The prefabricated unit or pressure vessel is newly-manufactured 
and installed on or after October 1, 2021, except as provided in 
paragraph (e)(4)(ii) of this section.
    (ii) An initial pressure test from the fabricated unit or pressure 
vessel manufacturer or other prior test of a new or existing 
prefabricated unit or pressure vessel may be used for a component that 
is temporarily installed in a pipeline facility in order to complete a 
testing, integrity assessment, repair, odorization, or emergency 
response-related task, including noise or pollution abatement. The 
temporary component must be promptly removed after that task is 
completed. If operational and environmental constraints require leaving 
a temporary prefabricated unit or pressure vessel under this paragraph 
in place for longer than 30 days, the operator must notify PHMSA and 
State or local pipeline safety authorities, as applicable, in accordance 
with Sec.  192.18.
    (iii) The manufacturer's pressure test must meet the minimum 
requirements of this part; and
    (iv) The operator inspects and remediates the prefabricated unit or 
pressure vessel after installation in accordance with paragraph 
(e)(3)(ii) of this section.
    (5) An existing prefabricated unit or pressure vessel that is 
temporarily removed from a pipeline facility to complete a testing, 
integrity assessment, repair, odorization, or emergency response-related 
task, including noise or pollution abatement, and then re-installed at 
the same location must be inspected in accordance with paragraph 
(e)(3)(ii) of this section; however, a new pressure test is not required 
provided no damage or threats to the operational integrity of the 
prefabricated unit or pressure vessel were identified during the 
inspection and the MAOP of the pipeline is not increased.
    (6) Except as provided in paragraphs (e)(4)(ii) and (5) of this 
section, on or after October 1, 2021, an existing prefabricated unit or 
pressure vessel relocated and operated at a different location must meet 
the requirements of this part and the following:

[[Page 466]]

    (i) The prefabricated unit or pressure vessel must be designed and 
constructed in accordance with the requirements of this part at the time 
the vessel is returned to operational service at the new location; and
    (ii) The prefabricated unit or pressure vessel must be pressure 
tested by the operator in accordance with the testing and inspection 
requirements of this part applicable to newly installed prefabricated 
units and pressure vessels.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-1, 35 FR 17660, 
Nov. 17, 1970; 58 FR 14521, Mar. 18, 1993; Amdt. 192-68, 58 FR 45268, 
Aug. 27, 1993; Amdt. 192-85, 63 FR 37502, July 13, 1998; Amdt. 192-119, 
80 FR 181, Jan. 5, 2015; Amdt. 192-120, 80 FR 12778, Mar. 11, 2015; 
Amdt. 192-119, 80 FR 46847, Aug. 6, 2015; 86 FR 2239, Jan. 11, 2021]



Sec.  192.155  Welded branch connections.

    Each welded branch connection made to pipe in the form of a single 
connection, or in a header or manifold as a series of connections, must 
be designed to ensure that the strength of the pipeline system is not 
reduced, taking into account the stresses in the remaining pipe wall due 
to the opening in the pipe or header, the shear stresses produced by the 
pressure acting on the area of the branch opening, and any external 
loadings due to thermal movement, weight, and vibration.



Sec.  192.157  Extruded outlets.

    Each extruded outlet must be suitable for anticipated service 
conditions and must be at least equal to the design strength of the pipe 
and other fittings in the pipeline to which it is attached.



Sec.  192.159  Flexibility.

    Each pipeline must be designed with enough flexibility to prevent 
thermal expansion or contraction from causing excessive stresses in the 
pipe or components, excessive bending or unusual loads at joints, or 
undesirable forces or moments at points of connection to equipment, or 
at anchorage or guide points.



Sec.  192.161  Supports and anchors.

    (a) Each pipeline and its associated equipment must have enough 
anchors or supports to:
    (1) Prevent undue strain on connected equipment;
    (2) Resist longitudinal forces caused by a bend or offset in the 
pipe; and
    (3) Prevent or damp out excessive vibration.
    (b) Each exposed pipeline must have enough supports or anchors to 
protect the exposed pipe joints from the maximum end force caused by 
internal pressure and any additional forces caused by temperature 
expansion or contraction or by the weight of the pipe and its contents.
    (c) Each support or anchor on an exposed pipeline must be made of 
durable, noncombustible material and must be designed and installed as 
follows:
    (1) Free expansion and contraction of the pipeline between supports 
or anchors may not be restricted.
    (2) Provision must be made for the service conditions involved.
    (3) Movement of the pipeline may not cause disengagement of the 
support equipment.
    (d) Each support on an exposed pipeline operated at a stress level 
of 50 percent or more of SMYS must comply with the following:
    (1) A structural support may not be welded directly to the pipe.
    (2) The support must be provided by a member that completely 
encircles the pipe.
    (3) If an encircling member is welded to a pipe, the weld must be 
continuous and cover the entire circumference.
    (e) Each underground pipeline that is connected to a relatively 
unyielding line or other fixed object must have enough flexibility to 
provide for possible movement, or it must have an anchor that will limit 
the movement of the pipeline.
    (f) Except for offshore pipelines, each underground pipeline that is 
being connected to new branches must have a firm foundation for both the 
header and the branch to prevent detrimental lateral and vertical 
movement.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, 
Jan. 21, 1988]

[[Page 467]]



Sec.  192.163  Compressor stations: Design and construction.

    (a) Location of compressor building. Except for a compressor 
building on a platform located offshore or in inland navigable waters, 
each main compressor building of a compressor station must be located on 
property under the control of the operator. It must be far enough away 
from adjacent property, not under control of the operator, to minimize 
the possibility of fire being communicated to the compressor building 
from structures on adjacent property. There must be enough open space 
around the main compressor building to allow the free movement of fire-
fighting equipment.
    (b) Building construction. Each building on a compressor station 
site must be made of noncombustible materials if it contains either--
    (1) Pipe more than 2 inches (51 millimeters) in diameter that is 
carrying gas under pressure; or
    (2) Gas handling equipment other than gas utilization equipment used 
for domestic purposes.
    (c) Exits. Each operating floor of a main compressor building must 
have at least two separated and unobstructed exits located so as to 
provide a convenient possibility of escape and an unobstructed passage 
to a place of safety. Each door latch on an exit must be of a type which 
can be readily opened from the inside without a key. Each swinging door 
located in an exterior wall must be mounted to swing outward.
    (d) Fenced areas. Each fence around a compressor station must have 
at least two gates located so as to provide a convenient opportunity for 
escape to a place of safety, or have other facilities affording a 
similarly convenient exit from the area. Each gate located within 200 
feet (61 meters) of any compressor plant building must open outward and, 
when occupied, must be openable from the inside without a key.
    (e) Electrical facilities. Electrical equipment and wiring installed 
in compressor stations must conform to the NFPA-70, so far as that code 
is applicable.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34605, 
Aug. 16, 1976; Amdt. 192-37, 46 FR 10159, Feb. 2, 1981; 58 FR 14521, 
Mar. 18, 1993; Amdt. 192-85, 63 FR 37502, 37503, July 13, 1998; Amdt. 
192-119, 80 FR 181, Jan. 5, 2015]



Sec.  192.165  Compressor stations: Liquid removal.

    (a) Where entrained vapors in gas may liquefy under the anticipated 
pressure and temperature conditions, the compressor must be protected 
against the introduction of those liquids in quantities that could cause 
damage.
    (b) Each liquid separator used to remove entrained liquids at a 
compressor station must:
    (1) Have a manually operable means of removing these liquids.
    (2) Where slugs of liquid could be carried into the compressors, 
have either automatic liquid removal facilities, an automatic compressor 
shutdown device, or a high liquid level alarm; and
    (3) Be manufactured in accordance with section VIII ASME Boiler and 
Pressure Vessel Code (BPVC) (incorporated by reference, see Sec.  192.7) 
and the additional requirements of Sec.  192.153(e) except that liquid 
separators constructed of pipe and fittings without internal welding 
must be fabricated with a design factor of 0.4, or less.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-119, 80 FR 181, 
Jan. 5, 2015; Amdt. 192-120, 80 FR 12778, Mar. 11, 2015]



Sec.  192.167  Compressor stations: Emergency shutdown.

    (a) Except for unattended field compressor stations of 1,000 
horsepower (746 kilowatts) or less, each compressor station must have an 
emergency shutdown system that meets the following:
    (1) It must be able to block gas out of the station and blow down 
the station piping.
    (2) It must discharge gas from the blowdown piping at a location 
where the gas will not create a hazard.
    (3) It must provide means for the shutdown of gas compressing 
equipment, gas fires, and electrical facilities in the vicinity of gas 
headers and in the compressor building, except that:

[[Page 468]]

    (i) Electrical circuits that supply emergency lighting required to 
assist station personnel in evacuating the compressor building and the 
area in the vicinity of the gas headers must remain energized; and
    (ii) Electrical circuits needed to protect equipment from damage may 
remain energized.
    (4) It must be operable from at least two locations, each of which 
is:
    (i) Outside the gas area of the station;
    (ii) Near the exit gates, if the station is fenced, or near 
emergency exits, if not fenced; and
    (iii) Not more than 500 feet (153 meters) from the limits of the 
station.
    (b) If a compressor station supplies gas directly to a distribution 
system with no other adequate source of gas available, the emergency 
shutdown system must be designed so that it will not function at the 
wrong time and cause an unintended outage on the distribution system.
    (c) On a platform located offshore or in inland navigable waters, 
the emergency shutdown system must be designed and installed to actuate 
automatically by each of the following events:
    (1) In the case of an unattended compressor station:
    (i) When the gas pressure equals the maximum allowable operating 
pressure plus 15 percent; or
    (ii) When an uncontrolled fire occurs on the platform; and
    (2) In the case of a compressor station in a building:
    (i) When an uncontrolled fire occurs in the building; or
    (ii) When the concentration of gas in air reaches 50 percent or more 
of the lower explosive limit in a building which has a source of 
ignition.

For the purpose of paragraph (c)(2)(ii) of this section, an electrical 
facility which conforms to Class 1, Group D, of the National Electrical 
Code is not a source of ignition.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34605, 
Aug. 16, 1976; Amdt. 192-85, 63 FR 37503, July 13, 1998]



Sec.  192.169  Compressor stations: Pressure limiting devices.

    (a) Each compressor station must have pressure relief or other 
suitable protective devices of sufficient capacity and sensitivity to 
ensure that the maximum allowable operating pressure of the station 
piping and equipment is not exceeded by more than 10 percent.
    (b) Each vent line that exhausts gas from the pressure relief valves 
of a compressor station must extend to a location where the gas may be 
discharged without hazard.



Sec.  192.171  Compressor stations: Additional safety equipment.

    (a) Each compressor station must have adequate fire protection 
facilities. If fire pumps are a part of these facilities, their 
operation may not be affected by the emergency shutdown system.
    (b) Each compressor station prime mover, other than an electrical 
induction or synchronous motor, must have an automatic device to shut 
down the unit before the speed of either the prime mover or the driven 
unit exceeds a maximum safe speed.
    (c) Each compressor unit in a compressor station must have a 
shutdown or alarm device that operates in the event of inadequate 
cooling or lubrication of the unit.
    (d) Each compressor station gas engine that operates with pressure 
gas injection must be equipped so that stoppage of the engine 
automatically shuts off the fuel and vents the engine distribution 
manifold.
    (e) Each muffler for a gas engine in a compressor station must have 
vent slots or holes in the baffles of each compartment to prevent gas 
from being trapped in the muffler.



Sec.  192.173  Compressor stations: Ventilation.

    Each compressor station building must be ventilated to ensure that 
employees are not endangered by the accumulation of gas in rooms, sumps, 
attics, pits, or other enclosed places.

[[Page 469]]



Sec.  192.175  Pipe-type and bottle-type holders.

    (a) Each pipe-type and bottle-type holder must be designed so as to 
prevent the accumulation of liquids in the holder, in connecting pipe, 
or in auxiliary equipment, that might cause corrosion or interfere with 
the safe operation of the holder.
    (b) Each pipe-type or bottle-type holder must have minimum clearance 
from other holders in accordance with the following formula:

C = (3D*P*F)/1000) in inches; (C = (3D*P*F*)/6,895) in millimeters

in which:

C = Minimum clearance between pipe containers or bottles in inches 
          (millimeters).
D = Outside diameter of pipe containers or bottles in inches 
          (millimeters).
P = Maximum allowable operating pressure, psi (kPa) gauge.
F = Design factor as set forth in Sec.  192.111 of this part.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, 
July 13, 1998; Amdt. 192-123, 82 FR 7997, Jan. 23, 2017]



Sec.  192.177  Additional provisions for bottle-type holders.

    (a) Each bottle-type holder must be--
    (1) Located on a site entirely surrounded by fencing that prevents 
access by unauthorized persons and with minimum clearance from the fence 
as follows:

------------------------------------------------------------------------
                                                             Minimum
          Maximum allowable operating pressure            clearance feet
                                                             (meters)
------------------------------------------------------------------------
Less than 1,000 p.s.i. (7 MPa) gage....................         25 (7.6)
1,000 p.s.i. (7 MPa) gage or more......................         100 (31)
------------------------------------------------------------------------

    (2) Designed using the design factors set forth in Sec.  192.111; 
and
    (3) Buried with a minimum cover in accordance with Sec.  192.327.
    (b) Each bottle-type holder manufactured from steel that is not 
weldable under field conditions must comply with the following:
    (1) A bottle-type holder made from alloy steel must meet the 
chemical and tensile requirements for the various grades of steel in 
ASTM A372/372M (incorporated by reference, see Sec.  192.7).
    (2) The actual yield-tensile ratio of the steel may not exceed 0.85.
    (3) Welding may not be performed on the holder after it has been 
heat treated or stress relieved, except that copper wires may be 
attached to the small diameter portion of the bottle end closure for 
cathodic protection if a localized thermit welding process is used.
    (4) The holder must be given a mill hydrostatic test at a pressure 
that produces a hoop stress at least equal to 85 percent of the SMYS.
    (5) The holder, connection pipe, and components must be leak tested 
after installation as required by subpart J of this part.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, 
Jan. 21, 1988; Amdt. 192-62, 54 FR 5628, Feb. 6, 1989; 58 FR 14521, Mar. 
18, 1993; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-119, 80 FR 
181, Jan. 5, 2015]



Sec.  192.179  Transmission line valves.

    (a) Each transmission line, other than offshore segments, must have 
sectionalizing block valves spaced as follows, unless in a particular 
case the Administrator finds that alternative spacing would provide an 
equivalent level of safety:
    (1) Each point on the pipeline in a Class 4 location must be within 
2\1/2\ miles (4 kilometers)of a valve.
    (2) Each point on the pipeline in a Class 3 location must be within 
4 miles (6.4 kilometers) of a valve.
    (3) Each point on the pipeline in a Class 2 location must be within 
7\1/2\ miles (12 kilometers) of a valve.
    (4) Each point on the pipeline in a Class 1 location must be within 
10 miles (16 kilometers) of a valve.
    (b) Each sectionalizing block valve on a transmission line, other 
than offshore segments, must comply with the following:
    (1) The valve and the operating device to open or close the valve 
must be readily accessible and protected from tampering and damage.
    (2) The valve must be supported to prevent settling of the valve or 
movement of the pipe to which it is attached.
    (c) Each section of a transmission line, other than offshore 
segments, between main line valves must have a blowdown valve with 
enough capacity to allow the transmission line to be blown down as 
rapidly as practicable.

[[Page 470]]

Each blowdown discharge must be located so the gas can be blown to the 
atmosphere without hazard and, if the transmission line is adjacent to 
an overhead electric line, so that the gas is directed away from the 
electrical conductors.
    (d) Offshore segments of transmission lines must be equipped with 
valves or other components to shut off the flow of gas to an offshore 
platform in an emergency.
    (e) For onshore transmission pipeline segments with diameters 
greater than or equal to 6 inches that are constructed after April 10, 
2023, the operator must install rupture-mitigation valves (RMV) or an 
alternative equivalent technology whenever a valve must be installed to 
meet the appropriate valve spacing requirements of this section. An 
operator seeking to use alternative equivalent technology must notify 
PHMSA in accordance with the procedures set forth in paragraph (g) of 
this section. All RMVs and alternative equivalent technologies installed 
pursuant to this paragraph (e) must meet the requirements of Sec.  
192.636. The installation requirements in this paragraph (e) do not 
apply to pipe segments with a potential impact radius (PIR), as defined 
in Sec.  192.903, that is less than or equal to 150 feet in either Class 
1 or Class 2 locations. An operator may request an extension of the 
installation compliance deadline requirements of this paragraph (e) if 
it can demonstrate to PHMSA, in accordance with the notification 
procedures in Sec.  192.18, that those installation compliance deadlines 
would be economically, technically, or operationally infeasible for a 
particular new pipeline.
    (f) For entirely replaced onshore transmission pipeline segments, as 
defined in Sec.  192.3, with diameters greater than or equal to 6 inches 
and that are installed after April 10, 2023, the operator must install 
RMVs or an alternative equivalent technology whenever a valve must be 
installed to meet the appropriate valve spacing requirements of this 
section. An operator seeking to use alternative equivalent technology 
must notify PHMSA in accordance with the procedures set forth in 
paragraph (g) of this section. All RMVs and alternative equivalent 
technologies installed pursuant to this paragraph (f) must meet the 
requirements of Sec.  192.636. The requirements of this paragraph (f) 
apply when the applicable pipeline replacement project involves a valve, 
either through addition, replacement, or removal. The installation 
requirements in this paragraph (f) do not apply to pipe segments with a 
PIR, as defined in Sec.  192.903, that is less than or equal to 150 feet 
in either Class 1 or Class 2 locations. An operator may request an 
extension of the installation compliance deadline requirements of this 
paragraph (f) if it can demonstrate to PHMSA, in accordance with the 
notification procedures in Sec.  192.18, that those installation 
compliance deadlines would be economically, technically, or 
operationally infeasible for a particular pipeline replacement project.
    (g) If an operator elects to use alternative equivalent technology 
in accordance with paragraph (e) or (f) of this section, the operator 
must notify PHMSA in accordance with the procedures in Sec.  192.18. The 
operator must include a technical and safety evaluation in its notice to 
PHMSA. Valves that are installed as alternative equivalent technology 
must comply with Sec. Sec.  192.634 and 192.636. An operator requesting 
use of manual valves as an alternative equivalent technology must also 
include within the notification submitted to PHMSA a demonstration that 
installation of an RMV as otherwise required would be economically, 
technically, or operationally infeasible. An operator may use a manual 
compressor station valve at a continuously manned station as an 
alternative equivalent technology, and use of such valve would not 
require a notification to PHMSA in accordance with Sec.  192.18, but it 
must comply with Sec.  192.636.
    (h) The valve spacing requirements of paragraph (a) of this section 
do not apply to pipe replacements on a pipeline if the distance between 
each point on the pipeline and the nearest valve does not exceed:
    (1) Four (4) miles in Class 4 locations, with a total spacing 
between valves no greater than 8 miles;
    (2) Seven-and-a-half (7\1/2\) miles in Class 3 locations, with a 
total spacing

[[Page 471]]

between valves no greater than 15 miles; or
    (3) Ten (10) miles in Class 1 or 2 locations, with a total spacing 
between valves no greater than 20 miles.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34606, 
Aug. 16, 1976; Amdt. 192-78, 61 FR 28784, June 6, 1996; Amdt. 192-85, 63 
FR 37503, July 13, 1998; Amdt. 192-130, 87 FR 20982, Apr. 8, 2022; Amdt. 
192-134, 88 FR 50061, Aug. 1, 2023]



Sec.  192.181  Distribution line valves.

    (a) Each high-pressure distribution system must have valves spaced 
so as to reduce the time to shut down a section of main in an emergency. 
The valve spacing is determined by the operating pressure, the size of 
the mains, and the local physical conditions.
    (b) Each regulator station controlling the flow or pressure of gas 
in a distribution system must have a valve installed on the inlet piping 
at a distance from the regulator station sufficient to permit the 
operation of the valve during an emergency that might preclude access to 
the station.
    (c) Each valve on a main installed for operating or emergency 
purposes must comply with the following:
    (1) The valve must be placed in a readily accessible location so as 
to facilitate its operation in an emergency.
    (2) The operating stem or mechanism must be readily accessible.
    (3) If the valve is installed in a buried box or enclosure, the box 
or enclosure must be installed so as to avoid transmitting external 
loads to the main.



Sec.  192.183  Vaults: Structural design requirements.

    (a) Each underground vault or pit for valves, pressure relieving, 
pressure limiting, or pressure regulating stations, must be able to meet 
the loads which may be imposed upon it, and to protect installed 
equipment.
    (b) There must be enough working space so that all of the equipment 
required in the vault or pit can be properly installed, operated, and 
maintained.
    (c) Each pipe entering, or within, a regulator vault or pit must be 
steel for sizes 10 inch (254 millimeters), and less, except that control 
and gage piping may be copper. Where pipe extends through the vault or 
pit structure, provision must be made to prevent the passage of gases or 
liquids through the opening and to avert strains in the pipe.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, 
July 13, 1998]



Sec.  192.185  Vaults: Accessibility.

    Each vault must be located in an accessible location and, so far as 
practical, away from:
    (a) Street intersections or points where traffic is heavy or dense;
    (b) Points of minimum elevation, catch basins, or places where the 
access cover will be in the course of surface waters; and
    (c) Water, electric, steam, or other facilities.



Sec.  192.187  Vaults: Sealing, venting, and ventilation.

    Each underground vault or closed top pit containing either a 
pressure regulating or reducing station, or a pressure limiting or 
relieving station, must be sealed, vented or ventilated as follows:
    (a) When the internal volume exceeds 200 cubic feet (5.7 cubic 
meters):
    (1) The vault or pit must be ventilated with two ducts, each having 
at least the ventilating effect of a pipe 4 inches (102 millimeters) in 
diameter;
    (2) The ventilation must be enough to minimize the formation of 
combustible atmosphere in the vault or pit; and
    (3) The ducts must be high enough above grade to disperse any gas-
air mixtures that might be discharged.
    (b) When the internal volume is more than 75 cubic feet (2.1 cubic 
meters) but less than 200 cubic feet (5.7 cubic meters):
    (1) If the vault or pit is sealed, each opening must have a tight 
fitting cover without open holes through which an explosive mixture 
might be ignited, and there must be a means for testing the internal 
atmosphere before removing the cover;
    (2) If the vault or pit is vented, there must be a means of 
preventing external sources of ignition from reaching the vault 
atmosphere; or
    (3) If the vault or pit is ventilated, paragraph (a) or (c) of this 
section applies.

[[Page 472]]

    (c) If a vault or pit covered by paragraph (b) of this section is 
ventilated by openings in the covers or gratings and the ratio of the 
internal volume, in cubic feet, to the effective ventilating area of the 
cover or grating, in square feet, is less than 20 to 1, no additional 
ventilation is required.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, 
July 13, 1998]



Sec.  192.189  Vaults: Drainage and waterproofing.

    (a) Each vault must be designed so as to minimize the entrance of 
water.
    (b) A vault containing gas piping may not be connected by means of a 
drain connection to any other underground structure.
    (c) Electrical equipment in vaults must conform to the applicable 
requirements of Class 1, Group D, of the National Electrical Code, NFPA-
70 (incorporated by reference, see Sec.  192.7).

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-76, 61 FR 26122, 
May 24, 1996; Amdt. 192-119, 80 FR 181, Jan. 5, 2015]



Sec.  192.191  [Reserved]



Sec.  192.193  Valve installation in plastic pipe.

    Each valve installed in plastic pipe must be designed so as to 
protect the plastic material against excessive torsional or shearing 
loads when the valve or shutoff is operated, and from any other 
secondary stresses that might be exerted through the valve or its 
enclosure.



Sec.  192.195  Protection against accidental overpressuring.

    (a) General requirements. Except as provided in Sec.  192.197, each 
pipeline that is connected to a gas source so that the maximum allowable 
operating pressure could be exceeded as the result of pressure control 
failure or of some other type of failure, must have pressure relieving 
or pressure limiting devices that meet the requirements of Sec. Sec.  
192.199 and 192.201.
    (b) Additional requirements for distribution systems. Each 
distribution system that is supplied from a source of gas that is at a 
higher pressure than the maximum allowable operating pressure for the 
system must--
    (1) Have pressure regulation devices capable of meeting the 
pressure, load, and other service conditions that will be experienced in 
normal operation of the system, and that could be activated in the event 
of failure of some portion of the system; and
    (2) Be designed so as to prevent accidental overpressuring.



Sec.  192.197  Control of the pressure of gas delivered from high-pressure 
distribution systems.

    (a) If the maximum actual operating pressure of the distribution 
system is 60 p.s.i. (414 kPa) gage, or less and a service regulator 
having the following characteristics is used, no other pressure limiting 
device is required:
    (1) A regulator capable of reducing distribution line pressure to 
pressures recommended for household appliances.
    (2) A single port valve with proper orifice for the maximum gas 
pressure at the regulator inlet.
    (3) A valve seat made of resilient material designed to withstand 
abrasion of the gas, impurities in gas, cutting by the valve, and to 
resist permanent deformation when it is pressed against the valve port.
    (4) Pipe connections to the regulator not exceeding 2 inches (51 
millimeters) in diameter.
    (5) A regulator that, under normal operating conditions, is able to 
regulate the downstream pressure within the necessary limits of accuracy 
and to limit the build-up of pressure under no-flow conditions to 
prevent a pressure that would cause the unsafe operation of any 
connected and properly adjusted gas utilization equipment.
    (6) A self-contained service regulator with no external static or 
control lines.
    (b) If the maximum actual operating pressure of the distribution 
system is 60 p.s.i. (414 kPa) gage, or less, and a service regulator 
that does not have all of the characteristics listed in paragraph (a) of 
this section is used, or if the gas contains materials that seriously 
interfere with the operation of service regulators, there must be 
suitable protective devices to prevent unsafe overpressuring of the 
customer's appliances if the service regulator fails.

[[Page 473]]

    (c) If the maximum actual operating pressure of the distribution 
system exceeds 60 p.s.i. (414 kPa) gage, one of the following methods 
must be used to regulate and limit, to the maximum safe value, the 
pressure of gas delivered to the customer:
    (1) A service regulator having the characteristics listed in 
paragraph (a) of this section, and another regulator located upstream 
from the service regulator. The upstream regulator may not be set to 
maintain a pressure higher than 60 p.s.i. (414 kPa) gage. A device must 
be installed between the upstream regulator and the service regulator to 
limit the pressure on the inlet of the service regulator to 60 p.s.i. 
(414 kPa) gage or less in case the upstream regulator fails to function 
properly. This device may be either a relief valve or an automatic 
shutoff that shuts, if the pressure on the inlet of the service 
regulator exceeds the set pressure (60 p.s.i. (414 kPa) gage or less), 
and remains closed until manually reset.
    (2) A service regulator and a monitoring regulator set to limit, to 
a maximum safe value, the pressure of the gas delivered to the customer.
    (3) A service regulator with a relief valve vented to the outside 
atmosphere, with the relief valve set to open so that the pressure of 
gas going to the customer does not exceed a maximum safe value. The 
relief valve may either be built into the service regulator or it may be 
a separate unit installed downstream from the service regulator. This 
combination may be used alone only in those cases where the inlet 
pressure on the service regulator does not exceed the manufacturer's 
safe working pressure rating of the service regulator, and may not be 
used where the inlet pressure on the service regulator exceeds 125 
p.s.i. (862 kPa) gage. For higher inlet pressures, the methods in 
paragraph (c) (1) or (2) of this section must be used.
    (4) A service regulator and an automatic shutoff device that closes 
upon a rise in pressure downstream from the regulator and remains closed 
until manually reset.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-1, 35 FR 17660, 
Nov. 7, 1970; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-93, 68 
FR 53900, Sept. 15, 2003]



Sec.  192.199  Requirements for design of pressure relief and limiting 
devices.

    Except for rupture discs, each pressure relief or pressure limiting 
device must:
    (a) Be constructed of materials such that the operation of the 
device will not be impaired by corrosion;
    (b) Have valves and valve seats that are designed not to stick in a 
position that will make the device inoperative;
    (c) Be designed and installed so that it can be readily operated to 
determine if the valve is free, can be tested to determine the pressure 
at which it will operate, and can be tested for leakage when in the 
closed position;
    (d) Have support made of noncombustible material;
    (e) Have discharge stacks, vents, or outlet ports designed to 
prevent accumulation of water, ice, or snow, located where gas can be 
discharged into the atmosphere without undue hazard;
    (f) Be designed and installed so that the size of the openings, 
pipe, and fittings located between the system to be protected and the 
pressure relieving device, and the size of the vent line, are adequate 
to prevent hammering of the valve and to prevent impairment of relief 
capacity;
    (g) Where installed at a district regulator station to protect a 
pipeline system from overpressuring, be designed and installed to 
prevent any single incident such as an explosion in a vault or damage by 
a vehicle from affecting the operation of both the overpressure 
protective device and the district regulator; and
    (h) Except for a valve that will isolate the system under protection 
from its source of pressure, be designed to prevent unauthorized 
operation of any stop valve that will make the pressure relief valve or 
pressure limiting device inoperative.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-1, 35 FR 17660, 
Nov. 17, 1970]



Sec.  192.201  Required capacity of pressure relieving and limiting 
stations.

    (a) Each pressure relief station or pressure limiting station or 
group of those stations installed to protect a pipeline must have enough 
capacity, and must be set to operate, to insure the following:

[[Page 474]]

    (1) In a low pressure distribution system, the pressure may not 
cause the unsafe operation of any connected and properly adjusted gas 
utilization equipment.
    (2) In pipelines other than a low pressure distribution system:
    (i) If the maximum allowable operating pressure is 60 p.s.i. (414 
kPa) gage or more, the pressure may not exceed the maximum allowable 
operating pressure plus 10 percent, or the pressure that produces a hoop 
stress of 75 percent of SMYS, whichever is lower;
    (ii) If the maximum allowable operating pressure is 12 p.s.i. (83 
kPa) gage or more, but less than 60 p.s.i. (414 kPa) gage, the pressure 
may not exceed the maximum allowable operating pressure plus 6 p.s.i. 
(41 kPa) gage; or
    (iii) If the maximum allowable operating pressure is less than 12 
p.s.i. (83 kPa) gage, the pressure may not exceed the maximum allowable 
operating pressure plus 50 percent.
    (b) When more than one pressure regulating or compressor station 
feeds into a pipeline, relief valves or other protective devices must be 
installed at each station to ensure that the complete failure of the 
largest capacity regulator or compressor, or any single run of lesser 
capacity regulators or compressors in that station, will not impose 
pressures on any part of the pipeline or distribution system in excess 
of those for which it was designed, or against which it was protected, 
whichever is lower.
    (c) Relief valves or other pressure limiting devices must be 
installed at or near each regulator station in a low-pressure 
distribution system, with a capacity to limit the maximum pressure in 
the main to a pressure that will not exceed the safe operating pressure 
for any connected and properly adjusted gas utilization equipment.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-9, 37 FR 20827, 
Oct. 4, 1972; Amdt. 192-85, 63 FR 37503, July 13, 1998]



Sec.  192.203  Instrument, control, and sampling pipe and components.

    (a) Applicability. This section applies to the design of instrument, 
control, and sampling pipe and components. It does not apply to 
permanently closed systems, such as fluid-filled temperature-responsive 
devices.
    (b) Materials and design. All materials employed for pipe and 
components must be designed to meet the particular conditions of service 
and the following:
    (1) Each takeoff connection and attaching boss, fitting, or adapter 
must be made of suitable material, be able to withstand the maximum 
service pressure and temperature of the pipe or equipment to which it is 
attached, and be designed to satisfactorily withstand all stresses 
without failure by fatigue.
    (2) Except for takeoff lines that can be isolated from sources of 
pressure by other valving, a shutoff valve must be installed in each 
takeoff line as near as practicable to the point of takeoff. Blowdown 
valves must be installed where necessary.
    (3) Brass or copper material may not be used for metal temperatures 
greater than 400 [deg]F (204 [deg]C).
    (4) Pipe or components that may contain liquids must be protected by 
heating or other means from damage due to freezing.
    (5) Pipe or components in which liquids may accumulate must have 
drains or drips.
    (6) Pipe or components subject to clogging from solids or deposits 
must have suitable connections for cleaning.
    (7) The arrangement of pipe, components, and supports must provide 
safety under anticipated operating stresses.
    (8) Each joint between sections of pipe, and between pipe and valves 
or fittings, must be made in a manner suitable for the anticipated 
pressure and temperature condition. Slip type expansion joints may not 
be used. Expansion must be allowed for by providing flexibility within 
the system itself.
    (9) Each control line must be protected from anticipated causes of 
damage and must be designed and installed to prevent damage to any one 
control line from making both the regulator and the over-pressure 
protective device inoperative.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR 28784, 
June 6, 1996; Amdt. 192-85, 63 FR 37503, July 13, 1998]

[[Page 475]]



Sec.  192.204  Risers installed after January 22, 2019.

    (a) Riser designs must be tested to ensure safe performance under 
anticipated external and internal loads acting on the assembly.
    (b) Factory assembled anodeless risers must be designed and tested 
in accordance with ASTM F1973-13 (incorporated by reference, see Sec.  
192.7).
    (c) All risers used to connect regulator stations to plastic mains 
must be rigid and designed to provide adequate support and resist 
lateral movement. Anodeless risers used in accordance with this 
paragraph must have a rigid riser casing.

[Amdt. 192-124, 83 FR 58718, Nov. 20, 2018]



Sec.  192.205  Records: Pipeline components.

    (a) For steel transmission pipelines installed after July 1, 2020, 
an operator must collect or make, and retain for the life of the 
pipeline, records documenting the manufacturing standard and pressure 
rating to which each valve was manufactured and tested in accordance 
with this subpart. Flanges, fittings, branch connections, extruded 
outlets, anchor forgings, and other components with material yield 
strength grades of 42,000 psi (X42) or greater and with nominal 
diameters of greater than 2 inches must have records documenting the 
manufacturing specification in effect at the time of manufacture, 
including yield strength, ultimate tensile strength, and chemical 
composition of materials.
    (b) For steel transmission pipelines installed on or before July 1, 
2020, if operators have records documenting the manufacturing standard 
and pressure rating for valves, flanges, fittings, branch connections, 
extruded outlets, anchor forgings, and other components with material 
yield strength grades of 42,000 psi (X42) or greater and with nominal 
diameters of greater than 2 inches, operators must retain such records 
for the life of the pipeline.
    (c) For steel transmission pipeline segments installed on or before 
July 1, 2020, if an operator does not have records necessary to 
establish the MAOP of a pipeline segment, the operator may be subject to 
the requirements of Sec.  192.624 according to the terms of that 
section.

[Amdt. 192-125, 84 FR 52245, Oct. 1, 2019]



                 Subpart E_Welding of Steel in Pipelines



Sec.  192.221  Scope.

    (a) This subpart prescribes minimum requirements for welding steel 
materials in pipelines.
    (b) This subpart does not apply to welding that occurs during the 
manufacture of steel pipe or steel pipeline components.



Sec.  192.225  Welding procedures.

    (a) Welding must be performed by a qualified welder or welding 
operator in accordance with welding procedures qualified under section 
5, section 12, Appendix A or Appendix B of API Std 1104 (incorporated by 
reference, see Sec.  192.7), or section IX of the ASME Boiler and 
Pressure Vessel Code (ASME BPVC) (incorporated by reference, see Sec.  
192.7) to produce welds meeting the requirements of this subpart. The 
quality of the test welds used to qualify welding procedures must be 
determined by destructive testing in accordance with the applicable 
welding standard(s).
    (b) Each welding procedure must be recorded in detail, including the 
results of the qualifying tests. This record must be retained and 
followed whenever the procedure is used.

[Amdt. 192-52, 51 FR 20297, June 4, 1986; Amdt. 192-94, 69 FR 32894, 
June 14, 2004; Amdt. 192-119, 80 FR 181, Jan. 5, 2015; Amdt. 192-120, 80 
FR 12778, Mar. 11, 2015; Amdt. 192-123, 82 FR 7997, Jan. 23, 2017]



Sec.  192.227  Qualification of welders and welding operators.

    (a) Except as provided in paragraph (b) of this section, each welder 
or welding operator must be qualified in accordance with section 6, 
section 12, Appendix A or Appendix B of API Std 1104 (incorporated by 
reference, see Sec.  192.7), or section IX of the ASME Boiler and 
Pressure Vessel Code (ASME BPVC) (incorporated by reference, see Sec.  
192.7). However, a welder or welding operator qualified under an earlier 
edition than the listed in Sec.  192.7 of this part may

[[Page 476]]

weld but may not requalify under that earlier edition.
    (b) A welder may qualify to perform welding on pipe to be operated 
at a pressure that produces a hoop stress of less than 20 percent of 
SMYS by performing an acceptable test weld, for the process to be used, 
under the test set forth in section I of Appendix C of this part. Each 
welder who is to make a welded service line connection to a main must 
first perform an acceptable test weld under section II of Appendix C of 
this part as a requirement of the qualifying test.
    (c) For steel transmission pipe installed after July 1, 2021, 
records demonstrating each individual welder qualification at the time 
of construction in accordance with this section must be retained for a 
minimum of 5 years following construction.

[Amdt. 192-120, 80 FR 12778, Mar. 11, 2015, as amended by Amdt. 192-123, 
82 FR 7997, Jan. 23, 2017; Amdt. 192-125, 84 FR 52245, Oct. 1, 2019]



Sec.  192.229  Limitations on welders and welding operators.

    (a) No welder or welding operator whose qualification is based on 
nondestructive testing may weld compressor station pipe and components.
    (b) A welder or welding operator may not weld with a particular 
welding process unless, within the preceding 6 calendar months, the 
welder or welding operator was engaged in welding with that process. 
Alternatively, welders or welding operators may demonstrate they have 
engaged in a specific welding process if they have performed a weld with 
that process that was tested and found acceptable under section 6, 9, 
12, or Appendix A of API Std 1104 (incorporated by reference, see Sec.  
192.7) within the preceding 7\1/2\ months.
    (c) A welder or welding operator qualified under Sec.  192.227(a)--
    (1) May not weld on pipe to be operated at a pressure that produces 
a hoop stress of 20 percent or more of SMYS unless within the preceding 
6 calendar months the welder or welding operator has had one weld tested 
and found acceptable under either section 6, section 9, section 12 or 
Appendix A of API Std 1104 (incorporated by reference, see Sec.  192.7). 
Alternatively, welders or welding operators may maintain an ongoing 
qualification status by performing welds tested and found acceptable 
under the above acceptance criteria at least twice each calendar year, 
but at intervals not exceeding 7\1/2\ months. A welder or welding 
operator qualified under an earlier edition of a standard listed in 
Sec.  192.7 of this part may weld, but may not re-qualify under that 
earlier edition; and,
    (2) May not weld on pipe to be operated at a pressure that produces 
a hoop stress of less than 20 percent of SMYS unless the welder or 
welding operator is tested in accordance with paragraph (c)(1) of this 
section or re-qualifies under paragraph (d)(1) or (d)(2) of this 
section.
    (d) A welder or welding operator qualified under Sec.  192.227(b) 
may not weld unless--
    (1) Within the preceding 15 calendar months, but at least once each 
calendar year, the welder or welding operator has re-qualified under 
Sec.  192.227(b); or
    (2) Within the preceding 7\1/2\ calendar months, but at least twice 
each calendar year, the welder or welding operator has had--
    (i) A production weld cut out, tested, and found acceptable in 
accordance with the qualifying test; or
    (ii) For a welder who works only on service lines 2 inches (51 
millimeters) or smaller in diameter, the welder has had two sample welds 
tested and found acceptable in accordance with the test in section III 
of Appendix C of this part.

[Amdt. 192-120, 80 FR 12778, Mar. 11, 2015, as amended at 86 FR 2240, 
Jan. 11, 2021]



Sec.  192.231  Protection from weather.

    The welding operation must be protected from weather conditions that 
would impair the quality of the completed weld.



Sec.  192.233  Miter joints.

    (a) A miter joint on steel pipe to be operated at a pressure that 
produces a hoop stress of 30 percent or more of SMYS may not deflect the 
pipe more than 3[deg].
    (b) A miter joint on steel pipe to be operated at a pressure that 
produces a hoop stress of less than 30 percent, but

[[Page 477]]

more than 10 percent, of SMYS may not deflect the pipe more than 12\1/
2\[deg] and must be a distance equal to one pipe diameter or more away 
from any other miter joint, as measured from the crotch of each joint.
    (c) A miter joint on steel pipe to be operated at a pressure that 
produces a hoop stress of 10 percent or less of SMYS may not deflect the 
pipe more than 90[deg].



Sec.  192.235  Preparation for welding.

    Before beginning any welding, the welding surfaces must be clean and 
free of any material that may be detrimental to the weld, and the pipe 
or component must be aligned to provide the most favorable condition for 
depositing the root bead. This alignment must be preserved while the 
root bead is being deposited.



Sec.  192.241  Inspection and test of welds.

    (a) Visual inspection of welding must be conducted by an individual 
qualified by appropriate training and experience to ensure that:
    (1) The welding is performed in accordance with the welding 
procedure; and
    (2) The weld is acceptable under paragraph (c) of this section.
    (b) The welds on a pipeline to be operated at a pressure that 
produces a hoop stress of 20 percent or more of SMYS must be 
nondestructively tested in accordance with Sec.  192.243, except that 
welds that are visually inspected and approved by a qualified welding 
inspector need not be nondestructively tested if:
    (1) The pipe has a nominal diameter of less than 6 inches (152 
millimeters); or
    (2) The pipeline is to be operated at a pressure that produces a 
hoop stress of less than 40 percent of SMYS and the welds are so limited 
in number that nondestructive testing is impractical.
    (c) The acceptability of a weld that is nondestructively tested or 
visually inspected is determined according to the standards in section 9 
or Appendix A of API Std 1104 (incorporated by reference, see Sec.  
192.7). Appendix A of API Std 1104 may not be used to accept cracks.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-37, 46 FR 10160, 
Feb. 2, 1981; Amdt. 192-78, 61 FR 28784, June 6, 1996; Amdt. 192-85, 63 
FR 37503, July 13, 1998; Amdt. 192-94, 69 FR 32894, June 14, 2004; Amdt. 
192-119, 80 FR 181, Jan. 5, 2015; Amdt. 192-120, 80 FR 12778, Mar. 11, 
2015]



Sec.  192.243  Nondestructive testing.

    (a) Nondestructive testing of welds must be performed by any 
process, other than trepanning, that will clearly indicate defects that 
may affect the integrity of the weld.
    (b) Nondestructive testing of welds must be performed:
    (1) In accordance with written procedures; and
    (2) By persons who have been trained and qualified in the 
established procedures and with the equipment employed in testing.
    (c) Procedures must be established for the proper interpretation of 
each nondestructive test of a weld to ensure the acceptability of the 
weld under Sec.  192.241(c).
    (d) When nondestructive testing is required under Sec.  192.241(b), 
the following percentages of each day's field butt welds, selected at 
random by the operator, must be nondestructively tested over their 
entire circumference:
    (1) In Class 1 locations, except offshore, at least 10 percent.
    (2) In Class 2 locations, at least 15 percent.
    (3) In Class 3 and Class 4 locations, at crossings of major or 
navigable rivers, offshore, and within railroad or public highway 
rights-of-way, including tunnels, bridges, and overhead road crossings, 
100 percent unless impracticable, in which case at least 90 percent. 
Nondestructive testing must be impracticable for each girth weld not 
tested.
    (4) At pipeline tie-ins, including tie-ins of replacement sections, 
100 percent.
    (e) Except for a welder or welding operator whose work is isolated 
from the principal welding activity, a sample of each welder or welding 
operator's work for each day must be nondestructively tested, when 
nondestructive testing is required under Sec.  192.241(b).

[[Page 478]]

    (f) When nondestructive testing is required under Sec.  192.241(b), 
each operator must retain, for the life of the pipeline, a record 
showing by milepost, engineering station, or by geographic feature, the 
number of girth welds made, the number nondestructively tested, the 
number rejected, and the disposition of the rejects.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34606, 
Aug. 16, 1976; Amdt. 192-50, 50 FR 37192, Sept. 12, 1985; Amdt. 192-78, 
61 FR 28784, June 6, 1996; Amdt. 192-120, 80 FR 12779, Mar. 11, 2015]



Sec.  192.245  Repair or removal of defects.

    (a) Each weld that is unacceptable under Sec.  192.241(c) must be 
removed or repaired. Except for welds on an offshore pipeline being 
installed from a pipeline vessel, a weld must be removed if it has a 
crack that is more than 8 percent of the weld length.
    (b) Each weld that is repaired must have the defect removed down to 
sound metal and the segment to be repaired must be preheated if 
conditions exist which would adversely affect the quality of the weld 
repair. After repair, the segment of the weld that was repaired must be 
inspected to ensure its acceptability.
    (c) Repair of a crack, or of any defect in a previously repaired 
area must be in accordance with written weld repair procedures that have 
been qualified under Sec.  192.225. Repair procedures must provide that 
the minimum mechanical properties specified for the welding procedure 
used to make the original weld are met upon completion of the final weld 
repair.

[Amdt. 192-46, 48 FR 48674, Oct. 20, 1983]



          Subpart F_Joining of Materials Other Than by Welding



Sec.  192.271  Scope.

    (a) This subpart prescribes minimum requirements for joining 
materials in pipelines, other than by welding.
    (b) This subpart does not apply to joining during the manufacture of 
pipe or pipeline components.



Sec.  192.273  General.

    (a) The pipeline must be designed and installed so that each joint 
will sustain the longitudinal pullout or thrust forces caused by 
contraction or expansion of the piping or by anticipated external or 
internal loading.
    (b) Each joint must be made in accordance with written procedures 
that have been proven by test or experience to produce strong gastight 
joints.
    (c) Each joint must be inspected to insure compliance with this 
subpart.



Sec.  192.275  Cast iron pipe.

    (a) Each caulked bell and spigot joint in cast iron pipe must be 
sealed with mechanical leak clamps.
    (b) Each mechanical joint in cast iron pipe must have a gasket made 
of a resilient material as the sealing medium. Each gasket must be 
suitably confined and retained under compression by a separate gland or 
follower ring.
    (c) Cast iron pipe may not be joined by threaded joints.
    (d) Cast iron pipe may not be joined by brazing.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5628, 
Feb. 6, 1989]



Sec.  192.277  Ductile iron pipe.

    (a) Ductile iron pipe may not be joined by threaded joints.
    (b) Ductile iron pipe may not be joined by brazing.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5628, 
Feb. 6, 1989]



Sec.  192.279  Copper pipe.

    Copper pipe may not be threaded except that copper pipe used for 
joining screw fittings or valves may be threaded if the wall thickness 
is equivalent to the comparable size of Schedule 40 or heavier wall pipe 
listed in Table C1 of ASME/ANSI B16.5.

[Amdt. 192-62, 54 FR 5628, Feb. 6, 1989, as amended at 58 FR 14521, Mar. 
18, 1993]



Sec.  192.281  Plastic pipe.

    (a) General. A plastic pipe joint that is joined by solvent cement, 
adhesive, or heat fusion may not be disturbed until it has properly set. 
Plastic pipe may not be joined by a threaded joint or miter joint.
    (b) Solvent cement joints. Each solvent cement joint on plastic pipe 
must comply with the following:

[[Page 479]]

    (1) The mating surfaces of the joint must be clean, dry, and free of 
material which might be detrimental to the joint.
    (2) The solvent cement must conform to ASTM D2564-12 for PVC 
(incorporated by reference, see Sec.  192.7).
    (3) The joint may not be heated or cooled to accelerate the setting 
of the cement.
    (c) Heat-fusion joints. Each heat fusion joint on a PE pipe or 
component, except for electrofusion joints, must comply with ASTM F2620 
(incorporated by reference in Sec.  192.7), or an alternative written 
procedure that has been demonstrated to provide an equivalent or 
superior level of safety and has been proven by test or experience to 
produce strong gastight joints, and the following:
    (1) A butt heat-fusion joint must be joined by a device that holds 
the heater element square to the ends of the pipe or component, 
compresses the heated ends together, and holds the pipe in proper 
alignment in accordance with the appropriate procedure qualified under 
Sec.  192.283.
    (2) A socket heat-fusion joint must be joined by a device that heats 
the mating surfaces of the pipe or component, uniformly and 
simultaneously, to establish the same temperature. The device used must 
be the same device specified in the operator's joining procedure for 
socket fusion.
    (3) An electrofusion joint must be made using the equipment and 
techniques prescribed by the fitting manufacturer, or using equipment 
and techniques shown, by testing joints to the requirements of Sec.  
192.283(a)(1)(iii), to be equivalent to or better than the requirements 
of the fitting manufacturer.
    (4) Heat may not be applied with a torch or other open flame.
    (d) Adhesive joints. Each adhesive joint on plastic pipe must comply 
with the following:
    (1) The adhesive must conform to ASTM D 2517 (incorporated by 
reference, see Sec.  192.7).
    (2) The materials and adhesive must be compatible with each other.
    (e) Mechanical joints. Each compression type mechanical joint on 
plastic pipe must comply with the following:
    (1) The gasket material in the coupling must be compatible with the 
plastic.
    (2) A rigid internal tubular stiffener, other than a split tubular 
stiffener, must be used in conjunction with the coupling.
    (3) All mechanical fittings must meet a listed specification based 
upon the applicable material.
    (4) All mechanical joints or fittings installed after January 22, 
2019, must be Category 1 as defined by a listed specification for the 
applicable material, providing a seal plus resistance to a force on the 
pipe joint equal to or greater than that which will cause no less than 
25% elongation of pipe, or the pipe fails outside the joint area if 
tested in accordance with the applicable standard.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-34, 44 FR 42973, 
July 23, 1979; Amdt. 192-58, 53 FR 1635, Jan. 21, 1988; Amdt. 192-61, 53 
FR 36793, Sept. 22, 1988; 58 FR 14521, Mar. 18, 1993; Amdt. 192-78, 61 
FR 28784, June 6, 1996; Amdt. 192-114, 75 FR 48603, Aug. 11, 2010; Amdt. 
192-119, 80 FR 181, Jan. 5, 2015; Amdt. 192-124, 83 FR 58718, Nov. 20, 
2018; 86 FR 2240, Jan. 11, 2021]



Sec.  192.283  Plastic pipe: Qualifying joining procedures.

    (a) Heat fusion, solvent cement, and adhesive joints. Before any 
written procedure established under Sec.  192.273(b) is used for making 
plastic pipe joints by a heat fusion, solvent cement, or adhesive 
method, the procedure must be qualified by subjecting specimen joints 
that are made according to the procedure to the following tests, as 
applicable:
    (1) The test requirements of--
    (i) In the case of thermoplastic pipe, based on the pipe material, 
the Sustained Pressure Test or the Minimum Hydrostatic Burst Test per 
the listed specification requirements. Additionally, for electrofusion 
joints, based on the pipe material, the Tensile Strength Test or the 
Joint Integrity Test per the listed specification.
    (ii) In the case of thermosetting plastic pipe, paragraph 8.5 
(Minimum Hydrostatic Burst Pressure) or paragraph 8.9 (Sustained Static 
Pressure Test) of ASTM D2517- 00 (incorporated by reference, see Sec.  
192.7).

[[Page 480]]

    (iii) In the case of electrofusion fittings for polyethylene (PE) 
pipe and tubing, paragraph 9.1 (Minimum Hydraulic Burst Pressure Test), 
paragraph 9.2 (Sustained Pressure Test), paragraph 9.3 (Tensile Strength 
Test), or paragraph 9.4 (Joint Integrity Tests) of ASTM F1055-98(2006) 
(incorporated by reference, see Sec.  192.7).
    (2) For procedures intended for lateral pipe connections, subject a 
specimen joint made from pipe sections joined at right angles according 
to the procedure to a force on the lateral pipe until failure occurs in 
the specimen. If failure initiates outside the joint area, the procedure 
qualifies for use.
    (3) For procedures intended for non-lateral pipe connections, 
perform tensile testing in accordance with a listed specification. If 
the test specimen elongates no less than 25% or failure initiates 
outside the joint area, the procedure qualifies for use.
    (b) Mechanical joints. Before any written procedure established 
under Sec.  192.273(b) is used for making mechanical plastic pipe 
joints, the procedure must be qualified in accordance with a listed 
specification based upon the pipe material.
    (c) A copy of each written procedure being used for joining plastic 
pipe must be available to the persons making and inspecting joints.

[Amdt. 192-124, 83 FR 58718, Nov. 20, 2018, as amended at 86 FR 2240, 
Jan. 11, 2021]



Sec.  192.285  Plastic pipe: Qualifying persons to make joints.

    (a) No person may make a plastic pipe joint unless that person has 
been qualified under the applicable joining procedure by:
    (1) Appropriate training or experience in the use of the procedure; 
and
    (2) Making a specimen joint from pipe sections joined according to 
the procedure that passes the inspection and test set forth in paragraph 
(b) of this section.
    (b) The specimen joint must be:
    (1) Visually examined during and after assembly or joining and found 
to have the same appearance as a joint or photographs of a joint that is 
acceptable under the procedure; and
    (2) In the case of a heat fusion, solvent cement, or adhesive joint:
    (i) Tested under any one of the test methods listed under Sec.  
192.283(a), and for PE heat fusion joints (except for electrofusion 
joints) visually inspected in accordance with ASTM F2620 (incorporated 
by reference, see Sec.  192.7), or a written procedure that has been 
demonstrated to provide an equivalent or superior level of safety, 
applicable to the type of joint and material being tested;
    (ii) Examined by ultrasonic inspection and found not to contain 
flaws that would cause failure; or
    (iii) Cut into at least 3 longitudinal straps, each of which is:
    (A) Visually examined and found not to contain voids or 
discontinuities on the cut surfaces of the joint area; and
    (B) Deformed by bending, torque, or impact, and if failure occurs, 
it must not initiate in the joint area.
    (c) A person must be re-qualified under an applicable procedure once 
each calendar year at intervals not exceeding 15 months, or after any 
production joint is found unacceptable by testing under Sec.  192.513.
    (d) Each operator shall establish a method to determine that each 
person making joints in plastic pipelines in the operator's system is 
qualified in accordance with this section.
    (e) For transmission pipe installed after July 1, 2021, records 
demonstrating each person's plastic pipe joining qualifications at the 
time of construction in accordance with this section must be retained 
for a minimum of 5 years following construction.

[Amdt. 192-34A, 45 FR 9935, Feb. 14, 1980, as amended by Amdt. 192-34B, 
46 FR 39, Jan. 2, 1981; Amdt. 192-93, 68 FR 53900, Sept. 15, 2003; Amdt. 
192-120, 80 FR 12779, Mar. 11, 2015; Amdt. 192-124, 83 FR 58718, Nov. 
20, 2018; Amdt. 192-125, 84 FR 52245, Oct. 1, 2019; 86 FR 2240, Jan. 11, 
2021]



Sec.  192.287  Plastic pipe: Inspection of joints.

    No person may carry out the inspection of joints in plastic pipes 
required by Sec. Sec.  192.273(c) and 192.285(b) unless that person has 
been qualified by appropriate training or experience in evaluating the 
acceptability of plastic pipe

[[Page 481]]

joints made under the applicable joining procedure.

[Amdt. 192-34, 44 FR 42974, July 23, 1979]



 Subpart G_General Construction Requirements for Transmission Lines and 
                                  Mains



Sec.  192.301  Scope.

    This subpart prescribes minimum requirements for constructing 
transmission lines and mains.



Sec.  192.303  Compliance with specifications or standards.

    Each transmission line or main must be constructed in accordance 
with comprehensive written specifications or standards that are 
consistent with this part.



Sec.  192.305  Inspection: General.

    Each transmission line or main must be inspected to ensure that it 
is constructed in accordance with this part.

    Effective Date Note: At 80 FR 12779, Mar. 11, 2015, Sec.  192.305 
was revised, effective Oct. 1, 2015. At 80 FR 58633, Sept. 30, 2015, 
this amendment was delayed indefinitely. For the convenience of the 
user, the revised text is set forth as follows:



Sec.  192.305  Inspection: General.

    Each transmission line and main must be inspected to ensure that it 
is constructed in accordance with this subpart. An operator must not use 
operator personnel to perform a required inspection if the operator 
personnel performed the construction task requiring inspection. Nothing 
in this section prohibits the operator from inspecting construction 
tasks with operator personnel who are involved in other construction 
tasks.



Sec.  192.307  Inspection of materials.

    Each length of pipe and each other component must be visually 
inspected at the site of installation to ensure that it has not 
sustained any visually determinable damage that could impair its 
serviceability.



Sec.  192.309  Repair of steel pipe.

    (a) Each imperfection or damage that impairs the serviceability of a 
length of steel pipe must be repaired or removed. If a repair is made by 
grinding, the remaining wall thickness must at least be equal to either:
    (1) The minimum thickness required by the tolerances in the 
specification to which the pipe was manufactured; or
    (2) The nominal wall thickness required for the design pressure of 
the pipeline.
    (b) Each of the following dents must be removed from steel pipe to 
be operated at a pressure that produces a hoop stress of 20 percent, or 
more, of SMYS, unless the dent is repaired by a method that reliable 
engineering tests and analyses show can permanently restore the 
serviceability of the pipe:
    (1) A dent that contains a stress concentrator such as a scratch, 
gouge, groove, or arc burn.
    (2) A dent that affects the longitudinal weld or a circumferential 
weld.
    (3) In pipe to be operated at a pressure that produces a hoop stress 
of 40 percent or more of SMYS, a dent that has a depth of:
    (i) More than \1/4\ inch (6.4 millimeters) in pipe 12\3/4\ inches 
(324 millimeters) or less in outer diameter; or
    (ii) More than 2 percent of the nominal pipe diameter in pipe over 
12\3/4\ inches (324 millimeters) in outer diameter.

For the purpose of this section a ``dent'' is a depression that produces 
a gross disturbance in the curvature of the pipe wall without reducing 
the pipe-wall thickness. The depth of a dent is measured as the gap 
between the lowest point of the dent and a prolongation of the original 
contour of the pipe.
    (c) Each arc burn on steel pipe to be operated at a pressure that 
produces a hoop stress of 40 percent, or more, of SMYS must be repaired 
or removed. If a repair is made by grinding, the arc burn must be 
completely removed and the remaining wall thickness must be at least 
equal to either:
    (1) The minimum wall thickness required by the tolerances in the 
specification to which the pipe was manufactured; or
    (2) The nominal wall thickness required for the design pressure of 
the pipeline.
    (d) A gouge, groove, arc burn, or dent may not be repaired by insert 
patching or by pounding out.
    (e) Each gouge, groove, arc burn, or dent that is removed from a 
length of

[[Page 482]]

pipe must be removed by cutting out the damaged portion as a cylinder.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-1, 35 FR 17660, 
Nov. 17, 1970; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-88, 
64 FR 69664, Dec. 14, 1999]



Sec.  192.311  Repair of plastic pipe.

    Each imperfection or damage that would impair the serviceability of 
plastic pipe must be repaired or removed.

[Amdt. 192-93, 68 FR 53900, Sept. 15, 2003]



Sec.  192.313  Bends and elbows.

    (a) Each field bend in steel pipe, other than a wrinkle bend made in 
accordance with Sec.  192.315, must comply with the following:
    (1) A bend must not impair the serviceability of the pipe.
    (2) Each bend must have a smooth contour and be free from buckling, 
cracks, or any other mechanical damage.
    (3) On pipe containing a longitudinal weld, the longitudinal weld 
must be as near as practicable to the neutral axis of the bend unless:
    (i) The bend is made with an internal bending mandrel; or
    (ii) The pipe is 12 inches (305 millimeters) or less in outside 
diameter or has a diameter to wall thickness ratio less than 70.
    (b) Each circumferential weld of steel pipe which is located where 
the stress during bending causes a permanent deformation in the pipe 
must be nondestructively tested either before or after the bending 
process.
    (c) Wrought-steel welding elbows and transverse segments of these 
elbows may not be used for changes in direction on steel pipe that is 2 
inches (51 millimeters) or more in diameter unless the arc length, as 
measured along the crotch, is at least 1 inch (25 millimeters).
    (d) An operator may not install plastic pipe with a bend radius that 
is less than the minimum bend radius specified by the manufacturer for 
the diameter of the pipe being installed.

[Amdt. 192-26, 41 FR 26018, June 24, 1976, as amended by Amdt. 192-29, 
42 FR 42866, Aug. 25, 1977; Amdt. 192-29, 42 FR 60148, Nov. 25, 1977; 
Amdt. 192-49, 50 FR 13225, Apr. 3, 1985; Amdt. 192-85, 63 FR 37503, July 
13, 1998; Amdt. 192-124, 83 FR 58718, Nov. 20, 2018]



Sec.  192.315  Wrinkle bends in steel pipe.

    (a) A wrinkle bend may not be made on steel pipe to be operated at a 
pressure that produces a hoop stress of 30 percent, or more, of SMYS.
    (b) Each wrinkle bend on steel pipe must comply with the following:
    (1) The bend must not have any sharp kinks.
    (2) When measured along the crotch of the bend, the wrinkles must be 
a distance of at least one pipe diameter.
    (3) On pipe 16 inches (406 millimeters) or larger in diameter, the 
bend may not have a deflection of more than 1\1/2\[deg] for each 
wrinkle.
    (4) On pipe containing a longitudinal weld the longitudinal seam 
must be as near as practicable to the neutral axis of the bend.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, 
July 13, 1998]



Sec.  192.317  Protection from hazards.

    (a) The operator must take all practicable steps to protect each 
transmission line or main from washouts, floods, unstable soil, 
landslides, or other hazards that may cause the pipeline to move or to 
sustain abnormal loads. In addition, the operator must take all 
practicable steps to protect offshore pipelines from damage by mud 
slides, water currents, hurricanes, ship anchors, and fishing 
operations.
    (b) Each aboveground transmission line or main, not located offshore 
or in inland navigable water areas, must be protected from accidental 
damage by vehicular traffic or other similar causes, either by being 
placed at a safe distance from the traffic or by installing barricades.
    (c) Pipelines, including pipe risers, on each platform located 
offshore or in inland navigable waters must be protected from accidental 
damage by vessels.

[Amdt. 192-27, 41 FR 34606, Aug. 16, 1976, as amended by Amdt. 192-78, 
61 FR 28784, June 6, 1996]



Sec.  192.319  Installation of pipe in a ditch.

    (a) When installed in a ditch, each transmission line that is to be 
operated at a pressure producing a hoop stress of 20 percent or more of 
SMYS must be

[[Page 483]]

installed so that the pipe fits the ditch so as to minimize stresses and 
protect the pipe coating from damage.
    (b) When a ditch for a transmission line or main is backfilled, it 
must be backfilled in a manner that:
    (1) Provides firm support under the pipe; and
    (2) Prevents damage to the pipe and pipe coating from equipment or 
from the backfill material.
    (c) All offshore pipe in water at least 12 feet (3.7 meters) deep 
but not more than 200 feet (61 meters) deep, as measured from the mean 
low tide, except pipe in the Gulf of Mexico and its inlets under 15 feet 
(4.6 meters) of water, must be installed so that the top of the pipe is 
below the natural bottom unless the pipe is supported by stanchions, 
held in place by anchors or heavy concrete coating, or protected by an 
equivalent means. Pipe in the Gulf of Mexico and its inlets under 15 
feet (4.6 meters) of water must be installed so that the top of the pipe 
is 36 inches (914 millimeters) below the seabed for normal excavation or 
18 inches (457 millimeters) for rock excavation.
    (d) Promptly after a ditch for an onshore steel transmission line is 
backfilled (if the construction project involves 1,000 feet or more of 
continuous backfill length along the pipeline), but not later than 6 
months after placing the pipeline in service, the operator must perform 
an assessment to assess any coating damage and ensure integrity of the 
coating using direct current voltage gradient (DCVG), alternating 
current voltage gradient (ACVG), or other technology that provides 
comparable information about the integrity of the coating. Coating 
surveys must be conducted, except in locations where effective coating 
surveys are precluded by geographical, technical, or safety reasons.
    (e) An operator must notify PHMSA in accordance with Sec.  192.18 at 
least 90 days in advance of using other technology to assess integrity 
of the coating under paragraph (d) of this section.
    (f) An operator of an onshore steel transmission pipeline must 
develop a remedial action plan and apply for any necessary permits 
within 6 months of completing the assessment that identified the 
deficiency. An operator must repair any coating damage classified as 
severe (voltage drop greater than 60 percent for DCVG or 70 dB[micro]V 
for ACVG) in accordance with section 4 of NACE SP0502 (incorporated by 
reference, see Sec.  192.7) within 6 months of the assessment, or as 
soon as practicable after obtaining necessary permits, not to exceed 6 
months after the receipt of permits.
    (g) An operator of an onshore steel transmission pipeline must make 
and retain for the life of the pipeline records documenting the coating 
assessment findings and remedial actions performed under paragraphs (d) 
through (f) of this section.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34606, 
Aug. 16, 1976; Amdt. 192-78, 61 FR 28784, June 6, 1996; Amdt. 192-85, 63 
FR 37503, July 13, 1998; Amdt. 192-132, 87 FR 52268, Aug. 24, 2022; 
Amdt. 192-133, 88 FR 24711, Apr. 24, 2023]



Sec.  192.321  Installation of plastic pipe.

    (a) Plastic pipe must be installed below ground level except as 
provided in paragraphs (g), (h), and (i) of this section.
    (b) Plastic pipe that is installed in a vault or any other below 
grade enclosure must be completely encased in gas-tight metal pipe and 
fittings that are adequately protected from corrosion.
    (c) Plastic pipe must be installed so as to minimize shear or 
tensile stresses.
    (d) Plastic pipe must have a minimum wall thickness in accordance 
with Sec.  192.121.
    (e) Plastic pipe that is not encased must have an electrically 
conducting wire or other means of locating the pipe while it is 
underground. Tracer wire may not be wrapped around the pipe and contact 
with the pipe must be minimized but is not prohibited. Tracer wire or 
other metallic elements installed for pipe locating purposes must be 
resistant to corrosion damage, either by use of coated copper wire or by 
other means.
    (f) Plastic pipe that is being encased must be inserted into the 
casing pipe in a manner that will protect the plastic. Plastic pipe that 
is being encased must be protected from damage at all entrance and all 
exit points of the casing.

[[Page 484]]

The leading end of the plastic must be closed before insertion.
    (g) Uncased plastic pipe may be temporarily installed above ground 
level under the following conditions:
    (1) The operator must be able to demonstrate that the cumulative 
aboveground exposure of the pipe does not exceed the manufacturer's 
recommended maximum period of exposure or 2 years, whichever is less.
    (2) The pipe either is located where damage by external forces is 
unlikely or is otherwise protected against such damage.
    (3) The pipe adequately resists exposure to ultraviolet light and 
high and low temperatures.
    (h) Plastic pipe may be installed on bridges provided that it is:
    (1) Installed with protection from mechanical damage, such as 
installation in a metallic casing;
    (2) Protected from ultraviolet radiation; and
    (3) Not allowed to exceed the pipe temperature limits specified in 
Sec.  192.121.
    (i) Plastic mains may terminate above ground level provided they 
comply with the following:
    (1) The above-ground level part of the plastic main is protected 
against deterioration and external damage.
    (2) The plastic main is not used to support external loads.
    (3) Installations of risers at regulator stations must meet the 
design requirements of Sec.  192.204.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR 28784, 
June 6, 1996; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-93, 68 
FR 53900, Sept. 15, 2003; Amdt. 192-94, 69 FR 32895, June 14, 2004; 
Amdt. 192-124, 83 FR 58718, Nov. 20, 2018]



Sec.  192.323  Casing.

    Each casing used on a transmission line or main under a railroad or 
highway must comply with the following:
    (a) The casing must be designed to withstand the superimposed loads.
    (b) If there is a possibility of water entering the casing, the ends 
must be sealed.
    (c) If the ends of an unvented casing are sealed and the sealing is 
strong enough to retain the maximum allowable operating pressure of the 
pipe, the casing must be designed to hold this pressure at a stress 
level of not more than 72 percent of SMYS.
    (d) If vents are installed on a casing, the vents must be protected 
from the weather to prevent water from entering the casing.



Sec.  192.325  Underground clearance.

    (a) Each transmission line must be installed with at least 12 inches 
(305 millimeters) of clearance from any other underground structure not 
associated with the transmission line. If this clearance cannot be 
attained, the transmission line must be protected from damage that might 
result from the proximity of the other structure.
    (b) Each main must be installed with enough clearance from any other 
underground structure to allow proper maintenance and to protect against 
damage that might result from proximity to other structures.
    (c) In addition to meeting the requirements of paragraph (a) or (b) 
of this section, each plastic transmission line or main must be 
installed with sufficient clearance, or must be insulated, from any 
source of heat so as to prevent the heat from impairing the 
serviceability of the pipe.
    (d) Each pipe-type or bottle-type holder must be installed with a 
minimum clearance from any other holder as prescribed in Sec.  
192.175(b).

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, 
July 13, 1998]



Sec.  192.327  Cover.

    (a) Except as provided in paragraphs (c), (e), (f), and (g) of this 
section, each buried transmission line must be installed with a minimum 
cover as follows:

------------------------------------------------------------------------
                                                  Normal    Consolidated
                   Location                        soil         rock
------------------------------------------------------------------------
Inches (Millimeters)..........................
Class 1 locations.............................    30 (762)     18 (457)
Class 2, 3, and 4 locations...................    36 (914)     24 (610)
Drainage ditches of public roads and railroad     36 (914)     24 (610)
 crossings....................................
------------------------------------------------------------------------

    (b) Except as provided in paragraphs (c) and (d) of this section, 
each buried main must be installed with at least 24 inches (610 
millimeters) of cover.

[[Page 485]]

    (c) Where an underground structure prevents the installation of a 
transmission line or main with the minimum cover, the transmission line 
or main may be installed with less cover if it is provided with 
additional protection to withstand anticipated external loads.
    (d) A main may be installed with less than 24 inches (610 
millimeters) of cover if the law of the State or municipality:
    (1) Establishes a minimum cover of less than 24 inches (610 
millimeters);
    (2) Requires that mains be installed in a common trench with other 
utility lines; and
    (3) Provides adequately for prevention of damage to the pipe by 
external forces.
    (e) Except as provided in paragraph (c) of this section, all pipe 
installed in a navigable river, stream, or harbor must be installed with 
a minimum cover of 48 inches (1,219 millimeters) in soil or 24 inches 
(610 millimeters) in consolidated rock between the top of the pipe and 
the underwater natural bottom (as determined by recognized and generally 
accepted practices).
    (f) All pipe installed offshore, except in the Gulf of Mexico and 
its inlets, under water not more than 200 feet (60 meters) deep, as 
measured from the mean low tide, must be installed as follows:
    (1) Except as provided in paragraph (c) of this section, pipe under 
water less than 12 feet (3.66 meters) deep, must be installed with a 
minimum cover of 36 inches (914 millimeters) in soil or 18 inches (457 
millimeters) in consolidated rock between the top of the pipe and the 
natural bottom.
    (2) Pipe under water at least 12 feet (3.66 meters) deep must be 
installed so that the top of the pipe is below the natural bottom, 
unless the pipe is supported by stanchions, held in place by anchors or 
heavy concrete coating, or protected by an equivalent means.
    (g) All pipelines installed under water in the Gulf of Mexico and 
its inlets, as defined in Sec.  192.3, must be installed in accordance 
with Sec.  192.612(b)(3).

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34606, 
Aug. 16, 1976; Amdt. 192-78, 61 FR 28785, June 6, 1996; Amdt. 192-85, 63 
FR 37503, July 13, 1998; Amdt. 192-98, 69 FR 48406, Aug. 10, 2004]



Sec.  192.328  Additional construction requirements for steel pipe using 
alternative maximum allowable operating pressure.

    For a new or existing pipeline segment to be eligible for operation 
at the alternative maximum allowable operating pressure calculated under 
Sec.  192.620, a segment must meet the following additional construction 
requirements. Records must be maintained, for the useful life of the 
pipeline, demonstrating compliance with these requirements:

------------------------------------------------------------------------
   To address this construction      The pipeline segment must meet this
              issue:                additional construction requirement:
------------------------------------------------------------------------
(a) Quality assurance.............  (1) The construction of the pipeline
                                     segment must be done under a
                                     quality assurance plan addressing
                                     pipe inspection, hauling and
                                     stringing, field bending, welding,
                                     non-destructive examination of
                                     girth welds, applying and testing
                                     field applied coating, lowering of
                                     the pipeline into the ditch,
                                     padding and backfilling, and
                                     hydrostatic testing.
                                    (2) The quality assurance plan for
                                     applying and testing field applied
                                     coating to girth welds must be:
                                    (i) Equivalent to that required
                                     under Sec.   192.112(f)(3) for
                                     pipe; and
                                    (ii) Performed by an individual with
                                     the knowledge, skills, and ability
                                     to assure effective coating
                                     application.
(b) Girth welds...................  (1) All girth welds on a new
                                     pipeline segment must be non-
                                     destructively examined in
                                     accordance with Sec.   192.243(b)
                                     and (c).
(c) Depth of cover................  (1) Notwithstanding any lesser depth
                                     of cover otherwise allowed in Sec.
                                      192.327, there must be at least 36
                                     inches (914 millimeters) of cover
                                     or equivalent means to protect the
                                     pipeline from outside force damage.
                                    (2) In areas where deep tilling or
                                     other activities could threaten the
                                     pipeline, the top of the pipeline
                                     must be installed at least one foot
                                     below the deepest expected
                                     penetration of the soil.

[[Page 486]]

 
(d) Initial strength testing......  (1) The pipeline segment must not
                                     have experienced failures
                                     indicative of systemic material
                                     defects during strength testing,
                                     including initial hydrostatic
                                     testing. A root cause analysis,
                                     including metallurgical examination
                                     of the failed pipe, must be
                                     performed for any failure
                                     experienced to verify that it is
                                     not indicative of a systemic
                                     concern. The results of this root
                                     cause analysis must be reported to
                                     each PHMSA pipeline safety regional
                                     office where the pipe is in service
                                     at least 60 days prior to operating
                                     at the alternative MAOP. An
                                     operator must also notify a State
                                     pipeline safety authority when the
                                     pipeline is located in a State
                                     where PHMSA has an interstate agent
                                     agreement, or an intrastate
                                     pipeline is regulated by that
                                     State.
(e) Interference currents.........  (1) For a new pipeline segment, the
                                     construction must address the
                                     impacts of induced alternating
                                     current from parallel electric
                                     transmission lines and other known
                                     sources of potential interference
                                     with corrosion control.
------------------------------------------------------------------------


[72 FR 62176, Oct. 17, 2008]



Sec.  192.329  Installation of plastic pipelines by trenchless excavation.

    Plastic pipelines installed by trenchless excavation must comply 
with the following:
    (a) Each operator must take practicable steps to provide sufficient 
clearance for installation and maintenance activities from other 
underground utilities and/or structures at the time of installation.
    (b) For each pipeline section, plastic pipe and components that are 
pulled through the ground must use a weak link, as defined by Sec.  
192.3, to ensure the pipeline will not be damaged by any excessive 
forces during the pulling process.

[Amdt. 192-124, 83 FR 58719, Nov. 20, 2018]



    Subpart H_Customer Meters, Service Regulators, and Service Lines



Sec.  192.351  Scope.

    This subpart prescribes minimum requirements for installing customer 
meters, service regulators, service lines, service line valves, and 
service line connections to mains.



Sec.  192.353  Customer meters and regulators: Location.

    (a) Each meter and service regulator, whether inside or outside a 
building, must be installed in a readily accessible location and be 
protected from corrosion and other damage, including, if installed 
outside a building, vehicular damage that may be anticipated. However, 
the upstream regulator in a series may be buried.
    (b) Each service regulator installed within a building must be 
located as near as practical to the point of service line entrance.
    (c) Each meter installed within a building must be located in a 
ventilated place and not less than 3 feet (914 millimeters) from any 
source of ignition or any source of heat which might damage the meter.
    (d) Where feasible, the upstream regulator in a series must be 
located outside the building, unless it is located in a separate 
metering or regulating building.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, 
July 13, 1998; Amdt. 192-93, 68 FR 53900, Sept. 15, 2003]



Sec.  192.355  Customer meters and regulators: Protection from damage.

    (a) Protection from vacuum or back pressure. If the customer's 
equipment might create either a vacuum or a back pressure, a device must 
be installed to protect the system.
    (b) Service regulator vents and relief vents. Service regulator 
vents and relief vents must terminate outdoors, and the outdoor terminal 
must--
    (1) Be rain and insect resistant;
    (2) Be located at a place where gas from the vent can escape freely 
into the atmosphere and away from any opening into the building; and
    (3) Be protected from damage caused by submergence in areas where 
flooding may occur.
    (c) Pits and vaults. Each pit or vault that houses a customer meter 
or regulator at a place where vehicular traffic is anticipated, must be 
able to support that traffic.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, 
Jan. 21, 1988]

[[Page 487]]



Sec.  192.357  Customer meters and regulators: Installation.

    (a) Each meter and each regulator must be installed so as to 
minimize anticipated stresses upon the connecting piping and the meter.
    (b) When close all-thread nipples are used, the wall thickness 
remaining after the threads are cut must meet the minimum wall thickness 
requirements of this part.
    (c) Connections made of lead or other easily damaged material may 
not be used in the installation of meters or regulators.
    (d) Each regulator that might release gas in its operation must be 
vented to the outside atmosphere.



Sec.  192.359  Customer meter installations: Operating pressure.

    (a) A meter may not be used at a pressure that is more than 67 
percent of the manufacturer's shell test pressure.
    (b) Each newly installed meter manufactured after November 12, 1970, 
must have been tested to a minimum of 10 p.s.i. (69 kPa) gage.
    (c) A rebuilt or repaired tinned steel case meter may not be used at 
a pressure that is more than 50 percent of the pressure used to test the 
meter after rebuilding or repairing.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-1, 35 FR 17660, 
Nov. 17, 1970; Amdt. 192-85, 63 FR 37503, July 13, 1998]



Sec.  192.361  Service lines: Installation.

    (a) Depth. Each buried service line must be installed with at least 
12 inches (305 millimeters) of cover in private property and at least 18 
inches (457 millimeters) of cover in streets and roads. However, where 
an underground structure prevents installation at those depths, the 
service line must be able to withstand any anticipated external load.
    (b) Support and backfill. Each service line must be properly 
supported on undisturbed or well-compacted soil, and material used for 
backfill must be free of materials that could damage the pipe or its 
coating.
    (c) Grading for drainage. Where condensate in the gas might cause 
interruption in the gas supply to the customer, the service line must be 
graded so as to drain into the main or into drips at the low points in 
the service line.
    (d) Protection against piping strain and external loading. Each 
service line must be installed so as to minimize anticipated piping 
strain and external loading.
    (e) Installation of service lines into buildings. Each underground 
service line installed below grade through the outer foundation wall of 
a building must:
    (1) In the case of a metal service line, be protected against 
corrosion;
    (2) In the case of a plastic service line, be protected from 
shearing action and backfill settlement; and
    (3) Be sealed at the foundation wall to prevent leakage into the 
building.
    (f) Installation of service lines under buildings. Where an 
underground service line is installed under a building:
    (1) It must be encased in a gas tight conduit;
    (2) The conduit and the service line must, if the service line 
supplies the building it underlies, extend into a normally usable and 
accessible part of the building; and
    (3) The space between the conduit and the service line must be 
sealed to prevent gas leakage into the building and, if the conduit is 
sealed at both ends, a vent line from the annular space must extend to a 
point where gas would not be a hazard, and extend above grade, 
terminating in a rain and insect resistant fitting.
    (g) Locating underground service lines. Each underground nonmetallic 
service line that is not encased must have a means of locating the pipe 
that complies with Sec.  192.321(e).

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-75, 61 FR 18517, 
Apr. 26, 1996; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-93, 
68 FR 53900, Sept. 15, 2003]



Sec.  192.363  Service lines: Valve requirements.

    (a) Each service line must have a service-line valve that meets the 
applicable requirements of subparts B and D of this part. A valve 
incorporated in a meter bar, that allows the meter to be bypassed, may 
not be used as a service-line valve.

[[Page 488]]

    (b) A soft seat service line valve may not be used if its ability to 
control the flow of gas could be adversely affected by exposure to 
anticipated heat.
    (c) Each service-line valve on a high-pressure service line, 
installed above ground or in an area where the blowing of gas would be 
hazardous, must be designed and constructed to minimize the possibility 
of the removal of the core of the valve with other than specialized 
tools.



Sec.  192.365  Service lines: Location of valves.

    (a) Relation to regulator or meter. Each service-line valve must be 
installed upstream of the regulator or, if there is no regulator, 
upstream of the meter.
    (b) Outside valves. Each service line must have a shut-off valve in 
a readily accessible location that, if feasible, is outside of the 
building.
    (c) Underground valves. Each underground service-line valve must be 
located in a covered durable curb box or standpipe that allows ready 
operation of the valve and is supported independently of the service 
lines.



Sec.  192.367  Service lines: General requirements for connections to main 
piping.

    (a) Location. Each service line connection to a main must be located 
at the top of the main or, if that is not practical, at the side of the 
main, unless a suitable protective device is installed to minimize the 
possibility of dust and moisture being carried from the main into the 
service line.
    (b) Compression-type connection to main. Each compression-type 
service line to main connection must:
    (1) Be designed and installed to effectively sustain the 
longitudinal pull-out or thrust forces caused by contraction or 
expansion of the piping, or by anticipated external or internal loading;
    (2) If gaskets are used in connecting the service line to the main 
connection fitting, have gaskets that are compatible with the kind of 
gas in the system; and
    (3) If used on pipelines comprised of plastic, be a Category 1 
connection as defined by a listed specification for the applicable 
material, providing a seal plus resistance to a force on the pipe joint 
equal to or greater than that which will cause no less than 25% 
elongation of pipe, or the pipe fails outside the joint area if tested 
in accordance with the applicable standard.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-75, 61 FR 18517, 
Apr. 26, 1996; Amdt. 192-124, 83 FR 58719, Nov. 20, 2018]



Sec.  192.369  Service lines: Connections to cast iron or ductile iron 
mains.

    (a) Each service line connected to a cast iron or ductile iron main 
must be connected by a mechanical clamp, by drilling and tapping the 
main, or by another method meeting the requirements of Sec.  192.273.
    (b) If a threaded tap is being inserted, the requirements of Sec.  
192.151 (b) and (c) must also be met.



Sec.  192.371  Service lines: Steel.

    Each steel service line to be operated at less than 100 p.s.i. (689 
kPa) gage must be constructed of pipe designed for a minimum of 100 
p.s.i. (689 kPa) gage.

[Amdt. 192-1, 35 FR 17660, Nov. 17, 1970, as amended by Amdt. 192-85, 63 
FR 37503, July 13, 1998]



Sec.  192.373  Service lines: Cast iron and ductile iron.

    (a) Cast or ductile iron pipe less than 6 inches (152 millimeters) 
in diameter may not be installed for service lines.
    (b) If cast iron pipe or ductile iron pipe is installed for use as a 
service line, the part of the service line which extends through the 
building wall must be of steel pipe.
    (c) A cast iron or ductile iron service line may not be installed in 
unstable soil or under a building.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, 
July 13, 1998]



Sec.  192.375  Service lines: Plastic.

    (a) Each plastic service line outside a building must be installed 
below ground level, except that--
    (1) It may be installed in accordance with Sec.  192.321(g); and
    (2) It may terminate above ground level and outside the building, 
if--
    (i) The above ground level part of the plastic service line is 
protected against deterioration and external damage;

[[Page 489]]

    (ii) The plastic service line is not used to support external loads; 
and
    (iii) The riser portion of the service line meets the design 
requirements of Sec.  192.204.
    (b) Each plastic service line inside a building must be protected 
against external damage.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR 28785, 
June 6, 1996; Amdt. 192-124, 83 FR 58719, Nov. 20, 2018]



Sec.  192.376  Installation of plastic service lines by trenchless 
excavation.

    Plastic service lines installed by trenchless excavation must comply 
with the following:
    (a) Each operator shall take practicable steps to provide sufficient 
clearance for installation and maintenance activities from other 
underground utilities and structures at the time of installation.
    (b) For each pipeline section, plastic pipe and components that are 
pulled through the ground must use a weak link, as defined by Sec.  
192.3, to ensure the pipeline will not be damaged by any excessive 
forces during the pulling process.

[Amdt. 192-124, 83 FR 58719, Nov. 20, 2018]



Sec.  192.377  Service lines: Copper.

    Each copper service line installed within a building must be 
protected against external damage.



Sec.  192.379  New service lines not in use.

    Each service line that is not placed in service upon completion of 
installation must comply with one of the following until the customer is 
supplied with gas:
    (a) The valve that is closed to prevent the flow of gas to the 
customer must be provided with a locking device or other means designed 
to prevent the opening of the valve by persons other than those 
authorized by the operator.
    (b) A mechanical device or fitting that will prevent the flow of gas 
must be installed in the service line or in the meter assembly.
    (c) The customer's piping must be physically disconnected from the 
gas supply and the open pipe ends sealed.

[Amdt. 192-8, 37 FR 20694, Oct. 3, 1972]



Sec.  192.381  Service lines: Excess flow valve performance standards.

    (a) Excess flow valves (EFVs) to be used on service lines that 
operate continuously throughout the year at a pressure not less than 10 
p.s.i. (69 kPa) gage must be manufactured and tested by the manufacturer 
according to an industry specification, or the manufacturer's written 
specification, to ensure that each valve will:
    (1) Function properly up to the maximum operating pressure at which 
the valve is rated;
    (2) Function properly at all temperatures reasonably expected in the 
operating environment of the service line;
    (3) At 10 p.s.i. (69 kPa) gage:
    (i) Close at, or not more than 50 percent above, the rated closure 
flow rate specified by the manufacturer; and
    (ii) Upon closure, reduce gas flow--
    (A) For an excess flow valve designed to allow pressure to equalize 
across the valve, to no more than 5 percent of the manufacturer's 
specified closure flow rate, up to a maximum of 20 cubic feet per hour 
(0.57 cubic meters per hour); or
    (B) For an excess flow valve designed to prevent equalization of 
pressure across the valve, to no more than 0.4 cubic feet per hour (.01 
cubic meters per hour); and
    (4) Not close when the pressure is less than the manufacturer's 
minimum specified operating pressure and the flow rate is below the 
manufacturer's minimum specified closure flow rate.
    (b) An excess flow valve must meet the applicable requirements of 
Subparts B and D of this part.
    (c) An operator must mark or otherwise identify the presence of an 
excess flow valve in the service line.
    (d) An operator shall locate an excess flow valve as near as 
practical to the fitting connecting the service line to its source of 
gas supply.
    (e) An operator should not install an excess flow valve on a service 
line where the operator has prior experience with contaminants in the 
gas stream, where these contaminants could be expected to cause the 
excess flow valve to malfunction or where the excess flow valve would 
interfere with necessary operation and maintenance

[[Page 490]]

activities on the service, such as blowing liquids from the line.

[Amdt. 192-79, 61 FR 31459, June 20, 1996, as amended by Amdt. 192-80, 
62 FR 2619, Jan. 17, 1997; Amdt. 192-85, 63 FR 37504, July 13, 1998; 
Amdt. 192-121, 81 FR 71001, Oct. 14, 2016]



Sec.  192.383  Excess flow valve installation.

    (a) Definitions. As used in this section:
    Branched service line means a gas service line that begins at the 
existing service line or is installed concurrently with the primary 
service line but serves a separate residence.
    Replaced service line means a gas service line where the fitting 
that connects the service line to the main is replaced or the piping 
connected to this fitting is replaced.
    Service line serving single-family residence means a gas service 
line that begins at the fitting that connects the service line to the 
main and serves only one single-family residence (SFR).
    (b) Installation required. An EFV installation must comply with the 
performance standards in Sec.  192.381. After April 14, 2017, each 
operator must install an EFV on any new or replaced service line serving 
the following types of services before the line is activated:
    (1) A single service line to one SFR;
    (2) A branched service line to a SFR installed concurrently with the 
primary SFR service line (i.e., a single EFV may be installed to protect 
both service lines);
    (3) A branched service line to a SFR installed off a previously 
installed SFR service line that does not contain an EFV;
    (4) Multifamily residences with known customer loads not exceeding 
1,000 SCFH per service, at time of service installation based on 
installed meter capacity, and
    (5) A single, small commercial customer served by a single service 
line with a known customer load not exceeding 1,000 SCFH, at the time of 
meter installation, based on installed meter capacity.
    (c) Exceptions to excess flow valve installation requirement. An 
operator need not install an excess flow valve if one or more of the 
following conditions are present:
    (1) The service line does not operate at a pressure of 10 psig or 
greater throughout the year;
    (2) The operator has prior experience with contaminants in the gas 
stream that could interfere with the EFV's operation or cause loss of 
service to a customer;
    (3) An EFV could interfere with necessary operation or maintenance 
activities, such as blowing liquids from the line; or
    (4) An EFV meeting the performance standards in Sec.  192.381 is not 
commercially available to the operator.
    (d) Customer's right to request an EFV. Existing service line 
customers who desire an EFV on service lines not exceeding 1,000 SCFH 
and who do not qualify for one of the exceptions in paragraph (c) of 
this section may request an EFV to be installed on their service lines. 
If an eligible service line customer requests an EFV installation, an 
operator must install the EFV at a mutually agreeable date. The 
operator's rate-setter determines how and to whom the costs of the 
requested EFVs are distributed.
    (e) Operator notification of customers concerning EFV installation. 
Operators must notify customers of their right to request an EFV in the 
following manner:
    (1) Except as specified in paragraphs (c) and (e)(5) of this 
section, each operator must provide written or electronic notification 
to customers of their right to request the installation of an EFV. 
Electronic notification can include emails, Web site postings, and e-
billing notices.
    (2) The notification must include an explanation for the service 
line customer of the potential safety benefits that may be derived from 
installing an EFV. The explanation must include information that an EFV 
is designed to shut off the flow of natural gas automatically if the 
service line breaks.
    (3) The notification must include a description of EFV installation 
and replacement costs. The notice must alert the customer that the costs 
for maintaining and replacing an EFV may later be incurred, and what 
those costs will be to the extent known.
    (4) The notification must indicate that if a service line customer 
requests

[[Page 491]]

installation of an EFV and the load does not exceed 1,000 SCFH and the 
conditions of paragraph (c) are not present, the operator must install 
an EFV at a mutually agreeable date.
    (5) Operators of master-meter systems and liquefied petroleum gas 
(LPG) operators with fewer than 100 customers may continuously post a 
general notification in a prominent location frequented by customers.
    (f) Operator evidence of customer notification. An operator must 
make a copy of the notice or notices currently in use available during 
PHMSA inspections or State inspections conducted under a pipeline safety 
program certified or approved by PHMSA under 49 U.S.C. 60105 or 60106.
    (g) Reporting. Except for operators of master-meter systems and LPG 
operators with fewer than 100 customers, each operator must report the 
EFV measures detailed in the annual report required by Sec.  191.11.

[Amdt. 192-121, 81 FR 71001, Oct. 14, 2016; 81 FR 72739, Oct. 21, 2016]



Sec.  192.385  Manual service line shut-off valve installation.

    (a) Definitions. As used in this section:
    Manual service line shut-off valve means a curb valve or other 
manually operated valve located near the service line that is safely 
accessible to operator personnel or other personnel authorized by the 
operator to manually shut off gas flow to the service line, if needed.
    (b) Installation requirement. The operator must install either a 
manual service line shut-off valve or, if possible, based on sound 
engineering analysis and availability, an EFV for any new or replaced 
service line with installed meter capacity exceeding 1,000 SCFH.
    (c) Accessibility and maintenance. Manual service line shut-off 
valves for any new or replaced service line must be installed in such a 
way as to allow accessibility during emergencies. Manual service shut-
off valves installed under this section are subject to regular scheduled 
maintenance, as documented by the operator and consistent with the valve 
manufacturer's specification.

[Amdt. 192-121, 81 FR 71002, Oct. 14, 2016]



              Subpart I_Requirements for Corrosion Control

    Source: Amdt. 192-4, 36 FR 12302, June 30, 1971, unless otherwise 
noted.



Sec.  192.451  Scope.

    (a) This subpart prescribes minimum requirements for the protection 
of metallic pipelines from external, internal, and atmospheric 
corrosion.
    (b) [Reserved]

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-27, 41 
FR 34606, Aug. 16, 1976; Amdt. 192-33, 43 FR 39389, Sept. 5, 1978]



Sec.  192.452  How does this subpart apply to converted pipelines and 
regulated onshore gathering pipelines?

    (a) Converted pipelines. Notwithstanding the date the pipeline was 
installed or any earlier deadlines for compliance, each pipeline which 
qualifies for use under this part in accordance with Sec.  192.14 must 
meet the requirements of this subpart specifically applicable to 
pipelines installed before August 1, 1971, and all other applicable 
requirements within 1 year after the pipeline is readied for service. 
However, the requirements of this subpart specifically applicable to 
pipelines installed after July 31, 1971, apply if the pipeline 
substantially meets those requirements before it is readied for service 
or it is a segment which is replaced, relocated, or substantially 
altered.
    (b) Type A and B onshore gathering lines. For any Type A or Type B 
regulated onshore gathering line under Sec.  192.9 existing on April 14, 
2006, that was not previously subject to this part, and for any onshore 
gathering line that becomes a regulated onshore gathering line under 
Sec.  192.9 after April 14, 2006, because of a change in class location 
or increase in dwelling density:
    (1) The requirements of this subpart specifically applicable to 
pipelines installed before August 1, 1971, apply to the gathering line 
regardless of the date the pipeline was actually installed; and
    (2) The requirements of this subpart specifically applicable to 
pipelines installed after July 31, 1971, apply only if the pipeline 
substantially meets those requirements.

[[Page 492]]

    (c) Type C onshore regulated gathering lines. For any Type C onshore 
regulated gathering pipeline under Sec.  192.9 existing on May 16, 2022, 
that was not previously subject to this part, and for any Type C onshore 
gas gathering pipeline that becomes subject to this subpart after May 
16, 2022, because of an increase in MAOP, change in class location, or 
presence of a building intended for human occupancy or other impacted 
site:
    (1) The requirements of this subpart specifically applicable to 
pipelines installed before August 1, 1971, apply to the gathering line 
regardless of the date the pipeline was actually installed; and
    (2) The requirements of this subpart specifically applicable to 
pipelines installed after July 31, 1971, apply only if the pipeline 
substantially meets those requirements.
    (d) Regulated onshore gathering lines generally. Any gathering line 
that is subject to this subpart per Sec.  192.9 at the time of 
construction must meet the requirements of this subpart applicable to 
pipelines installed after July 31, 1971.

[Amdt. 192-30, 42 FR 60148, Nov. 25, 1977, as amended by Amdt. 192-102, 
71 FR 13303, Mar. 15, 2006; Amdt. 192-129, 86 FR 63298, Nov. 15, 2021]



Sec.  192.453  General.

    The corrosion control procedures required by Sec.  192.605(b)(2), 
including those for the design, installation, operation, and maintenance 
of cathodic protection systems, must be carried out by, or under the 
direction of, a person qualified in pipeline corrosion control methods.

[Amdt. 192-71, 59 FR 6584, Feb. 11, 1994]



Sec.  192.455  External corrosion control: Buried or submerged pipelines 
installed after July 31, 1971.

    (a) Except as provided in paragraphs (b), (c), (f), and (g) of this 
section, each buried or submerged pipeline installed after July 31, 
1971, must be protected against external corrosion, including the 
following:
    (1) It must have an external protective coating meeting the 
requirements of Sec.  192.461.
    (2) It must have a cathodic protection system designed to protect 
the pipeline in accordance with this subpart, installed and placed in 
operation within 1 year after completion of construction.
    (b) An operator need not comply with paragraph (a) of this section, 
if the operator can demonstrate by tests, investigation, or experience 
in the area of application, including, as a minimum, soil resistivity 
measurements and tests for corrosion accelerating bacteria, that a 
corrosive environment does not exist. However, within 6 months after an 
installation made pursuant to the preceding sentence, the operator shall 
conduct tests, including pipe-to-soil potential measurements with 
respect to either a continuous reference electrode or an electrode using 
close spacing, not to exceed 20 feet (6 meters), and soil resistivity 
measurements at potential profile peak locations, to adequately evaluate 
the potential profile along the entire pipeline. If the tests made 
indicate that a corrosive condition exists, the pipeline must be 
cathodically protected in accordance with paragraph (a)(2) of this 
section.
    (c) An operator need not comply with paragraph (a) of this section, 
if the operator can demonstrate by tests, investigation, or experience 
that--
    (1) For a copper pipeline, a corrosive environment does not exist; 
or
    (2) For a temporary pipeline with an operating period of service not 
to exceed 5 years beyond installation, corrosion during the 5-year 
period of service of the pipeline will not be detrimental to public 
safety.
    (d) Notwithstanding the provisions of paragraph (b) or (c) of this 
section, if a pipeline is externally coated, it must be cathodically 
protected in accordance with paragraph (a)(2) of this section.
    (e) Aluminum may not be installed in a buried or submerged pipeline 
if that aluminum is exposed to an environment with a natural pH in 
excess of 8, unless tests or experience indicate its suitability in the 
particular environment involved.
    (f) This section does not apply to electrically isolated, metal 
alloy fittings in plastic pipelines, if:

[[Page 493]]

    (1) For the size fitting to be used, an operator can show by test, 
investigation, or experience in the area of application that adequate 
corrosion control is provided by the alloy composition; and
    (2) The fitting is designed to prevent leakage caused by localized 
corrosion pitting.
    (g) Electrically isolated metal alloy fittings installed after 
January 22, 2019, that do not meet the requirements of paragraph (f) 
must be cathodically protected, and must be maintained in accordance 
with the operator's integrity management plan.

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended at Amdt. 192-28, 42 
FR 35654, July 11, 1977; Amdt. 192-39, 47 FR 9844, Mar. 8, 1982; Amdt. 
192-78, 61 FR 28785, June 6, 1996; Amdt. 192-85, 63 FR 37504, July 13, 
1998; Amdt. 192-124, 83 FR 58719, Nov. 20, 2018]



Sec.  192.457  External corrosion control: Buried or submerged pipelines 
installed before August 1, 1971.

    (a) Except for buried piping at compressor, regulator, and measuring 
stations, each buried or submerged transmission line installed before 
August 1, 1971, that has an effective external coating must be 
cathodically protected along the entire area that is effectively coated, 
in accordance with this subpart. For the purposes of this subpart, a 
pipeline does not have an effective external coating if its cathodic 
protection current requirements are substantially the same as if it were 
bare. The operator shall make tests to determine the cathodic protection 
current requirements.
    (b) Except for cast iron or ductile iron, each of the following 
buried or submerged pipelines installed before August 1, 1971, must be 
cathodically protected in accordance with this subpart in areas in which 
active corrosion is found:
    (1) Bare or ineffectively coated transmission lines.
    (2) Bare or coated pipes at compressor, regulator, and measuring 
stations.
    (3) Bare or coated distribution lines.

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43 
FR 39390, Sept. 5, 1978; Amdt. 192-93, 68 FR 53900, Sept. 15, 2003]



Sec.  192.459  External corrosion control: Examination of buried pipeline 
when exposed.

    Whenever an operator has knowledge that any portion of a buried 
pipeline is exposed, the exposed portion must be examined for evidence 
of external corrosion if the pipe is bare, or if the coating is 
deteriorated. If external corrosion requiring remedial action under 
Sec. Sec.  192.483 through 192.489 is found, the operator shall 
investigate circumferentially and longitudinally beyond the exposed 
portion (by visual examination, indirect method, or both) to determine 
whether additional corrosion requiring remedial action exists in the 
vicinity of the exposed portion.

[Amdt. 192-87, 64 FR 56981, Oct. 22, 1999]



Sec.  192.461  External corrosion control: Protective coating.

    (a) Each external protective coating, whether conductive or 
insulating, applied for the purpose of external corrosion control must--
    (1) Be applied on a properly prepared surface;
    (2) Have sufficient adhesion to the metal surface to effectively 
resist underfilm migration of moisture;
    (3) Be sufficiently ductile to resist cracking;
    (4) Have sufficient strength to resist damage due to handling 
(including, but not limited to, transportation, installation, boring, 
and backfilling) and soil stress; and
    (5) Have properties compatible with any supplemental cathodic 
protection.
    (b) Each external protective coating which is an electrically 
insulating type must also have low moisture absorption and high 
electrical resistance.
    (c) Each external protective coating must be inspected just prior to 
lowering the pipe into the ditch and backfilling, and any damage 
detrimental to effective corrosion control must be repaired.
    (d) Each external protective coating must be protected from damage 
resulting from adverse ditch conditions or damage from supporting 
blocks.
    (e) If coated pipe is installed by boring, driving, or other similar 
method, precautions must be taken to minimize damage to the coating 
during installation.

[[Page 494]]

    (f) Promptly after the backfill of an onshore steel transmission 
pipeline ditch following repair or replacement (if the repair or 
replacement results in 1,000 feet or more of backfill length along the 
pipeline), but no later than 6 months after the backfill, the operator 
must perform an assessment to assess any coating damage and ensure 
integrity of the coating using direct current voltage gradient (DCVG), 
alternating current voltage gradient (ACVG), or other technology that 
provides comparable information about the integrity of the coating. 
Coating surveys must be conducted, except in locations where effective 
coating surveys are precluded by geographical, technical, or safety 
reasons.
    (g) An operator must notify PHMSA in accordance with Sec.  192.18 at 
least 90 days in advance of using other technology to assess integrity 
of the coating under paragraph (f) of this section.
    (h) An operator of an onshore steel transmission pipeline must 
develop a remedial action plan and apply for any necessary permits 
within 6 months of completing the assessment that identified the 
deficiency. The operator must repair any coating damage classified as 
severe (voltage drop greater than 60 percent for DCVG or 70 dB[micro]V 
for ACVG) in accordance with section 4 of NACE SP0502 (incorporated by 
reference, see Sec.  192.7) within 6 months of the assessment, or as 
soon as practicable after obtaining necessary permits, not to exceed 6 
months after the receipt of permits.
    (i) An operator of an onshore steel transmission pipeline must make 
and retain for the life of the pipeline records documenting the coating 
assessment findings and remedial actions performed under paragraphs (f) 
through (h) of this section.

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-132, 
87 FR 52268, Aug. 24, 2022]



Sec.  192.463  External corrosion control: Cathodic protection.

    (a) Each cathodic protection system required by this subpart must 
provide a level of cathodic protection that complies with one or more of 
the applicable criteria contained in appendix D of this part. If none of 
these criteria is applicable, the cathodic protection system must 
provide a level of cathodic protection at least equal to that provided 
by compliance with one or more of these criteria.
    (b) If amphoteric metals are included in a buried or submerged 
pipeline containing a metal of different anodic potential--
    (1) The amphoteric metals must be electrically isolated from the 
remainder of the pipeline and cathodically protected; or
    (2) The entire buried or submerged pipeline must be cathodically 
protected at a cathodic potential that meets the requirements of 
appendix D of this part for amphoteric metals.
    (c) The amount of cathodic protection must be controlled so as not 
to damage the protective coating or the pipe.



Sec.  192.465  External corrosion control: Monitoring and remediation.

    (a) Each pipeline that is under cathodic protection must be tested 
at least once each calendar year, but with intervals not exceeding 15 
months, to determine whether the cathodic protection meets the 
requirements of Sec.  192.463. However, if tests at those intervals are 
impractical for separately protected short sections of mains or 
transmission lines, not in excess of 100 feet (30 meters), or separately 
protected service lines, these pipelines may be surveyed on a sampling 
basis. At least 10 percent of these protected structures, distributed 
over the entire system must be surveyed each calendar year, with a 
different 10 percent checked each subsequent year, so that the entire 
system is tested in each 10-year period.
    (b) Cathodic protection rectifiers and impressed current power 
sources must be periodically inspected as follows:
    (1) Each cathodic protection rectifier or impressed current power 
source must be inspected six times each calendar year, but with 
intervals not exceeding 2\1/2\ months between inspections, to ensure 
adequate amperage and voltage levels needed to provide cathodic 
protection are maintained. This may be done either through remote 
measurement or through an onsite inspection of the rectifier.

[[Page 495]]

    (2) After January 1, 2022, each remotely inspected rectifier must be 
physically inspected for continued safe and reliable operation at least 
once each calendar year, but with intervals not exceeding 15 months.
    (c) Each reverse current switch, each diode, and each interference 
bond whose failure would jeopardize structure protection must be 
electrically checked for proper performance six times each calendar 
year, but with intervals not exceeding 2\1/2\ months. Each other 
interference bond must be checked at least once each calendar year, but 
with intervals not exceeding 15 months.
    (d) Each operator must promptly correct any deficiencies indicated 
by the inspection and testing required by paragraphs (a) through (c) of 
this section. For onshore gas transmission pipelines, each operator must 
develop a remedial action plan and apply for any necessary permits 
within 6 months of completing the inspection or testing that identified 
the deficiency. Remedial action must be completed promptly, but no later 
than the earliest of the following: prior to the next inspection or test 
interval required by this section; within 1 year, not to exceed 15 
months, of the inspection or test that identified the deficiency; or as 
soon as practicable, not to exceed 6 months, after obtaining any 
necessary permits.
    (e) After the initial evaluation required by Sec. Sec.  192.455(b) 
and (c) and 192.457(b), each operator must, not less than every 3 years 
at intervals not exceeding 39 months, reevaluate its unprotected 
pipelines and cathodically protect them in accordance with this subpart 
in areas in which active corrosion is found. The operator must determine 
the areas of active corrosion by electrical survey. However, on 
distribution lines and where an electrical survey is impractical on 
transmission lines, areas of active corrosion may be determined by other 
means that include review and analysis of leak repair and inspection 
records, corrosion monitoring records, exposed pipe inspection records, 
and the pipeline environment.
    (f) An operator must determine the extent of the area with 
inadequate cathodic protection for onshore gas transmission pipelines 
where any annual test station reading (pipe-to-soil potential 
measurement) indicates cathodic protection levels below the required 
levels in appendix D to this part.
    (1) Gas transmission pipeline operators must investigate and 
mitigate any non-systemic or location-specific causes.
    (2) To address systemic causes, an operator must conduct close 
interval surveys in both directions from the test station with a low 
cathodic protection reading at a maximum interval of approximately 5 
feet or less. An operator must conduct close interval surveys unless it 
is impractical based upon geographical, technical, or safety reasons. An 
operator must complete close interval surveys required by this section 
with the protective current interrupted unless it is impractical to do 
so for technical or safety reasons. An operator must remediate areas 
with insufficient cathodic protection levels, or areas where protective 
current is found to be leaving the pipeline, in accordance with 
paragraph (d) of this section. An operator must confirm the restoration 
of adequate cathodic protection following the implementation of remedial 
actions undertaken to mitigate systemic causes of external corrosion.

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43 
FR 39390, Sept. 5, 1978; Amdt. 192-35A, 45 FR 23441, Apr. 7, 1980; Amdt. 
192-85, 63 FR 37504, July 13, 1998; Amdt. 192-93, 68 FR 53900, Sept. 15, 
2003; Amdt. 192-114, 75 FR 48603, Aug. 11, 2010; 86 FR 2240, Jan. 11, 
2021; Amdt. 192-132, 87 FR 52269, Aug. 24, 2022]



Sec.  192.467  External corrosion control: Electrical isolation.

    (a) Each buried or submerged pipeline must be electrically isolated 
from other underground metallic structures, unless the pipeline and the 
other structures are electrically interconnected and cathodically 
protected as a single unit.
    (b) One or more insulating devices must be installed where 
electrical isolation of a portion of a pipeline is necessary to 
facilitate the application of corrosion control.
    (c) Except for unprotected copper inserted in ferrous pipe, each 
pipeline

[[Page 496]]

must be electrically isolated from metallic casings that are a part of 
the underground system. However, if isolation is not achieved because it 
is impractical, other measures must be taken to minimize corrosion of 
the pipeline inside the casing.
    (d) Inspection and electrical tests must be made to assure that 
electrical isolation is adequate.
    (e) An insulating device may not be installed in an area where a 
combustible atmosphere is anticipated unless precautions are taken to 
prevent arcing.
    (f) Where a pipeline is located in close proximity to electrical 
transmission tower footings, ground cables or counterpoise, or in other 
areas where fault currents or unusual risk of lightning may be 
anticipated, it must be provided with protection against damage due to 
fault currents or lightning, and protective measures must also be taken 
at insulating devices.

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43 
FR 39390, Sept. 5, 1978]



Sec.  192.469  External corrosion control: Test stations.

    Each pipeline under cathodic protection required by this subpart 
must have sufficient test stations or other contact points for 
electrical measurement to determine the adequacy of cathodic protection.

[Amdt. 192-27, 41 FR 34606, Aug. 16, 1976]



Sec.  192.471  External corrosion control: Test leads.

    (a) Each test lead wire must be connected to the pipeline so as to 
remain mechanically secure and electrically conductive.
    (b) Each test lead wire must be attached to the pipeline so as to 
minimize stress concentration on the pipe.
    (c) Each bared test lead wire and bared metallic area at point of 
connection to the pipeline must be coated with an electrical insulating 
material compatible with the pipe coating and the insulation on the 
wire.



Sec.  192.473  External corrosion control: Interference currents.

    (a) Each operator whose pipeline system is subjected to stray 
currents shall have in effect a continuing program to minimize the 
detrimental effects of such currents.
    (b) Each impressed current type cathodic protection system or 
galvanic anode system must be designed and installed so as to minimize 
any adverse effects on existing adjacent underground metallic 
structures.
    (c) For onshore gas transmission pipelines, the program required by 
paragraph (a) of this section must include:
    (1) Interference surveys for a pipeline system to detect the 
presence and level of any electrical stray current. Interference surveys 
must be conducted when potential monitoring indicates a significant 
increase in stray current, or when new potential stray current sources 
are introduced, such as through co-located pipelines, structures, or 
high voltage alternating current (HVAC) power lines, including from 
additional generation, a voltage up-rating, additional lines, new or 
enlarged power substations, or new pipelines or other structures;
    (2) Analysis of the results of the survey to determine the cause of 
the interference and whether the level could cause significant 
corrosion, impede safe operation, or adversely affect the environment or 
public;
    (3) Development of a remedial action plan to correct any instances 
where interference current is greater than or equal to 100 amps per 
meter squared alternating current (AC), or if it impedes the safe 
operation of a pipeline, or if it may cause a condition that would 
adversely impact the environment or the public; and
    (4) Application for any necessary permits within 6 months of 
completing the interference survey that identified the deficiency. An 
operator must complete remedial actions promptly, but no later than the 
earliest of the following: within 15 months after completing the 
interference survey that identified the deficiency; or as soon as 
practicable, but not to exceed 6 months, after obtaining any necessary 
permits.

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43 
FR 39390, Sept. 5, 1978; Amdt. 192-132, 87 FR 92269, Aug. 24, 2022; 
Amdt. 192-133, 88 FR 24711, Apr. 24, 2023]

[[Page 497]]



Sec.  192.475  Internal corrosion control: General.

    (a) Corrosive gas may not be transported by pipeline, unless the 
corrosive effect of the gas on the pipeline has been investigated and 
steps have been taken to minimize internal corrosion.
    (b) Whenever any pipe is removed from a pipeline for any reason, the 
internal surface must be inspected for evidence of corrosion. If 
internal corrosion is found--
    (1) The adjacent pipe must be investigated to determine the extent 
of internal corrosion;
    (2) Replacement must be made to the extent required by the 
applicable paragraphs of Sec. Sec.  192.485, 192.487, or 192.489; and
    (3) Steps must be taken to minimize the internal corrosion.
    (c) Gas containing more than 0.25 grain of hydrogen sulfide per 100 
cubic feet (5.8 milligrams/m\.3\) at standard conditions (4 parts per 
million) may not be stored in pipe-type or bottle-type holders.

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43 
FR 39390, Sept. 5, 1978; Amdt. 192-78, 61 FR 28785, June 6, 1996; Amdt. 
192-85, 63 FR 37504, July 13, 1998]



Sec.  192.476  Internal corrosion control: Design and construction of 
transmission line.

    (a) Design and construction. Except as provided in paragraph (b) of 
this section, each new transmission line and each replacement of line 
pipe, valve, fitting, or other line component in a transmission line 
must have features incorporated into its design and construction to 
reduce the risk of internal corrosion. At a minimum, unless it is 
impracticable or unnecessary to do so, each new transmission line or 
replacement of line pipe, valve, fitting, or other line component in a 
transmission line must:
    (1) Be configured to reduce the risk that liquids will collect in 
the line;
    (2) Have effective liquid removal features whenever the 
configuration would allow liquids to collect; and
    (3) Allow use of devices for monitoring internal corrosion at 
locations with significant potential for internal corrosion.
    (b) Exceptions to applicability. The design and construction 
requirements of paragraph (a) of this section do not apply to the 
following:
    (1) Offshore pipeline; and
    (2) Pipeline installed or line pipe, valve, fitting or other line 
component replaced before May 23, 2007.
    (c) Change to existing transmission line. When an operator changes 
the configuration of a transmission line, the operator must evaluate the 
impact of the change on internal corrosion risk to the downstream 
portion of an existing onshore transmission line and provide for removal 
of liquids and monitoring of internal corrosion as appropriate.
    (d) Records. An operator must maintain records demonstrating 
compliance with this section. Provided the records show why 
incorporating design features addressing paragraph (a)(1), (a)(2), or 
(a)(3) of this section is impracticable or unnecessary, an operator may 
fulfill this requirement through written procedures supported by as-
built drawings or other construction records.

[72 FR 20059, Apr. 23, 2007]



Sec.  192.477  Internal corrosion control: Monitoring.

    If corrosive gas is being transported, coupons or other suitable 
means must be used to determine the effectiveness of the steps taken to 
minimize internal corrosion. Each coupon or other means of monitoring 
internal corrosion must be checked two times each calendar year, but 
with intervals not exceeding 7\1/2\ months.

[Amdt. 192-33, 43 FR 39390, Sept. 5, 1978]



Sec.  192.478  Internal corrosion control: Onshore transmission monitoring 
and mitigation.

    (a) Each operator of an onshore gas transmission pipeline with 
corrosive constituents in the gas being transported must develop and 
implement a monitoring and mitigation program to mitigate the corrosive 
effects, as necessary. Potentially corrosive constituents include, but 
are not limited to: carbon dioxide, hydrogen sulfide, sulfur, microbes, 
and liquid water, either by itself or in combination. An operator must 
evaluate the partial pressure

[[Page 498]]

of each corrosive constituent, where applicable, by itself or in 
combination, to evaluate the effect of the corrosive constituents on the 
internal corrosion of the pipe and implement mitigation measures as 
necessary.
    (b) The monitoring and mitigation program described in paragraph (a) 
of this section must include:
    (1) The use of gas-quality monitoring methods at points where gas 
with potentially corrosive contaminants enters the pipeline to determine 
the gas stream constituents.
    (2) Technology to mitigate the potentially corrosive gas stream 
constituents. Such technologies may include product sampling, inhibitor 
injections, in-line cleaning pigging, separators, or other technology 
that mitigates potentially corrosive effects.
    (3) An evaluation at least once each calendar year, at intervals not 
to exceed 15 months, to ensure that potentially corrosive gas stream 
constituents are effectively monitored and mitigated.
    (c) An operator must review its monitoring and mitigation program at 
least once each calendar year, at intervals not to exceed 15 months, and 
based on the results of its monitoring and mitigation program, implement 
adjustments, as necessary.

[Amdt. 192-132, 87 FR 52270, Aug. 24, 2022]



Sec.  192.479  Atmospheric corrosion control: General.

    (a) Each operator must clean and coat each pipeline or portion of 
pipeline that is exposed to the atmosphere, except pipelines under 
paragraph (c) of this section.
    (b) Coating material must be suitable for the prevention of 
atmospheric corrosion.
    (c) Except portions of pipelines in offshore splash zones or soil-
to-air interfaces, the operator need not protect from atmospheric 
corrosion any pipeline for which the operator demonstrates by test, 
investigation, or experience appropriate to the environment of the 
pipeline that corrosion will--
    (1) Only be a light surface oxide; or
    (2) Not affect the safe operation of the pipeline before the next 
scheduled inspection.

[Amdt. 192-93, 68 FR 53901, Sept. 15, 2003]



Sec.  192.481  Atmospheric corrosion control: Monitoring.

    (a) Each operator must inspect and evaluate each pipeline or portion 
of the pipeline that is exposed to the atmosphere for evidence of 
atmospheric corrosion, as follows:

------------------------------------------------------------------------
                                              Then the frequency of
             Pipeline type:                       inspection is:
------------------------------------------------------------------------
(1) Onshore other than a Service Line..  At least once every 3 calendar
                                          years, but with intervals not
                                          exceeding 39 months.
(2) Onshore Service Line...............  At least once every 5 calendar
                                          years, but with intervals not
                                          exceeding 63 months, except as
                                          provided in paragraph (d) of
                                          this section.
(3) Offshore...........................  At least once each calendar
                                          year, but with intervals not
                                          exceeding 15 months.
------------------------------------------------------------------------

    (b) During inspections the operator must give particular attention 
to pipe at soil-to-air interfaces, under thermal insulation, under 
disbonded coatings, at pipe supports, in splash zones, at deck 
penetrations, and in spans over water.
    (c) If atmospheric corrosion is found during an inspection, the 
operator must provide protection against the corrosion as required by 
Sec.  192.479.
    (d) If atmospheric corrosion is found on a service line during the 
most recent inspection, then the next inspection of that pipeline or 
portion of pipeline must be within 3 calendar years, but with intervals 
not exceeding 39 months.

[Amdt. 192-93, 68 FR 53901, Sept. 15, 2003, as amended at 86 FR 2240, 
Jan. 11, 2021]



Sec.  192.483  Remedial measures: General.

    (a) Each segment of metallic pipe that replaces pipe removed from a 
buried or submerged pipeline because of

[[Page 499]]

external corrosion must have a properly prepared surface and must be 
provided with an external protective coating that meets the requirements 
of Sec.  192.461.
    (b) Each segment of metallic pipe that replaces pipe removed from a 
buried or submerged pipeline because of external corrosion must be 
cathodically protected in accordance with this subpart.
    (c) Except for cast iron or ductile iron pipe, each segment of 
buried or submerged pipe that is required to be repaired because of 
external corrosion must be cathodically protected in accordance with 
this subpart.



Sec.  192.485  Remedial measures: Transmission lines.

    (a) General corrosion. Each segment of transmission line with 
general corrosion and with a remaining wall thickness less than that 
required for the MAOP of the pipeline must be replaced or the operating 
pressure reduced commensurate with the strength of the pipe based on 
actual remaining wall thickness. However, corroded pipe may be repaired 
by a method that reliable engineering tests and analyses show can 
permanently restore the serviceability of the pipe. Corrosion pitting so 
closely grouped as to affect the overall strength of the pipe is 
considered general corrosion for the purpose of this paragraph.
    (b) Localized corrosion pitting. Each segment of transmission line 
pipe with localized corrosion pitting to a degree where leakage might 
result must be replaced or repaired, or the operating pressure must be 
reduced commensurate with the strength of the pipe, based on the actual 
remaining wall thickness in the pits.
    (c) Calculating remaining strength. Under paragraphs (a) and (b) of 
this section, the strength of pipe based on actual remaining wall 
thickness must be determined and documented in accordance with Sec.  
192.712.

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43 
FR 39390, Sept. 5, 1978; Amdt. 192-78, 61 FR 28785, June 6, 1996; Amdt. 
192-88, 64 FR 69664, Dec. 14, 1999; Amdt. 192-119, 80 FR 181, Jan. 5, 
2015; Amdt. 192-132, 87 FR 52270, Aug. 24, 2022]



Sec.  192.487  Remedial measures: Distribution lines other than cast iron 
or ductile iron lines.

    (a) General corrosion. Except for cast iron or ductile iron pipe, 
each segment of generally corroded distribution line pipe with a 
remaining wall thickness less than that required for the MAOP of the 
pipeline, or a remaining wall thickness less than 30 percent of the 
nominal wall thickness, must be replaced. However, corroded pipe may be 
repaired by a method that reliable engineering tests and analyses show 
can permanently restore the serviceability of the pipe. Corrosion 
pitting so closely grouped as to affect the overall strength of the pipe 
is considered general corrosion for the purpose of this paragraph.
    (b) Localized corrosion pitting. Except for cast iron or ductile 
iron pipe, each segment of distribution line pipe with localized 
corrosion pitting to a degree where leakage might result must be 
replaced or repaired.

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-88, 64 
FR 69665, Dec. 14, 1999]



Sec.  192.489  Remedial measures: Cast iron and ductile iron pipelines.

    (a) General graphitization. Each segment of cast iron or ductile 
iron pipe on which general graphitization is found to a degree where a 
fracture or any leakage might result, must be replaced.
    (b) Localized graphitization. Each segment of cast iron or ductile 
iron pipe on which localized graphitization is found to a degree where 
any leakage might result, must be replaced or repaired, or sealed by 
internal sealing methods adequate to prevent or arrest any leakage.



Sec.  192.490  Direct assessment.

    Each operator that uses direct assessment as defined in Sec.  
192.903 on an onshore transmission line made primarily of steel or iron 
to evaluate the effects of a threat in the first column must carry out 
the direct assessment according to the standard listed in the second 
column. These standards do not apply to methods associated with direct 
assessment, such as close interval surveys, voltage gradient surveys, or

[[Page 500]]

examination of exposed pipelines, when used separately from the direct 
assessment process.

------------------------------------------------------------------------
                  Threat                            Standard \1\
------------------------------------------------------------------------
External corrosion.......................  Sec.   192.925 \2\
Internal corrosion in pipelines that       Sec.   192.927
 transport dry gas.
Stress corrosion cracking................  Sec.   192.929
------------------------------------------------------------------------
\1\ For lines not subject to subpart O of this part, the terms ``covered
  segment'' and ``covered pipeline segment'' in Sec.  Sec.   192.925,
  192.927, and 192.929 refer to the pipeline segment on which direct
  assessment is performed.
\2\ In Sec.   192.925(b), the provision regarding detection of coating
  damage applies only to pipelines subject to subpart O of this part.


[Amdt. 192-101, 70 FR 61575, Oct. 25, 2005]



Sec.  192.491  Corrosion control records.

    (a) Each operator shall maintain records or maps to show the 
location of cathodically protected piping, cathodic protection 
facilities, galvanic anodes, and neighboring structures bonded to the 
cathodic protection system. Records or maps showing a stated number of 
anodes, installed in a stated manner or spacing, need not show specific 
distances to each buried anode.
    (b) Each record or map required by paragraph (a) of this section 
must be retained for as long as the pipeline remains in service.
    (c) Each operator shall maintain a record of each test, survey, or 
inspection required by this subpart in sufficient detail to demonstrate 
the adequacy of corrosion control measures or that a corrosive condition 
does not exist. These records must be retained for at least 5 years with 
the following exceptions:
    (1) Operators must retain records related to Sec. Sec.  192.465(a) 
and (e) and 192.475(b) for as long as the pipeline remains in service.
    (2) Operators must retain records of the two most recent atmospheric 
corrosion inspections for each distribution service line that is being 
inspected under the interval in Sec.  192.481(a)(2).

[Amdt. 192-78, 61 FR 28785, June 6, 1996, as amended at 86 FR 2241, Jan. 
11, 2021]



Sec.  192.493  In-line inspection of pipelines.

    When conducting in-line inspections of pipelines required by this 
part, an operator must comply with API STD 1163, ANSI/ASNT ILI-PQ, and 
NACE SP0102, (incorporated by reference, see Sec.  192.7). Assessments 
may be conducted using tethered or remotely controlled tools, not 
explicitly discussed in NACE SP0102, provided they comply with those 
sections of NACE SP0102 that are applicable.

[Amdt. 192-125, 84 FR 52245, Oct. 1, 2019]



                       Subpart J_Test Requirements



Sec.  192.501  Scope.

    This subpart prescribes minimum leak-test and strength-test 
requirements for pipelines.



Sec.  192.503  General requirements.

    (a) No person may operate a new segment of pipeline, or return to 
service a segment of pipeline that has been relocated or replaced, 
until--
    (1) It has been tested in accordance with this subpart and Sec.  
192.619 to substantiate the maximum allowable operating pressure; and
    (2) Each potentially hazardous leak has been located and eliminated.
    (b) The test medium must be liquid, air, natural gas, or inert gas 
that is--
    (1) Compatible with the material of which the pipeline is 
constructed;
    (2) Relatively free of sedimentary materials; and
    (3) Except for natural gas, nonflammable.
    (c) Except as provided in Sec.  192.505(a), if air, natural gas, or 
inert gas is used as the test medium, the following maximum hoop stress 
limitations apply:

------------------------------------------------------------------------
                                       Maximum hoop stress allowed as
                                             percentage of SMYS
          Class location           -------------------------------------
                                       Natural gas      Air or inert gas
------------------------------------------------------------------------
1.................................         80                 80
2.................................         30                 75
3.................................         30                 50
4.................................         30                 40
------------------------------------------------------------------------

    (d) Each joint used to tie in a test segment of pipeline is excepted 
from the specific test requirements of this subpart, but each non-welded 
joint must be leak tested at not less than its operating pressure.
    (e) If a component other than pipe is the only item being replaced 
or added

[[Page 501]]

to a pipeline, a strength test after installation is not required, if 
the manufacturer of the component certifies that:
    (1) The component was tested to at least the pressure required for 
the pipeline to which it is being added;
    (2) The component was manufactured under a quality control system 
that ensures that each item manufactured is at least equal in strength 
to a prototype and that the prototype was tested to at least the 
pressure required for the pipeline to which it is being added; or
    (3) The component carries a pressure rating established through 
applicable ASME/ANSI, Manufacturers Standardization Society of the Valve 
and Fittings Industry, Inc. (MSS) specifications, or by unit strength 
calculations as described in Sec.  192.143.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, 
Jan. 21, 1988; Amdt. 192-60, 53 FR 36029, Sept. 16, 1988; Amdt. 192-60A, 
54 FR 5485, Feb. 3, 1989; Amdt. 192-120, 80 FR 12779, Mar. 11, 2015]



Sec.  192.505  Strength test requirements for steel pipeline to operate at 
a hoop stress of 30 percent or more of SMYS.

    (a) Except for service lines, each segment of a steel pipeline that 
is to operate at a hoop stress of 30 percent or more of SMYS must be 
strength tested in accordance with this section to substantiate the 
proposed maximum allowable operating pressure. In addition, in a Class 1 
or Class 2 location, if there is a building intended for human occupancy 
within 300 feet (91 meters) of a pipeline, a hydrostatic test must be 
conducted to a test pressure of at least 125 percent of maximum 
operating pressure on that segment of the pipeline within 300 feet (91 
meters) of such a building, but in no event may the test section be less 
than 600 feet (183 meters) unless the length of the newly installed or 
relocated pipe is less than 600 feet (183 meters). However, if the 
buildings are evacuated while the hoop stress exceeds 50 percent of 
SMYS, air or inert gas may be used as the test medium.
    (b) In a Class 1 or Class 2 location, each compressor station 
regulator station, and measuring station, must be tested to at least 
Class 3 location test requirements.
    (c) Except as provided in paragraph (d) of this section, the 
strength test must be conducted by mai ntaining the pressure at or above 
the test pressure for at least 8 hours.
    (d) For fabricated units and short sections of pipe, for which a 
post installation test is impractical, a preinstallation strength test 
must be conducted by maintaining the pressure at or above the test 
pressure for at least 4 hours.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37504, 
July 13, 1998; Amdt. 192-94, 69 FR 32895, June 14, 2004; Amdt. 195-94, 
69 FR 54592, Sept. 9, 2004; Amdt. 192-120, 80 FR 12779, Mar. 11, 2015; 
86 FR 2241, Jan. 11, 2021]



Sec.  192.506  Transmission lines: Spike hydrostatic pressure test.

    (a) Spike test requirements. Whenever a segment of steel 
transmission pipeline that is operated at a hoop stress level of 30 
percent or more of SMYS is spike tested under this part, the spike 
hydrostatic pressure test must be conducted in accordance with this 
section.
    (1) The test must use water as the test medium.
    (2) The baseline test pressure must be as specified in the 
applicable paragraphs of Sec.  192.619(a)(2) or Sec.  192.620(a)(2), 
whichever applies.
    (3) The test must be conducted by maintaining a pressure at or above 
the baseline test pressure for at least 8 hours as specified in Sec.  
192.505.
    (4) After the test pressure stabilizes at the baseline pressure and 
within the first 2 hours of the 8-hour test interval, the hydrostatic 
pressure must be raised (spiked) to a minimum of the lesser of 1.5 times 
MAOP or 100% SMYS. This spike hydrostatic pressure test must be held for 
at least 15 minutes after the spike test pressure stabilizes.
    (b) Other technology or other technical evaluation process. 
Operators may use other technology or another process supported by a 
documented engineering analysis for establishing a spike hydrostatic 
pressure test or equivalent. Operators must notify PHMSA 90 days in 
advance of the assessment or reassessment requirements of this 
subchapter.

[[Page 502]]

The notification must be made in accordance with Sec.  192.18 and must 
include the following information:
    (1) Descriptions of the technology or technologies to be used for 
all tests, examinations, and assessments;
    (2) Procedures and processes to conduct tests, examinations, 
assessments, perform evaluations, analyze defects, and remediate defects 
discovered;
    (3) Data requirements, including original design, maintenance and 
operating history, anomaly or flaw characterization;
    (4) Assessment techniques and acceptance criteria;
    (5) Remediation methods for assessment findings;
    (6) Spike hydrostatic pressure test monitoring and acceptance 
procedures, if used;
    (7) Procedures for remaining crack growth analysis and pipeline 
segment life analysis for the time interval for additional assessments, 
as required; and
    (8) Evidence of a review of all procedures and assessments by a 
qualified technical subject matter expert.

[Amdt. 192-125, 84 FR 52245, Oct. 1, 2019]



Sec.  192.507  Test requirements for pipelines to operate at a hoop stress  
less than 30 percent of SMYS and at or above 100 p.s.i. (689 kPa) gage.

    Except for service lines and plastic pipelines, each segment of a 
pipeline that is to be operated at a hoop stress less than 30 percent of 
SMYS and at or above 100 p.s.i. (689 kPa) gage must be tested in 
accordance with the following:
    (a) The pipeline operator must use a test procedure that will ensure 
discovery of all potentially hazardous leaks in the segment being 
tested.
    (b) If, during the test, the segment is to be stressed to 20 percent 
or more of SMYS and natural gas, inert gas, or air is the test medium--
    (1) A leak test must be made at a pressure between 100 p.s.i. (689 
kPa) gage and the pressure required to produce a hoop stress of 20 
percent of SMYS; or
    (2) The line must be walked to check for leaks while the hoop stress 
is held at approximately 20 percent of SMYS.
    (c) The pressure must be maintained at or above the test pressure 
for at least 1 hour.
    (d) For fabricated units and short sections of pipe, for which a 
post installation test is impractical, a preinstallation pressure test 
must be conducted in accordance with the requirements of this section.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, 
Jan. 21, 1988; Amdt. 192-85, 63 FR 37504, July 13, 1998; 86 FR 2241, 
Jan. 21, 2021; 86 FR 12836, Mar. 5, 2021]



Sec.  192.509  Test requirements for pipelines to operate below 100 p.s.i. 
(689 kPa) gage.

    Except for service lines and plastic pipelines, each segment of a 
pipeline that is to be operated below 100 p.s.i. (689 kPa) gage must be 
leak tested in accordance with the following:
    (a) The test procedure used must ensure discovery of all potentially 
hazardous leaks in the segment being tested.
    (b) Each main that is to be operated at less than 1 p.s.i. (6.9 kPa) 
gage must be tested to at least 10 p.s.i. (69 kPa) gage and each main to 
be operated at or above 1 p.s.i. (6.9 kPa) gage must be tested to at 
least 90 p.s.i. (621 kPa) gage.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, 
Jan. 21, 1988; Amdt. 192-85, 63 FR 37504, July 13, 1998]



Sec.  192.511  Test requirements for service lines.

    (a) Each segment of a service line (other than plastic) must be leak 
tested in accordance with this section before being placed in service. 
If feasible, the service line connection to the main must be included in 
the test; if not feasible, it must be given a leakage test at the 
operating pressure when placed in service.
    (b) Each segment of a service line (other than plastic) intended to 
be operated at a pressure of at least 1 p.s.i. (6.9 kPa) gage but not 
more than 40 p.s.i. (276 kPa) gage must be given a leak test at a 
pressure of not less than 50 p.s.i. (345 kPa) gage.
    (c) Each segment of a service line (other than plastic) intended to 
be operated at pressures of more than 40 p.s.i. (276 kPa) gage must be 
tested to

[[Page 503]]

at least 90 p.s.i. (621 kPa) gage, except that each segment of a steel 
service line stressed to 20 percent or more of SMYS must be tested in 
accordance with Sec.  192.507 of this subpart.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-74, 61 FR 18517, 
Apr. 26, 1996; Amdt. 192-85, 63 FR 37504, July 13, 1998]



Sec.  192.513  Test requirements for plastic pipelines.

    (a) Each segment of a plastic pipeline must be tested in accordance 
with this section.
    (b) The test procedure must insure discovery of all potentially 
hazardous leaks in the segment being tested.
    (c) The test pressure must be at least 150% of the maximum operating 
pressure or 50 psi (345 kPa) gauge, whichever is greater. However, the 
maximum test pressure may not be more than 2.5 times the pressure 
determined under Sec.  192.121 at a temperature not less than the pipe 
temperature during the test.
    (d) During the test, the temperature of thermoplastic material may 
not be more than 100 [deg]F (38 [deg]C), or the temperature at which the 
material's long-term hydrostatic strength has been determined under the 
listed specification, whichever is greater.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-77, 61 FR 27793, 
June 3, 1996; 61 FR 45905, Aug. 30, 1996; Amdt. 192-85, 63 FR 37504, 
July 13, 1998; Amdt. 192-124, 83 FR 58719, Nov. 20, 2018]



Sec.  192.515  Environmental protection and safety requirements.

    (a) In conducting tests under this subpart, each operator shall 
insure that every reasonable precaution is taken to protect its 
employees and the general public during the testing. Whenever the hoop 
stress of the segment of the pipeline being tested will exceed 50 
percent of SMYS, the operator shall take all practicable steps to keep 
persons not working on the testing operation outside of the testing area 
until the pressure is reduced to or below the proposed maximum allowable 
operating pressure.
    (b) The operator shall insure that the test medium is disposed of in 
a manner that will minimize damage to the environment.



Sec.  192.517  Records.

    (a) An operator must make, and retain for the useful life of the 
pipeline, a record of each test performed under Sec. Sec.  192.505, 
192.506, and 192.507. The record must contain at least the following 
information:
    (1) The operator's name, the name of the operator's employee 
responsible for making the test, and the name of any test company used.
    (2) Test medium used.
    (3) Test pressure.
    (4) Test duration.
    (5) Pressure recording charts, or other record of pressure readings.
    (6) Elevation variations, whenever significant for the particular 
test.
    (7) Leaks and failures noted and their disposition.
    (b) Each operator must maintain a record of each test required by 
Sec. Sec.  192.509, 192.511, and 192.513 for at least 5 years.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-93, 68 FR 53901, 
Sept. 15, 2003; Amdt. 192-125, 84 FR 52245, Oct. 1, 2019]



                           Subpart K_Uprating



Sec.  192.551  Scope.

    This subpart prescribes minimum requirements for increasing maximum 
allowable operating pressures (uprating) for pipelines.



Sec.  192.553  General requirements.

    (a) Pressure increases. Whenever the requirements of this subpart 
require that an increase in operating pressure be made in increments, 
the pressure must be increased gradually, at a rate that can be 
controlled, and in accordance with the following:
    (1) At the end of each incremental increase, the pressure must be 
held constant while the entire segment of pipeline that is affected is 
checked for leaks.
    (2) Each leak detected must be repaired before a further pressure 
increase is made, except that a leak determined not to be potentially 
hazardous need not be repaired, if it is monitored during the pressure 
increase and it does not become potentially hazardous.

[[Page 504]]

    (b) Records. Each operator who uprates a segment of pipeline shall 
retain for the life of the segment a record of each investigation 
required by this subpart, of all work performed, and of each pressure 
test conducted, in connection with the uprating.
    (c) Written plan. Each operator who uprates a segment of pipeline 
shall establish a written procedure that will ensure that each 
applicable requirement of this subpart is complied with.
    (d) Limitation on increase in maximum allowable operating pressure. 
Except as provided in Sec.  192.555(c), a new maximum allowable 
operating pressure established under this subpart may not exceed the 
maximum that would be allowed under Sec. Sec.  192.619 and 192.621 for a 
new segment of pipeline constructed of the same materials in the same 
location. However, when uprating a steel pipeline, if any variable 
necessary to determine the design pressure under the design formula 
(Sec.  192.105) is unknown, the MAOP may be increased as provided in 
Sec.  192.619(a)(1).

[35 FR 13257, Aug. 10, 1970, as amended by Amdt. 192-78, 61 FR 28785, 
June 6, 1996; Amdt. 192-93, 68 FR 53901, Sept. 15, 2003]



Sec.  192.555  Uprating to a pressure that will produce a hoop stress of  
30 percent or more of SMYS in steel pipelines.

    (a) Unless the requirements of this section have been met, no person 
may subject any segment of a steel pipeline to an operating pressure 
that will produce a hoop stress of 30 percent or more of SMYS and that 
is above the established maximum allowable operating pressure.
    (b) Before increasing operating pressure above the previously 
established maximum allowable operating pressure the operator shall:
    (1) Review the design, operating, and maintenance history and 
previous testing of the segment of pipeline and determine whether the 
proposed increase is safe and consistent with the requirements of this 
part; and
    (2) Make any repairs, replacements, or alterations in the segment of 
pipeline that are necessary for safe operation at the increased 
pressure.
    (c) After complying with paragraph (b) of this section, an operator 
may increase the maximum allowable operating pressure of a segment of 
pipeline constructed before September 12, 1970, to the highest pressure 
that is permitted under Sec.  192.619, using as test pressure the 
highest pressure to which the segment of pipeline was previously 
subjected (either in a strength test or in actual operation).
    (d) After complying with paragraph (b) of this section, an operator 
that does not qualify under paragraph (c) of this section may increase 
the previously established maximum allowable operating pressure if at 
least one of the following requirements is met:
    (1) The segment of pipeline is successfully tested in accordance 
with the requirements of this part for a new line of the same material 
in the same location.
    (2) An increased maximum allowable operating pressure may be 
established for a segment of pipeline in a Class 1 location if the line 
has not previously been tested, and if:
    (i) It is impractical to test it in accordance with the requirements 
of this part;
    (ii) The new maximum operating pressure does not exceed 80 percent 
of that allowed for a new line of the same design in the same location; 
and
    (iii) The operator determines that the new maximum allowable 
operating pressure is consistent with the condition of the segment of 
pipeline and the design requirements of this part.
    (e) Where a segment of pipeline is uprated in accordance with 
paragraph (c) or (d)(2) of this section, the increase in pressure must 
be made in increments that are equal to:
    (1) 10 percent of the pressure before the uprating; or
    (2) 25 percent of the total pressure increase,

whichever produces the fewer number of increments.



Sec.  192.557  Uprating: Steel pipelines to a pressure that will produce a 
hoop stress less than 30 percent of SMYS: plastic, cast iron, and ductile  
iron pipelines. 

    (a) Unless the requirements of this section have been met, no person 
may subject:

[[Page 505]]

    (1) A segment of steel pipeline to an operating pressure that will 
produce a hoop stress less than 30 percent of SMYS and that is above the 
previously established maximum allowable operating pressure; or
    (2) A plastic, cast iron, or ductile iron pipeline segment to an 
operating pressure that is above the previously established maximum 
allowable operating pressure.
    (b) Before increasing operating pressure above the previously 
established maximum allowable operating pressure, the operator shall:
    (1) Review the design, operating, and maintenance history of the 
segment of pipeline;
    (2) Make a leakage survey (if it has been more than 1 year since the 
last survey) and repair any leaks that are found, except that a leak 
determined not to be potentially hazardous need not be repaired, if it 
is monitored during the pressure increase and it does not become 
potentially hazardous;
    (3) Make any repairs, replacements, or alterations in the segment of 
pipeline that are necessary for safe operation at the increased 
pressure;
    (4) Reinforce or anchor offsets, bends and dead ends in pipe joined 
by compression couplings or bell and spigot joints to prevent failure of 
the pipe joint, if the offset, bend, or dead end is exposed in an 
excavation;
    (5) Isolate the segment of pipeline in which the pressure is to be 
increased from any adjacent segment that will continue to be operated at 
a lower pressure; and
    (6) If the pressure in mains or service lines, or both, is to be 
higher than the pressure delivered to the customer, install a service 
regulator on each service line and test each regulator to determine that 
it is functioning. Pressure may be increased as necessary to test each 
regulator, after a regulator has been installed on each pipeline subject 
to the increased pressure.
    (c) After complying with paragraph (b) of this section, the increase 
in maximum allowable operating pressure must be made in increments that 
are equal to 10 p.s.i. (69 kPa) gage or 25 percent of the total pressure 
increase, whichever produces the fewer number of increments. Whenever 
the requirements of paragraph (b)(6) of this section apply, there must 
be at least two approximately equal incremental increases.
    (d) If records for cast iron or ductile iron pipeline facilities are 
not complete enough to determine stresses produced by internal pressure, 
trench loading, rolling loads, beam stresses, and other bending loads, 
in evaluating the level of safety of the pipeline when operating at the 
proposed increased pressure, the following procedures must be followed:
    (1) In estimating the stresses, if the original laying conditions 
cannot be ascertained, the operator shall assume that cast iron pipe was 
supported on blocks with tamped backfill and that ductile iron pipe was 
laid without blocks with tamped backfill.
    (2) Unless the actual maximum cover depth is known, the operator 
shall measure the actual cover in at least three places where the cover 
is most likely to be greatest and shall use the greatest cover measured.
    (3) Unless the actual nominal wall thickness is known, the operator 
shall determine the wall thickness by cutting and measuring coupons from 
at least three separate pipe lengths. The coupons must be cut from pipe 
lengths in areas where the cover depth is most likely to be the 
greatest. The average of all measurements taken must be increased by the 
allowance indicated in the following table:

----------------------------------------------------------------------------------------------------------------
                                                                      Allowance inches (millimeters)
                                                        --------------------------------------------------------
                                                                    Cast iron pipe
             Pipe size inches (millimeters)             --------------------------------------
                                                                              Centrifugally    Ductile iron pipe
                                                           Pit cast pipe        cast pipe
----------------------------------------------------------------------------------------------------------------
3 to 8 (76 to 203).....................................       0.075 (1.91)       0.065 (1.65)       0.065 (1.65)
10 to 12 (254 to 305)..................................        0.08 (2.03)        0.07 (1.78)        0.07 (1.78)
14 to 24 (356 to 610)..................................        0.08 (2.03)        0.08 (2.03)       0.075 (1.91)
30 to 42 (762 to 1067).................................        0.09 (2.29)        0.09 (2.29)       0.075 (1.91)
48 (1219)..............................................        0.09 (2.29)        0.09 (2.29)        0.08 (2.03)

[[Page 506]]

 
54 to 60 (1372 to 1524)................................        0.09 (2.29)  .................  .................
----------------------------------------------------------------------------------------------------------------

    (4) For cast iron pipe, unless the pipe manufacturing process is 
known, the operator shall assume that the pipe is pit cast pipe with a 
bursting tensile strength of 11,000 p.s.i. (76 MPa) gage and a modulus 
of rupture of 31,000 p.s.i. (214 MPa) gage.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-37, 46 FR 10160, 
Feb. 2, 1981; Amdt. 192-62, 54 FR 5628, Feb. 6, 1989; Amdt. 195-85, 63 
FR 37504, July 13, 1998]



                          Subpart L_Operations



Sec.  192.601  Scope.

    This subpart prescribes minimum requirements for the operation of 
pipeline facilities.



Sec.  192.603  General provisions.

    (a) No person may operate a segment of pipeline unless it is 
operated in accordance with this subpart.
    (b) Each operator shall keep records necessary to administer the 
procedures established under Sec.  192.605.
    (c) The Associate Administrator or the State Agency that has 
submitted a current certification under the pipeline safety laws, (49 
U.S.C. 60101 et seq.) with respect to the pipeline facility governed by 
an operator's plans and procedures may, after notice and opportunity for 
hearing as provided in 49 CFR 190.206 or the relevant State procedures, 
require the operator to amend its plans and procedures as necessary to 
provide a reasonable level of safety.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-66, 56 FR 31090, 
July 9, 1991; Amdt. 192-71, 59 FR 6584, Feb. 11, 1994; Amdt. 192-75, 61 
FR 18517, Apr. 26, 1996; Amdt. 192-118, 78 FR 58915, Sept. 25, 2013]



Sec.  192.605  Procedural manual for operations, maintenance, and 
emergencies.

    (a) General. Each operator shall prepare and follow for each 
pipeline, a manual of written procedures for conducting operations and 
maintenance activities and for emergency response. For transmission 
lines, the manual must also include procedures for handling abnormal 
operations. This manual must be reviewed and updated by the operator at 
intervals not exceeding 15 months, but at least once each calendar year. 
This manual must be prepared before operations of a pipeline system 
commence. Appropriate parts of the manual must be kept at locations 
where operations and maintenance activities are conducted.
    (b) Maintenance and normal operations. The manual required by 
paragraph (a) of this section must include procedures for the following, 
if applicable, to provide safety during maintenance and operations.
    (1) Operating, maintaining, and repairing the pipeline in accordance 
with each of the requirements of this subpart and subpart M of this 
part.
    (2) Controlling corrosion in accordance with the operations and 
maintenance requirements of subpart I of this part.
    (3) Making construction records, maps, and operating history 
available to appropriate operating personnel.
    (4) Gathering of data needed for reporting incidents under Part 191 
of this chapter in a timely and effective manner.
    (5) Starting up and shutting down any part of the pipeline in a 
manner designed to assure operation within the MAOP limits prescribed by 
this part, plus the build-up allowed for operation of pressure-limiting 
and control devices.
    (6) Maintaining compressor stations, including provisions for 
isolating units or sections of pipe and for purging before returning to 
service.
    (7) Starting, operating and shutting down gas compressor units.
    (8) Periodically reviewing the work done by operator personnel to 
determine the effectiveness, and adequacy of

[[Page 507]]

the procedures used in normal operation and maintenance and modifying 
the procedures when deficiencies are found.
    (9) Taking adequate precautions in excavated trenches to protect 
personnel from the hazards of unsafe accumulations of vapor or gas, and 
making available when needed at the excavation, emergency rescue 
equipment, including a breathing apparatus and, a rescue harness and 
line.
    (10) Systematic and routine testing and inspection of pipe-type or 
bottle-type holders including--
    (i) Provision for detecting external corrosion before the strength 
of the container has been impaired;
    (ii) Periodic sampling and testing of gas in storage to determine 
the dew point of vapors contained in the stored gas which, if condensed, 
might cause internal corrosion or interfere with the safe operation of 
the storage plant; and
    (iii) Periodic inspection and testing of pressure limiting equipment 
to determine that it is in safe operating condition and has adequate 
capacity.
    (11) Responding promptly to a report of a gas odor inside or near a 
building, unless the operator's emergency procedures under Sec.  
192.615(a)(3) specifically apply to these reports.
    (12) Implementing the applicable control room management procedures 
required by Sec.  192.631.
    (c) Abnormal operation. For transmission lines, the manual required 
by paragraph (a) of this section must include procedures for the 
following to provide safety when operating design limits have been 
exceeded:
    (1) Responding to, investigating, and correcting the cause of:
    (i) Unintended closure of valves or shutdowns;
    (ii) Increase or decrease in pressure or flow rate outside normal 
operating limits;
    (iii) Loss of communications;
    (iv) Operation of any safety device; and
    (v) Any other foreseeable malfunction of a component, deviation from 
normal operation, or personnel error, which may result in a hazard to 
persons or property.
    (2) Checking variations from normal operation after abnormal 
operation has ended at sufficient critical locations in the system to 
determine continued integrity and safe operation.
    (3) Notifying responsible operator personnel when notice of an 
abnormal operation is received.
    (4) Periodically reviewing the response of operator personnel to 
determine the effectiveness of the procedures controlling abnormal 
operation and taking corrective action where deficiencies are found.
    (5) The requirements of this paragraph (c) do not apply to natural 
gas distribution operators that are operating transmission lines in 
connection with their distribution system.
    (d) Safety-related condition reports. The manual required by 
paragraph (a) of this section must include instructions enabling 
personnel who perform operation and maintenance activities to recognize 
conditions that potentially may be safety-related conditions that are 
subject to the reporting requirements of Sec.  191.23 of this 
subchapter.
    (e) Surveillance, emergency response, and accident investigation. 
The procedures required by Sec. Sec.  192.613(a), 192.615, and 192.617 
must be included in the manual required by paragraph (a) of this 
section.

[Amdt. 192-71, 59 FR 6584, Feb. 11, 1994, as amended by Amdt. 192-71A, 
60 FR 14381, Mar. 17, 1995; Amdt. 192-93, 68 FR 53901, Sept. 15, 2003; 
Amdt. 192-112, 74 FR 63327, Dec. 3, 2009]



Sec.  192.607  Verification of Pipeline Material Properties and Attributes: 
Onshore steel transmission pipelines.

    (a) Applicability. Wherever required by this part, operators of 
onshore steel transmission pipelines must document and verify material 
properties and attributes in accordance with this section.
    (b) Documentation of material properties and attributes. Records 
established under this section documenting physical pipeline 
characteristics and attributes, including diameter, wall thickness, seam 
type, and grade (e.g., yield strength, ultimate tensile strength, or 
pressure rating for valves and flanges, etc.), must be maintained for 
the life of the pipeline and be traceable, verifiable, and complete. 
Charpy v-notch toughness values established

[[Page 508]]

under this section needed to meet the requirements of the ECA method at 
Sec.  192.624(c)(3) or the fracture mechanics requirements at Sec.  
192.712 must be maintained for the life of the pipeline.
    (c) Verification of material properties and attributes. If an 
operator does not have traceable, verifiable, and complete records 
required by paragraph (b) of this section, the operator must develop and 
implement procedures for conducting nondestructive or destructive tests, 
examinations, and assessments in order to verify the material properties 
of aboveground line pipe and components, and of buried line pipe and 
components when excavations occur at the following opportunities: 
Anomaly direct examinations, in situ evaluations, repairs, remediations, 
maintenance, and excavations that are associated with replacements or 
relocations of pipeline segments that are removed from service. The 
procedures must also provide for the following:
    (1) For nondestructive tests, at each test location, material 
properties for minimum yield strength and ultimate tensile strength must 
be determined at a minimum of 5 places in at least 2 circumferential 
quadrants of the pipe for a minimum total of 10 test readings at each 
pipe cylinder location.
    (2) For destructive tests, at each test location, a set of material 
properties tests for minimum yield strength and ultimate tensile 
strength must be conducted on each test pipe cylinder removed from each 
location, in accordance with API Specification 5L.
    (3) Tests, examinations, and assessments must be appropriate for 
verifying the necessary material properties and attributes.
    (4) If toughness properties are not documented, the procedures must 
include accepted industry methods for verifying pipe material toughness.
    (5) Verification of material properties and attributes for non-line 
pipe components must comply with paragraph (f) of this section.
    (d) Special requirements for nondestructive Methods. Procedures 
developed in accordance with paragraph (c) of this section for 
verification of material properties and attributes using nondestructive 
methods must:
    (1) Use methods, tools, procedures, and techniques that have been 
validated by a subject matter expert based on comparison with 
destructive test results on material of comparable grade and vintage;
    (2) Conservatively account for measurement inaccuracy and 
uncertainty using reliable engineering tests and analyses; and
    (3) Use test equipment that has been properly calibrated for 
comparable test materials prior to usage.
    (e) Sampling multiple segments of pipe. To verify material 
properties and attributes for a population of multiple, comparable 
segments of pipe without traceable, verifiable, and complete records, an 
operator may use a sampling program in accordance with the following 
requirements:
    (1) The operator must define separate populations of similar 
segments of pipe for each combination of the following material 
properties and attributes: Nominal wall thicknesses, grade, 
manufacturing process, pipe manufacturing dates, and construction dates. 
If the dates between the manufacture or construction of the pipeline 
segments exceeds 2 years, those segments cannot be considered as the 
same vintage for the purpose of defining a population under this 
section. The total population mileage is the cumulative mileage of 
pipeline segments in the population. The pipeline segments need not be 
continuous.
    (2) For each population defined according to paragraph (e)(1) of 
this section, the operator must determine material properties at all 
excavations that expose the pipe associated with anomaly direct 
examinations, in situ evaluations, repairs, remediations, or 
maintenance, except for pipeline segments exposed during excavation 
activities pursuant to Sec.  192.614, until completion of the lesser of 
the following:
    (i) One excavation per mile rounded up to the nearest whole number; 
or
    (ii) 150 excavations if the population is more than 150 miles.
    (3) Prior tests conducted for a single excavation according to the 
requirements of paragraph (c) of this section may be counted as one 
sample under the sampling requirements of this paragraph (e).

[[Page 509]]

    (4) If the test results identify line pipe with properties that are 
not consistent with available information or existing expectations or 
assumed properties used for operations and maintenance in the past, the 
operator must establish an expanded sampling program. The expanded 
sampling program must use valid statistical bases designed to achieve at 
least a 95% confidence level that material properties used in the 
operation and maintenance of the pipeline are valid. The approach must 
address how the sampling plan will be expanded to address findings that 
reveal material properties that are not consistent with all available 
information or existing expectations or assumed material properties used 
for pipeline operations and maintenance in the past. Operators must 
notify PHMSA in advance of using an expanded sampling approach in 
accordance with Sec.  192.18.
    (5) An operator may use an alternative statistical sampling approach 
that differs from the requirements specified in paragraph (e)(2) of this 
section. The alternative sampling program must use valid statistical 
bases designed to achieve at least a 95% confidence level that material 
properties used in the operation and maintenance of the pipeline are 
valid. The approach must address how the sampling plan will be expanded 
to address findings that reveal material properties that are not 
consistent with all available information or existing expectations or 
assumed material properties used for pipeline operations and maintenance 
in the past. Operators must notify PHMSA in advance of using an 
alternative sampling approach in accordance with Sec.  192.18.
    (f) Components. For mainline pipeline components other than line 
pipe, an operator must develop and implement procedures in accordance 
with paragraph (c) of this section for establishing and documenting the 
ANSI rating or pressure rating (in accordance with ASME/ANSI B16.5 
(incorporated by reference, see Sec.  192.7)),
    (1) Operators are not required to test for the chemical and 
mechanical properties of components in compressor stations, meter 
stations, regulator stations, separators, river crossing headers, 
mainline valve assemblies, valve operator piping, or cross-connections 
with isolation valves from the mainline pipeline.
    (2) Verification of material properties is required for non-line 
pipe components, including valves, flanges, fittings, fabricated 
assemblies, and other pressure retaining components and appurtenances 
that are:
    (i) Larger than 2 inches in nominal outside diameter,
    (ii) Material grades of 42,000 psi (Grade X-42) or greater, or
    (iii) Appurtenances of any size that are directly installed on the 
pipeline and cannot be isolated from mainline pipeline pressures.
    (3) Procedures for establishing material properties of non-line pipe 
components must be based on the documented manufacturing specification 
for the components. If specifications are not known, usage of 
manufacturer's stamped, marked, or tagged material pressure ratings and 
material type may be used to establish pressure rating. Operators must 
document the method used to determine the pressure rating and the 
findings of that determination.
    (g) Uprating. The material properties determined from the 
destructive or nondestructive tests required by this section cannot be 
used to raise the grade or specification of the material, unless the 
original grade or specification is unknown and MAOP is based on an 
assumed yield strength of 24,000 psi in accordance with Sec.  
192.107(b)(2).

[Amdt. 192-125, 84 FR 52245, Oct. 1, 2019]



Sec.  192.609  Change in class location: Required study.

    Whenever an increase in population density indicates a change in 
class location for a segment of an existing steel pipeline operating at 
hoop stress that is more than 40 percent of SMYS, or indicates that the 
hoop stress corresponding to the established maximum allowable operating 
pressure for a segment of existing pipeline is not commensurate with the 
present class location, the operator shall immediately make a study to 
determine:
    (a) The present class location for the segment involved.

[[Page 510]]

    (b) The design, construction, and testing procedures followed in the 
original construction, and a comparison of these procedures with those 
required for the present class location by the applicable provisions of 
this part.
    (c) The physical condition of the segment to the extent it can be 
ascertained from available records;
    (d) The operating and maintenance history of the segment;
    (e) The maximum actual operating pressure and the corresponding 
operating hoop stress, taking pressure gradient into account, for the 
segment of pipeline involved; and
    (f) The actual area affected by the population density increase, and 
physical barriers or other factors which may limit further expansion of 
the more densely populated area.



Sec.  192.610  Change in class location: Change in valve spacing.

    (a) If a class location change on a transmission pipeline occurs 
after October 5, 2022, and results in pipe replacement, of 2 or more 
miles, in the aggregate, within any 5 contiguous miles within a 24-month 
period, to meet the maximum allowable operating pressure (MAOP) 
requirements in Sec.  192.611, Sec.  192.619, or Sec.  192.620, then the 
requirements in Sec. Sec.  192.179, 192.634, and 192.636, as applicable, 
apply to the new class location, and the operator must install valves, 
including rupture-mitigation valves (RMV) or alternative equivalent 
technologies, as necessary, to comply with those sections. Such valves 
must be installed within 24 months of the class location change in 
accordance with the timing requirement in Sec.  192.611(d) for 
compliance after a class location change.
    (b) If a class location change on a gas transmission pipeline occurs 
after October 5, 2022, and results in pipe replacement of less than 2 
miles within 5 contiguous miles during a 24-month period, to meet the 
MAOP requirements in Sec.  192.611, Sec.  192.619, or Sec.  192.620, 
then within 24 months of the class location change, in accordance with 
Sec.  192.611(d), the operator must either:
    (1) Comply with the valve spacing requirements of Sec.  192.179(a) 
for the replaced pipeline segment; or
    (2) Install or use existing RMVs or alternative equivalent 
technologies so that the entirety of the replaced pipeline segments are 
between at least two RMVs or alternative equivalent technologies. The 
distance between RMVs and alternative equivalent technologies for the 
replaced segment must not exceed 20 miles. The RMVs and alternative 
equivalent technologies must comply with the applicable requirements of 
Sec.  192.636.
    (c) The provisions of paragraph (b) of this section do not apply to 
pipeline replacements that amount to less than 1,000 feet within any one 
contiguous mile during any 24-month period.

[Amdt. 192-130, 87 FR 20983, Apr. 8, 2022, as amended by Amdt. 192-134, 
88 FR 50061, Aug. 1, 2023]



Sec.  192.611  Change in class location: Confirmation or revision of  
maximum allowable operating pressure.

    (a) If the hoop stress corresponding to the established maximum 
allowable operating pressure of a segment of pipeline is not 
commensurate with the present class location, and the segment is in 
satisfactory physical condition, the maximum allowable operating 
pressure of that segment of pipeline must be confirmed or revised 
according to one of the following requirements:
    (1) If the segment involved has been previously tested in place for 
a period of not less than 8 hours:
    (i) The maximum allowable operating pressure is 0.8 times the test 
pressure in Class 2 locations, 0.667 times the test pressure in Class 3 
locations, or 0.555 times the test pressure in Class 4 locations. The 
corresponding hoop stress may not exceed 72 percent of the SMYS of the 
pipe in Class 2 locations, 60 percent of SMYS in Class 3 locations, or 
50 percent of SMYS in Class 4 locations.
    (ii) The alternative maximum allowable operating pressure is 0.8 
times the test pressure in Class 2 locations and 0.667 times the test 
pressure in Class 3 locations. For pipelines operating at alternative 
maximum allowable pressure per Sec.  192.620, the corresponding hoop 
stress may not exceed 80 percent of the SMYS of the pipe in Class 2 
locations and 67 percent of SMYS in Class 3 locations.

[[Page 511]]

    (2) The maximum allowable operating pressure of the segment involved 
must be reduced so that the corresponding hoop stress is not more than 
that allowed by this part for new segments of pipelines in the existing 
class location.
    (3) The segment involved must be tested in accordance with the 
applicable requirements of subpart J of this part, and its maximum 
allowable operating pressure must then be established according to the 
following criteria:
    (i) The maximum allowable operating pressure after the 
requalification test is 0.8 times the test pressure for Class 2 
locations, 0.667 times the test pressure for Class 3 locations, and 
0.555 times the test pressure for Class 4 locations.
    (ii) The corresponding hoop stress may not exceed 72 percent of the 
SMYS of the pipe in Class 2 locations, 60 percent of SMYS in Class 3 
locations, or 50 percent of SMYS in Class 4 locations.
    (iii) For pipeline operating at an alternative maximum allowable 
operating pressure per Sec.  192.620, the alternative maximum allowable 
operating pressure after the requalification test is 0.8 times the test 
pressure for Class 2 locations and 0.667 times the test pressure for 
Class 3 locations. The corresponding hoop stress may not exceed 80 
percent of the SMYS of the pipe in Class 2 locations and 67 percent of 
SMYS in Class 3 locations.
    (b) The maximum allowable operating pressure confirmed or revised in 
accordance with this section, may not exceed the maximum allowable 
operating pressure established before the confirmation or revision.
    (c) Confirmation or revision of the maximum allowable operating 
pressure of a segment of pipeline in accordance with this section does 
not preclude the application of Sec. Sec.  192.553 and 192.555.
    (d) Confirmation or revision of the maximum allowable operating 
pressure that is required as a result of a study under Sec.  192.609 
must be completed within 24 months of the change in class location. 
Pressure reduction under paragraph (a) (1) or (2) of this section within 
the 24-month period does not preclude establishing a maximum allowable 
operating pressure under paragraph (a)(3) of this section at a later 
date.

[Amdt. 192-63A, 54 FR 24174, June 6, 1989, as amended by Amdt. 192-78, 
61 FR 28785, June 6, 1996; Amdt. 192-94, 69 FR 32895, June 14, 2004; 73 
FR 62177, Oct. 17, 2008]



Sec.  192.612  Underwater inspection and reburial of pipelines in the Gulf  
of Mexico and its inlets.

    (a) Each operator shall prepare and follow a procedure to identify 
its pipelines in the Gulf of Mexico and its inlets in waters less than 
15 feet (4.6 meters) deep as measured from mean low water that are at 
risk of being an exposed underwater pipeline or a hazard to navigation. 
The procedures must be in effect August 10, 2005.
    (b) Each operator shall conduct appropriate periodic underwater 
inspections of its pipelines in the Gulf of Mexico and its inlets in 
waters less than 15 feet (4.6 meters) deep as measured from mean low 
water based on the identified risk.
    (c) If an operator discovers that its pipeline is an exposed 
underwater pipeline or poses a hazard to navigation, the operator 
shall--
    (1) Promptly, but not later than 24 hours after discovery, notify 
the National Response Center, telephone: 1-800-424-8802, of the location 
and, if available, the geographic coordinates of that pipeline.
    (2) Promptly, but not later than 7 days after discovery, mark the 
location of the pipeline in accordance with 33 CFR part 64 at the ends 
of the pipeline segment and at intervals of not over 500 yards (457 
meters) long, except that a pipeline segment less than 200 yards (183 
meters) long need only be marked at the center; and
    (3) Within 6 months after discovery, or not later than November 1 of 
the following year if the 6 month period is later than November 1 of the 
year of discovery, bury the pipeline so that the top of the pipe is 36 
inches (914 millimeters) below the underwater natural bottom (as 
determined by recognized and generally accepted practices) for normal 
excavation or 18 inches (457 millimeters) for rock excavation.
    (i) An operator may employ engineered alternatives to burial that 
meet

[[Page 512]]

or exceed the level of protection provided by burial.
    (ii) If an operator cannot obtain required state or Federal permits 
in time to comply with this section, it must notify OPS; specify whether 
the required permit is State or Federal; and, justify the delay.

[Amdt. 192-98, 69 FR 48406, Aug. 10, 2004]



Sec.  192.613  Continuing surveillance.

    (a) Each operator shall have a procedure for continuing surveillance 
of its facilities to determine and take appropriate action concerning 
changes in class location, failures, leakage history, corrosion, 
substantial changes in cathodic protection requirements, and other 
unusual operating and maintenance conditions.
    (b) If a segment of pipeline is determined to be in unsatisfactory 
condition but no immediate hazard exists, the operator shall initiate a 
program to recondition or phase out the segment involved, or, if the 
segment cannot be reconditioned or phased out, reduce the maximum 
allowable operating pressure in accordance with Sec.  192.619 (a) and 
(b).
    (c) Following an extreme weather event or natural disaster that has 
the likelihood of damage to pipeline facilities by the scouring or 
movement of the soil surrounding the pipeline or movement of the 
pipeline, such as a named tropical storm or hurricane; a flood that 
exceeds the river, shoreline, or creek high-water banks in the area of 
the pipeline; a landslide in the area of the pipeline; or an earthquake 
in the area of the pipeline, an operator must inspect all potentially 
affected onshore transmission pipeline facilities to detect conditions 
that could adversely affect the safe operation of that pipeline.
    (1) An operator must assess the nature of the event and the physical 
characteristics, operating conditions, location, and prior history of 
the affected pipeline in determining the appropriate method for 
performing the initial inspection to determine the extent of any damage 
and the need for the additional assessments required under this 
paragraph (c)(1).
    (2) An operator must commence the inspection required by paragraph 
(c) of this section within 72 hours after the point in time when the 
operator reasonably determines that the affected area can be safely 
accessed by personnel and equipment, and the personnel and equipment 
required to perform the inspection as determined by paragraph (c)(1) of 
this section are available. If an operator is unable to commence the 
inspection due to the unavailability of personnel or equipment, the 
operator must notify the appropriate PHMSA Region Director as soon as 
practicable.
    (3) An operator must take prompt and appropriate remedial action to 
ensure the safe operation of a pipeline based on the information 
obtained as a result of performing the inspection required by paragraph 
(c) of this section. Such actions might include, but are not limited to:
    (i) Reducing the operating pressure or shutting down the pipeline;
    (ii) Modifying, repairing, or replacing any damaged pipeline 
facilities;
    (iii) Preventing, mitigating, or eliminating any unsafe conditions 
in the pipeline right-of-way;
    (iv) Performing additional patrols, surveys, tests, or inspections;
    (v) Implementing emergency response activities with Federal, State, 
or local personnel; or
    (vi) Notifying affected communities of the steps that can be taken 
to ensure public safety.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-132, 87 FR 52270, 
Aug. 24, 2022]



Sec.  192.614  Damage prevention program.

    (a) Except as provided in paragraphs (d) and (e) of this section, 
each operator of a buried pipeline must carry out, in accordance with 
this section, a written program to prevent damage to that pipeline from 
excavation activities. For the purposes of this section, the term 
``excavation activities'' includes excavation, blasting, boring, 
tunneling, backfilling, the removal of aboveground structures by either 
explosive or mechanical means, and other earthmoving operations.
    (b) An operator may comply with any of the requirements of paragraph 
(c) of this section through participation in a public service program, 
such as a one-call system, but such participation

[[Page 513]]

does not relieve the operator of responsibility for compliance with this 
section. However, an operator must perform the duties of paragraph 
(c)(3) of this section through participation in a one-call system, if 
that one-call system is a qualified one-call system. In areas that are 
covered by more than one qualified one-call system, an operator need 
only join one of the qualified one-call systems if there is a central 
telephone number for excavators to call for excavation activities, or if 
the one-call systems in those areas communicate with one another. An 
operator's pipeline system must be covered by a qualified one-call 
system where there is one in place. For the purpose of this section, a 
one-call system is considered a ``qualified one-call system'' if it 
meets the requirements of section (b)(1) or (b)(2) of this section.
    (1) The state has adopted a one-call damage prevention program under 
Sec.  198.37 of this chapter; or
    (2) The one-call system:
    (i) Is operated in accordance with Sec.  198.39 of this chapter;
    (ii) Provides a pipeline operator an opportunity similar to a 
voluntary participant to have a part in management responsibilities; and
    (iii) Assesses a participating pipeline operator a fee that is 
proportionate to the costs of the one-call system's coverage of the 
operator's pipeline.
    (c) The damage prevention program required by paragraph (a) of this 
section must, at a minimum:
    (1) Include the identity, on a current basis, of persons who 
normally engage in excavation activities in the area in which the 
pipeline is located.
    (2) Provides for notification of the public in the vicinity of the 
pipeline and actual notification of the persons identified in paragraph 
(c)(1) of this section of the following as often as needed to make them 
aware of the damage prevention program:
    (i) The program's existence and purpose; and
    (ii) How to learn the location of underground pipelines before 
excavation activities are begun.
    (3) Provide a means of receiving and recording notification of 
planned excavation activities.
    (4) If the operator has buried pipelines in the area of excavation 
activity, provide for actual notification of persons who give notice of 
their intent to excavate of the type of temporary marking to be provided 
and how to identify the markings.
    (5) Provide for temporary marking of buried pipelines in the area of 
excavation activity before, as far as practical, the activity begins.
    (6) Provide as follows for inspection of pipelines that an operator 
has reason to believe could be damaged by excavation activities:
    (i) The inspection must be done as frequently as necessary during 
and after the activities to verify the integrity of the pipeline; and
    (ii) In the case of blasting, any inspection must include leakage 
surveys.
    (d) A damage prevention program under this section is not required 
for the following pipelines:
    (1) Pipelines located offshore.
    (2) Pipelines, other than those located offshore, in Class 1 or 2 
locations until September 20, 1995.
    (3) Pipelines to which access is physically controlled by the 
operator.
    (e) Pipelines operated by persons other than municipalities 
(including operators of master meters) whose primary activity does not 
include the transportation of gas need not comply with the following:
    (1) The requirement of paragraph (a) of this section that the damage 
prevention program be written; and
    (2) The requirements of paragraphs (c)(1) and (c)(2) of this 
section.

[Amdt. 192-40, 47 FR 13824, Apr. 1, 1982, as amended by Amdt. 192-57, 52 
FR 32800, Aug. 31, 1987; Amdt. 192-73, 60 FR 14650, Mar. 20, 1995; Amdt. 
192-78, 61 FR 28785, June 6, 1996; Amdt.192-82, 62 FR 61699, Nov. 19, 
1997; Amdt. 192-84, 63 FR 38758, July 20, 1998]



Sec.  192.615  Emergency plans.

    (a) Each operator shall establish written procedures to minimize the 
hazard resulting from a gas pipeline emergency. At a minimum, the 
procedures must provide for the following:
    (1) Receiving, identifying, and classifying notices of events which 
require immediate response by the operator.

[[Page 514]]

    (2) Establishing and maintaining adequate means of communication 
with the appropriate public safety answering point (i.e., 9-1-1 
emergency call center), where direct access to a 9-1-1 emergency call 
center is available from the location of the pipeline, and fire, police, 
and other public officials. Operators may establish liaison with the 
appropriate local emergency coordinating agencies, such as 9-1-1 
emergency call centers or county emergency managers, in lieu of 
communicating individually with each fire, police, or other public 
entity. An operator must determine the responsibilities, resources, 
jurisdictional area(s), and emergency contact telephone number(s) for 
both local and out-of-area calls of each Federal, State, and local 
government organization that may respond to a pipeline emergency, and 
inform such officials about the operator's ability to respond to a 
pipeline emergency and the means of communication during emergencies.
    (3) Prompt and effective response to a notice of each type of 
emergency, including the following:
    (i) Gas detected inside or near a building.
    (ii) Fire located near or directly involving a pipeline facility.
    (iii) Explosion occurring near or directly involving a pipeline 
facility.
    (iv) Natural disaster.
    (4) The availability of personnel, equipment, tools, and materials, 
as needed at the scene of an emergency.
    (5) Actions directed toward protecting people first and then 
property.
    (6) Taking necessary actions, including but not limited to, 
emergency shutdown, valve shut-off, or pressure reduction, in any 
section of the operator's pipeline system, to minimize hazards of 
released gas to life, property, or the environment.
    (7) Making safe any actual or potential hazard to life or property.
    (8) Notifying the appropriate public safety answering point (i.e., 
9-1-1 emergency call center) where direct access to a 9-1-1 emergency 
call center is available from the location of the pipeline, and fire, 
police, and other public officials, of gas pipeline emergencies to 
coordinate and share information to determine the location of the 
emergency, including both planned responses and actual responses during 
an emergency. The operator must immediately and directly notify the 
appropriate public safety answering point or other coordinating agency 
for the communities and jurisdictions in which the pipeline is located 
after receiving a notification of potential rupture, as defined in Sec.  
192.3, to coordinate and share information to determine the location of 
any release, regardless of whether the segment is subject to the 
requirements of Sec.  192.179, Sec.  192.634, or Sec.  192.636.
    (9) Safely restoring any service outage.
    (10) Beginning action under Sec.  192.617, if applicable, as soon 
after the end of the emergency as possible.
    (11) Actions required to be taken by a controller during an 
emergency in accordance with the operator's emergency plans and 
requirements set forth in Sec. Sec.  192.631, 192.634, and 192.636.
    (12) Each operator must develop written rupture identification 
procedures to evaluate and identify whether a notification of potential 
rupture, as defined in Sec.  192.3, is an actual rupture event or a non-
rupture event. These procedures must, at a minimum, specify the sources 
of information, operational factors, and other criteria that operator 
personnel use to evaluate a notification of potential rupture and 
identify an actual rupture. For operators installing valves in 
accordance with Sec.  192.179(e), Sec.  192.179(f), or that are subject 
to the requirements in Sec.  192.634, those procedures must provide for 
rupture identification as soon as practicable.
    (b) Each operator shall:
    (1) Furnish its supervisors who are responsible for emergency action 
a copy of that portion of the latest edition of the emergency procedures 
established under paragraph (a) of this section as necessary for 
compliance with those procedures.
    (2) Train the appropriate operating personnel to assure that they 
are knowledgeable of the emergency procedures and verify that the 
training is effective.
    (3) Review employee activities to determine whether the procedures 
were effectively followed in each emergency.

[[Page 515]]

    (c) Each operator must establish and maintain liaison with the 
appropriate public safety answering point(i.e., 9-1-1 emergency call 
center) where direct access to a 9-1-1 emergency call center is 
available from the location of the pipeline, as well as fire, police, 
and other public officials, to:
    (1) Learn the responsibility and resources of each government 
organization that may respond to a gas pipeline emergency;
    (2) Acquaint the officials with the operator's ability in responding 
to a gas pipeline emergency;
    (3) Identify the types of gas pipeline emergencies of which the 
operator notifies the officials; and
    (4) Plan how the operator and officials can engage in mutual 
assistance to minimize hazards to life or property.

[Amdt. 192-24, 41 FR 13587, Mar. 31, 1976, as amended by Amdt. 192-71, 
59 FR 6585, Feb. 11, 1994; Amdt. 192-112, 74 FR 63327, Dec. 3, 2009; 
Amdt. 192-130, 87 FR 20983, Apr. 8, 2022]



Sec.  192.616  Public awareness.

    (a) Except for an operator of a master meter or petroleum gas system 
covered under paragraph (j) of this section, each pipeline operator must 
develop and implement a written continuing public education program that 
follows the guidance provided in the American Petroleum Institute's 
(API) Recommended Practice (RP) 1162 (incorporated by reference, see 
Sec.  192.7).
    (b) The operator's program must follow the general program 
recommendations of API RP 1162 and assess the unique attributes and 
characteristics of the operator's pipeline and facilities.
    (c) The operator must follow the general program recommendations, 
including baseline and supplemental requirements of API RP 1162, unless 
the operator provides justification in its program or procedural manual 
as to why compliance with all or certain provisions of the recommended 
practice is not practicable and not necessary for safety.
    (d) The operator's program must specifically include provisions to 
educate the public, appropriate government organizations, and persons 
engaged in excavation related activities on:
    (1) Use of a one-call notification system prior to excavation and 
other damage prevention activities;
    (2) Possible hazards associated with unintended releases from a gas 
pipeline facility;
    (3) Physical indications that such a release may have occurred;
    (4) Steps that should be taken for public safety in the event of a 
gas pipeline release; and
    (5) Procedures for reporting such an event.
    (e) The program must include activities to advise affected 
municipalities, school districts, businesses, and residents of pipeline 
facility locations.
    (f) The program and the media used must be as comprehensive as 
necessary to reach all areas in which the operator transports gas.
    (g) The program must be conducted in English and in other languages 
commonly understood by a significant number and concentration of the 
non-English speaking population in the operator's area.
    (h) Operators in existence on June 20, 2005, must have completed 
their written programs no later than June 20, 2006. The operator of a 
master meter or petroleum gas system covered under paragraph (j) of this 
section must complete development of its written procedure by June 13, 
2008. Upon request, operators must submit their completed programs to 
PHMSA or, in the case of an intrastate pipeline facility operator, the 
appropriate State agency.
    (i) The operator's program documentation and evaluation results must 
be available for periodic review by appropriate regulatory agencies.
    (j) Unless the operator transports gas as a primary activity, the 
operator of a master meter or petroleum gas system is not required to 
develop a public awareness program as prescribed in paragraphs (a) 
through (g) of this section. Instead the operator must develop and 
implement a written procedure to provide its customers public awareness 
messages twice annually. If the master meter or petroleum gas system is 
located on property the operator does not control, the operator must 
provide similar messages twice annually to persons controlling the 
property. The

[[Page 516]]

public awareness message must include:
    (1) A description of the purpose and reliability of the pipeline;
    (2) An overview of the hazards of the pipeline and prevention 
measures used;
    (3) Information about damage prevention;
    (4) How to recognize and respond to a leak; and
    (5) How to get additional information.

[Amdt. 192-100, 70 FR 28842, May 19, 2005; 70 FR 35041, June 16, 2005; 
72 FR 70810, Dec. 13, 2007]



Sec.  192.617  Investigation of failures and incidents.

    (a) Post-failure and incident procedures. Each operator must 
establish and follow procedures for investigating and analyzing failures 
and incidents as defined in Sec.  191.3, including sending the failed 
pipe, component, or equipment for laboratory testing or examination, 
where appropriate, for the purpose of determining the causes and 
contributing factor(s) of the failure or incident and minimizing the 
possibility of a recurrence.
    (b) Post-failure and incident lessons learned. Each operator must 
develop, implement, and incorporate lessons learned from a post-failure 
or incident review into its written procedures, including personnel 
training and qualification programs, and design, construction, testing, 
maintenance, operations, and emergency procedure manuals and 
specifications.
    (c) Analysis of rupture and valve shut-offs. If an incident on an 
onshore gas transmission pipeline or a Type A gathering pipeline 
involves the closure of a rupture-mitigation valve (RMV), as defined in 
Sec.  192.3, or the closure of alternative equivalent technology, the 
operator of the pipeline must also conduct a post-incident analysis of 
all of the factors that may have impacted the release volume and the 
consequences of the incident and identify and implement operations and 
maintenance measures to prevent or minimize the consequences of a future 
incident. The requirements of this paragraph (c) are not applicable to 
distribution pipelines or Types B and C gas gathering pipelines. The 
analysis must include all relevant factors impacting the release volume 
and consequences, including, but not limited to, the following:
    (1) Detection, identification, operational response, system shut-
off, and emergency response communications, based on the type and volume 
of the incident;
    (2) Appropriateness and effectiveness of procedures and pipeline 
systems, including supervisory control and data acquisition (SCADA), 
communications, valve shut-off, and operator personnel;
    (3) Actual response time from identifying a rupture following a 
notification of potential rupture, as defined at Sec.  192.3, to 
initiation of mitigative actions and isolation of the pipeline segment, 
and the appropriateness and effectiveness of the mitigative actions 
taken;
    (4) Location and timeliness of actuation of RMVs or alternative 
equivalent technologies; and
    (5) All other factors the operator deems appropriate.
    (d) Rupture post-failure and incident summary. If a failure or 
incident on an onshore gas transmission pipeline or a Type A gathering 
pipeline involves the identification of a rupture following a 
notification of potential rupture, or the closure of an RMV (as those 
terms are defined in Sec.  192.3), or the closure of an alternative 
equivalent technology, the operator of the pipeline must complete a 
summary of the post-failure or incident review required by paragraph (c) 
of this section within 90 days of the incident, and while the 
investigation is pending, conduct quarterly status reviews until the 
investigation is complete and a final post-incident summary is prepared. 
The final post-failure or incident summary, and all other reviews and 
analyses produced under the requirements of this section, must be 
reviewed, dated, and signed by the operator's appropriate senior 
executive officer. The final post-failure or incident summary, all 
investigation and analysis documents used to prepare it, and records of 
lessons learned must be kept for the useful life of the pipeline. The 
requirements of this paragraph (d) are not applicable to distribution 
pipelines or Types B and C gas gathering pipelines.

[Amdt. 192-130, 87 FR 20983, Apr. 8, 2022]

[[Page 517]]



Sec.  192.619  Maximum allowable operating pressure: Steel or plastic 
pipelines.

    (a) No person may operate a segment of steel or plastic pipeline at 
a pressure that exceeds a maximum allowable operating pressure (MAOP) 
determined under paragraph (c), (d), or (e) of this section, or the 
lowest of the following:
    (1) The design pressure of the weakest element in the segment, 
determined in accordance with subparts C and D of this part. However, 
for steel pipe in pipelines being converted under Sec.  192.14 or 
uprated under subpart K of this part, if any variable necessary to 
determine the design pressure under the design formula (Sec.  192.105) 
is unknown, one of the following pressures is to be used as design 
pressure:
    (i) Eighty percent of the first test pressure that produces yield 
undersection N5 of Appendix N of ASME B31.8 (incorporated by reference, 
see Sec.  192.7), reduced by the appropriate factor in paragraph 
(a)(2)(ii) of this section; or
    (ii) If the pipe is 12\3/4\ inches (324 mm) or less in outside 
diameter and is not tested to yield under this paragraph, 200 p.s.i. 
(1379 kPa).
    (2) The pressure obtained by dividing the pressure to which the 
pipeline segment was tested after construction as follows:
    (i) For plastic pipe in all locations, the test pressure is divided 
by a factor of 1.5.
    (ii) For steel pipe operated at 100 psi (689 kPa) gage or more, the 
test pressure is divided by a factor determined in accordance with the 
Table 1 to paragraph (a)(2)(ii):

                                         Table 1 to Paragraph (a)(2)(ii)
----------------------------------------------------------------------------------------------------------------
                                                                            Factors,1 2 segment--
                                                           -----------------------------------------------------
                                          Installed before   Installed after
             Class location                (Nov. 12, 1970)   (Nov. 11, 1970)   Installed on or   Converted under
                                                             and before July    after July 1,     Sec.   192.14
                                                                 1, 2020            2020
----------------------------------------------------------------------------------------------------------------
1.......................................               1.1               1.1              1.25              1.25
2.......................................              1.25              1.25              1.25              1.25
3.......................................               1.4               1.5               1.5               1.5
4.......................................               1.4               1.5               1.5               1.5
----------------------------------------------------------------------------------------------------------------
\1\ For offshore pipeline segments installed, uprated or converted after July 31, 1977, that are not located on
  an offshore platform, the factor is 1.25. For pipeline segments installed, uprated or converted after July 31,
  1977, that are located on an offshore platform or on a platform in inland navigable waters, including a pipe
  riser, the factor is 1.5.
\2\ For a component with a design pressure established in accordance with Sec.   192.153(a) or (b) installed
  after July 14, 2004, the factor is 1.3.

    (3) The highest actual operating pressure to which the segment was 
subjected during the 5 years preceding the applicable date in the second 
column. This pressure restriction applies unless the segment was tested 
according to the requirements in paragraph (a)(2) of this section after 
the applicable date in the third column or the segment was uprated 
according to the requirements in subpart K of this part:

------------------------------------------------------------------------
        Pipeline segment             Pressure date         Test date
------------------------------------------------------------------------
(i) Onshore regulated gathering   March 15, 2006, or  5 years preceding
 pipeline (Type A or Type B        date pipeline       applicable date
 under Sec.   192.9(d)) that       becomes subject     in second column.
 first became subject to this      to this part,
 part (other than Sec.             whichever is
 192.612) after April 13, 2006.    later.
(ii) Onshore regulated gathering  May 16, 2023, or    5 years preceding
 pipeline (Type C under Sec.       date pipeline       applicable date
 192.9(d)) that first became       becomes subject     in second column.
 subject to this part (other       to this part,
 than Sec.   192.612) on or        whichever is
 after May 16, 2022.               later.
(iii) Onshore transmission        March 15, 2006, or  5 years preceding
 pipeline that was a gathering     date pipeline       applicable date
 pipeline not subject to this      becomes subject     in second column.
 part before March 15, 2006.       to this part,
                                   whichever is
                                   later.
(iv) Offshore gathering           July 1, 1976......  July 1, 1971.
 pipelines.
(v) All other pipelines.........  July 1, 1970......  July 1, 1965.
------------------------------------------------------------------------


[[Page 518]]

    (4) The pressure determined by the operator to be the maximum safe 
pressure after considering and accounting for records of material 
properties, including material properties verified in accordance with 
Sec.  192.607, if applicable, and the history of the pipeline segment, 
including known corrosion and actual operating pressure.
    (b) No person may operate a segment to which paragraph (a)(4) of 
this section is applicable, unless over-pressure protective devices are 
installed on the segment in a manner that will prevent the maximum 
allowable operating pressure from being exceeded, in accordance with 
Sec.  192.195.
    (c) The requirements on pressure restrictions in this section do not 
apply in the following instances:
    (1) An operator may operate a segment of pipeline found to be in 
satisfactory condition, considering its operating and maintenance 
history, at the highest actual operating pressure to which the segment 
was subjected during the 5 years preceding the applicable date in the 
second column of the table in paragraph (a)(3) of this section. An 
operator must still comply with Sec.  192.611.
    (2) For any Type C gas gathering pipeline under Sec.  192.9 existing 
on or before May 16, 2022, that was not previously subject to this part 
and the operator cannot determine the actual operating pressure of the 
pipeline for the 5 years preceding May 16, 2023, the operator may 
establish MAOP using other criteria based on a combination of operating 
conditions, other tests, and design with approval from PHMSA. The 
operator must notify PHMSA in accordance with Sec.  192.18. The 
notification must include the following information:
    (i) The proposed MAOP of the pipeline;
    (ii) Description of pipeline segment for which alternate methods are 
used to establish MAOP, including diameter, wall thickness, pipe grade, 
seam type, location, endpoints, other pertinent material properties, and 
age;
    (iii) Pipeline operating data, including operating history and 
maintenance history;
    (iv) Description of methods being used to establish MAOP;
    (v) Technical justification for use of the methods chosen to 
establish MAOP; and
    (vi) Evidence of review and acceptance of the justification by a 
qualified technical subject matter expert.
    (d) The operator of a pipeline segment of steel pipeline meeting the 
conditions prescribed in Sec.  192.620(b) may elect to operate the 
segment at a maximum allowable operating pressure determined under Sec.  
192.620(a).
    (e) Notwithstanding the requirements in paragraphs (a) through (d) 
of this section, operators of onshore steel transmission pipelines that 
meet the criteria specified in Sec.  192.624(a) must establish and 
document the maximum allowable operating pressure in accordance with 
Sec.  192.624.
    (f) Operators of onshore steel transmission pipelines must make and 
retain records necessary to establish and document the MAOP of each 
pipeline segment in accordance with paragraphs (a) through (e) of this 
section as follows:
    (1) Operators of pipelines in operation as of July 1, 2020 must 
retain any existing records establishing MAOP for the life of the 
pipeline;
    (2) Operators of pipelines in operation as of July 1, 2020 that do 
not have records establishing MAOP and are required to reconfirm MAOP in 
accordance with Sec.  192.624, must retain the records reconfirming MAOP 
for the life of the pipeline; and
    (3) Operators of pipelines placed in operation after July 1, 2020 
must make and retain records establishing MAOP for the life of the 
pipeline.

[35 FR 13257, Aug. 19, 1970]

    Editorial Note: For Federal Register citations affecting Sec.  
192.619, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.govinfo.gov.



Sec.  192.620  Alternative maximum allowable operating pressure for certain  
steel pipelines.

    (a) How does an operator calculate the alternative maximum allowable 
operating

[[Page 519]]

pressure? An operator calculates the alternative maximum allowable 
operating pressure by using different factors in the same formulas used 
for calculating maximum allowable operating pressure under Sec.  
192.619(a) as follows:
    (1) In determining the alternative design pressure under Sec.  
192.105, use a design factor determined in accordance with Sec.  
192.111(b), (c), or (d) or, if none of these paragraphs apply, in 
accordance with the following table:

------------------------------------------------------------------------
                                                            Alternative
                     Class location                        design factor
                                                                (F)
------------------------------------------------------------------------
1.......................................................            0.80
2.......................................................            0.67
3.......................................................            0.56
------------------------------------------------------------------------

    (i) For facilities installed prior to December 22, 2008, for which 
Sec.  192.111(b), (c), or (d) applies, use the following design factors 
as alternatives for the factors specified in those paragraphs: Sec.  
192.111(b)-0.67 or less; 192.111(c) and (d)-0.56 or less.
    (ii) [Reserved]
    (2) The alternative maximum allowable operating pressure is the 
lower of the following:
    (i) The design pressure of the weakest element in the pipeline 
segment, determined under subparts C and D of this part.
    (ii) The pressure obtained by dividing the pressure to which the 
pipeline segment was tested after construction by a factor determined in 
the following table:

------------------------------------------------------------------------
                                                            Alternative
                     Class location                         test factor
------------------------------------------------------------------------
1.......................................................            1.25
2.......................................................        \1\ 1.50
3.......................................................            1.50
------------------------------------------------------------------------
\1\ For Class 2 alternative maximum allowable operating pressure
  segments installed prior to December 22, 2008 the alternative test
  factor is 1.25.

    (b) When may an operator use the alternative maximum allowable 
operating pressure calculated under paragraph (a) of this section? An 
operator may use an alternative maximum allowable operating pressure 
calculated under paragraph (a) of this section if the following 
conditions are met:
    (1) The pipeline segment is in a Class 1, 2, or 3 location;
    (2) The pipeline segment is constructed of steel pipe meeting the 
additional design requirements in Sec.  192.112;
    (3) A supervisory control and data acquisition system provides 
remote monitoring and control of the pipeline segment. The control 
provided must include monitoring of pressures and flows, monitoring 
compressor start-ups and shut-downs, and remote closure of valves per 
paragraph (d)(3) of this section;
    (4) The pipeline segment meets the additional construction 
requirements described in Sec.  192.328;
    (5) The pipeline segment does not contain any mechanical couplings 
used in place of girth welds;
    (6) If a pipeline segment has been previously operated, the segment 
has not experienced any failure during normal operations indicative of a 
systemic fault in material as determined by a root cause analysis, 
including metallurgical examination of the failed pipe. The results of 
this root cause analysis must be reported to each PHMSA pipeline safety 
regional office where the pipeline is in service at least 60 days prior 
to operation at the alternative MAOP. An operator must also notify a 
State pipeline safety authority when the pipeline is located in a State 
where PHMSA has an interstate agent agreement, or an intrastate pipeline 
is regulated by that State; and
    (7) At least 95 percent of girth welds on a segment that was 
constructed prior to December 22, 2008, must have been non-destructively 
examined in accordance with Sec.  192.243(b) and (c).
    (c) What is an operator electing to use the alternative maximum 
allowable operating pressure required to do? If an operator elects to 
use the alternative maximum allowable operating pressure calculated 
under paragraph (a) of this section for a pipeline segment, the operator 
must do each of the following:
    (1) For pipelines already in service, notify the PHMSA pipeline 
safety regional office where the pipeline is in service of the intention 
to use the alternative pressure at least 180 days before operating at 
the alternative MAOP. For new pipelines, notify the PHMSA pipeline 
safety regional office of planned alternative MAOP design and operation 
at least 60 days prior to the earliest start date of either pipe 
manufacturing or construction activities. An operator must also notify 
the

[[Page 520]]

state pipeline safety authority when the pipeline is located in a state 
where PHMSA has an interstate agent agreement or where an intrastate 
pipeline is regulated by that state.
    (2) Certify, by signature of a senior executive officer of the 
company, as follows:
    (i) The pipeline segment meets the conditions described in paragraph 
(b) of this section; and
    (ii) The operating and maintenance procedures include the additional 
operating and maintenance requirements of paragraph (d) of this section; 
and
    (iii) The review and any needed program upgrade of the damage 
prevention program required by paragraph (d)(4)(v) of this section has 
been completed.
    (3) Send a copy of the certification required by paragraph (c)(2) of 
this section to each PHMSA pipeline safety regional office where the 
pipeline is in service 30 days prior to operating at the alternative 
MAOP. An operator must also send a copy to a State pipeline safety 
authority when the pipeline is located in a State where PHMSA has an 
interstate agent agreement, or an intrastate pipeline is regulated by 
that State.
    (4) For each pipeline segment, do one of the following:
    (i) Perform a strength test as described in Sec.  192.505 at a test 
pressure calculated under paragraph (a) of this section or
    (ii) For a pipeline segment in existence prior to December 22, 2008, 
certify, under paragraph (c)(2) of this section, that the strength test 
performed under Sec.  192.505 was conducted at test pressure calculated 
under paragraph (a) of this section, or conduct a new strength test in 
accordance with paragraph (c)(4)(i) of this section.
    (5) Comply with the additional operation and maintenance 
requirements described in paragraph (d) of this section.
    (6) If the performance of a construction task associated with 
implementing alternative MAOP that occurs after December 22, 2008, can 
affect the integrity of the pipeline segment, treat that task as a 
``covered task'', notwithstanding the definition in Sec.  192.801(b) and 
implement the requirements of subpart N as appropriate.
    (7) Maintain, for the useful life of the pipeline, records 
demonstrating compliance with paragraphs (b), (c)(6), and (d) of this 
section.
    (8) A Class 1 and Class 2 location can be upgraded one class due to 
class changes per Sec.  192.611(a). All class location changes from 
Class 1 to Class 2 and from Class 2 to Class 3 must have all anomalies 
evaluated and remediated per: The ``original pipeline class grade'' 
Sec.  192.620(d)(11) anomaly repair requirements; and all anomalies with 
a wall loss equal to or greater than 40 percent must be excavated and 
remediated. Pipelines in Class 4 may not operate at an alternative MAOP.
    (d) What additional operation and maintenance requirements apply to 
operation at the alternative maximum allowable operating pressure? In 
addition to compliance with other applicable safety standards in this 
part, if an operator establishes a maximum allowable operating pressure 
for a pipeline segment under paragraph (a) of this section, an operator 
must comply with the additional operation and maintenance requirements 
as follows:

------------------------------------------------------------------------
  To address increased risk of a
    maximum allowable operating
  pressure based on higher stress    Take the following additional step:
  levels in the following areas:
------------------------------------------------------------------------
(1) Identifying and evaluating      Develop a threat matrix consistent
 threats.                            with Sec.   192.917 to do the
                                     following:
                                    (i) Identify and compare the
                                     increased risk of operating the
                                     pipeline at the increased stress
                                     level under this section with
                                     conventional operation; and
                                    (ii) Describe and implement
                                     procedures used to mitigate the
                                     risk.
(2) Notifying the public..........  (i) Recalculate the potential impact
                                     circle as defined in Sec.   192.903
                                     to reflect use of the alternative
                                     maximum operating pressure
                                     calculated under paragraph (a) of
                                     this section and pipeline operating
                                     conditions; and
                                    (ii) In implementing the public
                                     education program required under
                                     Sec.   192.616, perform the
                                     following:
                                    (A) Include persons occupying
                                     property within 220 yards of the
                                     centerline and within the potential
                                     impact circle within the targeted
                                     audience; and

[[Page 521]]

 
                                    (B) Include information about the
                                     integrity management activities
                                     performed under this section within
                                     the message provided to the
                                     audience.
(3) Responding to an emergency in   (i) Ensure that the identification
 an area defined as a high           of high consequence areas reflects
 consequence area in Sec.            the larger potential impact circle
 192.903.                            recalculated under paragraph
                                     (d)(2)(i) of this section.
                                    (ii) If personnel response time to
                                     mainline valves on either side of
                                     the high consequence area exceeds
                                     one hour (under normal driving
                                     conditions and speed limits) from
                                     the time the event is identified in
                                     the control room, provide remote
                                     valve control through a supervisory
                                     control and data acquisition
                                     (SCADA) system, other leak
                                     detection system, or an alternative
                                     method of control.
                                    (iii) Remote valve control must
                                     include the ability to close and
                                     monitor the valve position (open or
                                     closed), and monitor pressure
                                     upstream and downstream.
                                    (iv) A line break valve control
                                     system using differential pressure,
                                     rate of pressure drop or other
                                     widely-accepted method is an
                                     acceptable alternative to remote
                                     valve control.
(4) Protecting the right-of-way...  (i) Patrol the right-of-way at
                                     intervals not exceeding 45 days,
                                     but at least 12 times each calendar
                                     year, to inspect for excavation
                                     activities, ground movement, wash
                                     outs, leakage, or other activities
                                     or conditions affecting the safety
                                     operation of the pipeline.
                                    (ii) Develop and implement a plan to
                                     monitor for and mitigate
                                     occurrences of unstable soil and
                                     ground movement.
                                    (iii) If observed conditions
                                     indicate the possible loss of
                                     cover, perform a depth of cover
                                     study and replace cover as
                                     necessary to restore the depth of
                                     cover or apply alternative means to
                                     provide protection equivalent to
                                     the originally-required depth of
                                     cover.
                                    (iv) Use line-of-sight line markers
                                     satisfying the requirements of Sec.
                                       192.707(d) except in agricultural
                                     areas, large water crossings or
                                     swamp, steep terrain, or where
                                     prohibited by Federal Energy
                                     Regulatory Commission orders,
                                     permits, or local law.
                                    (v) Review the damage prevention
                                     program under Sec.   192.614(a) in
                                     light of national consensus
                                     practices, to ensure the program
                                     provides adequate protection of the
                                     right-of-way. Identify the
                                     standards or practices considered
                                     in the review, and meet or exceed
                                     those standards or practices by
                                     incorporating appropriate changes
                                     into the program.
                                    (vi) Develop and implement a right-
                                     of-way management plan to protect
                                     the pipeline segment from damage
                                     due to excavation activities.
(5) Controlling internal corrosion  (i) Develop and implement a program
                                     to monitor for and mitigate the
                                     presence of, deleterious gas stream
                                     constituents.
                                    (ii) At points where gas with
                                     potentially deleterious
                                     contaminants enters the pipeline,
                                     use filter separators or separators
                                     and gas quality monitoring
                                     equipment.
                                    (iii) Use gas quality monitoring
                                     equipment that includes a moisture
                                     analyzer, chromatograph, and
                                     periodic hydrogen sulfide sampling.
                                    (iv) Use cleaning pigs and sample
                                     accumulated liquids. Use inhibitors
                                     when corrosive gas or liquids are
                                     present.
                                    (v) Address deleterious gas stream
                                     constituents as follows:
                                    (A) Limit carbon dioxide to 3
                                     percent by volume;
                                    (B) Allow no free water and
                                     otherwise limit water to seven
                                     pounds per million cubic feet of
                                     gas; and
                                    (C) Limit hydrogen sulfide to 1.0
                                     grain per hundred cubic feet (16
                                     ppm) of gas, where the hydrogen
                                     sulfide is greater than 0.5 grain
                                     per hundred cubic feet (8 ppm) of
                                     gas, implement a pigging and
                                     inhibitor injection program to
                                     address deleterious gas stream
                                     constituents, including follow-up
                                     sampling and quality testing of
                                     liquids at receipt points.
                                    (vi) Review the program at least
                                     quarterly based on the gas stream
                                     experience and implement
                                     adjustments to monitor for, and
                                     mitigate the presence of,
                                     deleterious gas stream
                                     constituents.
(6) Controlling interference that   (i) Prior to operating an existing
 can impact external corrosion.      pipeline segment at an alternate
                                     maximum allowable operating
                                     pressure calculated under this
                                     section, or within six months after
                                     placing a new pipeline segment in
                                     service at an alternate maximum
                                     allowable operating pressure
                                     calculated under this section,
                                     address any interference currents
                                     on the pipeline segment.
                                    (ii) To address interference
                                     currents, perform the following:
                                    (A) Conduct an interference survey
                                     to detect the presence and level of
                                     any electrical current that could
                                     impact external corrosion where
                                     interference is suspected;
                                    (B) Analyze the results of the
                                     survey; and
                                    (C) Take any remedial action needed
                                     within 6 months after completing
                                     the survey to protect the pipeline
                                     segment from deleterious current.
(7) Confirming external corrosion   (i) Within six months after placing
 control through indirect            the cathodic protection of a new
 assessment.                         pipeline segment in operation, or
                                     within six months after certifying
                                     a segment under Sec.
                                     192.620(c)(1) of an existing
                                     pipeline segment under this
                                     section, assess the adequacy of the
                                     cathodic protection through an
                                     indirect method such as close-
                                     interval survey, and the integrity
                                     of the coating using direct current
                                     voltage gradient (DCVG) or
                                     alternating current voltage
                                     gradient (ACVG).
                                    (ii) Remediate any construction
                                     damaged coating with a voltage drop
                                     classified as moderate or severe
                                     (IR drop greater than 35% for DCVG
                                     or 50 dB[micro]v for ACVG) under
                                     section 4 of NACE RP-0502-2002
                                     (incorporated by reference, see
                                     Sec.   192.7).

[[Page 522]]

 
                                    (iii) Within six months after
                                     completing the baseline internal
                                     inspection required under paragraph
                                     (d)(9) of this section, integrate
                                     the results of the indirect
                                     assessment required under paragraph
                                     (d)(7)(i) of this section with the
                                     results of the baseline internal
                                     inspection and take any needed
                                     remedial actions.
                                    (iv) For all pipeline segments in
                                     high consequence areas, perform
                                     periodic assessments as follows:
                                    (A) Conduct periodic close interval
                                     surveys with current interrupted to
                                     confirm voltage drops in
                                     association with periodic
                                     assessments under subpart O of this
                                     part.
                                    (B) Locate pipe-to-soil test
                                     stations at half-mile intervals
                                     within each high consequence area
                                     ensuring at least one station is
                                     within each high consequence area,
                                     if practicable.
                                    (C) Integrate the results with those
                                     of the baseline and periodic
                                     assessments for integrity done
                                     under paragraphs (d)(9) and (d)(10)
                                     of this section.
(8) Controlling external corrosion  (i) If an annual test station
 through cathodic protection.        reading indicates cathodic
                                     protection below the level of
                                     protection required in subpart I of
                                     this part, complete remedial action
                                     within six months of the failed
                                     reading or notify each PHMSA
                                     pipeline safety regional office
                                     where the pipeline is in service
                                     demonstrating that the integrity of
                                     the pipeline is not compromised if
                                     the repair takes longer than 6
                                     months. An operator must also
                                     notify a State pipeline safety
                                     authority when the pipeline is
                                     located in a State where PHMSA has
                                     an interstate agent agreement, or
                                     an intrastate pipeline is regulated
                                     by that State; and
                                    (ii) After remedial action to
                                     address a failed reading, confirm
                                     restoration of adequate corrosion
                                     control by a close interval survey
                                     on either side of the affected test
                                     station to the next test station
                                     unless the reason for the failed
                                     reading is determined to be a
                                     rectifier connection or power input
                                     problem that can be remediated and
                                     otherwise verified.
                                    (iii) If the pipeline segment has
                                     been in operation, the cathodic
                                     protection system on the pipeline
                                     segment must have been operational
                                     within 12 months of the completion
                                     of construction.
(9) Conducting a baseline           (i) Except as provided in paragraph
 assessment of integrity.            (d)(9)(iii) of this section, for a
                                     new pipeline segment operating at
                                     the new alternative maximum
                                     allowable operating pressure,
                                     perform a baseline internal
                                     inspection of the entire pipeline
                                     segment as follows:
                                    (A) Assess using a geometry tool
                                     after the initial hydrostatic test
                                     and backfill and within six months
                                     after placing the new pipeline
                                     segment in service; and
                                    (B) Assess using a high resolution
                                     magnetic flux tool within three
                                     years after placing the new
                                     pipeline segment in service at the
                                     alternative maximum allowable
                                     operating pressure.
                                    (ii) Except as provided in paragraph
                                     (d)(9)(iii) of this section, for an
                                     existing pipeline segment, perform
                                     a baseline internal assessment
                                     using a geometry tool and a high
                                     resolution magnetic flux tool
                                     before, but within two years prior
                                     to, raising pressure to the
                                     alternative maximum allowable
                                     operating pressure as allowed under
                                     this section.
                                    (iii) If headers, mainline valve by-
                                     passes, compressor station piping,
                                     meter station piping, or other
                                     short portion of a pipeline segment
                                     operating at alternative maximum
                                     allowable operating pressure cannot
                                     accommodate a geometry tool and a
                                     high resolution magnetic flux tool,
                                     use direct assessment (per Sec.
                                     192.925, Sec.   192.927 and/or Sec.
                                       192.929) or pressure testing (per
                                     subpart J of this part) to assess
                                     that portion.
(10) Conducting periodic            (i) Determine a frequency for
 assessments of integrity.           subsequent periodic integrity
                                     assessments as if all the
                                     alternative maximum allowable
                                     operating pressure pipeline
                                     segments were covered by subpart O
                                     of this part and
                                    (ii) Conduct periodic internal
                                     inspections using a high resolution
                                     magnetic flux tool on the frequency
                                     determined under paragraph
                                     (d)(10)(i) of this section, or
                                    (iii) Use direct assessment (per
                                     Sec.   192.925, Sec.   192.927 and/
                                     or Sec.   192.929) or pressure
                                     testing (per subpart J of this
                                     part) for periodic assessment of a
                                     portion of a segment to the extent
                                     permitted for a baseline assessment
                                     under paragraph (d)(9)(iii) of this
                                     section.
(11) Making repairs...............  (i) Perform the following when
                                     evaluating an anomaly:
                                    (A) Use the most conservative
                                     calculation for determining
                                     remaining strength or an
                                     alternative validated calculation
                                     based on pipe diameter, wall
                                     thickness, grade, operating
                                     pressure, operating stress level,
                                     and operating temperature: and
                                    (B) Take into account the tolerances
                                     of the tools used for the
                                     inspection.
                                    (ii) Repair a defect immediately if
                                     any of the following apply:
                                    (A) The defect is a dent discovered
                                     during the baseline assessment for
                                     integrity under paragraph (d)(9) of
                                     this section and the defect meets
                                     the criteria for immediate repair
                                     in Sec.   192.309(b).
                                    (B) The defect meets the criteria
                                     for immediate repair in Sec.
                                     192.933(d).
                                    (C) The alternative maximum
                                     allowable operating pressure was
                                     based on a design factor of 0.67
                                     under paragraph (a) of this section
                                     and the failure pressure is less
                                     than 1.25 times the alternative
                                     maximum allowable operating
                                     pressure.
                                    (D) The alternative maximum
                                     allowable operating pressure was
                                     based on a design factor of 0.56
                                     under paragraph (a) of this section
                                     and the failure pressure is less
                                     than or equal to 1.4 times the
                                     alternative maximum allowable
                                     operating pressure.
                                    (iii) If paragraph (d)(11)(ii) of
                                     this section does not require
                                     immediate repair, repair a defect
                                     within one year if any of the
                                     following apply:
                                    (A) The defect meets the criteria
                                     for repair within one year in Sec.
                                      192.933(d).

[[Page 523]]

 
                                    (B) The alternative maximum
                                     allowable operating pressure was
                                     based on a design factor of 0.80
                                     under paragraph (a) of this section
                                     and the failure pressure is less
                                     than 1.25 times the alternative
                                     maximum allowable operating
                                     pressure.
                                    (C) The alternative maximum
                                     allowable operating pressure was
                                     based on a design factor of 0.67
                                     under paragraph (a) of this section
                                     and the failure pressure is less
                                     than 1.50 times the alternative
                                     maximum allowable operating
                                     pressure.
                                    (D) The alternative maximum
                                     allowable operating pressure was
                                     based on a design factor of 0.56
                                     under paragraph (a) of this section
                                     and the failure pressure is less
                                     than or equal to 1.80 times the
                                     alternative maximum allowable
                                     operating pressure.
                                    (iv) Evaluate any defect not
                                     required to be repaired under
                                     paragraph (d)(11)(ii) or (iii) of
                                     this section to determine its
                                     growth rate, set the maximum
                                     interval for repair or re-
                                     inspection, and repair or re-
                                     inspect within that interval.
------------------------------------------------------------------------

    (e) Is there any change in overpressure protection associated with 
operating at the alternative maximum allowable operating pressure? 
Notwithstanding the required capacity of pressure relieving and limiting 
stations otherwise required by Sec.  192.201, if an operator establishes 
a maximum allowable operating pressure for a pipeline segment in 
accordance with paragraph (a) of this section, an operator must:
    (1) Provide overpressure protection that limits mainline pressure to 
a maximum of 104 percent of the maximum allowable operating pressure; 
and
    (2) Develop and follow a procedure for establishing and maintaining 
accurate set points for the supervisory control and data acquisition 
system.

[73 FR 62177, Oct. 17, 2008, as amended by Amdt. 192-111, 74 FR 62505, 
Nov. 30, 2009; Amdt. 192-120, 80 FR 12779, Mar. 11, 2015]



Sec.  192.621  Maximum allowable operating pressure: High-pressure 
distribution systems.

    (a) No person may operate a segment of a high pressure distribution 
system at a pressure that exceeds the lowest of the following pressures, 
as applicable:
    (1) The design pressure of the weakest element in the segment, 
determined in accordance with subparts C and D of this part.
    (2) 60 p.s.i. (414 kPa) gage, for a segment of a distribution system 
otherwise designed to operate at over 60 p.s.i. (414 kPa) gage, unless 
the service lines in the segment are equipped with service regulators or 
other pressure limiting devices in series that meet the requirements of 
Sec.  192.197(c).
    (3) 25 p.s.i. (172 kPa) gage in segments of cast iron pipe in which 
there are unreinforced bell and spigot joints.
    (4) The pressure limits to which a joint could be subjected without 
the possibility of its parting.
    (5) The pressure determined by the operator to be the maximum safe 
pressure after considering the history of the segment, particularly 
known corrosion and the actual operating pressures.
    (b) No person may operate a segment of pipeline to which paragraph 
(a)(5) of this section applies, unless overpressure protective devices 
are installed on the segment in a manner that will prevent the maximum 
allowable operating pressure from being exceeded, in accordance with 
Sec.  192.195.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37504, 
July 13, 1998]



Sec.  192.623  Maximum and minimum allowable operating pressure; 
Low-pressure distribution systems.

    (a) No person may operate a low-pressure distribution system at a 
pressure high enough to make unsafe the operation of any connected and 
properly adjusted low-pressure gas burning equipment.
    (b) No person may operate a low pressure distribution system at a 
pressure lower than the minimum pressure at which the safe and 
continuing operation of any connected and properly adjusted low-pressure 
gas burning equipment can be assured.

[[Page 524]]



Sec.  192.624  Maximum allowable operating pressure reconfirmation: 
Onshore steel transmission pipelines.

    (a) Applicability. Operators of onshore steel transmission pipeline 
segments must reconfirm the maximum allowable operating pressure (MAOP) 
of all pipeline segments in accordance with the requirements of this 
section if either of the following conditions are met:
    (1) Records necessary to establish the MAOP in accordance with Sec.  
192.619(a)(2), including records required by Sec.  192.517(a), are not 
traceable, verifiable, and complete and the pipeline is located in one 
of the following locations:
    (i) A high consequence area as defined in Sec.  192.903; or
    (ii) A Class 3 or Class 4 location.
    (2) The pipeline segment's MAOP was established in accordance with 
Sec.  192.619(c), the pipeline segment's MAOP is greater than or equal 
to 30 percent of the specified minimum yield strength, and the pipeline 
segment is located in one of the following areas:
    (i) A high consequence area as defined in Sec.  192.903;
    (ii) A Class 3 or Class 4 location; or
    (iii) A moderate consequence area as defined in Sec.  192.3, if the 
pipeline segment can accommodate inspection by means of instrumented 
inline inspection tools.
    (b) Procedures and completion dates. Operators of a pipeline subject 
to this section must develop and document procedures for completing all 
actions required by this section by July 1, 2021. These procedures must 
include a process for reconfirming MAOP for any pipelines that meet a 
condition of Sec.  192.624(a), and for performing a spike test or 
material verification in accordance with Sec. Sec.  192.506 and 192.607, 
if applicable. All actions required by this section must be completed 
according to the following schedule:
    (1) Operators must complete all actions required by this section on 
at least 50% of the pipeline mileage by July 3, 2028.
    (2) Operators must complete all actions required by this section on 
100% of the pipeline mileage by July 2, 2035 or as soon as practicable, 
but not to exceed 4 years after the pipeline segment first meets a 
condition of Sec.  192.624(a) (e.g., due to a location becoming a high 
consequence area), whichever is later.
    (3) If operational and environmental constraints limit an operator 
from meeting the deadlines in Sec.  192.624, the operator may petition 
for an extension of the completion deadlines by up to 1 year, upon 
submittal of a notification in accordance with Sec.  192.18. The 
notification must include an up-to-date plan for completing all actions 
in accordance with this section, the reason for the requested extension, 
current status, proposed completion date, outstanding remediation 
activities, and any needed temporary measures needed to mitigate the 
impact on safety.
    (c) Maximum allowable operating pressure determination. Operators of 
a pipeline segment meeting a condition in paragraph (a) of this section 
must reconfirm its MAOP using one of the following methods:
    (1) Method 1: Pressure test. Perform a pressure test and verify 
material properties records in accordance with Sec.  192.607 and the 
following requirements:
    (i) Pressure test. Perform a pressure test in accordance with 
subpart J of this part. The MAOP must be equal to the test pressure 
divided by the greater of either 1.25 or the applicable class location 
factor in Sec.  192.619(a)(2)(ii).
    (ii) Material properties records. Determine if the following 
material properties records are documented in traceable, verifiable, and 
complete records: Diameter, wall thickness, seam type, and grade 
(minimum yield strength, ultimate tensile strength).
    (iii) Material properties verification. If any of the records 
required by paragraph (c)(1)(ii) of this section are not documented in 
traceable, verifiable, and complete records, the operator must obtain 
the missing records in accordance with Sec.  192.607. An operator must 
test the pipe materials cut out from the test manifold sites at the time 
the pressure test is conducted. If there is a failure during the 
pressure test, the operator must test any removed pipe from the pressure 
test failure in accordance with Sec.  192.607.
    (2) Method 2: Pressure Reduction. Reduce pressure, as necessary, and 
limit MAOP to no greater than the highest

[[Page 525]]

actual operating pressure sustained by the pipeline during the 5 years 
preceding October 1, 2019, divided by the greater of 1.25 or the 
applicable class location factor in Sec.  192.619(a)(2)(ii). The highest 
actual sustained pressure must have been reached for a minimum 
cumulative duration of 8 hours during a continuous 30-day period. The 
value used as the highest actual sustained operating pressure must 
account for differences between upstream and downstream pressure on the 
pipeline by use of either the lowest maximum pressure value for the 
entire pipeline segment or using the operating pressure gradient along 
the entire pipeline segment (i.e., the location-specific operating 
pressure at each location).
    (i) Where the pipeline segment has had a class location change in 
accordance with Sec.  192.611, and records documenting diameter, wall 
thickness, seam type, grade (minimum yield strength and ultimate tensile 
strength), and pressure tests are not documented in traceable, 
verifiable, and complete records, the operator must reduce the pipeline 
segment MAOP as follows:
    (A) For pipeline segments where a class location changed from Class 
1 to Class 2, from Class 2 to Class 3, or from Class 3 to Class 4, 
reduce the pipeline MAOP to no greater than the highest actual operating 
pressure sustained by the pipeline during the 5 years preceding October 
1, 2019, divided by 1.39 for Class 1 to Class 2, 1.67 for Class 2 to 
Class 3, and 2.00 for Class 3 to Class 4.
    (B) For pipeline segments where a class location changed from Class 
1 to Class 3, reduce the pipeline MAOP to no greater than the highest 
actual operating pressure sustained by the pipeline during the 5 years 
preceding October 1, 2019, divided by 2.00.
    (ii) Future uprating of the pipeline segment in accordance with 
subpart K is allowed if the MAOP is established using Method 2.
    (iii) If an operator elects to use Method 2, but desires to use a 
less conservative pressure reduction factor or longer look-back period, 
the operator must notify PHMSA in accordance with Sec.  192.18 no later 
than 7 calendar days after establishing the reduced MAOP. The 
notification must include the following details:
    (A) Descriptions of the operational constraints, special 
circumstances, or other factors that preclude, or make it impractical, 
to use the pressure reduction factor specified in Sec.  192.624(c)(2);
    (B) The fracture mechanics modeling for failure stress pressures and 
cyclic fatigue crack growth analysis that complies with Sec.  192.712;
    (C) Justification that establishing MAOP by another method allowed 
by this section is impractical;
    (D) Justification that the reduced MAOP determined by the operator 
is safe based on analysis of the condition of the pipeline segment, 
including material properties records, material properties verified in 
accordance Sec.  192.607, and the history of the pipeline segment, 
particularly known corrosion and leakage, and the actual operating 
pressure, and additional compensatory preventive and mitigative measures 
taken or planned; and
    (E) Planned duration for operating at the requested MAOP, long-term 
remediation measures and justification of this operating time interval, 
including fracture mechanics modeling for failure stress pressures and 
cyclic fatigue growth analysis and other validated forms of engineering 
analysis that have been reviewed and confirmed by subject matter 
experts.
    (3) Method 3: Engineering Critical Assessment (ECA). Conduct an ECA 
in accordance with Sec.  192.632.
    (4) Method 4: Pipe Replacement. Replace the pipeline segment in 
accordance with this part.
    (5) Method 5: Pressure Reduction for Pipeline Segments with Small 
Potential Impact Radius. Pipelines with a potential impact radius (PIR) 
less than or equal to 150 feet may establish the MAOP as follows:
    (i) Reduce the MAOP to no greater than the highest actual operating 
pressure sustained by the pipeline during 5 years preceding October 1, 
2019, divided by 1.1. The highest actual sustained pressure must have 
been reached for a minimum cumulative duration of 8 hours during one 
continuous 30-day period. The reduced MAOP must account for differences 
between discharge and upstream pressure on the pipeline by

[[Page 526]]

use of either the lowest value for the entire pipeline segment or the 
operating pressure gradient (i.e., the location specific operating 
pressure at each location);
    (ii) Conduct patrols in accordance with Sec.  192.705 paragraphs (a) 
and (c) and conduct instrumented leakage surveys in accordance with 
Sec.  192.706 at intervals not to exceed those in the following table 1 
to Sec.  192.624(c)(5)(ii):

                   Table 1 to Sec.   192.624(c)(5)(ii)
------------------------------------------------------------------------
       Class locations               Patrols           Leakage surveys
------------------------------------------------------------------------
(A) Class 1 and Class 2.....  3 \1/2\ months, but   3 \1/2\ months, but
                               at least four times   at least four times
                               each calendar year.   each calendar year.
(B) Class 3 and Class 4.....  3 months, but at      3 months, but at
                               least six times       least six times
                               each calendar year.   each calendar year.
------------------------------------------------------------------------

    (iii) Under Method 5, future uprating of the pipeline segment in 
accordance with subpart K is allowed.
    (6) Method 6: Alternative Technology. Operators may use an 
alternative technical evaluation process that provides a documented 
engineering analysis for establishing MAOP. If an operator elects to use 
alternative technology, the operator must notify PHMSA in advance in 
accordance with Sec.  192.18. The notification must include descriptions 
of the following details:
    (i) The technology or technologies to be used for tests, 
examinations, and assessments; the method for establishing material 
properties; and analytical techniques with similar analysis from prior 
tool runs done to ensure the results are consistent with the required 
corresponding hydrostatic test pressure for the pipeline segment being 
evaluated;
    (ii) Procedures and processes to conduct tests, examinations, 
assessments and evaluations, analyze defects and flaws, and remediate 
defects discovered;
    (iii) Pipeline segment data, including original design, maintenance 
and operating history, anomaly or flaw characterization;
    (iv) Assessment techniques and acceptance criteria, including 
anomaly detection confidence level, probability of detection, and 
uncertainty of the predicted failure pressure quantified as a fraction 
of specified minimum yield strength;
    (v) If any pipeline segment contains cracking or may be susceptible 
to cracking or crack-like defects found through or identified by 
assessments, leaks, failures, manufacturing vintage histories, or any 
other available information about the pipeline, the operator must 
estimate the remaining life of the pipeline in accordance with paragraph 
Sec.  192.712;
    (vi) Operational monitoring procedures;
    (vii) Methodology and criteria used to justify and establish the 
MAOP; and
    (vii) Documentation of the operator's process and procedures used to 
implement the use of the alternative technology, including any records 
generated through its use.
    (d) Records. An operator must retain records of investigations, 
tests, analyses, assessments, repairs, replacements, alterations, and 
other actions taken in accordance with the requirements of this section 
for the life of the pipeline.

[Amdt. 192-125, 84 FR 52247, Oct. 1, 2019, as amended by Amdt. 192-127, 
85 FR 40134, July 6, 2020]



Sec.  192.625  Odorization of gas.

    (a) A combustible gas in a distribution line must contain a natural 
odorant or be odorized so that at a concentration in air of one-fifth of 
the lower explosive limit, the gas is readily detectable by a person 
with a normal sense of smell.
    (b) After December 31, 1976, a combustible gas in a transmission 
line in a Class 3 or Class 4 location must comply with the requirements 
of paragraph (a) of this section unless:
    (1) At least 50 percent of the length of the line downstream from 
that location is in a Class 1 or Class 2 location;
    (2) The line transports gas to any of the following facilities which 
received

[[Page 527]]

gas without an odorant from that line before May 5, 1975;
    (i) An underground storage field;
    (ii) A gas processing plant;
    (iii) A gas dehydration plant; or
    (iv) An industrial plant using gas in a process where the presence 
of an odorant:
    (A) Makes the end product unfit for the purpose for which it is 
intended;
    (B) Reduces the activity of a catalyst; or
    (C) Reduces the percentage completion of a chemical reaction;
    (3) In the case of a lateral line which transports gas to a 
distribution center, at least 50 percent of the length of that line is 
in a Class 1 or Class 2 location; or
    (4) The combustible gas is hydrogen intended for use as a feedstock 
in a manufacturing process.
    (c) In the concentrations in which it is used, the odorant in 
combustible gases must comply with the following:
    (1) The odorant may not be deleterious to persons, materials, or 
pipe.
    (2) The products of combustion from the odorant may not be toxic 
when breathed nor may they be corrosive or harmful to those materials to 
which the products of combustion will be exposed.
    (d) The odorant may not be soluble in water to an extent greater 
than 2.5 parts to 100 parts by weight.
    (e) Equipment for odorization must introduce the odorant without 
wide variations in the level of odorant.
    (f) To assure the proper concentration of odorant in accordance with 
this section, each operator must conduct periodic sampling of 
combustible gases using an instrument capable of determining the 
percentage of gas in air at which the odor becomes readily detectable. 
Operators of master meter systems may comply with this requirement by--
    (1) Receiving written verification from their gas source that the 
gas has the proper concentration of odorant; and
    (2) Conducting periodic ``sniff'' tests at the extremities of the 
system to confirm that the gas contains odorant.

[35 FR 13257, Aug. 19, 1970]

    Editorial Note: For Federal Register citations affecting Sec.  
192.625, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.govinfo.gov.



Sec.  192.627  Tapping pipelines under pressure.

    Each tap made on a pipeline under pressure must be performed by a 
crew qualified to make hot taps.



Sec.  192.629  Purging of pipelines.

    (a) When a pipeline is being purged of air by use of gas, the gas 
must be released into one end of the line in a moderately rapid and 
continuous flow. If gas cannot be supplied in sufficient quantity to 
prevent the formation of a hazardous mixture of gas and air, a slug of 
inert gas must be released into the line before the gas.
    (b) When a pipeline is being purged of gas by use of air, the air 
must be released into one end of the line in a moderately rapid and 
continuous flow. If air cannot be supplied in sufficient quantity to 
prevent the formation of a hazardous mixture of gas and air, a slug of 
inert gas must be released into the line before the air.



Sec.  192.631  Control room management.

    (a) General. (1) This section applies to each operator of a pipeline 
facility with a controller working in a control room who monitors and 
controls all or part of a pipeline facility through a SCADA system. Each 
operator must have and follow written control room management procedures 
that implement the requirements of this section, except that for each 
control room where an operator's activities are limited to either or 
both of:
    (i) Distribution with less than 250,000 services, or
    (ii) Transmission without a compressor station, the operator must 
have and follow written procedures that implement only paragraphs (d) 
(regarding fatigue), (i) (regarding compliance validation), and (j) 
(regarding compliance and deviations) of this section.
    (2) The procedures required by this section must be integrated, as 
appropriate, with operating and emergency procedures required by 
Sec. Sec.  192.605 and 192.615. An operator must develop the procedures 
no later than August 1, 2011,

[[Page 528]]

and must implement the procedures according to the following schedule. 
The procedures required by paragraphs (b), (c)(5), (d)(2) and (d)(3), 
(f) and (g) of this section must be implemented no later than October 1, 
2011. The procedures required by paragraphs (c)(1) through (4), (d)(1), 
(d)(4), and (e) must be implemented no later than August 1, 2012. The 
training procedures required by paragraph (h) must be implemented no 
later than August 1, 2012, except that any training required by another 
paragraph of this section must be implemented no later than the deadline 
for that paragraph.
    (b) Roles and responsibilities. Each operator must define the roles 
and responsibilities of a controller during normal, abnormal, and 
emergency operating conditions. To provide for a controller's prompt and 
appropriate response to operating conditions, an operator must define 
each of the following:
    (1) A controller's authority and responsibility to make decisions 
and take actions during normal operations;
    (2) A controller's role when an abnormal operating condition is 
detected, even if the controller is not the first to detect the 
condition, including the controller's responsibility to take specific 
actions and to communicate with others;
    (3) A controller's role during an emergency, even if the controller 
is not the first to detect the emergency, including the controller's 
responsibility to take specific actions and to communicate with others;
    (4) A method of recording controller shift-changes and any hand-over 
of responsibility between controllers; and
    (5) The roles, responsibilities and qualifications of others with 
the authority to direct or supersede the specific technical actions of a 
controller.
    (c) Provide adequate information. Each operator must provide its 
controllers with the information, tools, processes and procedures 
necessary for the controllers to carry out the roles and 
responsibilities the operator has defined by performing each of the 
following:
    (1) Implement sections 1, 4, 8, 9, 11.1, and 11.3 of API RP 1165 
(incorporated by reference, see Sec.  192.7) whenever a SCADA system is 
added, expanded or replaced, unless the operator demonstrates that 
certain provisions of sections 1, 4, 8, 9, 11.1, and 11.3 of API RP 1165 
are not practical for the SCADA system used;
    (2) Conduct a point-to-point verification between SCADA displays and 
related field equipment when field equipment is added or moved and when 
other changes that affect pipeline safety are made to field equipment or 
SCADA displays;
    (3) Test and verify an internal communication plan to provide 
adequate means for manual operation of the pipeline safely, at least 
once each calendar year, but at intervals not to exceed 15 months;
    (4) Test any backup SCADA systems at least once each calendar year, 
but at intervals not to exceed 15 months; and
    (5) Establish and implement procedures for when a different 
controller assumes responsibility, including the content of information 
to be exchanged.
    (d) Fatigue mitigation. Each operator must implement the following 
methods to reduce the risk associated with controller fatigue that could 
inhibit a controller's ability to carry out the roles and 
responsibilities the operator has defined:
    (1) Establish shift lengths and schedule rotations that provide 
controllers off-duty time sufficient to achieve eight hours of 
continuous sleep;
    (2) Educate controllers and supervisors in fatigue mitigation 
strategies and how off-duty activities contribute to fatigue;
    (3) Train controllers and supervisors to recognize the effects of 
fatigue; and
    (4) Establish a maximum limit on controller hours-of-service, which 
may provide for an emergency deviation from the maximum limit if 
necessary for the safe operation of a pipeline facility.
    (e) Alarm management. Each operator using a SCADA system must have a 
written alarm management plan to provide for effective controller 
response to alarms. An operator's plan must include provisions to:
    (1) Review SCADA safety-related alarm operations using a process 
that ensures alarms are accurate and support safe pipeline operations;

[[Page 529]]

    (2) Identify at least once each calendar month points affecting 
safety that have been taken off scan in the SCADA host, have had alarms 
inhibited, generated false alarms, or that have had forced or manual 
values for periods of time exceeding that required for associated 
maintenance or operating activities;
    (3) Verify the correct safety-related alarm set-point values and 
alarm descriptions at least once each calendar year, but at intervals 
not to exceed 15 months;
    (4) Review the alarm management plan required by this paragraph at 
least once each calendar year, but at intervals not exceeding 15 months, 
to determine the effectiveness of the plan;
    (5) Monitor the content and volume of general activity being 
directed to and required of each controller at least once each calendar 
year, but at intervals not to exceed 15 months, that will assure 
controllers have sufficient time to analyze and react to incoming 
alarms; and
    (6) Address deficiencies identified through the implementation of 
paragraphs (e)(1) through (e)(5) of this section.
    (f) Change management. Each operator must assure that changes that 
could affect control room operations are coordinated with the control 
room personnel by performing each of the following:
    (1) Establish communications between control room representatives, 
operator's management, and associated field personnel when planning and 
implementing physical changes to pipeline equipment or configuration;
    (2) Require its field personnel to contact the control room when 
emergency conditions exist and when making field changes that affect 
control room operations; and
    (3) Seek control room or control room management participation in 
planning prior to implementation of significant pipeline hydraulic or 
configuration changes.
    (g) Operating experience. Each operator must assure that lessons 
learned from its operating experience are incorporated, as appropriate, 
into its control room management procedures by performing each of the 
following:
    (1) Review incidents that must be reported pursuant to 49 CFR part 
191 to determine if control room actions contributed to the event and, 
if so, correct, where necessary, deficiencies related to:
    (i) Controller fatigue;
    (ii) Field equipment;
    (iii) The operation of any relief device;
    (iv) Procedures;
    (v) SCADA system configuration; and
    (vi) SCADA system performance.
    (2) Include lessons learned from the operator's experience in the 
training program required by this section.
    (h) Training. Each operator must establish a controller training 
program and review the training program content to identify potential 
improvements at least once each calendar year, but at intervals not to 
exceed 15 months. An operator's program must provide for training each 
controller to carry out the roles and responsibilities defined by the 
operator. In addition, the training program must include the following 
elements:
    (1) Responding to abnormal operating conditions likely to occur 
simultaneously or in sequence;
    (2) Use of a computerized simulator or non-computerized (tabletop) 
method for training controllers to recognize abnormal operating 
conditions;
    (3) Training controllers on their responsibilities for communication 
under the operator's emergency response procedures;
    (4) Training that will provide a controller a working knowledge of 
the pipeline system, especially during the development of abnormal 
operating conditions;
    (5) For pipeline operating setups that are periodically, but 
infrequently used, providing an opportunity for controllers to review 
relevant procedures in advance of their application; and
    (6) Control room team training and exercises that include both 
controllers and other individuals, defined by the operator, who would 
reasonably be expected to operationally collaborate with controllers 
(control room personnel) during normal, abnormal or emergency 
situations. Operators must

[[Page 530]]

comply with the team training requirements under this paragraph by no 
later than January 23, 2018.
    (i) Compliance validation. Upon request, operators must submit their 
procedures to PHMSA or, in the case of an intrastate pipeline facility 
regulated by a State, to the appropriate State agency.
    (j) Compliance and deviations. An operator must maintain for review 
during inspection:
    (1) Records that demonstrate compliance with the requirements of 
this section; and
    (2) Documentation to demonstrate that any deviation from the 
procedures required by this section was necessary for the safe operation 
of a pipeline facility.

[Amdt. 192-112, 74 FR 63327, Dec. 3, 2009, as amended at 75 FR 5537, 
Feb. 3, 2010; 76 FR 35135, June 16, 2011; Amdt. 192-123, 82 FR 7997, 
Jan. 23, 2017]



Sec.  192.632  Engineering Critical Assessment for Maximum Allowable  
Operating Pressure Reconfirmation: Onshore steel transmission pipelines.

    When an operator conducts an MAOP reconfirmation in accordance with 
Sec.  192.624(c)(3) ``Method 3'' using an ECA to establish the material 
strength and MAOP of the pipeline segment, the ECA must comply with the 
requirements of this section. The ECA must assess: Threats; loadings and 
operational circumstances relevant to those threats, including along the 
pipeline right-of way; outcomes of the threat assessment; relevant 
mechanical and fracture properties; in-service degradation or failure 
processes; and initial and final defect size relevance. The ECA must 
quantify the interacting effects of threats on any defect in the 
pipeline.
    (a) ECA Analysis. (1) The material properties required to perform an 
ECA analysis in accordance with this paragraph are as follows: Diameter, 
wall thickness, seam type, grade (minimum yield strength and ultimate 
tensile strength), and Charpy v-notch toughness values based upon the 
lowest operational temperatures, if applicable. If any material 
properties required to perform an ECA for any pipeline segment in 
accordance with this paragraph are not documented in traceable, 
verifiable and complete records, an operator must use conservative 
assumptions and include the pipeline segment in its program to verify 
the undocumented information in accordance with Sec.  192.607. The ECA 
must integrate, analyze, and account for the material properties, the 
results of all tests, direct examinations, destructive tests, and 
assessments performed in accordance with this section, along with other 
pertinent information related to pipeline integrity, including close 
interval surveys, coating surveys, interference surveys required by 
subpart I of this part, cause analyses of prior incidents, prior 
pressure test leaks and failures, other leaks, pipe inspections, and 
prior integrity assessments, including those required by Sec. Sec.  
192.617, 192.710, and subpart O of this part.
    (2) The ECA must analyze and determine the predicted failure 
pressure for the defect being assessed using procedures that implement 
the appropriate failure criteria and justification as follows:
    (i) The ECA must analyze any cracks or crack-like defects remaining 
in the pipe, or that could remain in the pipe, to determine the 
predicted failure pressure of each defect in accordance with Sec.  
192.712.
    (ii) The ECA must analyze any metal loss defects not associated with 
a dent, including corrosion, gouges, scrapes or other metal loss defects 
that could remain in the pipe, to determine the predicted failure 
pressure. ASME/ANSI B31G (incorporated by reference, see Sec.  192.7) or 
R-STRENG (incorporated by reference, see Sec.  192.7) must be used for 
corrosion defects. Both procedures and their analysis apply to corroded 
regions that do not penetrate the pipe wall over 80 percent of the wall 
thickness and are subject to the limitations prescribed in the 
equations' procedures. The ECA must use conservative assumptions for 
metal loss dimensions (length, width, and depth).
    (iii) When determining the predicted failure pressure for gouges, 
scrapes, selective seam weld corrosion, crack-related defects, or any 
defect within a dent, appropriate failure criteria and justification of 
the criteria must be used and documented.

[[Page 531]]

    (iv) If SMYS or actual material yield and ultimate tensile strength 
is not known or not documented by traceable, verifiable, and complete 
records, then the operator must assume 30,000 p.s.i. or determine the 
material properties using Sec.  192.607.
    (3) The ECA must analyze the interaction of defects to 
conservatively determine the most limiting predicted failure pressure. 
Examples include, but are not limited to, cracks in or near locations 
with corrosion metal loss, dents with gouges or other metal loss, or 
cracks in or near dents or other deformation damage. The ECA must 
document all evaluations and any assumptions used in the ECA process.
    (4) The MAOP must be established at the lowest predicted failure 
pressure for any known or postulated defect, or interacting defects, 
remaining in the pipe divided by the greater of 1.25 or the applicable 
factor listed in Sec.  192.619(a)(2)(ii).
    (b) Assessment to determine defects remaining in the pipe. An 
operator must utilize previous pressure tests or develop and implement 
an assessment program to determine the size of defects remaining in the 
pipe to be analyzed in accordance with paragraph (a) of this section.
    (1) An operator may use a previous pressure test that complied with 
subpart J to determine the defects remaining in the pipe if records for 
a pressure test meeting the requirements of subpart J of this part exist 
for the pipeline segment. The operator must calculate the largest defect 
that could have survived the pressure test. The operator must predict 
how much the defects have grown since the date of the pressure test in 
accordance with Sec.  192.712. The ECA must analyze the predicted size 
of the largest defect that could have survived the pressure test that 
could remain in the pipe at the time the ECA is performed. The operator 
must calculate the remaining life of the most severe defects that could 
have survived the pressure test and establish a re-assessment interval 
in accordance with the methodology in Sec.  192.712.
    (2) Operators may use an inline inspection program in accordance 
with paragraph (c) of this section.
    (3) Operators may use ``other technology'' if it is validated by a 
subject matter expert to produce an equivalent understanding of the 
condition of the pipe equal to or greater than pressure testing or an 
inline inspection program. If an operator elects to use ``other 
technology'' in the ECA, it must notify PHMSA in advance of using the 
other technology in accordance with Sec.  192.18. The ``other 
technology'' notification must have:
    (i) Descriptions of the technology or technologies to be used for 
all tests, examinations, and assessments, including characterization of 
defect size used in the crack assessments (length, depth, and 
volumetric); and
    (ii) Procedures and processes to conduct tests, examinations, 
assessments and evaluations, analyze defects, and remediate defects 
discovered.
    (c) In-line inspection. An inline inspection (ILI) program to 
determine the defects remaining the pipe for the ECA analysis must be 
performed using tools that can detect wall loss, deformation from dents, 
wrinkle bends, ovalities, expansion, seam defects, including cracking 
and selective seam weld corrosion, longitudinal, circumferential and 
girth weld cracks, hard spot cracking, and stress corrosion cracking.
    (1) If a pipeline has segments that might be susceptible to hard 
spots based on assessment, leak, failure, manufacturing vintage history, 
or other information, then the ILI program must include a tool that can 
detect hard spots.
    (2) If the pipeline has had a reportable incident, as defined in 
Sec.  191.3, attributed to a girth weld failure since its most recent 
pressure test, then the ILI program must include a tool that can detect 
girth weld defects unless the ECA analysis performed in accordance with 
this section includes an engineering evaluation program to analyze and 
account for the susceptibility of girth weld failure due to lateral 
stresses.
    (3) Inline inspection must be performed in accordance with Sec.  
192.493.
    (4) An operator must use unity plots or equivalent methodologies to 
validate the performance of the ILI tools in identifying and sizing 
actionable manufacturing and construction related anomalies. Enough data 
points

[[Page 532]]

must be used to validate tool performance at the same or better 
statistical confidence level provided in the tool specifications. The 
operator must have a process for identifying defects outside the tool 
performance specifications and following up with the ILI vendor to 
conduct additional in-field examinations, reanalyze ILI data, or both.
    (5) Interpretation and evaluation of assessment results must meet 
the requirements of Sec. Sec.  192.710, 192.713, and subpart O of this 
part, and must conservatively account for the accuracy and reliability 
of ILI, in-the-ditch examination methods and tools, and any other 
assessment and examination results used to determine the actual sizes of 
cracks, metal loss, deformation and other defect dimensions by applying 
the most conservative limit of the tool tolerance specification. ILI and 
in-the-ditch examination tools and procedures for crack assessments 
(length and depth) must have performance and evaluation standards 
confirmed for accuracy through confirmation tests for the defect types 
and pipe material vintage being evaluated. Inaccuracies must be 
accounted for in the procedures for evaluations and fracture mechanics 
models for predicted failure pressure determinations.
    (6) Anomalies detected by ILI assessments must be remediated in 
accordance with applicable criteria in Sec. Sec.  192.713 and 192.933.
    (d) Defect remaining life. If any pipeline segment contains cracking 
or may be susceptible to cracking or crack-like defects found through or 
identified by assessments, leaks, failures, manufacturing vintage 
histories, or any other available information about the pipeline, the 
operator must estimate the remaining life of the pipeline in accordance 
with Sec.  192.712.
    (e) Records. An operator must retain records of investigations, 
tests, analyses, assessments, repairs, replacements, alterations, and 
other actions taken in accordance with the requirements of this section 
for the life of the pipeline.

[Amdt. 192-125, 84 FR 52249, Oct. 1, 2019]



Sec.  192.634  Transmission lines: Onshore valve shut-off for rupture 
mitigation.

    (a) Applicability. For new or entirely replaced onshore transmission 
pipeline segments with diameters of 6 inches or greater that are located 
in high-consequence areas (HCA) or Class 3 or Class 4 locations and that 
are installed after April 10, 2023, an operator must install or use 
existing rupture-mitigation valves (RMV), or an alternative equivalent 
technology, according to the requirements of this section and Sec. Sec.  
192.179 and 192.636. RMVs and alternative equivalent technologies must 
be operational within 14 days of placing the new or replaced pipeline 
segment into service. An operator may request an extension of this 14-
day operation requirement if it can demonstrate to PHMSA, in accordance 
with the notification procedures in Sec.  192.18, that application of 
that requirement would be economically, technically, or operationally 
infeasible. The requirements of this section apply to all applicable 
pipe replacement projects, even those that do not otherwise involve the 
addition or replacement of a valve. This section does not apply to pipe 
segments in Class 1 or Class 2 locations that have a potential impact 
radius (PIR), as defined in Sec.  192.903, that is less than or equal to 
150 feet.
    (b) Maximum spacing between valves. RMVs, or alternative equivalent 
technology, must be installed in accordance with the following 
requirements:
    (1) Shut-off segment. For purposes of this section, a ``shut-off 
segment'' means the segment of pipe located between the upstream valve 
closest to the upstream endpoint of the new or replaced Class 3 or Class 
4 or HCA pipeline segment and the downstream valve closest to the 
downstream endpoint of the new or replaced Class 3 or Class 4 or HCA 
pipeline segment so that the entirety of the segment that is within the 
HCA or the Class 3 or Class 4 location is between at least two RMVs or 
alternative equivalent technologies. If any crossover or lateral pipe 
for gas receipts or deliveries connects to the shut-off segment between 
the upstream and downstream valves, the shut-off segment also must 
extend to a valve on

[[Page 533]]

the crossover connection(s) or lateral(s), such that, when all valves 
are closed, there is no flow path for gas to be transported to the 
rupture site (except for residual gas already in the shut-off segment). 
Multiple Class 3 or Class 4 locations or HCA segments may be contained 
within a single shut-off segment. The operator is not required to select 
the closest valve to the shut-off segment as the RMV, as that term is 
defined in Sec.  192.3, or the alternative equivalent technology. An 
operator may use a manual compressor station valve at a continuously 
manned station as an alternative equivalent technology, but it must be 
able to be closed within 30 minutes following rupture identification, as 
that term is defined at Sec.  192.3. Such a valve used as an alternative 
equivalent technology would not require a notification to PHMSA in 
accordance with Sec.  192.18.
    (2) Shut-off segment valve spacing. A pipeline subject to paragraph 
(a) of this section must have RMVs or alternative equivalent technology 
on the upstream and downstream side of the pipeline segment. The 
distance between RMVs or alternative equivalent technologies must not 
exceed:
    (i) Eight (8) miles for any Class 4 location,
    (ii) Fifteen (15) miles for any Class 3 location, or
    (iii) Twenty (20) miles for all other locations.
    (3) Laterals. Laterals extending from shut-off segments that 
contribute less than 5 percent of the total shut-off segment volume may 
have RMVs or alternative equivalent technologies that meet the actuation 
requirements of this section at locations other than mainline receipt/
delivery points, as long as all of the laterals contributing gas volumes 
to the shut-off segment do not contribute more than 5 percent of the 
total shut-off segment gas volume based upon maximum flow volume at the 
operating pressure. For laterals that are 12 inches in diameter or less, 
a check valve that allows gas to flow freely in one direction and 
contains a mechanism to automatically prevent flow in the other 
direction may be used as an alternative equivalent technology where it 
is positioned to stop flow into the shut-off segment. Such check valves 
that are used as an alternative equivalent technology in accordance with 
this paragraph (b)(3) are not subject to Sec.  192.636, but they must be 
inspected, operated, and remediated in accordance with Sec.  192.745, 
including for closure and leakage to ensure operational reliability. An 
operator using such a check valve as an alternative equivalent 
technology must notify PHMSA in accordance with Sec. Sec.  192.18 and 
192.179 and develop and implement maintenance procedures for such 
equipment that meet Sec.  192.745.
    (4) Crossovers. An operator may use a manual valve as an alternative 
equivalent technology in lieu of an RMV for a crossover connection if, 
during normal operations, the valve is closed to prevent the flow of gas 
by the use of a locking device or other means designed to prevent the 
opening of the valve by persons other than those authorized by the 
operator. The operator must develop and implement operating procedures 
and document that the valve has been closed and locked in accordance 
with the operator's lock-out and tag-out procedures to prevent the flow 
of gas. An operator using such a manual valve as an alternative 
equivalent technology must notify PHMSA in accordance with Sec. Sec.  
192.18 and 192.179.

[Amdt. 192-130, 87 FR 20984, Apr. 8, 2022, as amended by Amdt. 192-134, 
88 FR 50061, Aug. 1, 2023]



Sec.  192.635  Notification of potential rupture.

    (a) As used in this part, a ``notification of potential rupture'' 
refers to the notification of, or observation by, an operator (e.g., by 
or to its controller(s) in a control room, field personnel, nearby 
pipeline or utility personnel, the public, local responders, or public 
authorities) of one or more of the below indicia of a potential 
unintentional or uncontrolled release of a large volume of gas from a 
pipeline:
    (1) An unanticipated or unexplained pressure loss outside of the 
pipeline's normal operating pressures, as defined in the operator's 
written procedures. The operator must establish in its written 
procedures that an unanticipated or unplanned pressure loss is outside 
of the pipeline's normal operating pressures when there is a pressure 
loss

[[Page 534]]

greater than 10 percent occurring within a time interval of 15 minutes 
or less, unless the operator has documented in its written procedures 
the operational need for a greater pressure-change threshold due to 
pipeline flow dynamics (including changes in operating pressure, flow 
rate, or volume), that are caused by fluctuations in gas demand, gas 
receipts, or gas deliveries; or
    (2) An unanticipated or unexplained flow rate change, pressure 
change, equipment function, or other pipeline instrumentation indication 
at the upstream or downstream station that may be representative of an 
event meeting paragraph (a)(1) of this section; or
    (3) Any unanticipated or unexplained rapid release of a large volume 
of gas, a fire, or an explosion in the immediate vicinity of the 
pipeline.
    (b) A notification of potential rupture occurs when an operator 
first receives notice of or observes an event specified in paragraph (a) 
of this section.

[Amdt. 192-130, 87 FR 20985, Apr. 8, 2022]



Sec.  192.636  Transmission lines: Response to a rupture; capabilities of 
rupture-mitigation valves (RMVs) or alternative equivalent technologies.

    (a) Scope. The requirements in this section apply to rupture-
mitigation valves (RMVs), as defined in Sec.  192.3, or alternative 
equivalent technologies, installed pursuant to Sec. Sec.  192.179(e), 
(f), and (g) and 192.634.
    (b) Rupture identification and valve shut-off time. An operator 
must, as soon as practicable but within 30 minutes of rupture 
identification (see Sec.  192.615(a)(12)), fully close any RMVs or 
alternative equivalent technologies necessary to minimize the volume of 
gas released from a pipeline and mitigate the consequences of a rupture.
    (c) Open valves. An operator may leave an RMV or alternative 
equivalent technology open for more than 30 minutes, as required by 
paragraph (b) of this section, if the operator has previously 
established in its operating procedures and demonstrated within a notice 
submitted under Sec.  192.18 for PHMSA review, that closing the RMV or 
alternative equivalent technology would be detrimental to public safety. 
The request must have been coordinated with appropriate local emergency 
responders, and the operator and emergency responders must determine 
that it is safe to leave the valve open. Operators must have written 
procedures for determining whether to leave an RMV or alternative 
equivalent technology open, including plans to communicate with local 
emergency responders and minimize environmental impacts, which must be 
submitted as part of its notification to PHMSA.
    (d) Valve monitoring and operation capabilities. An RMV, as defined 
in Sec.  192.3, or alternative equivalent technology, must be capable of 
being monitored or controlled either remotely or by on-site personnel as 
follows:
    (1) Operated during normal, abnormal, and emergency operating 
conditions;
    (2) Monitored for valve status (i.e., open, closed, or partial 
closed/open), upstream pressure, and downstream pressure. For automatic 
shut-off valves (ASV), an operator does not need to monitor remotely a 
valve's status if the operator has the capability to monitor pressures 
or gas flow rate within each pipeline segment located between RMVs or 
alternative equivalent technologies to identify and locate a rupture. 
Pipeline segments that use manual valves or other alternative equivalent 
technologies must have the capability to monitor pressures or gas flow 
rates on the pipeline to identify and locate a rupture; and
    (3) Have a back-up power source to maintain SCADA systems or other 
remote communications for remote-control valve (RCV) or automatic shut-
off valve (ASV) operational status, or be monitored and controlled by 
on-site personnel.
    (e) Monitoring of valve shut-off response status. The position and 
operational status of an RMV must be appropriately monitored through 
electronic communication with remote instrumentation or other equivalent 
means. An operator does not need to monitor remotely an ASV's status if 
the operator has the capability to monitor pressures or gas flow rate on 
the pipeline to identify and locate a rupture.

[[Page 535]]

    (f) Flow modeling for automatic shut-off valves. Prior to using an 
ASV as an RMV, an operator must conduct flow modeling for the shut-off 
segment and any laterals that feed the shut-off segment, so that the 
valve will close within 30 minutes or less following rupture 
identification, consistent with the operator's procedures, and in 
accordance with Sec.  192.3 and this section. The flow modeling must 
include the anticipated maximum, normal, or any other flow volumes, 
pressures, or other operating conditions that may be encountered during 
the year, not exceeding a period of 15 months, and it must be modeled 
for the flow between the RMVs or alternative equivalent technologies, 
and any looped pipelines or gas receipt tie-ins. If operating conditions 
change that could affect the ASV set pressures and the 30-minute valve 
closure time after notification of potential rupture, as defined at 
Sec.  192.3, an operator must conduct a new flow model and reset the ASV 
set pressures prior to the next review for ASV set pressures in 
accordance with Sec.  192.745. The flow model must include a time/
pressure chart for the segment containing the ASV if a rupture occurs. 
An operator must conduct this flow modeling prior to making flow 
condition changes in a manner that could render the 30-minute valve 
closure time unachievable.
    (g) Manual valves in non-HCA, Class 1 locations. For pipeline 
segments in a Class 1 location that do not meet the definition of a high 
consequence area (HCA), an operator submitting a notification pursuant 
to Sec. Sec.  192.18 and 192.179 for use of manual valves as an 
alternative equivalent technology may also request an exemption from the 
requirements of Sec.  192.636(b).
    (h) Manual operation upon identification of a rupture. Operators 
using a manual valve as an alternative equivalent technology as 
authorized pursuant to Sec. Sec.  192.18, 192.179, and 192.634 and this 
section must develop and implement operating procedures that 
appropriately designate and locate nearby personnel to ensure valve 
shutoff in accordance with this section and Sec.  192.634. Manual 
operation of valves must include time for the assembly of necessary 
operating personnel, the acquisition of necessary tools and equipment, 
driving time under heavy traffic conditions and at the posted speed 
limit, walking time to access the valve, and time to shut off all valves 
manually, not to exceed the maximum response time allowed under 
paragraph (b) or (c) of this section.

[Amdt. 192-130, 87 FR 20985, Apr. 8, 2022, as amended by Amdt. 192-134, 
88 FR 50062, Aug. 1, 2023]



                          Subpart M_Maintenance



Sec.  192.701  Scope.

    This subpart prescribes minimum requirements for maintenance of 
pipeline facilities.



Sec.  192.703  General.

    (a) No person may operate a segment of pipeline, unless it is 
maintained in accordance with this subpart.
    (b) Each segment of pipeline that becomes unsafe must be replaced, 
repaired, or removed from service.
    (c) Hazardous leaks must be repaired promptly.



Sec.  192.705  Transmission lines: Patrolling.

    (a) Each operator shall have a patrol program to observe surface 
conditions on and adjacent to the transmission line right-of-way for 
indications of leaks, construction activity, and other factors affecting 
safety and operation.
    (b) The frequency of patrols is determined by the size of the line, 
the operating pressures, the class location, terrain, weather, and other 
relevant factors, but intervals between patrols may not be longer than 
prescribed in the following table:

------------------------------------------------------------------------
                                     Maximum interval between patrols
------------------------------------------------------------------------
                                    At highway and       At all other
     Class location of line       railroad crossings        places
------------------------------------------------------------------------
1, 2............................  7\1/2\ months; but  15 months; but at
                                   at least twice      least once each
                                   each calendar       calendar year.
                                   year.
3...............................  4\1/2\ months; but  7\1/2\ months; but
                                   at least four       at least twice
                                   times each          each calendar
                                   calendar year.      year.
4...............................  4\1/2\ months; but  4\1/2\ months; but
                                   at least four       at least four
                                   times each          times each
                                   calendar year.      calendar year.
------------------------------------------------------------------------


[[Page 536]]

    (c) Methods of patrolling include walking, driving, flying or other 
appropriate means of traversing the right-of-way.

[Amdt. 192-21, 40 FR 20283, May 9, 1975, as amended by Amdt. 192-43, 47 
FR 46851, Oct. 21, 1982; Amdt. 192-78, 61 FR 28786, June 6, 1996]



Sec.  192.706  Transmission lines: Leakage surveys.

    Leakage surveys of a transmission line must be conducted at 
intervals not exceeding 15 months, but at least once each calendar year. 
However, in the case of a transmission line which transports gas in 
conformity with Sec.  192.625 without an odor or odorant, leakage 
surveys using leak detector equipment must be conducted--
    (a) In Class 3 locations, at intervals not exceeding 7\1/2\ months, 
but at least twice each calendar year; and
    (b) In Class 4 locations, at intervals not exceeding 4\1/2\ months, 
but at least four times each calendar year.

[Amdt. 192-21, 40 FR 20283, May 9, 1975, as amended by Amdt. 192-43, 47 
FR 46851, Oct. 21, 1982; Amdt. 192-71, 59 FR 6585, Feb. 11, 1994]



Sec.  192.707  Line markers for mains and transmission lines.

    (a) Buried pipelines. Except as provided in paragraph (b) of this 
section, a line marker must be placed and maintained as close as 
practical over each buried main and transmission line:
    (1) At each crossing of a public road and railroad; and
    (2) Wherever necessary to identify the location of the transmission 
line or main to reduce the possibility of damage or interference.
    (b) Exceptions for buried pipelines. Line markers are not required 
for the following pipelines:
    (1) Mains and transmission lines located offshore, or at crossings 
of or under waterways and other bodies of water.
    (2) Mains in Class 3 or Class 4 locations where a damage prevention 
program is in effect under Sec.  192.614.
    (3) Transmission lines in Class 3 or 4 locations until March 20, 
1996.
    (4) Transmission lines in Class 3 or 4 locations where placement of 
a line marker is impractical.
    (c) Pipelines aboveground. Line markers must be placed and 
maintained along each section of a main and transmission line that is 
located aboveground in an area accessible to the public.
    (d) Marker warning. The following must be written legibly on a 
background of sharply contrasting color on each line marker:
    (1) The word ``Warning,'' ``Caution,'' or ``Danger'' followed by the 
words ``Gas (or name of gas transported) Pipeline'' all of which, except 
for markers in heavily developed urban areas, must be in letters at 
least 1 inch (25 millimeters) high with \1/4\ inch (6.4 millimeters) 
stroke.
    (2) The name of the operator and the telephone number (including 
area code) where the operator can be reached at all times.

[Amdt. 192-20, 40 FR 13505, Mar. 27, 1975; Amdt. 192-27, 41 FR 39752, 
Sept. 16, 1976, as amended by Amdt. 192-20A, 41 FR 56808, Dec. 30, 1976; 
Amdt. 192-44, 48 FR 25208, June 6, 1983; Amdt. 192-73, 60 FR 14650, Mar. 
20, 1995; Amdt. 192-85, 63 FR 37504, July 13, 1998]



Sec.  192.709  Transmission lines: Record keeping.

    Each operator shall maintain the following records for transmission 
lines for the periods specified:
    (a) The date, location, and description of each repair made to pipe 
(including pipe-to-pipe connections) must be retained for as long as the 
pipe remains in service.
    (b) The date, location, and description of each repair made to parts 
of the pipeline system other than pipe must be retained for at least 5 
years. However, repairs generated by patrols, surveys, inspections, or 
tests required by subparts L and M of this part must be retained in 
accordance with paragraph (c) of this section.
    (c) A record of each patrol, survey, inspection, and test required 
by subparts L and M of this part must be retained for at least 5 years 
or until the next patrol, survey, inspection, or test is completed, 
whichever is longer.

[Amdt. 192-78, 61 FR 28786, June 6, 1996]

[[Page 537]]



Sec.  192.710  Transmission lines: Assessments outside of high consequence 
areas.

    (a) Applicability: This section applies to onshore steel 
transmission pipeline segments with a maximum allowable operating 
pressure of greater than or equal to 30% of the specified minimum yield 
strength and are located in:
    (1) A Class 3 or Class 4 location; or
    (2) A moderate consequence area as defined in Sec.  192.3, if the 
pipeline segment can accommodate inspection by means of an instrumented 
inline inspection tool (i.e., ``smart pig'').
    (3) This section does not apply to a pipeline segment located in a 
high consequence area as defined in Sec.  192.903.
    (b) General--(1) Initial assessment. An operator must perform 
initial assessments in accordance with this section based on a risk-
based prioritization schedule and complete initial assessment for all 
applicable pipeline segments no later than July 3, 2034, or as soon as 
practicable but not to exceed 10 years after the pipeline segment first 
meets the conditions of Sec.  192.710(a) (e.g., due to a change in class 
location or the area becomes a moderate consequence area), whichever is 
later.
    (2) Periodic reassessment. An operator must perform periodic 
reassessments at least once every 10 years, with intervals not to exceed 
126 months, or a shorter reassessment interval based upon the type of 
anomaly, operational, material, and environmental conditions found on 
the pipeline segment, or as necessary to ensure public safety.
    (3) Prior assessment. An operator may use a prior assessment 
conducted before July 1, 2020 as an initial assessment for the pipeline 
segment, if the assessment met the subpart O requirements of part 192 
for in-line inspection at the time of the assessment. If an operator 
uses this prior assessment as its initial assessment, the operator must 
reassess the pipeline segment according to the reassessment interval 
specified in paragraph (b)(2) of this section calculated from the date 
of the prior assessment.
    (4) MAOP verification. An integrity assessment conducted in 
accordance with the requirements of Sec.  192.624(c) for establishing 
MAOP may be used as an initial assessment or reassessment under this 
section.
    (c) Assessment method. The initial assessments and the reassessments 
required by paragraph (b) of this section must be capable of identifying 
anomalies and defects associated with each of the threats to which the 
pipeline segment is susceptible and must be performed using one or more 
of the following methods:
    (1) Internal inspection. Internal inspection tool or tools capable 
of detecting those threats to which the pipeline is susceptible, such as 
corrosion, deformation and mechanical damage (e.g., dents, gouges and 
grooves), material cracking and crack-like defects (e.g., stress 
corrosion cracking, selective seam weld corrosion, environmentally 
assisted cracking, and girth weld cracks), hard spots with cracking, and 
any other threats to which the covered segment is susceptible. When 
performing an assessment using an in-line inspection tool, an operator 
must comply with Sec.  192.493;
    (2) Pressure test. Pressure test conducted in accordance with 
subpart J of this part. The use of subpart J pressure testing is 
appropriate for threats such as internal corrosion, external corrosion, 
and other environmentally assisted corrosion mechanisms; manufacturing 
and related defect threats, including defective pipe and pipe seams; and 
stress corrosion cracking, selective seam weld corrosion, dents and 
other forms of mechanical damage;
    (3) Spike hydrostatic pressure test. A spike hydrostatic pressure 
test conducted in accordance with Sec.  192.506. A spike hydrostatic 
pressure test is appropriate for time-dependent threats such as stress 
corrosion cracking; selective seam weld corrosion; manufacturing and 
related defects, including defective pipe and pipe seams; and other 
forms of defect or damage involving cracks or crack-like defects;
    (4) Direct examination. Excavation and in situ direct examination by 
means of visual examination, direct measurement, and recorded non-
destructive examination results and data needed to assess all applicable 
threats. Based upon the threat assessed, examples of appropriate non-
destructive examination methods include ultrasonic testing

[[Page 538]]

(UT), phased array ultrasonic testing (PAUT), Inverse Wave Field 
Extrapolation (IWEX), radiography, and magnetic particle inspection 
(MPI);
    (5) Guided Wave Ultrasonic Testing. Guided Wave Ultrasonic Testing 
(GWUT) as described in Appendix F;
    (6) Direct assessment. Direct assessment to address threats of 
external corrosion, internal corrosion, and stress corrosion cracking. 
The use of use of direct assessment to address threats of external 
corrosion, internal corrosion, and stress corrosion cracking is allowed 
only if appropriate for the threat and pipeline segment being assessed. 
Use of direct assessment for threats other than the threat for which the 
direct assessment method is suitable is not allowed. An operator must 
conduct the direct assessment in accordance with the requirements listed 
in Sec.  192.923 and with the applicable requirements specified in 
Sec. Sec.  192.925, 192.927 and 192.929; or
    (7) Other technology. Other technology that an operator demonstrates 
can provide an equivalent understanding of the condition of the line 
pipe for each of the threats to which the pipeline is susceptible. An 
operator must notify PHMSA in advance of using the other technology in 
accordance with Sec.  192.18.
    (d) Data analysis. An operator must analyze and account for the data 
obtained from an assessment performed under paragraph (c) of this 
section to determine if a condition could adversely affect the safe 
operation of the pipeline using personnel qualified by knowledge, 
training, and experience. In addition, when analyzing inline inspection 
data, an operator must account for uncertainties in reported results 
(e.g., tool tolerance, detection threshold, probability of detection, 
probability of identification, sizing accuracy, conservative anomaly 
interaction criteria, location accuracy, anomaly findings, and unity 
chart plots or equivalent for determining uncertainties and verifying 
actual tool performance) in identifying and characterizing anomalies.
    (e) Discovery of condition. Discovery of a condition occurs when an 
operator has adequate information about a condition to determine that 
the condition presents a potential threat to the integrity of the 
pipeline. An operator must promptly, but no later than 180 days after 
conducting an integrity assessment, obtain sufficient information about 
a condition to make that determination, unless the operator demonstrates 
that 180 days is impracticable.
    (f) Remediation. An operator must comply with the requirements in 
Sec. Sec.  192.485, 192.711, 192.712, 192.713, and 192.714, where 
applicable, if a condition that could adversely affect the safe 
operation of a pipeline is discovered.
    (g) Analysis of information. An operator must analyze and account 
for all available relevant information about a pipeline in complying 
with the requirements in paragraphs (a) through (f) of this section.

[Amdt. 192-125, 84 FR 52250, Oct. 1, 2019, as amended by Amdt. 192-132, 
87 FR 52270, Aug. 24, 2022]



Sec.  192.711  Transmission lines: General requirements for repair  
procedures.

    (a) Temporary repairs. Each operator must take immediate temporary 
measures to protect the public whenever:
    (1) A leak, imperfection, or damage that impairs its serviceability 
is found in a segment of steel transmission line operating at or above 
40 percent of the SMYS; and
    (2) It is not feasible to make a permanent repair at the time of 
discovery.
    (b) Permanent repairs. An operator must make permanent repairs on 
its pipeline system according to the following:
    (1)(i) Non-integrity management repairs for gathering lines and 
offshore transmission lines: For gathering lines subject to this section 
in accordance with Sec.  192.9 and for offshore transmission lines, an 
operator must make permanent repairs as soon as feasible.
    (ii) Non-integrity management repairs for onshore transmission 
lines: Except for gathering lines exempted from this section in 
accordance with Sec.  192.9 and offshore transmission lines, after May 
24, 2023, whenever an operator discovers any condition that could 
adversely affect the safe operation of a pipeline segment not covered by 
an integrity management program under

[[Page 539]]

subpart O of this part, it must correct the condition as prescribed in 
Sec.  192.714.
    (2) Integrity management repairs: When an operator discovers a 
condition on a pipeline covered under Subpart O-Gas Transmission 
Pipeline Integrity Management, the operator must remediate the condition 
as prescribed by Sec.  192.933(d).
    (c) Welded patch. Except as provided in Sec.  192.717(b)(3), no 
operator may use a welded patch as a means of repair.

[Amdt. 192-114, 75 FR 48604, Aug. 11, 2010, as amended by Amdt. 192-132, 
87 FR 52270, Aug. 24, 2022]



Sec.  192.712  Analysis of predicted failure pressure and critical strain 
level.

    (a) Applicability. Whenever required by this part, operators of 
onshore steel transmission pipelines must analyze anomalies or defects 
to determine the predicted failure pressure at the location of the 
anomaly or defect, and the remaining life of the pipeline segment at the 
location of the anomaly or defect, in accordance with this section.
    (b) Corrosion metal loss. When analyzing corrosion metal loss under 
this section, an operator must use a suitable remaining strength 
calculation method including, ASME/ANSI B31G (incorporated by reference, 
see Sec.  192.7); R-STRENG (incorporated by reference, see Sec.  192.7); 
or an alternative equivalent method of remaining strength calculation 
that will provide an equally conservative result.
    (1) If an operator would choose to use a remaining strength 
calculation method that could provide a less conservative result than 
the methods listed in paragraph (b) introductory text, the operator must 
notify PHMSA in advance in accordance with Sec.  192.18(c).
    (2) The notification provided for by paragraph (b)(1) of this 
section must include a comparison of its predicted failure pressures to 
R-STRENG or ASME/ANSI B31G, all burst pressure tests used, and any other 
technical reviews used to qualify the calculation method(s) for varying 
corrosion profiles.
    (c) Dents and other mechanical damage. To evaluate dents and other 
mechanical damage that could result in a stress riser or other integrity 
impact, an operator must develop a procedure and perform an engineering 
critical assessment as follows:
    (1) Identify and evaluate potential threats to the pipe segment in 
the vicinity of the anomaly or defect, including ground movement, 
external loading, fatigue, cracking, and corrosion.
    (2) Review high-resolution magnetic flux leakage (HR-MFL) high-
resolution deformation, inertial mapping, and crack detection inline 
inspection data for damage in the dent area and any associated weld 
region, including available data from previous inline inspections.
    (3) Perform pipeline curvature-based strain analysis using recent 
HR-Deformation inspection data.
    (4) Compare the dent profile between the most recent and previous 
in-line inspections to identify significant changes in dent depth and 
shape.
    (5) Identify and quantify all previous and present significant loads 
acting on the dent.
    (6) Evaluate the strain level associated with the anomaly or defect 
and any nearby welds using Finite Element Analysis, or other technology 
in accordance with this section. Using Finite Element Analysis to 
quantify the dent strain, and then estimating and evaluating the damage 
using the Strain Limit Damage (SLD) and Ductile Failure Damage Indicator 
(DFDI) at the dent, are appropriate evaluation methods.
    (7) The analyses performed in accordance with this section must 
account for material property uncertainties, model inaccuracies, and 
inline inspection tool sizing tolerances.
    (8) Dents with a depth greater than 10 percent of the pipe outside 
diameter or with geometric strain levels that exceed the lessor of 10 
percent or exceed the critical strain for the pipe material properties 
must be remediated in accordance with Sec.  192.713, Sec.  192.714, or 
Sec.  192.933, as applicable.
    (9) Using operational pressure data, a valid fatigue life prediction 
model that is appropriate for the pipeline segment, and assuming a 
reassessment safety factor of 5 or greater for the assessment interval, 
estimate the fatigue life of the dent by Finite Element Analysis or 
other analytical technique that is

[[Page 540]]

technically appropriate for dent assessment and reassessment intervals 
in accordance with this section. Multiple dent or other fatigue models 
must be used for the evaluation as a part of the engineering critical 
assessment.
    (10) If the dent or mechanical damage is suspected to have cracks, 
then a crack growth rate assessment is required to ensure adequate life 
for the dent with crack(s) until remediation or the dent with crack(s) 
must be evaluated and remediated in accordance with the criteria and 
timing requirements in Sec.  192.713, Sec.  192.714, or Sec.  192.933, 
as applicable.
    (11) An operator using an engineering critical assessment procedure, 
other technologies, or techniques to comply with paragraph (c) of this 
section must submit advance notification to PHMSA, with the relevant 
procedures, in accordance with Sec.  192.18.
    (d) Cracks and crack-like defects--(1) Crack analysis models. When 
analyzing cracks and crack-like defects under this section, an operator 
must determine predicted failure pressure, failure stress pressure, and 
crack growth using a technically proven fracture mechanics model 
appropriate to the failure mode (ductile, brittle or both), material 
properties (pipe and weld properties), and boundary condition used 
(pressure test, ILI, or other).
    (2) Analysis for crack growth and remaining life. If the pipeline 
segment is susceptible to cyclic fatigue or other loading conditions 
that could lead to fatigue crack growth, fatigue analysis must be 
performed using an applicable fatigue crack growth law (for example, 
Paris Law) or other technically appropriate engineering methodology. For 
other degradation processes that can cause crack growth, appropriate 
engineering analysis must be used. The above methodologies must be 
validated by a subject matter expert to determine conservative 
predictions of flaw growth and remaining life at the maximum allowable 
operating pressure. The operator must calculate the remaining life of 
the pipeline by determining the amount of time required for the crack to 
grow to a size that would fail at maximum allowable operating pressure.
    (i) When calculating crack size that would fail at MAOP, and the 
material toughness is not documented in traceable, verifiable, and 
complete records, the same Charpy v-notch toughness value established in 
paragraph (e)(2) of this section must be used.
    (ii) Initial and final flaw size must be determined using a fracture 
mechanics model appropriate to the failure mode (ductile, brittle or 
both) and boundary condition used (pressure test, ILI, or other).
    (iii) An operator must re-evaluate the remaining life of the 
pipeline before 50% of the remaining life calculated by this analysis 
has expired. The operator must determine and document if further 
pressure tests or use of other assessment methods are required at that 
time. The operator must continue to re-evaluate the remaining life of 
the pipeline before 50% of the remaining life calculated in the most 
recent evaluation has expired.
    (3) Cracks that survive pressure testing. For cases in which the 
operator does not have in-line inspection crack anomaly data and is 
analyzing potential crack defects that could have survived a pressure 
test, the operator must calculate the largest potential crack defect 
sizes using the methods in paragraph (d)(1) of this section. If pipe 
material toughness is not documented in traceable, verifiable, and 
complete records, the operator must use one of the following for Charpy 
v-notch toughness values based upon minimum operational temperature and 
equivalent to a full-size specimen value:
    (i) Charpy v-notch toughness values from comparable pipe with known 
properties of the same vintage and from the same steel and pipe 
manufacturer;
    (ii) A conservative Charpy v-notch toughness value to determine the 
toughness based upon the material properties verification process 
specified in Sec.  192.607;
    (iii) A full size equivalent Charpy v-notch upper-shelf toughness 
level of 120 ft.-lbs.; or
    (iv) Other appropriate values that an operator demonstrates can 
provide conservative Charpy v-notch toughness values of the crack-
related conditions of the pipeline segment. Operators

[[Page 541]]

using an assumed Charpy v-notch toughness value must notify PHMSA in 
accordance with Sec.  192.18.
    (e) Data. In performing the analyses of predicted or assumed 
anomalies or defects in accordance with this section, an operator must 
use data as follows.
    (1) An operator must explicitly analyze and account for 
uncertainties in reported assessment results (including tool tolerance, 
detection threshold, probability of detection, probability of 
identification, sizing accuracy, conservative anomaly interaction 
criteria, location accuracy, anomaly findings, and unity chart plots or 
equivalent for determining uncertainties and verifying tool performance) 
in identifying and characterizing the type and dimensions of anomalies 
or defects used in the analyses, unless the defect dimensions have been 
verified using in situ direct measurements.
    (2) The analyses performed in accordance with this section must 
utilize pipe and material properties that are documented in traceable, 
verifiable, and complete records. If documented data required for any 
analysis is not available, an operator must obtain the undocumented data 
through Sec.  192.607. Until documented material properties are 
available, the operator shall use conservative assumptions as follows:
    (i) Material toughness. An operator must use one of the following 
for material toughness:
    (A) Charpy v-notch toughness values from comparable pipe with known 
properties of the same vintage and from the same steel and pipe 
manufacturer;
    (B) A conservative Charpy v-notch toughness value to determine the 
toughness based upon the ongoing material properties verification 
process specified in Sec.  192.607;
    (C) If the pipeline segment does not have a history of reportable 
incidents caused by cracking or crack-like defects, maximum Charpy v-
notch toughness values of 13.0 ft.-lbs. for body cracks and 4.0 ft.-lbs. 
for cold weld, lack of fusion, and selective seam weld corrosion 
defects;
    (D) If the pipeline segment has a history of reportable incidents 
caused by cracking or crack-like defects, maximum Charpy v-notch 
toughness values of 5.0 ft.-lbs. for body cracks and 1.0 ft.-lbs. for 
cold weld, lack of fusion, and selective seam weld corrosion; or
    (E) Other appropriate values that an operator demonstrates can 
provide conservative Charpy v-notch toughness values of crack-related 
conditions of the pipeline segment. Operators using an assumed Charpy v-
notch toughness value must notify PHMSA in advance in accordance with 
Sec.  192.18 and include in the notification the bases for demonstrating 
that the Charpy v-notch toughness values proposed are appropriate and 
conservative for use in analysis of crack-related conditions.
    (ii) Material strength. An operator must assume one of the following 
for material strength:
    (A) Grade A pipe (30,000 psi), or
    (B) The specified minimum yield strength that is the basis for the 
current maximum allowable operating pressure.
    (iii) Pipe dimensions and other data. Until pipe wall thickness, 
diameter, or other data are determined and documented in accordance with 
Sec.  192.607, the operator must use values upon which the current MAOP 
is based.
    (f) Review. Analyses conducted in accordance with this section must 
be reviewed and confirmed by a subject matter expert.
    (g) Records. An operator must keep for the life of the pipeline 
records of the investigations, analyses, and other actions taken in 
accordance with the requirements of this section. Records must document 
justifications, deviations, and determinations made for the following, 
as applicable:
    (1) The technical approach used for the analysis;
    (2) All data used and analyzed;
    (3) Pipe and weld properties;
    (4) Procedures used;
    (5) Evaluation methodology used;
    (6) Models used;
    (7) Direct in situ examination data;
    (8) In-line inspection tool run information evaluated, including any 
multiple in-line inspection tool runs;
    (9) Pressure test data and results;
    (10) In-the-ditch assessments;
    (11) All measurement tool, assessment, and evaluation accuracy 
specifications and tolerances used in technical and operational results;

[[Page 542]]

    (12) All finite element analysis results;
    (13) The number of pressure cycles to failure, the equivalent number 
of annual pressure cycles, and the pressure cycle counting method;
    (14) The predicted fatigue life and predicted failure pressure from 
the required fatigue life models and fracture mechanics evaluation 
methods;
    (15) Safety factors used for fatigue life and/or predicted failure 
pressure calculations;
    (16) Reassessment time interval and safety factors;
    (17) The date of the review;
    (18) Confirmation of the results by qualified technical subject 
matter experts; and
    (19) Approval by responsible operator management personnel.
    (h) Reassessments. If an operator uses an engineering critical 
assessment method in accordance with paragraphs (c) and (d) of this 
section to determine the maximum reevaluation intervals, the operator 
must reassess the anomalies as follows:
    (1) If the anomaly is in an HCA, the operator must reassess the 
anomaly within a maximum of 7 years in accordance with Sec.  192.939(a), 
unless the safety factor is expected to go below what is specified in 
paragraph (c) or (d) of this section.
    (2) If the anomaly is outside of an HCA, the operator must perform a 
reassessment of the anomaly within a maximum of 10 years in accordance 
with Sec.  192.710(b), unless the anomaly safety factor is expected to 
go below what is specified in paragraph (c) or (d) of this section.

[Amdt. 192-125, 84 FR 52251, Oct. 1, 2019, as amended by Amdt. 192-132, 
87 FR 52270, Aug. 24, 2022]



Sec.  192.713  Transmission lines: Permanent field repair of imperfections 
and damages.

    (a) Each imperfection or damage that impairs the serviceability of 
pipe in a steel transmission line operating at or above 40 percent of 
SMYS must be--
    (1) Removed by cutting out and replacing a cylindrical piece of 
pipe; or
    (2) Repaired by a method that reliable engineering tests and 
analyses show can permanently restore the serviceability of the pipe.
    (b) Operating pressure must be at a safe level during repair 
operations.

[Amdt. 192-88, 64 FR 69665, Dec. 14, 1999]



Sec.  192.714  Transmission lines: Repair criteria for onshore transmission 
pipelines.

    (a) Applicability. This section applies to onshore transmission 
pipelines not subject to the repair criteria in subpart O of this part, 
and which do not operate under an alternative MAOP in accordance with 
Sec. Sec.  192.112, 192.328, and 192.620. Pipeline segments that are 
located in high consequence areas, as defined in Sec.  192.903, must 
comply with the applicable actions specified by the integrity management 
requirements in subpart O. Pipeline segments operating under an 
alternative MAOP in accordance with Sec. Sec.  192.112, 192.328, and 
192.620 must comply with Sec.  192.620(d)(11).
    (b) General. Each operator must, in repairing its pipeline systems, 
ensure that the repairs are made in a safe manner and are made to 
prevent damage to persons, property, and the environment. A pipeline 
segment's operating pressure must be less than the predicted failure 
pressure determined in accordance with Sec.  192.712 during repair 
operations. Repairs performed in accordance with this section must use 
pipe and material properties that are documented in traceable, 
verifiable, and complete records. If documented data required for any 
analysis, including predicted failure pressure for determining MAOP, is 
not available, an operator must obtain the undocumented data through 
Sec.  192.607. Until documented material properties are available, the 
operator must use the conservative assumptions in either Sec.  
192.712(e)(2) or, if appropriate following a pressure test, in Sec.  
192.712(d)(3).
    (c) Schedule for evaluation and remediation. An operator must 
remediate conditions according to a schedule that prioritizes the 
conditions for evaluation and remediation. Unless paragraph (d) of this 
section provides a special requirement for remediating certain 
conditions, an operator must calculate the predicted failure pressure of 
anomalies or defects and follow the schedule in ASME/ANSI B31.8S 
(incorporated by

[[Page 543]]

reference, see Sec.  192.7), section 7, Figure 4. If an operator cannot 
meet the schedule for any condition, the operator must document the 
reasons why it cannot meet the schedule and how the changed schedule 
will not jeopardize public safety. Each condition that meets any of the 
repair criteria in paragraph (d) of this section in an onshore steel 
transmission pipeline must be--
    (1) Removed by cutting out and replacing a cylindrical piece of pipe 
that will permanently restore the pipeline's MAOP based on the use of 
Sec.  192.105 and the design factors for the class location in which it 
is located; or
    (2) Repaired by a method, shown by technically proven engineering 
tests and analyses, that will permanently restore the pipeline's MAOP 
based upon the determined predicted failure pressure times the design 
factor for the class location in which it is located.
    (d) Remediation of certain conditions. For onshore transmission 
pipelines not located in high consequence areas, an operator must 
remediate a listed condition according to the following criteria:
    (1) Immediate repair conditions. An operator's evaluation and 
remediation schedule for immediate repair conditions must follow section 
7 of ASME/ANSI B31.8S (incorporated by reference, see Sec.  192.7). An 
operator must repair the following conditions immediately upon 
discovery:
    (i) Metal loss anomalies where a calculation of the remaining 
strength of the pipe at the location of the anomaly shows a predicted 
failure pressure, determined in accordance with Sec.  192.712(b), of 
less than or equal to 1.1 times the MAOP.
    (ii) A dent located between the 8 o'clock and 4 o'clock positions 
(upper \2/3\ of the pipe) that has metal loss, cracking, or a stress 
riser, unless an engineering analysis performed in accordance with Sec.  
192.712(c) demonstrates critical strain levels are not exceeded.
    (iii) Metal loss greater than 80 percent of nominal wall regardless 
of dimensions.
    (iv) Metal loss preferentially affecting a detected longitudinal 
seam, if that seam was formed by direct current, low-frequency or high-
frequency electric resistance welding, electric flash welding, or has a 
longitudinal joint factor less than 1.0, and the predicted failure 
pressure determined in accordance with Sec.  192.712(d) is less than 
1.25 times the MAOP.
    (v) A crack or crack-like anomaly meeting any of the following 
criteria:
    (A) Crack depth plus any metal loss is greater than 50 percent of 
pipe wall thickness;
    (B) Crack depth plus any metal loss is greater than the inspection 
tool's maximum measurable depth; or
    (C) The crack or crack-like anomaly has a predicted failure 
pressure, determined in accordance with Sec.  192.712(d), that is less 
than 1.25 times the MAOP.
    (vi) An indication or anomaly that, in the judgment of the person 
designated by the operator to evaluate the assessment results, requires 
immediate action.
    (2) Two-year conditions. An operator must repair the following 
conditions within 2 years of discovery:
    (i) A smooth dent located between the 8 o'clock and 4 o'clock 
positions (upper \2/3\ of the pipe) with a depth greater than 6 percent 
of the pipeline diameter (greater than 0.50 inches in depth for a 
pipeline diameter less than Nominal Pipe Size (NPS) 12), unless an 
engineering analysis performed in accordance with Sec.  192.712(c) 
demonstrates critical strain levels are not exceeded.
    (ii) A dent with a depth greater than 2 percent of the pipeline 
diameter (0.250 inches in depth for a pipeline diameter less than NPS 
12) that affects pipe curvature at a girth weld or at a longitudinal or 
helical (spiral) seam weld, unless an engineering analysis performed in 
accordance with Sec.  192.712(c) demonstrates critical strain levels are 
not exceeded.
    (iii) A dent located between the 4 o'clock and 8 o'clock positions 
(lower \1/3\ of the pipe) that has metal loss, cracking, or a stress 
riser, unless an engineering analysis performed in accordance with Sec.  
192.712(c) demonstrates critical strain levels are not exceeded.
    (iv) For metal loss anomalies, a calculation of the remaining 
strength of the pipe shows a predicted failure pressure, determined in 
accordance with Sec.  192.712(b) at the location of the anomaly, of less 
than 1.39 times the MAOP

[[Page 544]]

for Class 2 locations, or less than 1.50 times the MAOP for Class 3 and 
4 locations. For metal loss anomalies in Class 1 locations with a 
predicted failure pressure greater than 1.1 times MAOP, an operator must 
follow the remediation schedule specified in ASME/ANSI B31.8S 
(incorporated by reference, see Sec.  192.7), section 7, Figure 4, as 
specified in paragraph (c) of this section.
    (v) Metal loss that is located at a crossing of another pipeline, is 
in an area with widespread circumferential corrosion, or could affect a 
girth weld, and that has a predicted failure pressure, determined in 
accordance with Sec.  192.712(b), less than 1.39 times the MAOP for 
Class 1 locations or where Class 2 locations contain Class 1 pipe that 
has been uprated in accordance with Sec.  192.611, or less than 1.50 
times the MAOP for all other Class 2 locations and all Class 3 and 4 
locations.
    (vi) Metal loss preferentially affecting a detected longitudinal 
seam, if that seam was formed by direct current, low-frequency or high-
frequency electric resistance welding, electric flash welding, or that 
has a longitudinal joint factor less than 1.0, and where the predicted 
failure pressure determined in accordance with Sec.  192.712(d) is less 
than 1.39 times the MAOP for Class 1 locations or where Class 2 
locations contain Class 1 pipe that has been uprated in accordance with 
Sec.  192.611, or less than 1.50 times the MAOP for all other Class 2 
locations and all Class 3 and 4 locations.
    (vii) A crack or crack-like anomaly that has a predicted failure 
pressure, determined in accordance with Sec.  192.712(d), that is less 
than 1.39 times the MAOP for Class 1 locations or where Class 2 
locations contain Class 1 pipe that has been uprated in accordance with 
Sec.  192.611, or less than 1.50 times the MAOP for all other Class 2 
locations and all Class 3 and 4 locations.
    (3) Monitored conditions. An operator must record and monitor the 
following conditions during subsequent risk assessments and integrity 
assessments for any change that may require remediation.
    (i) A dent that is located between the 4 o'clock and 8 o'clock 
positions (bottom \1/3\ of the pipe) with a depth greater than 6 percent 
of the pipeline diameter (greater than 0.50 inches in depth for a 
pipeline diameter less than NPS 12), and where an engineering analysis, 
performed in accordance with Sec.  192.712(c), demonstrates critical 
strain levels are not exceeded.
    (ii) A dent located between the 8 o'clock and 4 o'clock positions 
(upper \2/3\ of the pipe) with a depth greater than 6 percent of the 
pipeline diameter (greater than 0.50 inches in depth for a pipeline 
diameter less than NPS 12), and where an engineering analysis performed 
in accordance with Sec.  192.712(c) determines that critical strain 
levels are not exceeded.
    (iii) A dent with a depth greater than 2 percent of the pipeline 
diameter (0.250 inches in depth for a pipeline diameter less than NPS 
12) that affects pipe curvature at a girth weld or longitudinal or 
helical (spiral) seam weld, and where an engineering analysis of the 
dent and girth or seam weld, performed in accordance with Sec.  
192.712(c), demonstrates critical strain levels are not exceeded. These 
analyses must consider weld mechanical properties.
    (iv) A dent that has metal loss, cracking, or a stress riser, and 
where an engineering analysis performed in accordance with Sec.  
192.712(c) demonstrates critical strain levels are not exceeded.
    (v) Metal loss preferentially affecting a detected longitudinal 
seam, if that seam was formed by direct current, low-frequency or high-
frequency electric resistance welding, electric flash welding, or that 
has a longitudinal joint factor less than 1.0, and where the predicted 
failure pressure, determined in accordance with Sec.  192.712(d), is 
greater than or equal to 1.39 times the MAOP for Class 1 locations or 
where Class 2 locations contain Class 1 pipe that has been uprated in 
accordance with Sec.  192.611, or is greater than or equal to 1.50 times 
the MAOP for all other Class 2 locations and all Class 3 and 4 
locations.
    (vi) A crack or crack-like anomaly for which the predicted failure 
pressure, determined in accordance with Sec.  192.712(d), is greater 
than or equal to

[[Page 545]]

1.39 times the MAOP for Class 1 locations or where Class 2 locations 
contain Class 1 pipe that has been uprated in accordance with Sec.  
192.611, or is greater than or equal to 1.50 times the MAOP for all 
other Class 2 locations and all Class 3 and 4 locations.
    (e) Temporary pressure reduction. (1) Immediately upon discovery and 
until an operator remediates the condition specified in paragraph (d)(1) 
of this section, or upon a determination by an operator that it is 
unable to respond within the time limits for the conditions specified in 
paragraph (d)(2) of this section, the operator must reduce the operating 
pressure of the affected pipeline to any one of the following based on 
safety considerations for the public and operating personnel:
    (i) A level not exceeding 80 percent of the operating pressure at 
the time the condition was discovered;
    (ii) A level not exceeding the predicted failure pressure times the 
design factor for the class location in which the affected pipeline is 
located; or
    (iii) A level not exceeding the predicted failure pressure divided 
by 1.1.
    (2) An operator must notify PHMSA in accordance with Sec.  192.18 if 
it cannot meet the schedule for evaluation and remediation required 
under paragraph (c) or (d) of this section and cannot provide safety 
through a temporary reduction in operating pressure or other action. 
Notification to PHMSA does not alleviate an operator from the 
evaluation, remediation, or pressure reduction requirements in this 
section.
    (3) When a pressure reduction, in accordance with paragraph (e) of 
this section, exceeds 365 days, an operator must notify PHMSA in 
accordance with Sec.  192.18 and explain the reasons for the remediation 
delay. This notice must include a technical justification that the 
continued pressure reduction will not jeopardize the integrity of the 
pipeline.
    (4) An operator must document and keep records of the calculations 
and decisions used to determine the reduced operating pressure and the 
implementation of the actual reduced operating pressure for a period of 
5 years after the pipeline has been repaired.
    (f) Other conditions. Unless another timeframe is specified in 
paragraph (d) of this section, an operator must take appropriate 
remedial action to correct any condition that could adversely affect the 
safe operation of a pipeline system in accordance with the criteria, 
schedules, and methods defined in the operator's operating and 
maintenance procedures.
    (g) In situ direct examination of crack defects. Whenever an 
operator finds conditions that require the pipeline to be repaired, in 
accordance with this section, an operator must perform a direct 
examination of known locations of cracks or crack-like defects using 
technology that has been validated to detect tight cracks (equal to or 
less than 0.008 inches crack opening), such as inverse wave field 
extrapolation (IWEX), phased array ultrasonic testing (PAUT), ultrasonic 
testing (UT), or equivalent technology. ``In situ'' examination tools 
and procedures for crack assessments (length, depth, and volumetric) 
must have performance and evaluation standards, including pipe or weld 
surface cleanliness standards for the inspection, confirmed by subject 
matter experts qualified by knowledge, training, and experience in 
direct examination inspection for accuracy of the type of defects and 
pipe material being evaluated. The procedures must account for 
inaccuracies in evaluations and fracture mechanics models for failure 
pressure determinations.
    (h) Determining predicted failure pressures and critical strain 
levels. An operator must perform all determinations of predicted failure 
pressures and critical strain levels required by this section in 
accordance with Sec.  192.712.

[Amdt. 192-132, 87 FR 52711, Aug. 24, 2022, as amended by Amdt. 192-133, 
88 FR 24712, Apr. 24, 2023]



Sec.  192.715  Transmission lines: Permanent field repair of welds.

    Each weld that is unacceptable under Sec.  192.241(c) must be 
repaired as follows:
    (a) If it is feasible to take the segment of transmission line out 
of service, the weld must be repaired in accordance with the applicable 
requirements of Sec.  192.245.
    (b) A weld may be repaired in accordance with Sec.  192.245 while 
the segment of transmission line is in service if:
    (1) The weld is not leaking;

[[Page 546]]

    (2) The pressure in the segment is reduced so that it does not 
produce a stress that is more than 20 percent of the SMYS of the pipe; 
and
    (3) Grinding of the defective area can be limited so that at least 
\1/8\-inch (3.2 millimeters) thickness in the pipe weld remains.
    (c) A defective weld which cannot be repaired in accordance with 
paragraph (a) or (b) of this section must be repaired by installing a 
full encirclement welded split sleeve of appropriate design.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37504, 
July 13, 1998]



Sec.  192.717  Transmission lines: Permanent field repair of leaks.

    Each permanent field repair of a leak on a transmission line must be 
made by--
    (a) Removing the leak by cutting out and replacing a cylindrical 
piece of pipe; or
    (b) Repairing the leak by one of the following methods:
    (1) Install a full encirclement welded split sleeve of appropriate 
design, unless the transmission line is joined by mechanical couplings 
and operates at less than 40 percent of SMYS.
    (2) If the leak is due to a corrosion pit, install a properly 
designed bolt-on-leak clamp.
    (3) If the leak is due to a corrosion pit and on pipe of not more 
than 40,000 psi (267 Mpa) SMYS, fillet weld over the pitted area a steel 
plate patch with rounded corners, of the same or greater thickness than 
the pipe, and not more than one-half of the diameter of the pipe in 
size.
    (4) If the leak is on a submerged offshore pipeline or submerged 
pipeline in inland navigable waters, mechanically apply a full 
encirclement split sleeve of appropriate design.
    (5) Apply a method that reliable engineering tests and analyses show 
can permanently restore the serviceability of the pipe.

[Amdt. 192-88, 64 FR 69665, Dec. 14, 1999]



Sec.  192.719  Transmission lines: Testing of repairs.

    (a) Testing of replacement pipe. If a segment of transmission line 
is repaired by cutting out the damaged portion of the pipe as a 
cylinder, the replacement pipe must be tested to the pressure required 
for a new line installed in the same location. This test may be made on 
the pipe before it is installed.
    (b) Testing of repairs made by welding. Each repair made by welding 
in accordance with Sec. Sec.  192.713, 192.715, and 192.717 must be 
examined in accordance with Sec.  192.241.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-54, 51 FR 41635, 
Nov. 18, 1986]



Sec.  192.720  Distribution systems: Leak repair.

    Mechanical leak repair clamps installed after January 22, 2019 may 
not be used as a permanent repair method for plastic pipe.

[Amdt. 192-124, 83 FR 58719, Nov. 20, 2018]



Sec.  192.721  Distribution systems: Patrolling.

    (a) The frequency of patrolling mains must be determined by the 
severity of the conditions which could cause failure or leakage, and the 
consequent hazards to public safety.
    (b) Mains in places or on structures where anticipated physical 
movement or external loading could cause failure or leakage must be 
patrolled--
    (1) In business districts, at intervals not exceeding 4\1/2\ months, 
but at least four times each calendar year; and
    (2) Outside business districts, at intervals not exceeding 7\1/2\ 
months, but at least twice each calendar year.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR 46851, 
Oct. 21, 1982; Amdt. 192-78, 61 FR 28786, June 6, 1996]



Sec.  192.723  Distribution systems: Leakage surveys.

    (a) Each operator of a distribution system shall conduct periodic 
leakage surveys in accordance with this section.
    (b) The type and scope of the leakage control program must be 
determined by the nature of the operations and the local conditions, but 
it must meet the following minimum requirements:
    (1) A leakage survey with leak detector equipment must be conducted 
in business districts, including tests of

[[Page 547]]

the atmosphere in gas, electric, telephone, sewer, and water system 
manholes, at cracks in pavement and sidewalks, and at other locations 
providing an opportunity for finding gas leaks, at intervals not 
exceeding 15 months, but at least once each calendar year.
    (2) A leakage survey with leak detector equipment must be conducted 
outside business districts as frequently as necessary, but at least once 
every 5 calendar years at intervals not exceeding 63 months. However, 
for cathodically unprotected distribution lines subject to Sec.  
192.465(e) on which electrical surveys for corrosion are impractical, a 
leakage survey must be conducted at least once every 3 calendar years at 
intervals not exceeding 39 months.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR 46851, 
Oct. 21, 1982; Amdt. 192-70, 58 FR 54528, 54529, Oct. 22, 1993; Amdt. 
192-71, 59 FR 6585, Feb. 11, 1994; Amdt. 192-94, 69 FR 32895, June 14, 
2004; Amdt. 192-94, 69 FR 54592, Sept. 9, 2004]



Sec.  192.725  Test requirements for reinstating service lines.

    (a) Except as provided in paragraph (b) of this section, each 
disconnected service line must be tested in the same manner as a new 
service line, before being reinstated.
    (b) Each service line temporarily disconnected from the main must be 
tested from the point of disconnection to the service line valve in the 
same manner as a new service line, before reconnecting. However, if 
provisions are made to maintain continuous service, such as by 
installation of a bypass, any part of the original service line used to 
maintain continuous service need not be tested.



Sec.  192.727  Abandonment or deactivation of facilities.

    (a) Each operator shall conduct abandonment or deactivation of 
pipelines in accordance with the requirements of this section.
    (b) Each pipeline abandoned in place must be disconnected from all 
sources and supplies of gas; purged of gas; in the case of offshore 
pipelines, filled with water or inert materials; and sealed at the ends. 
However, the pipeline need not be purged when the volume of gas is so 
small that there is no potential hazard.
    (c) Except for service lines, each inactive pipeline that is not 
being maintained under this part must be disconnected from all sources 
and supplies of gas; purged of gas; in the case of offshore pipelines, 
filled with water or inert materials; and sealed at the ends. However, 
the pipeline need not be purged when the volume of gas is so small that 
there is no potential hazard.
    (d) Whenever service to a customer is discontinued, one of the 
following must be complied with:
    (1) The valve that is closed to prevent the flow of gas to the 
customer must be provided with a locking device or other means designed 
to prevent the opening of the valve by persons other than those 
authorized by the operator.
    (2) A mechanical device or fitting that will prevent the flow of gas 
must be installed in the service line or in the meter assembly.
    (3) The customer's piping must be physically disconnected from the 
gas supply and the open pipe ends sealed.
    (e) If air is used for purging, the operator shall insure that a 
combustible mixture is not present after purging.
    (f) Each abandoned vault must be filled with a suitable compacted 
material.
    (g) For each abandoned offshore pipeline facility or each abandoned 
onshore pipeline facility that crosses over, under or through a 
commercially navigable waterway, the last operator of that facility must 
file a report upon abandonment of that facility.
    (1) The preferred method to submit data on pipeline facilities 
abandoned after October 10, 2000 is to the National Pipeline Mapping 
System (NPMS) in accordance with the NPMS ``Standards for Pipeline and 
Liquefied Natural Gas Operator Submissions.'' To obtain a copy of the 
NPMS Standards, please refer to the NPMS homepage at http://
www.npms.phmsa.dot.gov or contact the NPMS National Repository at 703-
317-3073. A digital data format is preferred, but hard copy submissions 
are acceptable if they comply with the NPMS

[[Page 548]]

Standards. In addition to the NPMS-required attributes, operators must 
submit the date of abandonment, diameter, method of abandonment, and 
certification that, to the best of the operator's knowledge, all of the 
reasonably available information requested was provided and, to the best 
of the operator's knowledge, the abandonment was completed in accordance 
with applicable laws. Refer to the NPMS Standards for details in 
preparing your data for submission. The NPMS Standards also include 
details of how to submit data. Alternatively, operators may submit 
reports by mail, fax or e-mail to the Office of Pipeline Safety, 
Pipeline and Hazardous Materials Safety Administration, U.S. Department 
of Transportation, Information Resources Manager, PHP-10, 1200 New 
Jersey Avenue, SE., Washington, DC 20590-0001; fax (202) 366-4566; e-
mail InformationResourcesManager@phmsa.

dot.gov. The information in the report must contain all reasonably 
available information related to the facility, including information in 
the possession of a third party. The report must contain the location, 
size, date, method of abandonment, and a certification that the facility 
has been abandoned in accordance with all applicable laws.
    (2) [Reserved]

[Amdt. 192-8, 37 FR 20695, Oct. 3, 1972, as amended by Amdt. 192-27, 41 
FR 34607, Aug. 16, 1976; Amdt. 192-71, 59 FR 6585, Feb. 11, 1994; Amdt. 
192-89, 65 FR 54443, Sept. 8, 2000; 65 FR 57861, Sept. 26, 2000; 70 FR 
11139, Mar. 8, 2005; Amdt. 192-103, 72 FR 4656, Feb. 1, 2007; 73 FR 
16570, Mar. 28, 2008; 74 FR 2894, Jan. 16, 2009]



Sec.  192.731  Compressor stations: Inspection and testing of relief  
devices. 

    (a) Except for rupture discs, each pressure relieving device in a 
compressor station must be inspected and tested in accordance with 
Sec. Sec.  192.739 and 192.743, and must be operated periodically to 
determine that it opens at the correct set pressure.
    (b) Any defective or inadequate equipment found must be promptly 
repaired or replaced.
    (c) Each remote control shutdown device must be inspected and tested 
at intervals not exceeding 15 months, but at least once each calendar 
year, to determine that it functions properly.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR 46851, 
Oct. 21, 1982]



Sec.  192.735  Compressor stations: Storage of combustible materials.

    (a) Flammable or combustible materials in quantities beyond those 
required for everyday use, or other than those normally used in 
compressor buildings, must be stored a safe distance from the compressor 
building.
    (b) Aboveground oil or gasoline storage tanks must be protected in 
accordance with NFPA-30 (incorporated by reference, see Sec.  192.7) .

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-119, 80 FR 181, 
Jan. 5, 2015; 80 FR 46847, Aug. 6, 2015]



Sec.  192.736  Compressor stations: Gas detection.

    (a) Not later than September 16, 1996, each compressor building in a 
compressor station must have a fixed gas detection and alarm system, 
unless the building is--
    (1) Constructed so that at least 50 percent of its upright side area 
is permanently open; or
    (2) Located in an unattended field compressor station of 1,000 
horsepower (746 kW) or less.
    (b) Except when shutdown of the system is necessary for maintenance 
under paragraph (c) of this section, each gas detection and alarm system 
required by this section must--
    (1) Continuously monitor the compressor building for a concentration 
of gas in air of not more than 25 percent of the lower explosive limit; 
and
    (2) If that concentration of gas is detected, warn persons about to 
enter the building and persons inside the building of the danger.
    (c) Each gas detection and alarm system required by this section 
must be maintained to function properly. The maintenance must include 
performance tests.

[58 FR 48464, Sept. 16, 1993, as amended by Amdt. 192-85, 63 FR 37504, 
July 13, 1998]

[[Page 549]]



Sec.  192.739  Pressure limiting and regulating stations: Inspection and 
testing.

    (a) Each pressure limiting station, relief device (except rupture 
discs), and pressure regulating station and its equipment must be 
subjected at intervals not exceeding 15 months, but at least once each 
calendar year, to inspections and tests to determine that it is--
    (1) In good mechanical condition;
    (2) Adequate from the standpoint of capacity and reliability of 
operation for the service in which it is employed;
    (3) Except as provided in paragraph (b) of this section, set to 
control or relieve at the correct pressure consistent with the pressure 
limits of Sec.  192.201(a); and
    (4) Properly installed and protected from dirt, liquids, or other 
conditions that might prevent proper operation.
    (b) For steel pipelines whose MAOP is determined under Sec.  
192.619(c), if the MAOP is 60 psi (414 kPa) gage or more, the control or 
relief pressure limit is as follows:

------------------------------------------------------------------------
  If the MAOP produces a hoop stress that
                    is:                      Then the pressure limit is:
------------------------------------------------------------------------
Greater than 72 percent of SMYS...........  MAOP plus 4 percent.
Unknown as a percentage of SMYS...........  A pressure that will prevent
                                             unsafe operation of the
                                             pipeline considering its
                                             operating and maintenance
                                             history and MAOP.
------------------------------------------------------------------------


[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR 46851, 
Oct. 21, 1982; Amdt. 192-93, 68 FR 53901, Sept. 15, 2003; Amdt. 192-96, 
69 FR 27863, May 17, 2004]



Sec.  192.740  Pressure regulating, limiting, and overpressure   
protection--Individual service lines directly connected to regulated 
gathering or transmission pipelines.

    (a) This section applies, except as provided in paragraph (c) of 
this section, to any service line directly connected to a transmission 
pipeline or regulated gathering pipeline as determined in Sec.  192.8 
that is not operated as part of a distribution system.
    (b) Each pressure regulating or limiting device, relief device 
(except rupture discs), automatic shutoff device, and associated 
equipment must be inspected and tested at least once every 3 calendar 
years, not exceeding 39 months, to determine that it is:
    (1) In good mechanical condition;
    (2) Adequate from the standpoint of capacity and reliability of 
operation for the service in which it is employed;
    (3) Set to control or relieve at the correct pressure consistent 
with the pressure limits of Sec.  192.197; and to limit the pressure on 
the inlet of the service regulator to 60 psi (414 kPa) gauge or less in 
case the upstream regulator fails to function properly; and
    (4) Properly installed and protected from dirt, liquids, or other 
conditions that might prevent proper operation.
    (c) This section does not apply to equipment installed on:
    (1) A service line that only serves engines that power irrigation 
pumps;
    (2) A service line included in a distribution integrity management 
plan meeting the requirements of subpart P of this part; or
    (3) A service line directly connected to either a production or 
gathering pipeline other than a regulated gathering line as determined 
in Sec.  192.8 of this part.

[Amdt. 192-123, 82 FR 7998, Jan. 23, 2017, as amended at 86 FR 2241, 
Jan. 11, 2021]



Sec.  192.741  Pressure limiting and regulating stations: Telemetering or   
recording gauges.

    (a) Each distribution system supplied by more than one district 
pressure regulating station must be equipped with telemetering or 
recording pressure gauges to indicate the gas pressure in the district.
    (b) On distribution systems supplied by a single district pressure 
regulating station, the operator shall determine the necessity of 
installing telemetering or recording gauges in the district, taking into 
consideration the number of customers supplied, the operating pressures, 
the capacity of the installation, and other operating conditions.
    (c) If there are indications of abnormally high or low pressure, the 
regulator and the auxiliary equipment must be inspected and the 
necessary measures employed to correct any unsatisfactory operating 
conditions.

[[Page 550]]



Sec.  192.743  Pressure limiting and regulating stations: Capacity of 
relief devices.

    (a) Pressure relief devices at pressure limiting stations and 
pressure regulating stations must have sufficient capacity to protect 
the facilities to which they are connected. Except as provided in Sec.  
192.739(b), the capacity must be consistent with the pressure limits of 
Sec.  192.201(a). This capacity must be determined at intervals not 
exceeding 15 months, but at least once each calendar year, by testing 
the devices in place or by review and calculations.
    (b) If review and calculations are used to determine if a device has 
sufficient capacity, the calculated capacity must be compared with the 
rated or experimentally determined relieving capacity of the device for 
the conditions under which it operates. After the initial calculations, 
subsequent calculations need not be made if the annual review documents 
that parameters have not changed to cause the rated or experimentally 
determined relieving capacity to be insufficient.
    (c) If a relief device is of insufficient capacity, a new or 
additional device must be installed to provide the capacity required by 
paragraph (a) of this section.

[Amdt. 192-93, 68 FR 53901, Sept. 15, 2003, as amended by Amdt. 192-96, 
69 FR 27863, May 17, 2004]



Sec.  192.745  Valve maintenance: Transmission lines.

    (a) Each transmission line valve that might be required during any 
emergency must be inspected and partially operated at intervals not 
exceeding 15 months, but at least once each calendar year.
    (b) Each operator must take prompt remedial action to correct any 
valve found inoperable, unless the operator designates an alternative 
valve.
    (c) For each remote-control valve (RCV) installed in accordance with 
Sec.  192.179 or Sec.  192.634, an operator must conduct a point-to-
point verification between SCADA system displays and the installed 
valves, sensors, and communications equipment, in accordance with Sec.  
192.631(c) and (e).
    (d) For each alternative equivalent technology installed on an 
onshore pipeline under Sec.  192.179(e) or (f) or Sec.  192.634 that is 
manually or locally operated (i.e., not a rupture-mitigation valve 
(RMV), as that term is defined in Sec.  192.3):
    (1) Operators must achieve a valve closure time of 30 minutes or 
less, pursuant to Sec.  192.636(b), through an initial drill and through 
periodic validation as required in paragraph (d)(2) of this section. An 
operator must review and document the results of each phase of the drill 
response to validate the total response time, including confirming the 
rupture, and valve shut-off time as being less than or equal to 30 
minutes after rupture identification.
    (2) Within each pipeline system and within each operating or 
maintenance field work unit, operators must randomly select a valve 
serving as an alternative equivalent technology in lieu of an RMV for an 
annual 30-minute-total response time validation drill that simulates 
worst-case conditions for that location to ensure compliance with Sec.  
192.636. Operators are not required to close the valve fully during the 
drill; a minimum 25 percent valve closure is sufficient to demonstrate 
compliance with drill requirements unless the operator has operational 
information that requires an additional closure percentage for 
maintaining reliability. The response drill must occur at least once 
each calendar year, with intervals not to exceed 15 months. Operators 
must include in their written procedures the method they use to randomly 
select which alternative equivalent technology is tested in accordance 
with this paragraph.
    (3) If the 30-minute-maximum response time cannot be achieved during 
the drill, the operator must revise response efforts to achieve 
compliance with Sec.  192.636 as soon as practicable but no later than 
12 months after the drill. Alternative valve shut-off measures must be 
in place in accordance with paragraph (e) of this section within 7 days 
of a failed drill.
    (4) Based on the results of response-time drills, the operator must 
include lessons learned in:
    (i) Training and qualifications programs;

[[Page 551]]

    (ii) Design, construction, testing, maintenance, operating, and 
emergency procedures manuals; and
    (iii) Any other areas identified by the operator as needing 
improvement.
    (5) The requirements of this paragraph (d) do not apply to manual 
valves who, pursuant to Sec.  192.636(g), have been exempted from the 
requirements of Sec.  192.636(b).
    (e) Each operator must develop and implement remedial measures to 
correct any valve installed on an onshore pipeline under Sec.  
192.179(e) or (f) or Sec.  192.634 that is indicated to be inoperable or 
unable to maintain effective shut-off as follows:
    (1) Repair or replace the valve as soon as practicable but no later 
than 12 months after finding that the valve is inoperable or unable to 
maintain effective shut-off. An operator must request an extension from 
PHMSA in accordance with Sec.  192.18 if repair or replacement of a 
valve within 12 months would be economically, technically, or 
operationally infeasible; and
    (2) Designate an alternative valve acting as an RMV within 7 
calendar days of the finding while repairs are being made and document 
an interim response plan to maintain safety. Such valves are not 
required to comply with the valve spacing requirements of this part.
    (f) An operator using an ASV as an RMV, in accordance with 
Sec. Sec.  192.3, 192.179, 192.634, and 192.636, must document and 
confirm the ASV shut-in pressures, in accordance with Sec.  192.636(f), 
on a calendar year basis not to exceed 15 months. ASV shut-in set 
pressures must be proven and reset individually at each ASV, as 
required, on a calendar year basis not to exceed 15 months.

[Amdt. 192-43, 47 FR 46851, Oct. 21, 1982, as amended by Amdt. 192-93, 
68 FR 53901, Sept. 15, 2003; Amdt. 192-87 FR 20986, Apr. 8, 2022]



Sec.  192.747  Valve maintenance: Distribution systems.

    (a) Each valve, the use of which may be necessary for the safe 
operation of a distribution system, must be checked and serviced at 
intervals not exceeding 15 months, but at least once each calendar year.
    (b) Each operator must take prompt remedial action to correct any 
valve found inoperable, unless the operator designates an alternative 
valve.

[Amdt. 192-43, 47 FR 46851, Oct. 21, 1982, as amended by Amdt. 192-93, 
68 FR 53901, Sept. 15, 2003]



Sec.  192.749  Vault maintenance.

    (a) Each vault housing pressure regulating and pressure limiting 
equipment, and having a volumetric internal content of 200 cubic feet 
(5.66 cubic meters) or more, must be inspected at intervals not 
exceeding 15 months, but at least once each calendar year, to determine 
that it is in good physical condition and adequately ventilated.
    (b) If gas is found in the vault, the equipment in the vault must be 
inspected for leaks, and any leaks found must be repaired.
    (c) The ventilating equipment must also be inspected to determine 
that it is functioning properly.
    (d) Each vault cover must be inspected to assure that it does not 
present a hazard to public safety.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR 46851, 
Oct. 21, 1982; Amdt. 192-85, 63 FR 37504, July 13, 1998]



Sec.  192.750  Launcher and receiver safety.

    Any launcher or receiver used after July 1, 2021, must be equipped 
with a device capable of safely relieving pressure in the barrel before 
removal or opening of the launcher or receiver barrel closure or flange 
and insertion or removal of in-line inspection tools, scrapers, or 
spheres. An operator must use a device to either: Indicate that pressure 
has been relieved in the barrel; or alternatively prevent opening of the 
barrel closure or flange when pressurized, or insertion or removal of 
in-line devices (e.g. inspection tools, scrapers, or spheres), if 
pressure has not been relieved.

[Amdt. 192-125, 84 FR 52252, Oct. 1, 2019]



Sec.  192.751  Prevention of accidental ignition.

    Each operator shall take steps to minimize the danger of accidental 
ignition of gas in any structure or area where the presence of gas 
constitutes a

[[Page 552]]

hazard of fire or explosion, including the following:
    (a) When a hazardous amount of gas is being vented into open air, 
each potential source of ignition must be removed from the area and a 
fire extinguisher must be provided.
    (b) Gas or electric welding or cutting may not be performed on pipe 
or on pipe components that contain a combustible mixture of gas and air 
in the area of work.
    (c) Post warning signs, where appropriate.



Sec.  192.753  Caulked bell and spigot joints.

    (a) Each cast iron caulked bell and spigot joint that is subject to 
pressures of more than 25 psi (172kPa) gage must be sealed with:
    (1) A mechanical leak clamp; or
    (2) A material or device which:
    (i) Does not reduce the flexibility of the joint;
    (ii) Permanently bonds, either chemically or mechanically, or both, 
with the bell and spigot metal surfaces or adjacent pipe metal surfaces; 
and
    (iii) Seals and bonds in a manner that meets the strength, 
environmental, and chemical compatibility requirements of Sec. Sec.  
192.53 (a) and (b) and 192.143.
    (b) Each cast iron caulked bell and spigot joint that is subject to 
pressures of 25 psi (172kPa) gage or less and is exposed for any reason 
must be sealed by a means other than caulking.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-25, 41 FR 23680, 
June 11, 1976; Amdt. 192-85, 63 FR 37504, July 13, 1998; Amdt. 192-93, 
68 FR 53901, Sept. 15, 2003]



Sec.  192.755  Protecting cast-iron pipelines.

    When an operator has knowledge that the support for a segment of a 
buried cast-iron pipeline is disturbed:
    (a) That segment of the pipeline must be protected, as necessary, 
against damage during the disturbance by:
    (1) Vibrations from heavy construction equipment, trains, trucks, 
buses, or blasting;
    (2) Impact forces by vehicles;
    (3) Earth movement;
    (4) Apparent future excavations near the pipeline; or
    (5) Other foreseeable outside forces which may subject that segment 
of the pipeline to bending stress.
    (b) As soon as feasible, appropriate steps must be taken to provide 
permanent protection for the disturbed segment from damage that might 
result from external loads, including compliance with applicable 
requirements of Sec. Sec.  192.317(a), 192.319, and 192.361(b)-(d).

[Amdt. 192-23, 41 FR 13589, Mar. 31, 1976]



Sec.  192.756  Joining plastic pipe by heat fusion; equipment maintenance 
and calibration.

    Each operator must maintain equipment used in joining plastic pipe 
in accordance with the manufacturer's recommended practices or with 
written procedures that have been proven by test and experience to 
produce acceptable joints.

[Amdt. 192-124, 83 FR 58719, Nov. 20, 2018]



              Subpart N_Qualification of Pipeline Personnel

    Source: Amdt. 192-86, 64 FR 46865, Aug. 27, 1999, unless otherwise 
noted.



Sec.  192.801  Scope.

    (a) This subpart prescribes the minimum requirements for operator 
qualification of individuals performing covered tasks on a pipeline 
facility.
    (b) For the purpose of this subpart, a covered task is an activity, 
identified by the operator, that:
    (1) Is performed on a pipeline facility;
    (2) Is an operations or maintenance task;
    (3) Is performed as a requirement of this part; and
    (4) Affects the operation or integrity of the pipeline.



Sec.  192.803  Definitions.

    Abnormal operating condition means a condition identified by the 
operator that may indicate a malfunction of a component or deviation 
from normal operations that may:
    (a) Indicate a condition exceeding design limits; or
    (b) Result in a hazard(s) to persons, property, or the environment.
    Evaluation means a process, established and documented by the 
operator,

[[Page 553]]

to determine an individual's ability to perform a covered task by any of 
the following:
    (a) Written examination;
    (b) Oral examination;
    (c) Work performance history review;
    (d) Observation during:
    (1) Performance on the job,
    (2) On the job training, or
    (3) Simulations;
    (e) Other forms of assessment.
    Qualified means that an individual has been evaluated and can:
    (a) Perform assigned covered tasks; and
    (b) Recognize and react to abnormal operating conditions.

[Amdt. 192-86, 64 FR 46865, Aug. 27, 1999, as amended by Amdt. 192-90, 
66 FR 43523, Aug. 20, 2001]



Sec.  192.805  Qualification program.

    Each operator shall have and follow a written qualification program. 
The program shall include provisions to:
    (a) Identify covered tasks;
    (b) Ensure through evaluation that individuals performing covered 
tasks are qualified;
    (c) Allow individuals that are not qualified pursuant to this 
subpart to perform a covered task if directed and observed by an 
individual that is qualified;
    (d) Evaluate an individual if the operator has reason to believe 
that the individual's performance of a covered task contributed to an 
incident as defined in Part 191;
    (e) Evaluate an individual if the operator has reason to believe 
that the individual is no longer qualified to perform a covered task;
    (f) Communicate changes that affect covered tasks to individuals 
performing those covered tasks;
    (g) Identify those covered tasks and the intervals at which 
evaluation of the individual's qualifications is needed;
    (h) After December 16, 2004, provide training, as appropriate, to 
ensure that individuals performing covered tasks have the necessary 
knowledge and skills to perform the tasks in a manner that ensures the 
safe operation of pipeline facilities; and
    (i) After December 16, 2004, notify the Administrator or a state 
agency participating under 49 U.S.C. Chapter 601 if an operator 
significantly modifies the program after the administrator or state 
agency has verified that it complies with this section. Notifications to 
PHMSA must be submitted in accordance with Sec.  192.18.

[Amdt. 192-86, 64 FR 46865, Aug. 27, 1999, as amended by Amdt. 192-100, 
70 FR 10335, Mar. 3, 2005; Amdt. 192-120, 80 FR 12779, Mar. 11, 2015; 
Amdt. 192-125, 84 FR 52252, Oct. 1, 2019]



Sec.  192.807  Recordkeeping.

    Each operator shall maintain records that demonstrate compliance 
with this subpart.
    (a) Qualification records shall include:
    (1) Identification of qualified individual(s);
    (2) Identification of the covered tasks the individual is qualified 
to perform;
    (3) Date(s) of current qualification; and
    (4) Qualification method(s).
    (b) Records supporting an individual's current qualification shall 
be maintained while the individual is performing the covered task. 
Records of prior qualification and records of individuals no longer 
performing covered tasks shall be retained for a period of five years.



Sec.  192.809  General.

    (a) Operators must have a written qualification program by April 27, 
2001. The program must be available for review by the Administrator or 
by a state agency participating under 49 U.S.C. Chapter 601 if the 
program is under the authority of that state agency.
    (b) Operators must complete the qualification of individuals 
performing covered tasks by October 28, 2002.
    (c) Work performance history review may be used as a sole evaluation 
method for individuals who were performing a covered task prior to 
October 26, 1999.
    (d) After October 28, 2002, work performance history may not be used 
as a sole evaluation method.
    (e) After December 16, 2004, observation of on-the-job performance 
may not

[[Page 554]]

be used as the sole method of evaluation.

[Amdt. 192-86, 64 FR 46865, Aug. 27, 1999, as amended by Amdt. 192-90, 
66 FR 43524, Aug. 20, 2001; Amdt. 192-100, 70 FR 10335, Mar. 3, 2005]



        Subpart O_Gas Transmission Pipeline Integrity Management

    Source: 68 FR 69817, Dec. 15, 2003, unless otherwise noted.



Sec.  192.901  What do the regulations in this subpart cover?

    This subpart prescribes minimum requirements for an integrity 
management program on any gas transmission pipeline covered under this 
part. For gas transmission pipelines constructed of plastic, only the 
requirements in Sec. Sec.  192.917, 192.921, 192.935 and 192.937 apply.



Sec.  192.903  What definitions apply to this subpart?

    The following definitions apply to this subpart:
    Assessment is the use of testing techniques as allowed in this 
subpart to ascertain the condition of a covered pipeline segment.
    Confirmatory direct assessment is an integrity assessment method 
using more focused application of the principles and techniques of 
direct assessment to identify internal and external corrosion in a 
covered transmission pipeline segment.
    Covered segment or covered pipeline segment means a segment of gas 
transmission pipeline located in a high consequence area. The terms gas 
and transmission line are defined in Sec.  192.3.
    Direct assessment is an integrity assessment method that utilizes a 
process to evaluate certain threats (i.e., external corrosion, internal 
corrosion and stress corrosion cracking) to a covered pipeline segment's 
integrity. The process includes the gathering and integration of risk 
factor data, indirect examination or analysis to identify areas of 
suspected corrosion, direct examination of the pipeline in these areas, 
and post assessment evaluation.
    High consequence area means an area established by one of the 
methods described in paragraphs (1) or (2) as follows:
    (1) An area defined as--
    (i) A Class 3 location under Sec.  192.5; or
    (ii) A Class 4 location under Sec.  192.5; or
    (iii) Any area in a Class 1 or Class 2 location where the potential 
impact radius is greater than 660 feet (200 meters), and the area within 
a potential impact circle contains 20 or more buildings intended for 
human occupancy; or
    (iv) Any area in a Class 1 or Class 2 location where the potential 
impact circle contains an identified site.
    (2) The area within a potential impact circle containing--
    (i) 20 or more buildings intended for human occupancy, unless the 
exception in paragraph (4) applies; or
    (ii) An identified site.
    (3) Where a potential impact circle is calculated under either 
method (1) or (2) to establish a high consequence area, the length of 
the high consequence area extends axially along the length of the 
pipeline from the outermost edge of the first potential impact circle 
that contains either an identified site or 20 or more buildings intended 
for human occupancy to the outermost edge of the last contiguous 
potential impact circle that contains either an identified site or 20 or 
more buildings intended for human occupancy. (See figure E.I.A. in 
appendix E.)
    (4) If in identifying a high consequence area under paragraph 
(1)(iii) of this definition or paragraph (2)(i) of this definition, the 
radius of the potential impact circle is greater than 660 feet (200 
meters), the operator may identify a high consequence area based on a 
prorated number of buildings intended for human occupancy with a 
distance of 660 feet (200 meters) from the centerline of the pipeline 
until December 17, 2006. If an operator chooses this approach, the 
operator must prorate the number of buildings intended for human 
occupancy based on the ratio of an area with a radius of 660 feet (200 
meters) to the area of the potential impact circle (i.e., the prorated 
number of buildings intended for human occupancy is equal to 20 x (660 
feet) [or 200 meters]/potential impact radius in feet [or meters] \2\).

[[Page 555]]

    Identified site means each of the following areas:
    (a) An outside area or open structure that is occupied by twenty 
(20) or more persons on at least 50 days in any twelve (12)-month 
period. (The days need not be consecutive.) Examples include but are not 
limited to, beaches, playgrounds, recreational facilities, camping 
grounds, outdoor theaters, stadiums, recreational areas near a body of 
water, or areas outside a rural building such as a religious facility; 
or
    (b) A building that is occupied by twenty (20) or more persons on at 
least five (5) days a week for ten (10) weeks in any twelve (12)-month 
period. (The days and weeks need not be consecutive.) Examples include, 
but are not limited to, religious facilities, office buildings, 
community centers, general stores, 4-H facilities, or roller skating 
rinks; or
    (c) A facility occupied by persons who are confined, are of impaired 
mobility, or would be difficult to evacuate. Examples include but are 
not limited to hospitals, prisons, schools, day-care facilities, 
retirement facilities or assisted-living facilities.
    Potential impact circle is a circle of radius equal to the potential 
impact radius (PIR).
    Potential impact radius (PIR) means the radius of a circle within 
which the potential failure of a pipeline could have significant impact 
on people or property. PIR is determined by the formula r = 0.69* 
(square root of (p*d \2\)), where `r' is the radius of a circular area 
in feet surrounding the point of failure, `p' is the maximum allowable 
operating pressure (MAOP) in the pipeline segment in pounds per square 
inch and `d' is the nominal diameter of the pipeline in inches.

    Note: 0.69 is the factor for natural gas. This number will vary for 
other gases depending upon their heat of combustion. An operator 
transporting gas other than natural gas must use section 3.2 of ASME/
ANSI B31.8S (incorporated by reference, see Sec.  192.7) to calculate 
the impact radius formula.

    Remediation is a repair or mitigation activity an operator takes on 
a covered segment to limit or reduce the probability of an undesired 
event occurring or the expected consequences from the event.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18231, 
Apr. 6, 2004; Amdt. 192-95, 69 FR 29904, May 26, 2004; Amdt. 192-103, 72 
FR 4657, Feb. 1, 2007; Amdt. 192-119, 80 FR 181, Jan. 5, 2015]



Sec.  192.905  How does an operator identify a high consequence area?

    (a) General. To determine which segments of an operator's 
transmission pipeline system are covered by this subpart, an operator 
must identify the high consequence areas. An operator must use method 
(1) or (2) from the definition in Sec.  192.903 to identify a high 
consequence area. An operator may apply one method to its entire 
pipeline system, or an operator may apply one method to individual 
portions of the pipeline system. An operator must describe in its 
integrity management program which method it is applying to each portion 
of the operator's pipeline system. The description must include the 
potential impact radius when utilized to establish a high consequence 
area. (See appendix E.I. for guidance on identifying high consequence 
areas.)
    (b)(1) Identified sites. An operator must identify an identified 
site, for purposes of this subpart, from information the operator has 
obtained from routine operation and maintenance activities and from 
public officials with safety or emergency response or planning 
responsibilities who indicate to the operator that they know of 
locations that meet the identified site criteria. These public officials 
could include officials on a local emergency planning commission or 
relevant Native American tribal officials.
    (2) If a public official with safety or emergency response or 
planning responsibilities informs an operator that it does not have the 
information to identify an identified site, the operator must use one of 
the following sources, as appropriate, to identify these sites.
    (i) Visible marking (e.g., a sign); or
    (ii) The site is licensed or registered by a Federal, State, or 
local government agency; or
    (iii) The site is on a list (including a list on an internet web 
site) or map

[[Page 556]]

maintained by or available from a Federal, State, or local government 
agency and available to the general public.
    (c) Newly identified areas. When an operator has information that 
the area around a pipeline segment not previously identified as a high 
consequence area could satisfy any of the definitions in Sec.  192.903, 
the operator must complete the evaluation using method (1) or (2). If 
the segment is determined to meet the definition as a high consequence 
area, it must be incorporated into the operator's baseline assessment 
plan as a high consequence area within one year from the date the area 
is identified.



Sec.  192.907  What must an operator do to implement this subpart?

    (a) General. No later than December 17, 2004, an operator of a 
covered pipeline segment must develop and follow a written integrity 
management program that contains all the elements described in Sec.  
192.911 and that addresses the risks on each covered transmission 
pipeline segment. The initial integrity management program must consist, 
at a minimum, of a framework that describes the process for implementing 
each program element, how relevant decisions will be made and by whom, a 
time line for completing the work to implement the program element, and 
how information gained from experience will be continuously incorporated 
into the program. The framework will evolve into a more detailed and 
comprehensive program. An operator must make continual improvements to 
the program.
    (b) Implementation Standards. In carrying out this subpart, an 
operator must follow the requirements of this subpart and of ASME/ANSI 
B31.8S (incorporated by reference, see Sec.  192.7) and its appendices, 
where specified. An operator may follow an equivalent standard or 
practice only when the operator demonstrates the alternative standard or 
practice provides an equivalent level of safety to the public and 
property. In the event of a conflict between this subpart and ASME/ANSI 
B31.8S, the requirements in this subpart control.



Sec.  192.909  How can an operator change its integrity management program?

    (a) General. An operator must document any change to its program and 
the reasons for the change before implementing the change.
    (b) Notification. An operator must notify OPS, in accordance with 
Sec.  192.18, of any change to the program that may substantially affect 
the program's implementation or may significantly modify the program or 
schedule for carrying out the program elements. An operator must provide 
notification within 30 days after adopting this type of change into its 
program.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18231, 
Apr. 6, 2004; Amdt. 192-125, 84 FR 52253, Oct. 1, 2019]



Sec.  192.911  What are the elements of an integrity management program?

    An operator's initial integrity management program begins with a 
framework (see Sec.  192.907) and evolves into a more detailed and 
comprehensive integrity management program, as information is gained and 
incorporated into the program. An operator must make continual 
improvements to its program. The initial program framework and 
subsequent program must, at minimum, contain the following elements. 
(When indicated, refer to ASME/ANSI B31.8S (incorporated by reference, 
see Sec.  192.7) for more detailed information on the listed element.)
    (a) An identification of all high consequence areas, in accordance 
with Sec.  192.905.
    (b) A baseline assessment plan meeting the requirements of Sec.  
192.919 and Sec.  192.921.
    (c) An identification of threats to each covered pipeline segment, 
which must include data integration and a risk assessment. An operator 
must use the threat identification and risk assessment to prioritize 
covered segments for assessment (Sec.  192.917) and to evaluate the 
merits of additional preventive and mitigative measures (Sec.  192.935) 
for each covered segment.
    (d) A direct assessment plan, if applicable, meeting the 
requirements of Sec.  192.923, and depending on the threat assessed, of 
Sec. Sec.  192.925, 192.927, or 192.929.

[[Page 557]]

    (e) Provisions meeting the requirements of Sec.  192.933 for 
remediating conditions found during an integrity assessment.
    (f) A process for continual evaluation and assessment meeting the 
requirements of Sec.  192.937.
    (g) If applicable, a plan for confirmatory direct assessment meeting 
the requirements of Sec.  192.931.
    (h) Provisions meeting the requirements of Sec.  192.935 for adding 
preventive and mitigative measures to protect the high consequence area.
    (i) A performance plan as outlined in ASME/ANSI B31.8S, section 9 
that includes performance measures meeting the requirements of Sec.  
192.945.
    (j) Record keeping provisions meeting the requirements of Sec.  
192.947.
    (k) A management of change process as required by Sec.  192.13(d).
    (l) A quality assurance process as outlined in ASME/ANSI B31.8S, 
section 12.
    (m) A communication plan that includes the elements of ASME/ANSI 
B31.8S, section 10, and that includes procedures for addressing safety 
concerns raised by--
    (1) OPS; and
    (2) A State or local pipeline safety authority when a covered 
segment is located in a State where OPS has an interstate agent 
agreement.
    (n) Procedures for providing (when requested), by electronic or 
other means, a copy of the operator's risk analysis or integrity 
management program to--
    (1) OPS; and
    (2) A State or local pipeline safety authority when a covered 
segment is located in a State where OPS has an interstate agent 
agreement.
    (o) Procedures for ensuring that each integrity assessment is being 
conducted in a manner that minimizes environmental and safety risks.
    (p) A process for identification and assessment of newly-identified 
high consequence areas. (See Sec.  192.905 and Sec.  192.921.)

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18231, 
Apr. 6, 2004; Amdt. 192-132, 87 FR 52273, Aug. 24, 2022]



Sec.  192.913  When may an operator deviate its program from certain 
requirements of this subpart?

    (a) General. ASME/ANSI B31.8S (incorporated by reference, see Sec.  
192.7) provides the essential features of a performance-based or a 
prescriptive integrity management program. An operator that uses a 
performance-based approach that satisfies the requirements for 
exceptional performance in paragraph (b) of this section may deviate 
from certain requirements in this subpart, as provided in paragraph (c) 
of this section.
    (b) Exceptional performance. An operator must be able to demonstrate 
the exceptional performance of its integrity management program through 
the following actions.
    (1) To deviate from any of the requirements set forth in paragraph 
(c) of this section, an operator must have a performance-based integrity 
management program that meets or exceed the performance-based 
requirements of ASME/ANSI B31.8S and includes, at a minimum, the 
following elements--
    (i) A comprehensive process for risk analysis;
    (ii) All risk factor data used to support the program;
    (iii) A comprehensive data integration process;
    (iv) A procedure for applying lessons learned from assessment of 
covered pipeline segments to pipeline segments not covered by this 
subpart;
    (v) A procedure for evaluating every incident, including its cause, 
within the operator's sector of the pipeline industry for implications 
both to the operator's pipeline system and to the operator's integrity 
management program;
    (vi) A performance matrix that demonstrates the program has been 
effective in ensuring the integrity of the covered segments by 
controlling the identified threats to the covered segments;
    (vii) Semi-annual performance measures beyond those required in 
Sec.  192.945 that are part of the operator's performance plan. (See 
Sec.  192.911(i).) An operator must submit these measures, by electronic 
or other means, on a semi-annual frequency to OPS in accordance with 
Sec.  192.951; and

[[Page 558]]

    (viii) An analysis that supports the desired integrity reassessment 
interval and the remediation methods to be used for all covered 
segments.
    (2) In addition to the requirements for the performance-based plan, 
an operator must--
    (i) Have completed at least two integrity assessments on each 
covered pipeline segment the operator is including under the 
performance-based approach, and be able to demonstrate that each 
assessment effectively addressed the identified threats on the covered 
segment.
    (ii) Remediate all anomalies identified in the more recent 
assessment according to the requirements in Sec.  192.933, and 
incorporate the results and lessons learned from the more recent 
assessment into the operator's data integration and risk assessment.
    (c) Deviation. Once an operator has demonstrated that it has 
satisfied the requirements of paragraph (b) of this section, the 
operator may deviate from the prescriptive requirements of ASME/ANSI 
B31.8S and of this subpart only in the following instances.
    (1) The time frame for reassessment as provided in Sec.  192.939 
except that reassessment by some method allowed under this subpart 
(e.g., confirmatory direct assessment) must be carried out at intervals 
no longer than seven years;
    (2) The time frame for remediation as provided in Sec.  192.933 if 
the operator demonstrates the time frame will not jeopardize the safety 
of the covered segment.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18231, 
Apr. 6, 2004]



Sec.  192.915  What knowledge and training must personnel have to carry 
out an integrity management program?

    (a) Supervisory personnel. The integrity management program must 
provide that each supervisor whose responsibilities relate to the 
integrity management program possesses and maintains a thorough 
knowledge of the integrity management program and of the elements for 
which the supervisor is responsible. The program must provide that any 
person who qualifies as a supervisor for the integrity management 
program has appropriate training or experience in the area for which the 
person is responsible.
    (b) Persons who carry out assessments and evaluate assessment 
results. The integrity management program must provide criteria for the 
qualification of any person--
    (1) Who conducts an integrity assessment allowed under this subpart; 
or
    (2) Who reviews and analyzes the results from an integrity 
assessment and evaluation; or
    (3) Who makes decisions on actions to be taken based on these 
assessments.
    (c) Persons responsible for preventive and mitigative measures. The 
integrity management program must provide criteria for the qualification 
of any person--
    (1) Who implements preventive and mitigative measures to carry out 
this subpart, including the marking and locating of buried structures; 
or
    (2) Who directly supervises excavation work carried out in 
conjunction with an integrity assessment.



Sec.  192.917  How does an operator identify potential threats to pipeline 
integrity and use the threat identification in its integrity program?

    (a) Threat identification. An operator must identify and evaluate 
all potential threats to each covered pipeline segment. Potential 
threats that an operator must consider include, but are not limited to, 
the threats listed in ASME/ANSI B31.8S (incorporated by reference, see 
Sec.  192.7), section 2, which are grouped under the following four 
threat categories:
    (1) Time dependent threats such as internal corrosion, external 
corrosion, and stress corrosion cracking;
    (2) Stable threats, such as manufacturing, welding, fabrication, or 
construction defects;
    (3) Time independent threats, such as third party damage, mechanical 
damage, incorrect operational procedure, weather related and outside 
force damage, to include consideration of seismicity, geology, and soil 
stability of the area; and
    (4) Human error, such as operational or maintenance mishaps, or 
design and construction mistakes.
    (b) Data gathering and integration. To identify and evaluate the 
potential

[[Page 559]]

threats to a covered pipeline segment, an operator must gather and 
integrate existing data and information on the entire pipeline that 
could be relevant to the covered segment. In performing data gathering 
and integration, an operator must follow the requirements in ASME/ANSI 
B31.8S, section 4.
    Operators must begin to integrate all pertinent data elements 
specified in this section starting on May 24, 2023, with all available 
attributes integrated by February 26, 2024. An operator may request an 
extension of up to 1 year by submitting a notification to PHMSA at least 
90 days before February 26, 2024, in accordance with Sec.  192.18. The 
notification must include a reasonable and technically justified basis, 
an up-to-date plan for completing all actions required by this paragraph 
(b), the reason for the requested extension, current safety or 
mitigation status of the pipeline segment, the proposed completion date, 
and any needed temporary safety measures to mitigate the impact on 
safety. An operator must gather and evaluate the set of data listed in 
paragraph (b)(1) of this section. The evaluation must analyze both the 
covered segment and similar non-covered segments, and it must:
    (1) Integrate pertinent information about pipeline attributes to 
ensure safe operation and pipeline integrity, including information 
derived from operations and maintenance activities required under this 
part, and other relevant information, including, but not limited to:
    (i) Pipe diameter, wall thickness, seam type, and joint factor;
    (ii) Manufacturer and manufacturing date, including manufacturing 
data and records;
    (iii) Material properties including, but not limited to, grade, 
specified minimum yield strength (SMYS), and ultimate tensile strength;
    (iv) Equipment properties;
    (v) Year of installation;
    (vi) Bending method;
    (vii) Joining method, including process and inspection results;
    (viii) Depth of cover;
    (ix) Crossings, casings (including if shorted), and locations of 
foreign line crossings and nearby high voltage power lines;
    (x) Hydrostatic or other pressure test history, including test 
pressures and test leaks or failures, failure causes, and repairs;
    (xi) Pipe coating methods (both manufactured and field applied), 
including the method or process used to apply girth weld coating, 
inspection reports, and coating repairs;
    (xii) Soil, backfill;
    (xiii) Construction inspection reports, including but not limited 
to:
    (A) Post backfill coating surveys; and
    (B) Coating inspection (``jeeping'' or ``holiday inspection'') 
reports;
    (xiv) Cathodic protection installed, including, but not limited to, 
type and location;
    (xv) Coating type;
    (xvi) Gas quality;
    (xvii) Flow rate;
    (xviii) Normal maximum and minimum operating pressures, including 
maximum allowable operating pressure (MAOP);
    (xix) Class location;
    (xx) Leak and failure history, including any in-service ruptures or 
leaks from incident reports, abnormal operations, safety-related 
conditions (both reported and unreported) and failure investigations 
required by Sec.  192.617, and their identified causes and consequences;
    (xxi) Coating condition;
    (xxii) Cathodic protection (CP) system performance;
    (xxiii) Pipe wall temperature;
    (xxiv) Pipe operational and maintenance inspection reports, 
including, but not limited to:
    (A) Data gathered through integrity assessments required under this 
part, including, but not limited to, in-line inspections, pressure 
tests, direct assessments, guided wave ultrasonic testing, or other 
methods;
    (B) Close interval survey (CIS) and electrical survey results;
    (C) CP rectifier readings;
    (D) CP test point survey readings and locations;
    (E) Alternating current, direct current, and foreign structure 
interference surveys;
    (F) Pipe coating surveys, including surveys to detect coating 
damage, disbonded coatings, or other conditions that compromise the 
effectiveness of

[[Page 560]]

corrosion protection, including, but not limited to, direct current 
voltage gradient or alternating current voltage gradient inspections;
    (G) Results of examinations of exposed portions of buried pipelines 
(e.g., pipe and pipe coating condition, see Sec.  192.459), including 
the results of any non-destructive examinations of the pipe, seam, or 
girth weld (i.e. bell hole inspections);
    (H) Stress corrosion cracking excavations and findings;
    (I) Selective seam weld corrosion excavations and findings;
    (J) Any indication of seam cracking; and
    (K) Gas stream sampling and internal corrosion monitoring results, 
including cleaning pig sampling results;
    (xxv) External and internal corrosion monitoring;
    (xxvi) Operating pressure history and pressure fluctuations, 
including an analysis of effects of pressure cycling and instances of 
exceeding MAOP by any amount;
    (xxvii) Performance of regulators, relief valves, pressure control 
devices, or any other device to control or limit operating pressure to 
less than MAOP;
    (xxviii) Encroachments;
    (xxix) Repairs;
    (xxx) Vandalism;
    (xxxi) External forces;
    (xxxii) Audits and reviews;
    (xxxiii) Industry experience for incident, leak, and failure 
history;
    (xxxiv) Aerial photography; and
    (xxxv) Exposure to natural forces in the area of the pipeline, 
including seismicity, geology, and soil stability of the area.
    (2) Use validated information and data as inputs, to the maximum 
extent practicable. If input is obtained from subject matter experts 
(SME), an operator must employ adequate control measures to ensure 
consistency and accuracy of information. Control measures may include 
training of SMEs or the use of outside technical experts (independent 
expert reviews) to assess the quality of processes and the judgment of 
SMEs. An operator must document the names and qualifications of the 
individuals who approve SME inputs used in the current risk assessment.
    (3) Identify and analyze spatial relationships among anomalous 
information (e.g., corrosion coincident with foreign line crossings or 
evidence of pipeline damage where overhead imaging shows evidence of 
encroachment).
    (4) Analyze the data for interrelationships among pipeline integrity 
threats, including combinations of applicable risk factors that increase 
the likelihood of incidents or increase the potential consequences of 
incidents.
    (c) Risk assessment. An operator must conduct a risk assessment that 
follows ASME/ANSI B31.8S, section 5, and that analyzes the identified 
threats and potential consequences of an incident for each covered 
segment. An operator must ensure the validity of the methods used to 
conduct the risk assessment considering the incident, leak, and failure 
history of the pipeline segments and other historical information. Such 
a validation must ensure the risk assessment methods produce a risk 
characterization that is consistent with the operator's and industry 
experience, including evaluations of the cause of past incidents, as 
determined by root cause analysis or other equivalent means, and include 
sensitivity analysis of the factors used to characterize both the 
likelihood of loss of pipeline integrity and consequences of the 
postulated loss of pipeline integrity. An operator must use the risk 
assessment to determine additional preventive and mitigative measures 
needed for each covered segment in accordance with Sec.  192.935 and 
periodically evaluate the integrity of each covered pipeline segment in 
accordance with Sec.  192.937. Beginning February 26, 2024, the risk 
assessment must:
    (1) Analyze how a potential failure could affect high consequence 
areas;
    (2) Analyze the likelihood of failure due to each individual threat 
and each unique combination of threats that interact or simultaneously 
contribute to risk at a common location;
    (3) Account for, and compensate for, uncertainties in the model and 
the data used in the risk assessment; and
    (4) Evaluate the potential risk reduction associated with candidate 
risk reduction activities, such as preventive and mitigative measures, 
and reduced

[[Page 561]]

anomaly remediation and assessment intervals.
    (5) In conjunction with Sec.  192.917(b), an operator may request an 
extension of up to 1 year for the requirements of this paragraph by 
submitting a notification to PHMSA at least 90 days before February 26, 
2024, in accordance with Sec.  192.18. The notification must include a 
reasonable and technically justified basis, an up-to-date plan for 
completing all actions required by this paragraph (c)(5), the reason for 
the requested extension, current safety or mitigation status of the 
pipeline segment, the proposed completion date, and any needed temporary 
safety measures to mitigate the impact on safety.
    (d) Plastic transmission pipeline. An operator of a plastic 
transmission pipeline must assess the threats to each covered segment 
using the information in sections 4 and 5 of ASME B31.8S and consider 
any threats unique to the integrity of plastic pipe, such as poor joint 
fusion practices, pipe with poor slow crack growth (SCG) resistance, 
brittle pipe, circumferential cracking, hydrocarbon softening of the 
pipe, internal and external loads, longitudinal or lateral loads, 
proximity to elevated heat sources, and point loading.
    (e) Actions to address particular threats. If an operator identifies 
any of the following threats, the operator must take the following 
actions to address the threat.
    (1) Third party damage. An operator must utilize the data 
integration required in paragraph (b) of this section and ASME/ANSI 
B31.8S, Appendix A7 to determine the susceptibility of each covered 
segment to the threat of third party damage. If an operator identifies 
the threat of third party damage, the operator must implement 
comprehensive additional preventive measures in accordance with Sec.  
192.935 and monitor the effectiveness of the preventive measures. If, in 
conducting a baseline assessment under Sec.  192.921, or a reassessment 
under Sec.  192.937, an operator uses an internal inspection tool or 
external corrosion direct assessment, the operator must integrate data 
from these assessments with data related to any encroachment or foreign 
line crossing on the covered segment, to define where potential 
indications of third party damage may exist in the covered segment. An 
operator must also have procedures in its integrity management program 
addressing actions it will take to respond to findings from this data 
integration.
    (2) Cyclic fatigue. An operator must analyze and account for whether 
cyclic fatigue or other loading conditions (including ground movement, 
and suspension bridge condition) could lead to a failure of a 
deformation, including a dent or gouge, crack, or other defect in the 
covered segment. The analysis must assume the presence of threats in the 
covered segment that could be exacerbated by cyclic fatigue. An operator 
must use the results from the analysis together with the criteria used 
to determine the significance of the threat(s) to the covered segment to 
prioritize the integrity baseline assessment or reassessment. Failure 
stress pressure and crack growth analysis of cracks and crack-like 
defects must be conducted in accordance with Sec.  192.712. An operator 
must monitor operating pressure cycles and periodically, but at least 
every 7 calendar years, with intervals not to exceed 90 months, 
determine if the cyclic fatigue analysis remains valid or if the cyclic 
fatigue analysis must be revised based on changes to operating pressure 
cycles or other loading conditions.
    (3) Manufacturing and construction defects. An operator must analyze 
the covered segment to determine and account for the risk of failure 
from manufacturing and construction defects (including seam defects) in 
the covered segment. The analysis must account for the results of prior 
assessments on the covered segment. An operator may consider 
manufacturing and construction related defects to be stable defects only 
if the covered segment has been subjected to hydrostatic pressure 
testing satisfying the criteria of subpart J of at least 1.25 times 
MAOP, and the covered segment has not experienced a reportable incident 
attributed to a manufacturing or construction defect since the date of 
the most recent subpart J pressure test. If any of the following changes 
occur in the covered segment, an operator must prioritize

[[Page 562]]

the covered segment as a high-risk segment for the baseline assessment 
or a subsequent reassessment.
    (i) The pipeline segment has experienced a reportable incident, as 
defined in Sec.  191.3, since its most recent successful subpart J 
pressure test, due to an original manufacturing-related defect, or a 
construction-, installation-, or fabrication-related defect;
    (ii) MAOP increases; or
    (iii) The stresses leading to cyclic fatigue increase.
    (4) Electric Resistance Welded (ERW) pipe. If a covered pipeline 
segment contains low frequency ERW pipe, lap welded pipe, pipe with 
longitudinal joint factor less than 1.0 as defined in Sec.  192.113, or 
other pipe that satisfies the conditions specified in ASME/ANSI B31.8S, 
Appendices A4.3 and A4.4, and any covered or non-covered segment in the 
pipeline system with such pipe has experienced seam failure (including 
seam cracking and selective seam weld corrosion), or operating pressure 
on the covered segment has increased over the maximum operating pressure 
experienced during the preceding 5 years (including abnormal operation 
as defined in Sec.  192.605(c)), or MAOP has been increased, an operator 
must select an assessment technology or technologies with a proven 
application capable of assessing seam integrity and seam corrosion 
anomalies. The operator must prioritize the covered segment as a high-
risk segment for the baseline assessment or a subsequent reassessment. 
Pipe with seam cracks must be evaluated using fracture mechanics 
modeling for failure stress pressures and cyclic fatigue crack growth 
analysis to estimate the remaining life of the pipe in accordance with 
Sec.  192.712.
    (5) Corrosion. If an operator identifies corrosion on a covered 
pipeline segment that could adversely affect the integrity of the line 
(conditions specified in Sec.  192.933), the operator must evaluate and 
remediate, as necessary, all pipeline segments (both covered and non-
covered) with similar material coating and environmental 
characteristics. An operator must establish a schedule for evaluating 
and remediating, as necessary, the similar segments that is consistent 
with the operator's established operating and maintenance procedures 
under part 192 for testing and repair.
    (6) Cracks. If an operator identifies any crack or crack-like defect 
(e.g., stress corrosion cracking or other environmentally assisted 
cracking, seam defects, selective seam weld corrosion, girth weld 
cracks, hook cracks, and fatigue cracks) on a covered pipeline segment 
that could adversely affect the integrity of the pipeline, the operator 
must evaluate, and remediate, as necessary, all pipeline segments (both 
covered and non-covered) with similar characteristics associated with 
the crack or crack-like defect. Similar characteristics may include 
operating and maintenance histories, material properties, and 
environmental characteristics. An operator must establish a schedule for 
evaluating, and remediating, as necessary, the similar pipeline segments 
that is consistent with the operator's established operating and 
maintenance procedures under this part for testing and repair.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18231, 
Apr. 6, 2004; Amdt. 192-125, 84 FR 52253, Oct. 1, 2019; Amdt. 192-132, 
87 FR 52273, Aug. 24, 2022]



Sec.  192.919  What must be in the baseline assessment plan?

    An operator must include each of the following elements in its 
written baseline assessment plan:
    (a) Identification of the potential threats to each covered pipeline 
segment and the information supporting the threat identification. (See 
Sec.  192.917.);
    (b) The methods selected to assess the integrity of the line pipe, 
including an explanation of why the assessment method was selected to 
address the identified threats to each covered segment. The integrity 
assessment method an operator uses must be based on the threats 
identified to the covered segment. (See Sec.  192.917.) More than one 
method may be required to address all the threats to the covered 
pipeline segment;
    (c) A schedule for completing the integrity assessment of all 
covered segments, including risk factors considered in establishing the 
assessment schedule;

[[Page 563]]

    (d) If applicable, a direct assessment plan that meets the 
requirements of Sec. Sec.  192.923, and depending on the threat to be 
addressed, of Sec.  192.925, Sec.  192.927, or Sec.  192.929; and
    (e) A procedure to ensure that the baseline assessment is being 
conducted in a manner that minimizes environmental and safety risks.



Sec.  192.921  How is the baseline assessment to be conducted?

    (a) Assessment methods. An operator must assess the integrity of the 
line pipe in each covered segment by applying one or more of the 
following methods for each threat to which the covered segment is 
susceptible. An operator must select the method or methods best suited 
to address the threats identified to the covered segment (See Sec.  
192.917).
    (1) Internal inspection tool or tools capable of detecting those 
threats to which the pipeline is susceptible. The use of internal 
inspection tools is appropriate for threats such as corrosion, 
deformation and mechanical damage (including dents, gouges and grooves), 
material cracking and crack-like defects (e.g., stress corrosion 
cracking, selective seam weld corrosion, environmentally assisted 
cracking, and girth weld cracks), hard spots with cracking, and any 
other threats to which the covered segment is susceptible. When 
performing an assessment using an in-line inspection tool, an operator 
must comply with Sec.  192.493. In addition, an operator must analyze 
and account for uncertainties in reported results (e.g., tool tolerance, 
detection threshold, probability of detection, probability of 
identification, sizing accuracy, conservative anomaly interaction 
criteria, location accuracy, anomaly findings, and unity chart plots or 
equivalent for determining uncertainties and verifying actual tool 
performance) in identifying and characterizing anomalies;
    (2) Pressure test conducted in accordance with subpart J of this 
part. The use of subpart J pressure testing is appropriate for threats 
such as internal corrosion; external corrosion and other environmentally 
assisted corrosion mechanisms; manufacturing and related defects 
threats, including defective pipe and pipe seams; stress corrosion 
cracking; selective seam weld corrosion; dents; and other forms of 
mechanical damage. An operator must use the test pressures specified in 
Table 3 of section 5 of ASME/ANSI B31.8S (incorporated by reference, see 
Sec.  192.7) to justify an extended reassessment interval in accordance 
with Sec.  192.939.
    (3) Spike hydrostatic pressure test conducted in accordance with 
Sec.  192.506. The use of spike hydrostatic pressure testing is 
appropriate for time-dependent threats such as stress corrosion 
cracking; selective seam weld corrosion; manufacturing and related 
defects, including defective pipe and pipe seams; and other forms of 
defect or damage involving cracks or crack-like defects;
    (4) Excavation and in situ direct examination by means of visual 
examination, direct measurement, and recorded non-destructive 
examination results and data needed to assess all threats. Based upon 
the threat assessed, examples of appropriate non-destructive examination 
methods include ultrasonic testing (UT), phased array ultrasonic testing 
(PAUT), inverse wave field extrapolation (IWEX), radiography, and 
magnetic particle inspection (MPI);
    (5) Guided wave ultrasonic testing (GWUT) as described in Appendix 
F. The use of GWUT is appropriate for internal and external pipe wall 
loss;
    (6) Direct assessment to address threats of external corrosion, 
internal corrosion, and stress corrosion cracking. The use of direct 
assessment to address threats of external corrosion, internal corrosion, 
and stress corrosion cracking is allowed only if appropriate for the 
threat and the pipeline segment being assessed. Use of direct assessment 
for threats other than the threat for which the direct assessment method 
is suitable is not allowed. An operator must conduct the direct 
assessment in accordance with the requirements listed in Sec.  192.923 
and with the applicable requirements specified in Sec. Sec.  192.925, 
192.927 and 192.929; or
    (7) Other technology that an operator demonstrates can provide an 
equivalent understanding of the condition of the line pipe for each of 
the threats to which the pipeline is susceptible. An

[[Page 564]]

operator must notify PHMSA in advance of using the other technology in 
accordance with Sec.  192.18.
    (b) Prioritizing segments. An operator must prioritize the covered 
pipeline segments for the baseline assessment according to a risk 
analysis that considers the potential threats to each covered segment. 
The risk analysis must comply with the requirements in Sec.  192.917.
    (c) Assessment for particular threats. In choosing an assessment 
method for the baseline assessment of each covered segment, an operator 
must take the actions required in Sec.  192.917(e) to address particular 
threats that it has identified.
    (d) Time period. An operator must prioritize all the covered 
segments for assessment in accordance with Sec.  192.917 (c) and 
paragraph (b) of this section. An operator must assess at least 50% of 
the covered segments beginning with the highest risk segments, by 
December 17, 2007. An operator must complete the baseline assessment of 
all covered segments by December 17, 2012.
    (e) Prior assessment. An operator may use a prior integrity 
assessment conducted before December 17, 2002 as a baseline assessment 
for the covered segment, if the integrity assessment meets the baseline 
requirements in this subpart and subsequent remedial actions to address 
the conditions listed in Sec.  192.933 have been carried out. In 
addition, if an operator uses this prior assessment as its baseline 
assessment, the operator must reassess the line pipe in the covered 
segment according to the requirements of Sec.  192.937 and Sec.  
192.939.
    (f) Newly identified areas. When an operator identifies a new high 
consequence area (see Sec.  192.905), an operator must complete the 
baseline assessment of the line pipe in the newly identified high 
consequence area within ten (10) years from the date the area is 
identified.
    (g) Newly installed pipe. An operator must complete the baseline 
assessment of a newly-installed segment of pipe covered by this subpart 
within ten (10) years from the date the pipe is installed. An operator 
may conduct a pressure test in accordance with paragraph (a)(2) of this 
section, to satisfy the requirement for a baseline assessment.
    (h) Plastic transmission pipeline. If the threat analysis required 
in Sec.  192.917(d) on a plastic transmission pipeline indicates that a 
covered segment is susceptible to failure from causes other than third-
party damage, an operator must conduct a baseline assessment of the 
segment in accordance with the requirements of this section and of Sec.  
192.917. The operator must justify the use of an alternative assessment 
method that will address the identified threats to the covered segment.
    (i) Baseline assessments for pipeline segments with a reconfirmed 
MAOP. An integrity assessment conducted in accordance with the 
requirements of Sec.  192.624(c) may be used as a baseline assessment 
under this section.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18232, 
Apr. 6, 2004; Amdt. 192-125, 84 FR 52253, Oct. 1, 2019]



Sec.  192.923  How is direct assessment used and for what threats?

    (a) General. An operator may use direct assessment either as a 
primary assessment method or as a supplement to the other assessment 
methods allowed under this subpart. An operator may only use direct 
assessment as the primary assessment method to address the identified 
threats of external corrosion (EC), internal corrosion (IC), and stress 
corrosion cracking (SCC).
    (b) Primary method. An operator using direct assessment as a primary 
assessment method must have a plan that complies with the requirements 
in--
    (1) Section 192.925 and ASME/ANSI B31.8S (incorporated by reference, 
see Sec.  192.7) section 6.4, and NACE SP0502 (incorporated by 
reference, see Sec.  192.7) , if addressing external corrosion (EC).
    (2) Section 192.927 and NACE SP0206 (incorporated by reference, see 
Sec.  192.7), if addressing internal corrosion (IC).
    (3) Section 192.929 and NACE SP0204 (incorporated by reference, see 
Sec.  192.7), if addressing stress corrosion cracking (SCC).
    (c) Supplemental method. An operator using direct assessment as a 
supplemental assessment method for any applicable threat must have a 
plan that

[[Page 565]]

follows the requirements for confirmatory direct assessment in Sec.  
192.931.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-114, 75 FR 48604, 
Aug. 11, 2010; Amdt. 192-119, 80 FR 178, 182, Jan. 5, 2015; 80 FR 46847, 
Aug. 6, 2015; Amdt. 192-132, 87 FR 52274, Aug. 24, 2022]



Sec.  192.925  What are the requirements for using External Corrosion  
Direct Assessment (ECDA)?

    (a) Definition. ECDA is a four-step process that combines 
preassessment, indirect inspection, direct examination, and post 
assessment to evaluate the threat of external corrosion to the integrity 
of a pipeline.
    (b) General requirements. An operator that uses direct assessment to 
assess the threat of external corrosion must follow the requirements in 
this section, in ASME/ANSI B31.8S (incorporated by reference, see Sec.  
192.7), section 6.4, and in NACE SP0502 (incorporated by reference, see 
Sec.  192.7). An operator must develop and implement a direct assessment 
plan that has procedures addressing pre-assessment, indirect inspection, 
direct examination, and post assessment. If the ECDA detects pipeline 
coating damage, the operator must also integrate the data from the ECDA 
with other information from the data integration (Sec.  192.917(b)) to 
evaluate the covered segment for the threat of third party damage and to 
address the threat as required by Sec.  192.917(e)(1).
    (1) Preassessment. In addition to the requirements in ASME/ANSI 
B31.8S section 6.4 and NACE SP0502, section 3, the plan's procedures for 
preassessment must include--
    (i) Provisions for applying more restrictive criteria when 
conducting ECDA for the first time on a covered segment; and
    (ii) The basis on which an operator selects at least two different, 
but complementary indirect assessment tools to assess each ECDA Region. 
If an operator utilizes an indirect inspection method that is not 
discussed in Appendix A of NACE SP0502, the operator must demonstrate 
the applicability, validation basis, equipment used, application 
procedure, and utilization of data for the inspection method.
    (2) Indirect inspection. In addition to the requirements in ASME/
ANSI B31.8S, section 6.4 and in NACE SP0502, section 4, the plan's 
procedures for indirect inspection of the ECDA regions must include--
    (i) Provisions for applying more restrictive criteria when 
conducting ECDA for the first time on a covered segment;
    (ii) Criteria for identifying and documenting those indications that 
must be considered for excavation and direct examination. Minimum 
identification criteria include the known sensitivities of assessment 
tools, the procedures for using each tool, and the approach to be used 
for decreasing the physical spacing of indirect assessment tool readings 
when the presence of a defect is suspected;
    (iii) Criteria for defining the urgency of excavation and direct 
examination of each indication identified during the indirect 
examination. These criteria must specify how an operator will define the 
urgency of excavating the indication as immediate, scheduled or 
monitored; and
    (iv) Criteria for scheduling excavation of indications for each 
urgency level.
    (3) Direct examination. In addition to the requirements in ASME/ANSI 
B31.8S section 6.4 and NACE SP0502, section 5, the plan's procedures for 
direct examination of indications from the indirect examination must 
include--
    (i) Provisions for applying more restrictive criteria when 
conducting ECDA for the first time on a covered segment;
    (ii) Criteria for deciding what action should be taken if either:
    (A) Corrosion defects are discovered that exceed allowable limits 
(Section 5.5.2.2 of NACE SP0502), or
    (B) Root cause analysis reveals conditions for which ECDA is not 
suitable (Section 5.6.2 of NACE SP0502);
    (iii) Criteria and notification procedures for any changes in the 
ECDA Plan, including changes that affect the severity classification, 
the priority of direct examination, and the time frame for direct 
examination of indications; and
    (iv) Criteria that describe how and on what basis an operator will 
reclassify and reprioritize any of the provisions

[[Page 566]]

that are specified in section 5.9 of NACE SP0502.
    (4) Post assessment and continuing evaluation. In addition to the 
requirements in ASME/ANSI B31.8S section 6.4 and NACE SP0502, section 6, 
the plan's procedures for post assessment of the effectiveness of the 
ECDA process must include--
    (i) Measures for evaluating the long-term effectiveness of ECDA in 
addressing external corrosion in covered segments; and
    (ii) Criteria for evaluating whether conditions discovered by direct 
examination of indications in each ECDA region indicate a need for 
reassessment of the covered segment at an interval less than that 
specified in Sec.  192.939. (See Appendix D of NACE SP0502.)

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 29904, 
May 26, 2004; Amdt. 192-114, 75 FR 48604, Aug. 11, 2010; Amdt. 192-119, 
80 FR 178, Jan. 5, 2015; Amdt. 192-120, 80 FR 12779, Mar. 11, 2015]



Sec.  192.927  What are the requirements for using Internal Corrosion   
Direct Assessment (ICDA)?

    (a) Definition. Internal Corrosion Direct Assessment (ICDA) is a 
process an operator uses to identify areas along the pipeline where 
fluid or other electrolyte introduced during normal operation or by an 
upset condition may reside, and then focuses direct examination on the 
locations in covered segments where internal corrosion is most likely to 
exist. The process identifies the potential for internal corrosion 
caused by microorganisms, or fluid with CO2, O2, 
hydrogen sulfide or other contaminants present in the gas.
    (b) General requirements. An operator using direct assessment as an 
assessment method to address internal corrosion in a covered pipeline 
segment must follow the requirements in this section and in NACE SP0206 
(incorporated by reference, see Sec.  192.7). The Dry Gas Internal 
Corrosion Direct Assessment (DG-ICDA) process described in this section 
applies only for a segment of pipe transporting normally dry natural gas 
(see Sec.  192.3) and not for a segment with electrolytes normally 
present in the gas stream. If an operator uses ICDA to assess a covered 
segment operating with electrolytes present in the gas stream, the 
operator must develop a plan that demonstrates how it will conduct ICDA 
in the segment to address internal corrosion effectively and must notify 
PHMSA in accordance with Sec.  192.18. In the event of a conflict 
between this section and NACE SP0206, the requirements in this section 
control.
    (c) The ICDA plan. An operator must develop and follow an ICDA plan 
that meets NACE SP0206 (incorporated by reference, see Sec.  192.7) and 
that implements all four steps of the DG-ICDA process, including pre-
assessment, indirect inspection, detailed examination at excavation 
locations, and post-assessment evaluation and monitoring. The plan must 
identify the locations of all ICDA regions within covered segments in 
the transmission system. An ICDA region is a continuous length of pipe 
(including weld joints), uninterrupted by any significant change in 
water or flow characteristics, that includes similar physical 
characteristics or operating history. An ICDA region extends from the 
location where liquid may first enter the pipeline and encompasses the 
entire area along the pipeline where internal corrosion may occur until 
a new input introduces the possibility of water entering the pipeline. 
In cases where a single covered segment is partially located in two or 
more ICDA regions, the four-step ICDA process must be completed for each 
ICDA region in which the covered segment is partially located to 
complete the assessment of the covered segment.
    (1) Preassessment. An operator must comply with NACE SP0206 
(incorporated by reference, see Sec.  192.7) in conducting the 
preassessment step of the ICDA process.
    (2) Indirect inspection. An operator must comply with NACE SP0206 
(incorporated by reference, see Sec.  192.7), and the following 
additional requirements, in conducting the Indirect Inspection step of 
the ICDA process. An operator must explicitly document the results of 
its feasibility assessment as required by NACE SP0206, section 3.3 
(incorporated by reference, see Sec.  192.7); if any condition that 
precludes the successful application of ICDA applies, then ICDA may not 
be used, and another assessment method must be selected. When

[[Page 567]]

performing the indirect inspection, the operator must use actual 
pipeline-specific data, exclusively. The use of assumed pipeline or 
operational data is prohibited. When calculating the critical 
inclination angle of liquid holdup and the inclination profile of the 
pipeline, the operator must consider the accuracy, reliability, and 
uncertainty of the data used to make those calculations, including, but 
not limited to, gas flow velocity (including during upset conditions), 
pipeline elevation profile survey data (including specific profile at 
features with inclinations such as road crossings, river crossings, 
drains, valves, drips, etc.), topographical data, and depth of cover. An 
operator must select locations for direct examination and establish the 
extent of pipe exposure needed (i.e., the size of the bell hole), to 
account for these uncertainties and their cumulative effect on the 
precise location of predicted liquid dropout.
    (3) Detailed examination. An operator must comply with NACE SP0206 
(incorporated by reference, see Sec.  192.7) in conducting the detailed 
examination step of the ICDA process. When an operator first uses ICDA 
for a covered segment, an operator must identify a minimum of two 
locations for excavation within each covered segment associated with the 
ICDA region and must perform a detailed examination for internal 
corrosion at each location using ultrasonic thickness measurements, 
radiography, or other generally accepted measurement techniques that can 
examine for internal corrosion or other threats that are being assessed. 
One location must be the low point (e.g., sag, drip, valve, manifold, 
dead-leg) within the covered segment nearest to the beginning of the 
ICDA region. The second location must be further downstream, within the 
covered segment, near the end of the ICDA region. Whenever corrosion is 
found during ICDA at any location, the operator must:
    (i) Evaluate the severity of the defect (remaining strength) and 
remediate the defect in accordance with Sec.  192.933 if the condition 
is in a covered segment, or in accordance with Sec. Sec.  192.485 and 
192.714 if the condition is not in a covered segment;
    (ii) Expand the detailed examination program to determine all 
locations that have internal corrosion within the ICDA region, and 
accurately characterize the nature, extent, and root cause of the 
internal corrosion. In cases where the internal corrosion was identified 
within the ICDA region but outside the covered segment, the expanded 
detailed examination program must also include at least two detailed 
examinations within each covered segment associated with the ICDA 
region, at the location within the covered segment(s) most likely to 
have internal corrosion. One location must be the low point (e.g., sags, 
drips, valves, manifolds, dead-legs, traps) within the covered segment 
nearest to the beginning of the ICDA region. The second location must be 
further downstream, within the covered segment. In instances of first 
use of ICDA for a covered segment, where these locations have already 
been examined in accordance with paragraph (c)(3) of this section, two 
additional detailed examinations must be conducted within the covered 
segment; and
    (iii) Expand the detailed examination program to evaluate the 
potential for internal corrosion in all pipeline segments (both covered 
and non-covered) in the operator's pipeline system with similar 
characteristics to the ICDA region in which the corrosion was found and 
remediate identified instances of internal corrosion in accordance with 
either Sec.  192.933 or Sec. Sec.  192.485 and 192.714, as appropriate.
    (4) Post-assessment evaluation and monitoring. An operator must 
comply with NACE SP0206 (incorporated by reference, see Sec.  192.7) in 
performing the post assessment step of the ICDA process. In addition to 
NACE SP0206, the evaluation and monitoring process must also include--
    (i) An evaluation of the effectiveness of ICDA as an assessment 
method for addressing internal corrosion and determining whether a 
covered segment should be reassessed at more frequent intervals than 
those specified in Sec.  192.939. An operator must carry out this 
evaluation within 1 year of conducting an ICDA;
    (ii) Validation of the flow modeling calculations by comparison of 
actual

[[Page 568]]

locations of discovered internal corrosion with locations predicted by 
the model (if the flow model cannot be validated, then ICDA is not 
feasible for the segment); and
    (iii) Continuous monitoring of each ICDA region that contains a 
covered segment where internal corrosion has been identified by using 
techniques such as coupons or ultrasonic (UT) sensors or electronic 
probes, and by periodically drawing off liquids at low points and 
chemically analyzing the liquids for the presence of corrosion products. 
An operator must base the frequency of the monitoring and liquid 
analysis on results from all integrity assessments that have been 
conducted in accordance with the requirements of this subpart and risk 
factors specific to the ICDA region.
    At a minimum, the monitoring frequency must be two times each 
calendar year, but at intervals not exceeding 7\1/2\ months. If an 
operator finds any evidence of corrosion products in the ICDA region, 
the operator must take prompt action in accordance with one of the two 
following required actions, and remediate the conditions the operator 
finds in accordance with Sec.  192.933 or Sec. Sec.  192.485 and 
192.714, as applicable.
    (A) Conduct excavations of, and detailed examinations at, locations 
downstream from where the electrolytes might have entered the pipe to 
investigate and accurately characterize the nature, extent, and root 
cause of the corrosion, including the monitoring and mitigation 
requirements of Sec.  192.478; or
    (B) Assess the covered segment using another integrity assessment 
method allowed by this subpart.
    (5) Other requirements. The ICDA plan must also include the 
following:
    (i) Criteria an operator will apply in making key decisions 
(including, but not limited to, ICDA feasibility, definition of ICDA 
regions and sub-regions, and conditions requiring excavation) in 
implementing each stage of the ICDA process; and
    (ii) Provisions that the analysis be carried out on the entire 
pipeline in which covered segments are present, except that application 
of the remediation criteria of Sec.  192.933 may be limited to covered 
segments.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18232, 
Apr. 6, 2004; Amdt. 192-132, 87 FR 52275, Aug. 24, 2022]



Sec.  192.929  What are the requirements for using Direct Assessment for 
Stress Corrosion Cracking?

    (a) Definition. A Stress Corrosion Cracking Direct Assessment 
(SCCDA) is a process to assess a covered pipeline segment for the 
presence of stress corrosion cracking (SCC) by systematically gathering 
and analyzing excavation data from pipe having similar operational 
characteristics and residing in a similar physical environment.
    (b) General requirements. An operator using direct assessment as an 
integrity assessment method for addressing SCC in a covered pipeline 
segment must develop and follow an SCCDA plan that meets NACE SP0204 
(incorporated by reference, see Sec.  192.7) and that implements all 
four steps of the SCCDA process, including pre-assessment, indirect 
inspection, detailed examination at excavation locations, and post-
assessment evaluation and monitoring. As specified in NACE SP0204, SCCDA 
is complementary with other inspection methods for SCC, such as in-line 
inspection or hydrostatic testing with a spike test, and it is not 
necessarily an alternative or replacement for these methods in all 
instances. Additionally, the plan must provide for--
    (1) Data gathering and integration. An operator's plan must provide 
for a systematic process to collect and evaluate data for all covered 
pipeline segments to identify whether the conditions for SCC are present 
and to prioritize the covered pipeline segments for assessment in 
accordance with NACE SP0204, sections 3 and 4, and Table 1 (incorporated 
by reference, see Sec.  192.7). This process must also include gathering 
and evaluating data related to SCC at all sites an operator excavates 
while conducting its pipeline operations (both within and outside 
covered segments) where the criteria in NACE SP0204 (incorporated by 
reference, see Sec.  192.7) indicate the potential for SCC. This data 
gathering process must be conducted in accordance with NACE

[[Page 569]]

SP0204, section 5.3 (incorporated by reference, see Sec.  192.7), and 
must include, at a minimum, all data listed in NACE SP0204, Table 2 
(incorporated by reference, see Sec.  192.7). Further, the following 
factors must be analyzed as part of this evaluation:
    (i) The effects of a carbonate-bicarbonate environment, including 
the implications of any factors that promote the production of a 
carbonate-bicarbonate environment, such as soil temperature, moisture, 
the presence or generation of carbon dioxide, or cathodic protection 
(CP);
    (ii) The effects of cyclic loading conditions on the susceptibility 
and propagation of SCC in both high-pH and near-neutral-pH environments;
    (iii) The effects of variations in applied CP, such as 
overprotection, CP loss for extended periods, and high negative 
potentials;
    (iv) The effects of coatings that shield CP when disbonded from the 
pipe; and
    (v) Other factors that affect the mechanistic properties associated 
with SCC, including, but not limited to, historical and present-day 
operating pressures, high tensile residual stresses, flowing product 
temperatures, and the presence of sulfides.
    (2) Indirect inspection. In addition to NACE SP0204, the plan's 
procedures for indirect inspection must include provisions for 
conducting at least two above ground surveys using the complementary 
measurement tools most appropriate for the pipeline segment based on an 
evaluation of integrated data.
    (3) Direct examination. In addition to NACE SP0204, the plan's 
procedures for direct examination must provide for an operator 
conducting a minimum of three direct examinations for SCC within the 
covered pipeline segment spaced at the locations determined to be the 
most likely for SCC to occur.
    (4) Remediation and mitigation. If SCC is discovered in a covered 
pipeline segment, an operator must mitigate the threat in accordance 
with one of the following applicable methods:
    (i) Removing the pipe with SCC; remediating the pipe with a Type B 
sleeve; performing hydrostatic testing in accordance with paragraph 
(b)(4)(ii) of this section; or by grinding out the SCC defect and 
repairing the pipe. If an operator uses grinding for repair, the 
operator must also perform the following as a part of the repair 
procedure: nondestructive testing for any remaining cracks or other 
defects; a measurement of the remaining wall thickness; and a 
determination of the remaining strength of the pipe at the repair 
location that is performed in accordance with Sec.  192.712 and that 
meets the design requirements of Sec. Sec.  192.111 and 192.112, as 
applicable. The pipe and material properties an operator uses in 
remaining strength calculations must be documented in traceable, 
verifiable, and complete records. If such records are not available, an 
operator must base the pipe and material properties used in the 
remaining strength calculations on properties determined and documented 
in accordance with Sec.  192.607, if applicable.
    (ii) Performing a spike pressure test in accordance with Sec.  
192.506 based upon the class location of the pipeline segment. The MAOP 
must be no greater than the test pressure specified in Sec.  192.506(a) 
divided by: 1.39 for Class 1 locations and Class 2 locations that 
contain Class 1 pipe that has been uprated in accordance with Sec.  
192.611; and 1.50 for all other Class 2 locations and all Class 3 and 
Class 4 locations. An operator must repair any test failures due to SCC 
by replacing the pipe segment and re-testing the segment until the pipe 
passes the test without failures (such as pipe seam or gasket leaks, or 
a pipe rupture). At a minimum, an operator must repair pipe segments 
that pass the pressure test but have SCC present by grinding the segment 
in accordance with paragraph (b)(4)(i) of this section.
    (5) Post assessment. An operator's procedures for post-assessment, 
in addition to the procedures listed in NACE SP0204, sections 6.3, 
``periodic reassessment,'' and 6.4, ``effectiveness of SCCDA,'' must 
include the development of a reassessment plan based on the 
susceptibility of the operator's pipe to SCC as well as the mechanistic 
behavior of identified cracking. An operator's reassessment intervals 
must comply with Sec.  192.939. The plan must include the following 
factors, in addition

[[Page 570]]

to any factors the operator determines appropriate:
    (i) The evaluation of discovered crack clusters during the direct 
examination step in accordance with NACE SP0204, sections 5.3.5.7, 5.4, 
and 5.5 (incorporated by reference, see Sec.  192.7);
    (ii) Conditions conducive to the creation of a carbonate-bicarbonate 
environment;
    (iii) Conditions in the application (or loss) of CP that can create 
or exacerbate SCC;
    (iv) Operating temperature and pressure conditions, including 
operating stress levels on the pipe;
    (v) Cyclic loading conditions;
    (vi) Mechanistic conditions that influence crack initiation and 
growth rates;
    (vii) The effects of interacting crack clusters;
    (viii) The presence of sulfides; and
    (ix) Disbonded coatings that shield CP from the pipe.

[Amdt. 192-132, 87 FR 52276, Aug. 24, 2022]



Sec.  192.931  How may Confirmatory Direct Assessment (CDA) be used?

    An operator using the confirmatory direct assessment (CDA) method as 
allowed in Sec.  192.937 must have a plan that meets the requirements of 
this section and of Sec. Sec.  192.925 (ECDA) and Sec.  192.927 (ICDA).
    (a) Threats. An operator may only use CDA on a covered segment to 
identify damage resulting from external corrosion or internal corrosion.
    (b) External corrosion plan. An operator's CDA plan for identifying 
external corrosion must comply with Sec.  192.925 with the following 
exceptions.
    (1) The procedures for indirect examination may allow use of only 
one indirect examination tool suitable for the application.
    (2) The procedures for direct examination and remediation must 
provide that--
    (i) All immediate action indications must be excavated for each ECDA 
region; and
    (ii) At least one high risk indication that meets the criteria of 
scheduled action must be excavated in each ECDA region.
    (c) Internal corrosion plan. An operator's CDA plan for identifying 
internal corrosion must comply with Sec.  192.927 except that the plan's 
procedures for identifying locations for excavation may require 
excavation of only one high risk location in each ICDA region.
    (d) Defects requiring near-term remediation. If an assessment 
carried out under paragraph (b) or (c) of this section reveals any 
defect requiring remediation prior to the next scheduled assessment, the 
operator must schedule the next assessment in accordance with NACE 
SP0502 (incorporated by reference, see Sec.  192.7), section 6.2 and 
6.3. If the defect requires immediate remediation, then the operator 
must reduce pressure consistent with Sec.  192.933 until the operator 
has completed reassessment using one of the assessment techniques 
allowed in Sec.  192.937.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-114, 75 FR 48604, 
Aug. 11, 2010; Amdt. 192-119, 80 FR 178, Jan. 5, 2015]



Sec.  192.933  What actions must be taken to address integrity issues?

    (a) General requirements. An operator must take prompt action to 
address all anomalous conditions the operator discovers through the 
integrity assessment. In addressing all conditions, an operator must 
evaluate all anomalous conditions and remediate those that could reduce 
a pipeline's integrity. An operator must be able to demonstrate that the 
remediation of the condition will ensure the condition is unlikely to 
pose a threat to the integrity of the pipeline until the next 
reassessment of the covered segment. Repairs performed in accordance 
with this section must use pipe and material properties that are 
documented in traceable, verifiable, and complete records. If documented 
data required for any analysis is not available, an operator must obtain 
the undocumented data through Sec.  192.607. Until documented material 
properties are available, the operator must use the conservative 
assumptions in either Sec.  192.712(e)(2) or, if appropriate following a 
pressure test, in Sec.  192.712(d)(3).
    (1) Temporary pressure reduction. (i) If an operator is unable to 
respond within the time limits for certain conditions specified in this 
section, the operator must temporarily reduce the operating pressure of 
the pipeline or take other

[[Page 571]]

action that ensures the safety of the covered segment. An operator must 
reduce the operating pressure to one of the following:
    (A) A level not exceeding 80 percent of the operating pressure at 
the time the condition was discovered;
    (B) A level not exceeding the predicted failure pressure times the 
design factor for the class location in which the affected pipeline is 
located; or
    (C) A level not exceeding the predicted failure pressure divided by 
1.1.
    (ii) An operator must determine the predicted failure pressure in 
accordance with Sec.  192.712. An operator must notify PHMSA in 
accordance with Sec.  192.18 if it cannot meet the schedule for 
evaluation and remediation required under paragraph (c) or (d) of this 
section and cannot provide safety through a temporary reduction in 
operating pressure or other action. The operator must document and keep 
records of the calculations and decisions used to determine the reduced 
operating pressure, and the implementation of the actual reduced 
operating pressure, for a period of 5 years after the pipeline has been 
remediated.
    (2) Long-term pressure reduction. When a pressure reduction exceeds 
365 days, an operator must notify PHMSA under Sec.  192.18 and explain 
the reasons for the remediation delay. This notice must include a 
technical justification that the continued pressure reduction will not 
jeopardize the integrity of the pipeline.
    (b) Discovery of condition. Discovery of a condition occurs when an 
operator has adequate information about a condition to determine that 
the condition presents a potential threat to the integrity of the 
pipeline. For the purposes of this section, a condition that presents a 
potential threat includes, but is not limited to, those conditions that 
require remediation or monitoring listed under paragraphs (d)(1) through 
(3) of this section. An operator must promptly, but no later than 180 
days after conducting an integrity assessment, obtain sufficient 
information about a condition to make that determination, unless the 
operator demonstrates that the 180-day period is impracticable. In cases 
where a determination is not made within the 180-day period, the 
operator must notify PHMSA, in accordance with Sec.  192.18, and provide 
an expected date when adequate information will become available. 
Notification to PHMSA does not alleviate an operator from the discovery 
requirements of this paragraph (b).
    (c) Schedule for evaluation and remediation. An operator must 
complete remediation of a condition according to a schedule prioritizing 
the conditions for evaluation and remediation. Unless a special 
requirement for remediating certain conditions applies, as provided in 
paragraph (d) of this section, an operator must follow the schedule in 
ASME/ANSI B31.8S (incorporated by reference, see Sec.  192.7), section 
7, Figure 4. If an operator cannot meet the schedule for any condition, 
the operator must explain the reasons why it cannot meet the schedule 
and how the changed schedule will not jeopardize public safety.
    (d) Special requirements for scheduling remediation--(1) Immediate 
repair conditions. An operator's evaluation and remediation schedule 
must follow ASME/ANSI B31.8S, section 7 (incorporated by reference, see 
Sec.  192.7) in providing for immediate repair conditions. To maintain 
safety, an operator must temporarily reduce operating pressure in 
accordance with paragraph (a) of this section or shut down the pipeline 
until the operator completes the repair of these conditions. An operator 
must treat the following conditions as immediate repair conditions:
    (i) A metal loss anomaly where a calculation of the remaining 
strength of the pipe shows a predicted failure pressure determined in 
accordance with Sec.  192.712(b) less than or equal to 1.1 times the 
MAOP at the location of the anomaly.
    (ii) A dent located between the 8 o'clock and 4 o'clock positions 
(upper \2/3\ of the pipe) that has metal loss, cracking, or a stress 
riser, unless engineering analyses performed in accordance with Sec.  
192.712(c) demonstrate critical strain levels are not exceeded.
    (iii) Metal loss greater than 80 percent of nominal wall regardless 
of dimensions.
    (iv) Metal loss preferentially affecting a detected longitudinal 
seam, if

[[Page 572]]

that seam was formed by direct current, low-frequency or high-frequency 
electric resistance welding, electric flash welding, or with a 
longitudinal joint factor less than 1.0, and where the predicted failure 
pressure determined in accordance with Sec.  192.712(d) is less than 
1.25 times the MAOP.
    (v) A crack or crack-like anomaly meeting any of the following 
criteria:
    (A) Crack depth plus any metal loss is greater than 50 percent of 
pipe wall thickness;
    (B) Crack depth plus any metal loss is greater than the inspection 
tool's maximum measurable depth; or
    (C) The crack or crack-like anomaly has a predicted failure 
pressure, determined in accordance with Sec.  192.712(d), that is less 
than 1.25 times the MAOP.
    (vi) An indication or anomaly that, in the judgment of the person 
designated by the operator to evaluate the assessment results, requires 
immediate action.
    (2) One-year conditions. Except for conditions listed in paragraphs 
(d)(1) and (3) of this section, an operator must remediate any of the 
following within 1 year of discovery of the condition:
    (i) A smooth dent located between the 8 o'clock and 4 o'clock 
positions (upper \2/3\ of the pipe) with a depth greater than 6 percent 
of the pipeline diameter (greater than 0.50 inches in depth for a 
pipeline diameter less than Nominal Pipe Size (NPS) 12), unless 
engineering analyses performed in accordance with Sec.  192.712(c) 
demonstrate critical strain levels are not exceeded.
    (ii) A dent with a depth greater than 2 percent of the pipeline 
diameter (0.250 inches in depth for a pipeline diameter less than NPS 
12) that affects pipe curvature at a girth weld or at a longitudinal or 
helical (spiral) seam weld, unless engineering analyses performed in 
accordance with Sec.  192.712(c) demonstrate critical strain levels are 
not exceeded.
    (iii) A dent located between the 4 o'clock and 8 o'clock positions 
(lower \1/3\ of the pipe) that has metal loss, cracking, or a stress 
riser, unless engineering analyses performed in accordance with Sec.  
192.712(c) demonstrate critical strain levels are not exceeded.
    (iv) Metal loss anomalies where a calculation of the remaining 
strength of the pipe at the location of the anomaly shows a predicted 
failure pressure, determined in accordance with Sec.  192.712(b), less 
than 1.39 times the MAOP for Class 2 locations, and less than 1.50 times 
the MAOP for Class 3 and 4 locations. For metal loss anomalies in Class 
1 locations with a predicted failure pressure greater than 1.1 times 
MAOP, an operator must follow the remediation schedule specified in 
ASME/ANSI B31.8S (incorporated by reference, see Sec.  192.7), section 
7, Figure 4, in accordance with paragraph (c) of this section.
    (v) Metal loss that is located at a crossing of another pipeline, or 
is in an area with widespread circumferential corrosion, or could affect 
a girth weld, that has a predicted failure pressure, determined in 
accordance with Sec.  192.712(b), of less than 1.39 times the MAOP for 
Class 1 locations or where Class 2 locations contain Class 1 pipe that 
has been uprated in accordance with Sec.  192.611, or less than 1.50 
times the MAOP for all other Class 2 locations and all Class 3 and 4 
locations.
    (vi) Metal loss preferentially affecting a detected longitudinal 
seam, if that seam was formed by direct current, low-frequency or high-
frequency electric resistance welding, electric flash welding, or with a 
longitudinal joint factor less than 1.0, and where the predicted failure 
pressure, determined in accordance with Sec.  192.712(d), is less than 
1.39 times the MAOP for Class 1 locations or where Class 2 locations 
contain Class 1 pipe that has been uprated in accordance with Sec.  
192.611, or less than 1.50 times the MAOP for all other Class 2 
locations and all Class 3 and 4 locations.
    (vii) A crack or crack-like anomaly that has a predicted failure 
pressure, determined in accordance with Sec.  192.712(d), that is less 
than 1.39 times the MAOP for Class 1 locations or where Class 2 
locations contain Class 1 pipe that has been uprated in accordance with 
Sec.  192.611, or less than 1.50 times the MAOP for all other Class 2 
locations and all Class 3 and 4 locations.

[[Page 573]]

    (3) Monitored conditions. An operator is not required by this 
section to schedule remediation of the following less severe conditions 
but must record and monitor the conditions during subsequent risk 
assessments and integrity assessments for any change that may require 
remediation. Monitored indications are the least severe and do not 
require an operator to examine and evaluate them until the next 
scheduled integrity assessment interval, but if an anomaly is expected 
to grow to dimensions or have a predicted failure pressure (with a 
safety factor) meeting a 1-year condition prior to the next scheduled 
assessment, then the operator must repair the condition:
    (i) A dent with a depth greater than 6 percent of the pipeline 
diameter (greater than 0.50 inches in depth for a pipeline diameter less 
than NPS 12), located between the 4 o'clock position and the 8 o'clock 
position (bottom \1/3\ of the pipe), and for which engineering analyses 
of the dent, performed in accordance with Sec.  192.712(c), demonstrate 
critical strain levels are not exceeded.
    (ii) A dent located between the 8 o'clock and 4 o'clock positions 
(upper \2/3\ of the pipe) with a depth greater than 6 percent of the 
pipeline diameter (greater than 0.50 inches in depth for a pipeline 
diameter less than NPS 12), and for which engineering analyses of the 
dent, performed in accordance with Sec.  192.712(c), demonstrate 
critical strain levels are not exceeded.
    (iii) A dent with a depth greater than 2 percent of the pipeline 
diameter (0.250 inches in depth for a pipeline diameter less than NPS 
12) that affects pipe curvature at a girth weld or longitudinal or 
helical (spiral) seam weld, and for which engineering analyses, 
performed in accordance with Sec.  192.712(c), of the dent and girth or 
seam weld demonstrate that critical strain levels are not exceeded.
    (iv) A dent that has metal loss, cracking, or a stress riser, and 
where engineering analyses performed in accordance with Sec.  192.712(c) 
demonstrate critical strain levels are not exceeded.
    (v) Metal loss preferentially affecting a detected longitudinal 
seam, if that seam was formed by direct current, low-frequency or high-
frequency electric resistance welding, electric flash welding, or with a 
longitudinal joint factor less than 1.0, and where the predicted failure 
pressure, determined in accordance with Sec.  192.712(d), is greater 
than or equal to 1.39 times the MAOP for Class 1 locations or where 
Class 2 locations contain Class 1 pipe that has been uprated in 
accordance with Sec.  192.611, or greater than or equal to 1.50 times 
the MAOP for all other Class 2 locations and all Class 3 and 4 
locations.
    (vi) A crack or crack-like anomaly for which the predicted failure 
pressure, determined in accordance with Sec.  192.712(d), is greater 
than or equal to 1.39 times the MAOP for Class 1 locations or where 
Class 2 locations contain Class 1 pipe that has been uprated in 
accordance with Sec.  192.611, or greater than or equal to 1.50 times 
the MAOP for all other Class 2 locations and all Class 3 and 4 
locations.
    (e) In situ direct examination of crack defects. Whenever an 
operator finds conditions that require the pipeline to be repaired, in 
accordance with this section, an operator must perform a direct 
examination of known locations of cracks or crack-like defects using 
technology that has been validated to detect tight cracks (equal to or 
less than 0.008 inches crack opening), such as inverse wave field 
extrapolation (IWEX), phased array ultrasonic testing (PAUT), ultrasonic 
testing (UT), or equivalent technology. ``In situ'' examination tools 
and procedures for crack assessments (length, depth, and volumetric) 
must have performance and evaluation standards, including pipe or weld 
surface cleanliness standards for the inspection, confirmed by subject 
matter experts qualified by knowledge, training, and experience in 
direct examination inspection for accuracy of the type of defects and 
pipe material being evaluated. The procedures must account for 
inaccuracies in evaluations and fracture mechanics models for failure 
pressure determinations.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18233, 
Apr. 6, 2004; Amdt. 192-104, 72 FR 39016, July 17, 2007; Amdt. 192-119, 
80 FR 182, Jan. 5, 2015; 80 FR 46847, Aug. 6, 2015; Amdt. No. 192-125, 
84 FR 52254, Oct. 1, 2019; Amdt. 192-132, 87 FR 52277, Aug. 24, 2022; 
Amdt. 192-133, 88 FR 24712, Apr. 24, 2023]

[[Page 574]]



Sec.  192.935  What additional preventive and mitigative measures must an 
operator take?

    (a) General requirements. (1) An operator must take additional 
measures beyond those already required by this part to prevent a 
pipeline failure and to mitigate the consequences of a pipeline failure 
in a high consequence area. Such additional measures must be based on 
the risk analyses required by Sec.  192.917. Measures that operators 
must consider in the analysis, if necessary, to prevent or mitigate the 
consequences of a pipeline failure include, but are not limited to:
    (i) Correcting the root causes of past incidents to prevent 
recurrence;
    (ii) Establishing and implementing adequate operations and 
maintenance processes that could increase safety;
    (iii) Establishing and deploying adequate resources for the 
successful execution of preventive and mitigative measures;
    (iv) Installing automatic shut-off valves or remote-control valves;
    (v) Installing pressure transmitters on both sides of automatic 
shut-off valves and remote-control valves that communicate with the 
pipeline control center;
    (vi) Installing computerized monitoring and leak detection systems;
    (vii) Replacing pipe segments with pipe of heavier wall thickness or 
higher strength;
    (viii) Conducting additional right-of-way patrols;
    (ix) Conducting hydrostatic tests in areas where pipe material has 
quality issues or lost records;
    (x) Testing to determine material mechanical and chemical properties 
for unknown properties that are needed to assure integrity or 
substantiate MAOP evaluations, including material property tests from 
removed pipe that is representative of the in-service pipeline;
    (xi) Re-coating damaged, poorly performing, or disbonded coatings;
    (xii) Performing additional depth-of-cover surveys at roads, 
streams, and rivers;
    (xiii) Remediating inadequate depth-of-cover;
    (xiv) Providing additional training to personnel on response 
procedures and conducting drills with local emergency responders; and
    (xv) Implementing additional inspection and maintenance programs.
    (2) Operators must document the risk analysis, the preventive and 
mitigative measures considered, and the basis for implementing or not 
implementing any preventive and mitigative measures considered, in 
accordance with Sec.  192.947(d).
    (b) Third party damage and outside force damage--
    (1) Third party damage. An operator must enhance its damage 
prevention program, as required under Sec.  192.614 of this part, with 
respect to a covered segment to prevent and minimize the consequences of 
a release due to third party damage. Enhanced measures to an existing 
damage prevention program include, at a minimum--
    (i) Using qualified personnel (see Sec.  192.915) for work an 
operator is conducting that could adversely affect the integrity of a 
covered segment, such as marking, locating, and direct supervision of 
known excavation work.
    (ii) Collecting in a central database information that is location 
specific on excavation damage that occurs in covered and non covered 
segments in the transmission system and the root cause analysis to 
support identification of targeted additional preventative and 
mitigative measures in the high consequence areas. This information must 
include recognized damage that is not required to be reported as an 
incident under part 191.
    (iii) Participating in one-call systems in locations where covered 
segments are present.
    (iv) Monitoring of excavations conducted on covered pipeline 
segments by pipeline personnel. If an operator finds physical evidence 
of encroachment involving excavation that the operator did not monitor 
near a covered segment, an operator must either excavate the area near 
the encroachment or conduct an above ground survey using methods defined 
in NACE SP0502 (incorporated by reference, see Sec.  192.7). An operator 
must excavate, and remediate, in accordance with ANSI/ASME B31.8S and 
Sec.  192.933 any indication of coating holidays or discontinuity 
warranting direct examination.

[[Page 575]]

    (2) Outside force damage. If an operator determines that outside 
force (e.g., earth movement, loading, longitudinal, or lateral forces, 
seismicity of the area, floods, unstable suspension bridge) is a threat 
to the integrity of a covered segment, the operator must take measures 
to minimize the consequences to the covered segment from outside force 
damage. These measures include increasing the frequency of aerial, foot 
or other methods of patrols; adding external protection; reducing 
external stress; relocating the line; or inline inspections with 
geospatial and deformation tools.
    (c) Risk analysis for gas releases and protection against ruptures. 
If an operator determines, based on a risk analysis, that a rupture-
mitigation valve (RMV) or alternative equivalent technology would be an 
efficient means of adding protection to a high-consequence area (HCA) in 
the event of a gas release, an operator must install the RMV or 
alternative equivalent technology. In making that determination, an 
operator must, at least, evaluate the following factors--timing of leak 
detection and pipe shutdown capabilities, the type of gas being 
transported, operating pressure, the rate of potential release, pipeline 
profile, the potential for ignition, and location of nearest response 
personnel. An RMV or alternative equivalent technology installed under 
this paragraph must meet all of the other applicable requirements in 
this part.
    (d) Pipelines operating below 30% SMYS. An operator of a 
transmission pipeline operating below 30% SMYS located in a high 
consequence area must follow the requirements in paragraphs (d)(1) and 
(d)(2) of this section. An operator of a transmission pipeline operating 
below 30% SMYS located in a Class 3 or Class 4 area but not in a high 
consequence area must follow the requirements in paragraphs (d)(1), 
(d)(2) and (d)(3) of this section.
    (1) Apply the requirements in paragraphs (b)(1)(i) and (b)(1)(iii) 
of this section to the pipeline; and
    (2) Either monitor excavations near the pipeline, or conduct patrols 
as required by Sec.  192.705 of the pipeline at bi-monthly intervals. If 
an operator finds any indication of unreported construction activity, 
the operator must conduct a follow up investigation to determine if 
mechanical damage has occurred.
    (3) Perform instrumented leak surveys using leak detector equipment 
at least twice each calendar year, at intervals not exceeding 7 \1/2\ 
months. For unprotected pipelines or cathodically protected pipe where 
electrical surveys are impractical, instrumented leak surveys must be 
performed at least four times each calendar year, at intervals not 
exceeding 4 \1/2\ months. Electrical surveys are indirect assessments 
that include close interval surveys, alternating current voltage 
gradient surveys, direct current voltage gradient surveys, or their 
equivalent.
    (e) Plastic transmission pipeline. An operator of a plastic 
transmission pipeline must apply the requirements in paragraphs 
(b)(1)(i), (b)(1)(iii) and (b)(1)(iv) of this section to the covered 
segments of the pipeline.
    (f) Periodic evaluations. Risk analyses and assessments conducted 
under paragraph (c) of this section must be reviewed by the operator and 
certified by a senior executive of the company, for operational matters 
that could affect rupture-mitigation processes and procedures. Review 
and certification must occur once per calendar year, with the period 
between reviews not to exceed 15 months, and must also occur within 3 
months of an incident or safety-related condition, as those terms are 
defined at Sec. Sec.  191.3 and 191.23, respectively.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18233, 
Apr. 6, 2004; Amdt. 192-95, 69 FR 29904, May 26, 2004; Amdt. 192-114, 75 
FR 48604, Aug. 11, 2010; Amdt. 192-119, 80 FR 178, Jan. 5, 2015; Amdt. 
192-125, 84 FR 52254, Oct. 1, 2019; Amdt. 192-130, 87 FR 20986, Apr. 8, 
2022; Amdt. 192-132, 87 FR 52279, Aug. 24, 2022]



Sec.  192.937  What is a continual process of evaluation and assessment to 
maintain a pipeline's integrity?

    (a) General. After completing the baseline integrity assessment of a 
covered segment, an operator must continue to assess the line pipe of 
that segment at the intervals specified in Sec.  192.939 and 
periodically evaluate the integrity of each covered pipeline segment as 
provided in paragraph (b) of this section. An operator must reassess

[[Page 576]]

a covered segment on which a prior assessment is credited as a baseline 
under Sec.  192.921(e) by no later than December 17, 2009. An operator 
must reassess a covered segment on which a baseline assessment is 
conducted during the baseline period specified in Sec.  192.921(d) by no 
later than seven years after the baseline assessment of that covered 
segment unless the evaluation under paragraph (b) of this section 
indicates earlier reassessment.
    (b) Evaluation. An operator must conduct a periodic evaluation as 
frequently as needed to assure the integrity of each covered segment. 
The periodic evaluation must be based on a data integration and risk 
assessment of the entire pipeline as specified in Sec.  192.917. For 
plastic transmission pipelines, the periodic evaluation is based on the 
threat analysis specified in 192.917(d). For all other transmission 
pipelines, the evaluation must consider the past and present integrity 
assessment results, data integration and risk assessment information 
(Sec.  192.917), and decisions about remediation (Sec.  192.933) and 
additional preventive and mitigative actions (Sec.  192.935). An 
operator must use the results from this evaluation to identify the 
threats specific to each covered segment and the risk represented by 
these threats.
    (c) Assessment methods. In conducting the integrity reassessment, an 
operator must assess the integrity of the line pipe in each covered 
segment by applying one or more of the following methods for each threat 
to which the covered segment is susceptible. An operator must select the 
method or methods best suited to address the threats identified on the 
covered segment (see Sec.  192.917).
    (1) Internal inspection tools. When performing an assessment using 
an in-line inspection tool, an operator must comply with the following 
requirements:
    (i) Perform the in-line inspection in accordance with Sec.  192.493;
    (ii) Select a tool or combination of tools capable of detecting the 
threats to which the pipeline segment is susceptible such as corrosion, 
deformation and mechanical damage (e.g. dents, gouges and grooves), 
material cracking and crack-like defects (e.g. stress corrosion 
cracking, selective seam weld corrosion, environmentally assisted 
cracking, and girth weld cracks), hard spots with cracking, and any 
other threats to which the covered segment is susceptible; and
    (iii) Analyze and account for uncertainties in reported results 
(e.g., tool tolerance, detection threshold, probability of detection, 
probability of identification, sizing accuracy, conservative anomaly 
interaction criteria, location accuracy, anomaly findings, and unity 
chart plots or equivalent for determining uncertainties and verifying 
actual tool performance) in identifying and characterizing anomalies.
    (2) Pressure test conducted in accordance with subpart J of this 
part. The use of pressure testing is appropriate for threats such as: 
Internal corrosion; external corrosion and other environmentally 
assisted corrosion mechanisms; manufacturing and related defects 
threats, including defective pipe and pipe seams; stress corrosion 
cracking; selective seam weld corrosion; dents; and other forms of 
mechanical damage. An operator must use the test pressures specified in 
table 3 of section 5 of ASME/ANSI B31.8S (incorporated by reference, see 
Sec.  192.7) to justify an extended reassessment interval in accordance 
with Sec.  192.939.
    (3) Spike hydrostatic pressure test in accordance with Sec.  
192.506. The use of spike hydrostatic pressure testing is appropriate 
for time-dependent threats such as: Stress corrosion cracking; selective 
seam weld corrosion; manufacturing and related defects, including 
defective pipe and pipe seams; and other forms of defect or damage 
involving cracks or crack-like defects;
    (4) Excavation and in situ direct examination by means of visual 
examination, direct measurement, and recorded non-destructive 
examination results and data needed to assess all threats. Based upon 
the threat assessed, examples of appropriate non-destructive examination 
methods include ultrasonic testing (UT), phased array ultrasonic testing 
(PAUT), inverse wave field extrapolation (IWEX), radiography, or 
magnetic particle inspection (MPI);
    (5) Guided wave ultrasonic testing (GWUT) as described in Appendix 
F.

[[Page 577]]

The use of GWUT is appropriate for internal and external pipe wall loss;
    (6) Direct assessment to address threats of external corrosion, 
internal corrosion, and stress corrosion cracking. The use of direct 
assessment to address threats of external corrosion, internal corrosion, 
and stress corrosion cracking is allowed only if appropriate for the 
threat and pipeline segment being assessed. Use of direct assessment for 
threats other than the threat for which the direct assessment method is 
suitable is not allowed. An operator must conduct the direct assessment 
in accordance with the requirements listed in Sec.  192.923 and with the 
applicable requirements specified in Sec. Sec.  192.925, 192.927, and 
192.929;
    (7) Other technology that an operator demonstrates can provide an 
equivalent understanding of the condition of the line pipe for each of 
the threats to which the pipeline is susceptible. An operator must 
notify PHMSA in advance of using the other technology in accordance with 
Sec.  192.18; or
    (8) Confirmatory direct assessment when used on a covered segment 
that is scheduled for reassessment at a period longer than 7 calendar 
years. An operator using this reassessment method must comply with Sec.  
192.931.
    (d) MAOP reconfirmation assessments. An integrity assessment 
conducted in accordance with the requirements of Sec.  192.624(c) may be 
used as a reassessment under this section.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18234, 
Apr. 6, 2004; Amdt. 192-125, 84 FR 52254, Oct. 1, 2019]



Sec.  192.939  What are the required reassessment intervals?

    An operator must comply with the following requirements in 
establishing the reassessment interval for the operator's covered 
pipeline segments.
    (a) Pipelines operating at or above 30% SMYS. An operator must 
establish a reassessment interval for each covered segment operating at 
or above 30% SMYS in accordance with the requirements of this section. 
The maximum reassessment interval by an allowable reassessment method is 
7 calendar years. Operators may request a 6-month extension of the 7-
calendar-year reassessment interval if the operator submits written 
notice to OPS, in accordance with Sec.  192.18, with sufficient 
justification of the need for the extension. If an operator establishes 
a reassessment interval that is greater than 7 calendar years, the 
operator must, within the 7-calendar-year period, conduct a confirmatory 
direct assessment on the covered segment, and then conduct the follow-up 
reassessment at the interval the operator has established. A 
reassessment carried out using confirmatory direct assessment must be 
done in accordance with Sec.  192.931. The table that follows this 
section sets forth the maximum allowed reassessment intervals.
    (1) Pressure test or internal inspection or other equivalent 
technology. An operator that uses pressure testing or internal 
inspection as an assessment method must establish the reassessment 
interval for a covered pipeline segment by--
    (i) Basing the interval on the identified threats for the covered 
segment (see Sec.  192.917) and on the analysis of the results from the 
last integrity assessment and from the data integration and risk 
assessment required by Sec.  192.917; or
    (ii) Using the intervals specified for different stress levels of 
pipeline (operating at or above 30% SMYS) listed in ASME B31.8S 
(incorporated by reference, see Sec.  192.7), section 5, Table 3.
    (2) External Corrosion Direct Assessment. An operator that uses ECDA 
that meets the requirements of this subpart must determine the 
reassessment interval according to the requirements in paragraphs 6.2 
and 6.3 of NACE SP0502 (incorporated by reference, see Sec.  192.7).
    (3) Internal Corrosion or SCC Direct Assessment. An operator that 
uses ICDA or SCCDA in accordance with the requirements of this subpart 
must determine the reassessment interval according to the following 
method. However, the reassessment interval cannot exceed those specified 
for direct assessment in ASME/ANSI B31.8S, section 5, Table 3.
    (i) Determine the largest defect most likely to remain in the 
covered segment and the corrosion rate appropriate for the pipe, soil 
and protection conditions;

[[Page 578]]

    (ii) Use the largest remaining defect as the size of the largest 
defect discovered in the SCC or ICDA segment; and
    (iii) Estimate the reassessment interval as half the time required 
for the largest defect to grow to a critical size.
    (b) Pipelines Operating below 30% SMYS. An operator must establish a 
reassessment interval for each covered segment operating below 30% SMYS 
in accordance with the requirements of this section. The maximum 
reassessment interval by an allowable reassessment method is 7 calendar 
years. Operators may request a 6-month extension of the 7-calendar-year 
reassessment interval if the operator submits written notice to OPS in 
accordance with Sec.  192.18. The notice must include sufficient 
justification of the need for the extension. An operator must establish 
reassessment by at least one of the following--
    (1) Reassessment by pressure test, internal inspection or other 
equivalent technology following the requirements in paragraph (a)(1) of 
this section except that the stress level referenced in paragraph 
(a)(1)(ii) of this section would be adjusted to reflect the lower 
operating stress level. If an established interval is more than 7 
calendar years, an operator must conduct by the seventh calendar year of 
the interval either a confirmatory direct assessment in accordance with 
Sec.  192.931, or a low stress reassessment in accordance with Sec.  
192.941.
    (2) Reassessment by ECDA following the requirements in paragraph 
(a)(2) of this section.
    (3) Reassessment by ICDA or SCCDA following the requirements in 
paragraph (a)(3) of this section.
    (4) Reassessment by confirmatory direct assessment at 7-year 
intervals in accordance with Sec.  192.931, with reassessment by one of 
the methods listed in paragraphs (b)(1) through (b)(3) of this section 
by year 20 of the interval.
    (5) Reassessment by the low stress assessment method at 7-year 
intervals in accordance with Sec.  192.941 with reassessment by one of 
the methods listed in paragraphs (b)(1) through (b)(3) of this section 
by year 20 of the interval.
    (6) The following table sets forth the maximum reassessment 
intervals. Also refer to Appendix E.II for guidance on Assessment 
Methods and Assessment Schedule for Transmission Pipelines Operating 
Below 30% SMYS. In case of conflict between the rule and the guidance in 
the Appendix, the requirements of the rule control. An operator must 
comply with the following requirements in establishing a reassessment 
interval for a covered segment:

                                          Maximum Reassessment Interval
----------------------------------------------------------------------------------------------------------------
                                                                 Pipeline operating at
          Assessment method             Pipeline operating at    or above 30% SMYS, up      Pipeline operating
                                          or above 50% SMYS           to 50% SMYS             below 30% SMYS
----------------------------------------------------------------------------------------------------------------
Internal Inspection Tool, Pressure     10 years (*)...........  15 years (*)...........  20 years. (**)
 Test or Direct Assessment.
Confirmatory Direct Assessment.......  7 years................  7 years................  7 years.
Low Stress Reassessment..............  Not applicable.........  Not applicable.........  7 years + ongoing
                                                                                          actions specified in
                                                                                          Sec.   192.941.
----------------------------------------------------------------------------------------------------------------
(*) A Confirmatory direct assessment as described in Sec.   192.931 must be conducted by year 7 in a 10-year
  interval and years 7 and 14 of a 15-year interval.
(**) A low stress reassessment or Confirmatory direct assessment must be conducted by years 7 and 14 of the
  interval.


[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18234, 
Apr. 6, 2004; Amdt. 192-114, 75 FR 48604, Aug. 11, 2010; Amdt. 192-119, 
80 FR 178, 182, Jan. 5, 2015; Amdt. 192-125, 84 FR 52255, Oct. 1, 2019]



Sec.  192.941  What is a low stress reassessment?

    (a) General. An operator of a transmission line that operates below 
30% SMYS may use the following method to reassess a covered segment in 
accordance with Sec.  192.939. This method of reassessment addresses the 
threats of external and internal corrosion. The operator must have 
conducted a baseline assessment of the covered segment in accordance 
with the requirements of Sec. Sec.  192.919 and 192.921.

[[Page 579]]

    (b) External corrosion. An operator must take one of the following 
actions to address external corrosion on the low stress covered segment.
    (1) Cathodically protected pipe. To address the threat of external 
corrosion on cathodically protected pipe in a covered segment, an 
operator must perform an indirect assessment on the covered segment at 
least once every 7 calendar years. The indirect assessment must be 
conducted using one of the following means: indirect examination method, 
such as a close interval survey; alternating current voltage gradient 
survey; direct current voltage gradient survey; or the equivalent of any 
of these methods. An operator must evaluate the cathodic protection and 
corrosion threat for the covered segment and include the results of each 
indirect assessment as part of the overall evaluation. This evaluation 
must also include, at a minimum, the leak repair and inspection records, 
corrosion monitoring records, exposed pipe inspection records, and the 
pipeline environment.
    (2) Unprotected pipe or cathodically protected pipe where external 
corrosion assessments are impractical. If an external corrosion 
assessment is impractical on the covered segment an operator must--
    (i) Conduct leakage surveys as required by Sec.  192.706 at 4-month 
intervals; and
    (ii) Every 18 months, identify and remediate areas of active 
corrosion by evaluating leak repair and inspection records, corrosion 
monitoring records, exposed pipe inspection records, and the pipeline 
environment.
    (c) Internal corrosion. To address the threat of internal corrosion 
on a covered segment, an operator must--
    (1) Conduct a gas analysis for corrosive agents at least once each 
calendar year;
    (2) Conduct periodic testing of fluids removed from the segment. At 
least once each calendar year test the fluids removed from each storage 
field that may affect a covered segment; and
    (3) At least every seven (7) years, integrate data from the analysis 
and testing required by paragraphs (c)(1)-(c)(2) with applicable 
internal corrosion leak records, incident reports, safety-related 
condition reports, repair records, patrol records, exposed pipe reports, 
and test records, and define and implement appropriate remediation 
actions.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18234, 
Apr. 6, 2004; Amdt. 192-132, 87 FR 52279, Aug. 24, 2022]



Sec.  192.943  When can an operator deviate from these reassessment 
intervals?

    (a) Waiver from reassessment interval in limited situations. In the 
following limited instances, OPS may allow a waiver from a reassessment 
interval required by Sec.  192.939 if OPS finds a waiver would not be 
inconsistent with pipeline safety.
    (1) Lack of internal inspection tools. An operator who uses internal 
inspection as an assessment method may be able to justify a longer 
reassessment period for a covered segment if internal inspection tools 
are not available to assess the line pipe. To justify this, the operator 
must demonstrate that it cannot obtain the internal inspection tools 
within the required reassessment period and that the actions the 
operator is taking in the interim ensure the integrity of the covered 
segment.
    (2) Maintain product supply. An operator may be able to justify a 
longer reassessment period for a covered segment if the operator 
demonstrates that it cannot maintain local product supply if it conducts 
the reassessment within the required interval.
    (b) How to apply. If one of the conditions specified in paragraph 
(a) (1) or (a) (2) of this section applies, an operator may seek a 
waiver of the required reassessment interval. An operator must apply for 
a waiver in accordance with 49 U.S.C. 60118(c), at least 180 days before 
the end of the required reassessment interval, unless local product 
supply issues make the period impractical. If local product supply 
issues make the period impractical, an operator must apply for the 
waiver as soon as the need for the waiver becomes known.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18234, 
Apr. 6, 2004]

[[Page 580]]



Sec.  192.945  What methods must an operator use to measure program  
effectiveness?

    (a) General. An operator must include in its integrity management 
program methods to measure whether the program is effective in assessing 
and evaluating the integrity of each covered pipeline segment and in 
protecting the high consequence areas. These measures must include the 
four overall performance measures specified in ASME/ANSI B31.8S 
(incorporated by reference, see Sec.  192.7 of this part), section 9.4, 
and the specific measures for each identified threat specified in ASME/
ANSI B31.8S, Appendix A. An operator must submit the four overall 
performance measures as part of the annual report required by Sec.  
191.17 of this subchapter.
    (b) External Corrosion Direct assessment. In addition to the general 
requirements for performance measures in paragraph (a) of this section, 
an operator using direct assessment to assess the external corrosion 
threat must define and monitor measures to determine the effectiveness 
of the ECDA process. These measures must meet the requirements of Sec.  
192.925.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18234, 
Apr. 6, 2004; 75 FR 72906, Nov. 26, 2010]



Sec.  192.947  What records must an operator keep?

    An operator must maintain, for the useful life of the pipeline, 
records that demonstrate compliance with the requirements of this 
subpart. At minimum, an operator must maintain the following records for 
review during an inspection.
    (a) A written integrity management program in accordance with Sec.  
192.907;
    (b) Documents supporting the threat identification and risk 
assessment in accordance with Sec.  192.917;
    (c) A written baseline assessment plan in accordance with Sec.  
192.919;
    (d) Documents to support any decision, analysis and process 
developed and used to implement and evaluate each element of the 
baseline assessment plan and integrity management program. Documents 
include those developed and used in support of any identification, 
calculation, amendment, modification, justification, deviation and 
determination made, and any action taken to implement and evaluate any 
of the program elements;
    (e) Documents that demonstrate personnel have the required training, 
including a description of the training program, in accordance with 
Sec.  192.915;
    (f) Schedule required by Sec.  192.933 that prioritizes the 
conditions found during an assessment for evaluation and remediation, 
including technical justifications for the schedule.
    (g) Documents to carry out the requirements in Sec. Sec.  192.923 
through 192.929 for a direct assessment plan;
    (h) Documents to carry out the requirements in Sec.  192.931 for 
confirmatory direct assessment;
    (i) Verification that an operator has provided any documentation or 
notification required by this subpart to be provided to OPS, and when 
applicable, a State authority with which OPS has an interstate agent 
agreement, and a State or local pipeline safety authority that regulates 
a covered pipeline segment within that State.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18234, 
Apr. 6, 2004]



Sec.  192.949  [Reserved]



Sec.  192.951  Where does an operator file a report?

    An operator must file any report required by this subpart 
electronically to the Pipeline and Hazardous Materials Safety 
Administration in accordance with Sec.  191.7 of this subchapter.

[Amdt. 192-115, 75 FR 72906, Nov. 26, 2010]



      Subpart P_Gas Distribution Pipeline Integrity Management (IM)

    Source: 74 FR 63934, Dec. 4, 2009, unless otherwise noted.



Sec.  192.1001  What definitions apply to this subpart?

    The following definitions apply to this subpart:
    Excavation Damage means any impact that results in the need to 
repair or replace an underground facility due to a weakening, or the 
partial or complete destruction, of the facility, including,

[[Page 581]]

but not limited to, the protective coating, lateral support, cathodic 
protection or the housing for the line device or facility.
    Hazardous Leak means a leak that represents an existing or probable 
hazard to persons or property and requires immediate repair or 
continuous action until the conditions are no longer hazardous.
    Integrity Management Plan or IM Plan means a written explanation of 
the mechanisms or procedures the operator will use to implement its 
integrity management program and to ensure compliance with this subpart.
    Integrity Management Program or IM Program means an overall approach 
by an operator to ensure the integrity of its gas distribution system.
    Mechanical fitting means a mechanical device used to connect 
sections of pipe. The term ``Mechanical fitting'' applies only to:
    (1) Stab Type fittings;
    (2) Nut Follower Type fittings;
    (3) Bolted Type fittings; or
    (4) Other Compression Type fittings.
    Small LPG Operator means an operator of a liquefied petroleum gas 
(LPG) distribution pipeline that serves fewer than 100 customers from a 
single source.

[74 FR 63934, Dec. 4, 2009, as amended at 76 FR 5499, Feb. 1, 2011]



Sec.  192.1003  What do the regulations in this subpart cover?

    (a) General. Unless exempted in paragraph (b) of this section, this 
subpart prescribes minimum requirements for an IM program for any gas 
distribution pipeline covered under this part, including liquefied 
petroleum gas systems. A gas distribution operator must follow the 
requirements in this subpart.
    (b) Exceptions. This subpart does not apply to:
    (1) Individual service lines directly connected to a production line 
or a gathering line other than a regulated onshore gathering line as 
determined in Sec.  192.8;
    (2) Individual service lines directly connected to either a 
transmission or regulated gathering pipeline and maintained in 
accordance with Sec.  192.740(a) and (b); and
    (3) Master meter systems.

[86 FR 2241, Jan. 11, 2021]



Sec.  192.1005  What must a gas distribution operator (other than a small 
LPG operator) do to implement this subpart?

    No later than August 2, 2011 a gas distribution operator must 
develop and implement an integrity management program that includes a 
written integrity management plan as specified in Sec.  192.1007.

[74 FR 63934, Dec. 4, 2009, as amended at 86 FR 2241, Jan. 11, 2021]



Sec.  192.1007  What are the required elements of an integrity management 
plan?

    A written integrity management plan must contain procedures for 
developing and implementing the following elements:
    (a) Knowledge. An operator must demonstrate an understanding of its 
gas distribution system developed from reasonably available information.
    (1) Identify the characteristics of the pipeline's design and 
operations and the environmental factors that are necessary to assess 
the applicable threats and risks to its gas distribution pipeline.
    (2) Consider the information gained from past design, operations, 
and maintenance.
    (3) Identify additional information needed and provide a plan for 
gaining that information over time through normal activities conducted 
on the pipeline (for example, design, construction, operations or 
maintenance activities).
    (4) Develop and implement a process by which the IM program will be 
reviewed periodically and refined and improved as needed.
    (5) Provide for the capture and retention of data on any new 
pipeline installed. The data must include, at a minimum, the location 
where the new pipeline is installed and the material of which it is 
constructed.
    (b) Identify threats. The operator must consider the following 
categories of threats to each gas distribution pipeline: Corrosion 
(including atmospheric corrosion), natural forces, excavation damage, 
other outside force

[[Page 582]]

damage, material or welds, equipment failure, incorrect operations, and 
other issues that could threaten the integrity of its pipeline. An 
operator must consider reasonably available information to identify 
existing and potential threats. Sources of data may include incident and 
leak history, corrosion control records (including atmospheric corrosion 
records), continuing surveillance records, patrolling records, 
maintenance history, and excavation damage experience.
    (c) Evaluate and rank risk. An operator must evaluate the risks 
associated with its distribution pipeline. In this evaluation, the 
operator must determine the relative importance of each threat and 
estimate and rank the risks posed to its pipeline. This evaluation must 
consider each applicable current and potential threat, the likelihood of 
failure associated with each threat, and the potential consequences of 
such a failure. An operator may subdivide its pipeline into regions with 
similar characteristics (e.g., contiguous areas within a distribution 
pipeline consisting of mains, services and other appurtenances; areas 
with common materials or environmental factors), and for which similar 
actions likely would be effective in reducing risk.
    (d) Identify and implement measures to address risks. Determine and 
implement measures designed to reduce the risks from failure of its gas 
distribution pipeline. These measures must include an effective leak 
management program (unless all leaks are repaired when found).
    (e) Measure performance, monitor results, and evaluate 
effectiveness. (1) Develop and monitor performance measures from an 
established baseline to evaluate the effectiveness of its IM program. An 
operator must consider the results of its performance monitoring in 
periodically re-evaluating the threats and risks. These performance 
measures must include the following:
    (i) Number of hazardous leaks either eliminated or repaired as 
required by Sec.  192.703(c) of this subchapter (or total number of 
leaks if all leaks are repaired when found), categorized by cause;
    (ii) Number of excavation damages;
    (iii) Number of excavation tickets (receipt of information by the 
underground facility operator from the notification center);
    (iv) Total number of leaks either eliminated or repaired, 
categorized by cause;
    (v) Number of hazardous leaks either eliminated or repaired as 
required by Sec.  192.703(c) (or total number of leaks if all leaks are 
repaired when found), categorized by material; and
    (vi) Any additional measures the operator determines are needed to 
evaluate the effectiveness of the operator's IM program in controlling 
each identified threat.
    (f) Periodic Evaluation and Improvement. An operator must re-
evaluate threats and risks on its entire pipeline and consider the 
relevance of threats in one location to other areas. Each operator must 
determine the appropriate period for conducting complete program 
evaluations based on the complexity of its system and changes in factors 
affecting the risk of failure. An operator must conduct a complete 
program re-evaluation at least every five years. The operator must 
consider the results of the performance monitoring in these evaluations.
    (g) Report results. Report, on an annual basis, the four measures 
listed in paragraphs (e)(1)(i) through (e)(1)(iv) of this section, as 
part of the annual report required by Sec.  191.11. An operator also 
must report the four measures to the state pipeline safety authority if 
a state exercises jurisdiction over the operator's pipeline.

[74 FR 63934, Dec. 4, 2009, as amended at 76 FR 5499, Feb. 1, 2011; 86 
FR 2241, Jan. 11, 2021]



Sec.  192.1009  [Reserved]



Sec.  192.1011  What records must an operator keep?

    An operator must maintain records demonstrating compliance with the 
requirements of this subpart for at least 10 years. The records must 
include copies of superseded integrity management plans developed under 
this subpart.

[[Page 583]]



Sec.  192.1013  When may an operator deviate from required periodic 
inspections under this part?

    (a) An operator may propose to reduce the frequency of periodic 
inspections and tests required in this part on the basis of the 
engineering analysis and risk assessment required by this subpart.
    (b) An operator must submit its proposal to the PHMSA Associate 
Administrator for Pipeline Safety or, in the case of an intrastate 
pipeline facility regulated by the State, the appropriate State agency. 
The applicable oversight agency may accept the proposal on its own 
authority, with or without conditions and limitations, on a showing that 
the operator's proposal, which includes the adjusted interval, will 
provide an equal or greater overall level of safety.
    (c) An operator may implement an approved reduction in the frequency 
of a periodic inspection or test only where the operator has developed 
and implemented an integrity management program that provides an equal 
or improved overall level of safety despite the reduced frequency of 
periodic inspections.



Sec.  192.1015  What must a small LPG operator do to implement this 
subpart?

    (a) General. No later than August 2, 2011, a small LPG operator must 
develop and implement an IM program that includes a written IM plan as 
specified in paragraph (b) of this section. The IM program for these 
pipelines should reflect the relative simplicity of these types of 
pipelines.
    (b) Elements. A written integrity management plan must address, at a 
minimum, the following elements:
    (1) Knowledge. The operator must demonstrate knowledge of its 
pipeline, which, to the extent known, should include the approximate 
location and material of its pipeline. The operator must identify 
additional information needed and provide a plan for gaining knowledge 
over time through normal activities conducted on the pipeline (for 
example, design, construction, operations or maintenance activities).
    (2) Identify threats. The operator must consider, at minimum, the 
following categories of threats (existing and potential): Corrosion 
(including atmospheric corrosion), natural forces, excavation damage, 
other outside force damage, material or weld failure, equipment failure, 
and incorrect operation.
    (3) Rank risks. The operator must evaluate the risks to its pipeline 
and estimate the relative importance of each identified threat.
    (4) Identify and implement measures to mitigate risks. The operator 
must determine and implement measures designed to reduce the risks from 
failure of its pipeline.
    (5) Measure performance, monitor results, and evaluate 
effectiveness. The operator must monitor, as a performance measure, the 
number of leaks eliminated or repaired on its pipeline and their causes.
    (6) Periodic evaluation and improvement. The operator must determine 
the appropriate period for conducting IM program evaluations based on 
the complexity of its pipeline and changes in factors affecting the risk 
of failure. An operator must re-evaluate its entire program at least 
every 5 years. The operator must consider the results of the performance 
monitoring in these evaluations.
    (c) Records. The operator must maintain, for a period of at least 10 
years, the following records:
    (1) A written IM plan in accordance with this section, including 
superseded IM plans;
    (2) Documents supporting threat identification; and
    (3) Documents showing the location and material of all piping and 
appurtenances that are installed after the effective date of the 
operator's IM program and, to the extent known, the location and 
material of all pipe and appurtenances that were existing on the 
effective date of the operator's program.

[74 FR 63934, Dec. 4, 2009, as amended at 86 FR 2242, Jan. 11, 2021]



[[Page 584]]



                 Sec. Appendix A to Part 192 [Reserved]



    Sec. Appendix B to Part 192--Qualification of Pipe and Components

                        I. List of Specifications

                      A. Listed Pipe Specifications

API Spec 5L--Steel pipe, ``API Specification for Line Pipe'' 
(incorporated by reference, see Sec.  192.7).
ASTM A53/A53M--Steel pipe, ``Standard Specification for Pipe, Steel 
Black and Hot-Dipped, Zinc-Coated, Welded and Seamless'' (incorporated 
by reference, see Sec.  192.7).
ASTM A106/A-106M--Steel pipe, ``Standard Specification for Seamless 
Carbon Steel Pipe for High Temperature Service'' (incorporated by 
reference, see Sec.  192.7).
ASTM A333/A333M--Steel pipe, ``Standard Specification for Seamless and 
Welded Steel Pipe for Low Temperature Service'' (incorporated by 
reference, see Sec.  192.7).
ASTM A381--Steel pipe, ``Standard Specification for Metal-Arc-Welded 
Steel Pipe for Use with High-Pressure Transmission Systems'' 
(incorporated by reference, see Sec.  192.7).
ASTM A671/A671M--Steel pipe, ``Standard Specification for Electric-
Fusion-Welded Pipe for Atmospheric and Lower Temperatures'' 
(incorporated by reference, see Sec.  192.7).
ASTM A672/A672M-09--Steel pipe, ``Standard Specification for Electric-
Fusion-Welded Steel Pipe for High-Pressure Service at Moderate 
Temperatures'' (incorporated by reference, see Sec.  192.7).
ASTM A691/A691M-09--Steel pipe, ``Standard Specification for Carbon and 
Alloy Steel Pipe, Electric-Fusion-Welded for High Pressure Service at 
High Temperatures'' (incorporated by reference, see Sec.  192.7).
ASTM D2513``Standard Specification for Polyethylene (PE) Gas Pressure 
Pipe, Tubing, and Fittings'' (incorporated by reference, see Sec.  
192.7).
ASTM D 2517-00--Thermosetting plastic pipe and tubing, ``Standard 
Specification for Reinforced Epoxy Resin Gas Pressure Pipe and 
Fittings'' (incorporated by reference, see Sec.  192.7).
ASTM F2785-12 ``Standard Specification for Polyamide 12 Gas Pressure 
Pipe, Tubing, and Fittings'' (PA-12) (incorporated by reference, see 
Sec.  192.7).
ASTM F2817-10 ``Standard Specification for Poly (Vinyl Chloride) (PVC) 
Gas Pressure Pipe and Fittings for Maintenance or Repair'' (incorporated 
by reference, see Sec.  192.7).
ASTM F2945-12a ``Standard Specification for Polyamide 11 Gas Pressure 
Pipe, Tubing, and Fittings'' (PA-11) (incorporated by reference, see 
Sec.  192.7).

              B. Other Listed Specifications for Components

ASME B16.40-2008 ``Manually Operated Thermoplastic Gas Shutoffs and 
Valves in Gas Distribution Systems'' (incorporated by reference, see 
Sec.  192.7).
ASTM D2513-Standard Specification for Polyethylene (PE) Gas Pressure 
Pipe, Tubing, and Fittings'' (incorporated by reference, see Sec.  
192.7).
ASTM D 2517-00--Thermosetting plastic pipe and tubing, ``Standard 
Specification for Reinforced Epoxy Resin Gas Pressure Pipe and 
Fittings'' (incorporated by reference, see Sec.  192.7).
ASTM F2785-12 ``Standard Specification for Polyamide 12 Gas Pressure 
Pipe, Tubing, and Fittings'' (PA-12) (incorporated by reference, see 
Sec.  192.7).
ASTM F2945-12a ``Standard Specification for Polyamide 11 Gas Pressure 
Pipe, Tubing, and Fittings'' (PA-11) (incorporated by reference, see 
Sec.  192.7).
ASTM F1055-98 (2006) ``Standard Specification for Electrofusion Type 
Polyethylene Fittings for Outside Diameter Controlled Polyethylene Pipe 
and Tubing'' (incorporated by reference, see Sec.  192.7).
ASTM F1924-12 ``Standard Specification for Plastic Mechanical Fittings 
for Use on Outside Diameter Controlled Polyethylene Gas Distribution 
Pipe and Tubing'' (incorporated by reference, see Sec.  192.7).
ASTM F1948-12 ``Standard Specification for Metallic Mechanical Fittings 
for Use on Outside Diameter Controlled Thermoplastic Gas Distribution 
Pipe and Tubing'' (incorporated by reference, see Sec.  192.7).
ASTM F1973-13 ``Standard Specification for Factory Assembled Anodeless 
Risers and Transition Fittings in Polyethylene (PE) and Polyamide 11 (PA 
11) and Polyamide 12 (PA 12) Fuel Gas Distribution Systems'' 
(incorporated by reference, see Sec.  192.7).
ASTM F 2600-09 ``Standard Specification for Electrofusion Type 
Polyamide-11 Fittings for Outside Diameter Controlled Polyamide-11 Pipe 
and Tubing'' (incorporated by reference, see Sec.  192.7).
ASTM F2145-13 ``Standard Specification for Polyamide 11 (PA 11) and 
Polyamide 12 (PA12) Mechanical Fittings for Use on Outside Diameter 
Controlled Polyamide 11 and Polyamide 12 Pipe and Tubing'' (incorporated 
by reference, see Sec.  192.7).
ASTM F2767-12 ``Specification for Electrofusion Type Polyamide-12 
Fittings for Outside Diameter Controlled Polyamide-12 Pipe and Tubing 
for Gas Distribution'' (incorporated by reference, see Sec.  192.7).
ASTM F2817-10 ``Standard Specification for Poly (Vinyl Chloride) (PVC) 
Gas Pressure Pipe and Fittings for Maintenance or Repair'' (incorporated 
by reference, see Sec.  192.7).

[[Page 585]]

    II. Steel pipe of unknown or unlisted specification.
    A. Bending Properties. For pipe 2 inches (51 millimeters) or less in 
diameter, a length of pipe must be cold bent through at least 90 degrees 
around a cylindrical mandrel that has a diameter 12 times the diameter 
of the pipe, without developing cracks at any portion and without 
opening the longitudinal weld.
    For pipe more than 2 inches (51 millimeters) in diameter, the pipe 
must meet the requirements of the flattening tests set forth in ASTM 
A53/A53M (incorporated by reference, see Sec.  192.7), except that the 
number of tests must be at least equal to the minimum required in 
paragraph II-D of this appendix to determine yield strength.
    B. Weldability. A girth weld must be made in the pipe by a welder 
who is qualified under subpart E of this part. The weld must be made 
under the most severe conditions under which welding will be allowed in 
the field and by means of the same procedure that will be used in the 
field. On pipe more than 4 inches (102 millimeters) in diameter, at 
least one test weld must be made for each 100 lengths of pipe. On pipe 4 
inches (102 millimeters) or less in diameter, at least one test weld 
must be made for each 400 lengths of pipe. The weld must be tested in 
accordance with API Standard 1104 (incorporated by reference, see Sec.  
192.7). If the requirements of API Standard 1104 cannot be met, 
weldability may be established by making chemical tests for carbon and 
manganese, and proceeding in accordance with section IX of the ASME 
Boiler and Pressure Vessel Code (ibr, see 192.7). The same number of 
chemical tests must be made as are required for testing a girth weld.
    C. Inspection. The pipe must be clean enough to permit adequate 
inspection. It must be visually inspected to ensure that it is 
reasonably round and straight and there are no defects which might 
impair the strength or tightness of the pipe.
    D. Tensile Properties. If the tensile properties of the pipe are not 
known, the minimum yield strength may be taken as 24,000 p.s.i. (165 
MPa) or less, or the tensile properties may be established by performing 
tensile tests as set forth in API Specification 5L (incorporated by 
reference, see Sec.  192.7). All test specimens shall be selected at 
random and the following number of tests must be performed:

                   Number of Tensile Tests--All Sizes
------------------------------------------------------------------------
 
------------------------------------------------------------------------
10 lengths or less........................  1 set of tests for each
                                             length.
11 to 100 lengths.........................  1 set of tests for each 5
                                             lengths, but not less than
                                             10 tests.
Over 100 lengths..........................  1 set of tests for each 10
                                             lengths, but not less than
                                             20 tests.
------------------------------------------------------------------------

If the yield-tensile ratio, based on the properties determined by those 
tests, exceeds 0.85, the pipe may be used only as provided in Sec.  
192.55(c).
    III. Steel pipe manufactured before November 12, 1970, to earlier 
editions of listed specifications. Steel pipe manufactured before 
November 12, 1970, in accordance with a specification of which a later 
edition is listed in section I of this appendix, is qualified for use 
under this part if the following requirements are met:
    A. Inspection. The pipe must be clean enough to permit adequate 
inspection. It must be visually inspected to ensure that it is 
reasonably round and straight and that there are no defects which might 
impair the strength or tightness of the pipe.
    B. Similarity of specification requirements. The edition of the 
listed specification under which the pipe was manufactured must have 
substantially the same requirements with respect to the following 
properties as a later edition of that specification listed in section I 
of this appendix:
    (1) Physical (mechanical) properties of pipe, including yield and 
tensile strength, elongation, and yield to tensile ratio, and testing 
requirements to verify those properties.
    (2) Chemical properties of pipe and testing requirements to verify 
those properties.
    C. Inspection or test of welded pipe. On pipe with welded seams, one 
of the following requirements must be met:
    (1) The edition of the listed specification to which the pipe was 
manufactured must have substantially the same requirements with respect 
to nondestructive inspection of welded seams and the standards for 
acceptance or rejection and repair as a later edition of the 
specification listed in section I of this appendix.
    (2) The pipe must be tested in accordance with subpart J of this 
part to at least 1.25 times the maximum allowable operating pressure if 
it is to be installed in a class 1 location and to at least 1.5 times 
the maximum allowable operating pressure if it is to be installed in a 
class 2, 3, or 4 location. Notwithstanding any shorter time period 
permitted under subpart J of this part, the test pressure must be 
maintained for at least 8 hours.

[35 FR 13257, Aug. 19, 1970]

    Editorial Note: For Federal Register citations affecting appendix B 
to part 192, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.govinfo.gov.

[[Page 586]]



  Sec. Appendix C to Part 192--Qualification of Welders for Low Stress 
                               Level Pipe

    I. Basic test. The test is made on pipe 12 inches (305 millimeters) 
or less in diameter. The test weld must be made with the pipe in a 
horizontal fixed position so that the test weld includes at least one 
section of overhead position welding. The beveling, root opening, and 
other details must conform to the specifications of the procedure under 
which the welder is being qualified. Upon completion, the test weld is 
cut into four coupons and subjected to a root bend test. If, as a result 
of this test, two or more of the four coupons develop a crack in the 
weld material, or between the weld material and base metal, that is more 
than \1/8\-inch (3.2 millimeters) long in any direction, the weld is 
unacceptable. Cracks that occur on the corner of the specimen during 
testing are not considered. A welder who successfully passes a butt-weld 
qualification test under this section shall be qualified to weld on all 
pipe diameters less than or equal to 12 inches.
    II. Additional tests for welders of service line connections to 
mains. A service line connection fitting is welded to a pipe section 
with the same diameter as a typical main. The weld is made in the same 
position as it is made in the field. The weld is unacceptable if it 
shows a serious undercutting or if it has rolled edges. The weld is 
tested by attempting to break the fitting off the run pipe. The weld is 
unacceptable if it breaks and shows incomplete fusion, overlap, or poor 
penetration at the junction of the fitting and run pipe.
    III. Periodic tests for welders of small service lines. Two samples 
of the welder's work, each about 8 inches (203 millimeters) long with 
the weld located approximately in the center, are cut from steel service 
line and tested as follows:
    (1) One sample is centered in a guided bend testing machine and bent 
to the contour of the die for a distance of 2 inches (51 millimeters) on 
each side of the weld. If the sample shows any breaks or cracks after 
removal from the bending machine, it is unacceptable.
    (2) The ends of the second sample are flattened and the entire joint 
subjected to a tensile strength test. If failure occurs adjacent to or 
in the weld metal, the weld is unacceptable. If a tensile strength 
testing machine is not available, this sample must also pass the bending 
test prescribed in subparagraph (1) of this paragraph.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37504, 
July 13, 1998; Amdt. 192-94, 69 FR 32896, June 14, 2004]



   Sec. Appendix D to Part 192--Criteria for Cathodic Protection and 
                      Determination of Measurements

    I. Criteria for cathodic protection-- A. Steel, cast iron, and 
ductile iron structures. (1) A negative (cathodic) voltage of at least 
0.85 volt, with reference to a saturated copper-copper sulfate half 
cell. Determination of this voltage must be made with the protective 
current applied, and in accordance with sections II and IV of this 
appendix.
    (2) A negative (cathodic) voltage shift of at least 300 millivolts. 
Determination of this voltage shift must be made with the protective 
current applied, and in accordance with sections II and IV of this 
appendix. This criterion of voltage shift applies to structures not in 
contact with metals of different anodic potentials.
    (3) A minimum negative (cathodic) polarization voltage shift of 100 
millivolts. This polarization voltage shift must be determined in 
accordance with sections III and IV of this appendix.
    (4) A voltage at least as negative (cathodic) as that originally 
established at the beginning of the Tafel segment of the E-log-I curve. 
This voltage must be measured in accordance with section IV of this 
appendix.
    (5) A net protective current from the electrolyte into the structure 
surface as measured by an earth current technique applied at 
predetermined current discharge (anodic) points of the structure.
    B. Aluminum structures. (1) Except as provided in paragraphs (3) and 
(4) of this paragraph, a minimum negative (cathodic) voltage shift of 
150 millivolts, produced by the application of protective current. The 
voltage shift must be determined in accordance with sections II and IV 
of this appendix.
    (2) Except as provided in paragraphs (3) and (4) of this paragraph, 
a minimum negative (cathodic) polarization voltage shift of 100 
millivolts. This polarization voltage shift must be determined in 
accordance with sections III and IV of this appendix.
    (3) Notwithstanding the alternative minimum criteria in paragraphs 
(1) and (2) of this paragraph, aluminum, if cathodically protected at 
voltages in excess of 1.20 volts as measured with reference to a copper-
copper sulfate half cell, in accordance with section IV of this 
appendix, and compensated for the voltage (IR) drops other than those 
across the structure-electrolyte boundary may suffer corrosion resulting 
from the build-up of alkali on the metal surface. A voltage in excess of 
1.20 volts may not be used unless previous test results indicate no 
appreciable corrosion will occur in the particular environment.
    (4) Since aluminum may suffer from corrosion under high pH 
conditions, and since application of cathodic protection tends to 
increase the pH at the metal surface, careful

[[Page 587]]

investigation or testing must be made before applying cathodic 
protection to stop pitting attack on aluminum structures in environments 
with a natural pH in excess of 8.
    C. Copper structures. A minimum negative (cathodic) polarization 
voltage shift of 100 millivolts. This polarization voltage shift must be 
determined in accordance with sections III and IV of this appendix.
    D. Metals of different anodic potentials. A negative (cathodic) 
voltage, measured in accordance with section IV of this appendix, equal 
to that required for the most anodic metal in the system must be 
maintained. If amphoteric structures are involved that could be damaged 
by high alkalinity covered by paragraphs (3) and (4) of paragraph B of 
this section, they must be electrically isolated with insulating 
flanges, or the equivalent.
    II. Interpretation of voltage measurement. Voltage (IR) drops other 
than those across the structure-electrolyte boundary must be considered 
for valid interpretation of the voltage measurement in paragraphs A(1) 
and (2) and paragraph B(1) of section I of this appendix.
    III. Determination of polarization voltage shift. The polarization 
voltage shift must be determined by interrupting the protective current 
and measuring the polarization decay. When the current is initially 
interrupted, an immediate voltage shift occurs. The voltage reading 
after the immediate shift must be used as the base reading from which to 
measure polarization decay in paragraphs A(3), B(2), and C of section I 
of this appendix.
    IV. Reference half cells. A. Except as provided in paragraphs B and 
C of this section, negative (cathodic) voltage must be measured between 
the structure surface and a saturated copper-copper sulfate half cell 
contacting the electrolyte.
    B. Other standard reference half cells may be substituted for the 
saturated cooper-copper sulfate half cell. Two commonly used reference 
half cells are listed below along with their voltage equivalent to -0.85 
volt as referred to a saturated copper-copper sulfate half cell:
    (1) Saturated KCl calomel half cell: -0.78 volt.
    (2) Silver-silver chloride half cell used in sea water: -0.80 volt.
    C. In addition to the standard reference half cells, an alternate 
metallic material or structure may be used in place of the saturated 
copper-copper sulfate half cell if its potential stability is assured 
and if its voltage equivalent referred to a saturated copper-copper 
sulfate half cell is established.

[Amdt. 192-4, 36 FR 12305, June 30, 1971]



 Sec. Appendix E to Part 192--Guidance on Determining High Consequence 
 Areas and on Carrying out Requirements in the Integrity Management Rule

           I. Guidance on Determining a High Consequence Area

    To determine which segments of an operator's transmission pipeline 
system are covered for purposes of the integrity management program 
requirements, an operator must identify the high consequence areas. An 
operator must use method (1) or (2) from the definition in Sec.  192.903 
to identify a high consequence area. An operator may apply one method to 
its entire pipeline system, or an operator may apply one method to 
individual portions of the pipeline system. (Refer to figure E.I.A for a 
diagram of a high consequence area).

[[Page 588]]

[GRAPHIC] [TIFF OMITTED] TR06AP04.003

    II. Guidance on Assessment Methods and Additional Preventive and 
             Mitigative Measures for Transmission Pipelines

    (a) Table E.II.1 gives guidance to help an operator implement 
requirements on additional preventive and mitigative measures for 
addressing time dependent and independent threats for a transmission 
pipeline operating below 30% SMYS not in an HCA (i.e. outside of 
potential impact circle) but located within a Class 3 or Class 4 
Location.
    (b) Table E.II.2 gives guidance to help an operator implement 
requirements on assessment methods for addressing time dependent and 
independent threats for a transmission pipeline in an HCA.
    (c) Table E.II.3 gives guidance on preventative & mitigative 
measures addressing time

[[Page 589]]

dependent and independent threats for transmission pipelines that 
operate below 30% SMYS, in HCAs.
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[GRAPHIC] [TIFF OMITTED] TR06AP04.010


[[Page 596]]



[Amdt. 192-95, 69 FR 18234, Apr. 6, 2004, as amended by Amdt. 192-95, 
May 26, 2004]



     Sec. Appendix F to Part 192--Criteria for Conducting Integrity 
         Assessments Using Guided Wave Ultrasonic Testing (GWUT)

    This appendix defines criteria which must be properly implemented 
for use of guided wave ultrasonic testing (GWUT) as an integrity 
assessment method. Any application of GWUT that does not conform to 
these criteria is considered ``other technology'' as described by 
Sec. Sec.  192.710(c)(7), 192.921(a)(7), and 192.937(c)(7), for which 
OPS must be notified 90 days prior to use in accordance with Sec. Sec.  
192.921(a)(7) or 192.937(c)(7). GWUT in the ``Go-No Go'' mode means that 
all indications (wall loss anomalies) above the testing threshold (a 
maximum of 5% of cross sectional area (CSA) sensitivity) be directly 
examined, in-line tool inspected, pressure tested, or replaced prior to 
completing the integrity assessment on the carrier pipe.
    I. Equipment and Software: Generation. The equipment and the 
computer software used are critical to the success of the inspection. 
Computer software for the inspection equipment must be reviewed and 
updated, as required, on an annual basis, with intervals not to exceed 
15 months, to support sensors, enhance functionality, and resolve any 
technical or operational issues identified.
    II. Inspection Range. The inspection range and sensitivity are set 
by the signal to noise (S/N) ratio but must still keep the maximum 
threshold sensitivity at 5% cross sectional area (CSA). A signal that 
has an amplitude that is at least twice the noise level can be reliably 
interpreted. The greater the S/N ratio the easier it is to identify and 
interpret signals from small changes. The signal to noise ratio is 
dependent on several variables such as surface roughness, coating, 
coating condition, associated pipe fittings (T's, elbows, flanges), soil 
compaction, and environment. Each of these affects the propagation of 
sound waves and influences the range of the test. It may be necessary to 
inspect from both ends of the pipeline segment to achieve a full 
inspection. In general, the inspection range can approach 60 to 100 feet 
for a 5% CSA, depending on field conditions.
    III. Complete Pipe Inspection. To ensure that the entire pipeline 
segment is assessed there should be at least a 2 to 1 signal to noise 
ratio across the entire pipeline segment that is inspected. This may 
require multiple GWUT shots. Double-ended inspections are expected. 
These two inspections are to be overlaid to show the minimum 2 to 1 S/N 
ratio is met in the middle. If possible, show the same near or midpoint 
feature from both sides and show an approximate 5% distance overlap.
    IV. Sensitivity. The detection sensitivity threshold determines the 
ability to identify a cross sectional change. The maximum threshold 
sensitivity cannot be greater than 5% of the cross sectional area (CSA).
    The locations and estimated CSA of all metal loss features in excess 
of the detection threshold must be determined and documented.
    All defect indications in the ``Go-No Go'' mode above the 5% testing 
threshold must be directly examined, in-line inspected, pressure tested, 
or replaced prior to completing the integrity assessment.
    V. Wave Frequency. Because a single wave frequency may not detect 
certain defects, a minimum of three frequencies must be run for each 
inspection to determine the best frequency for characterizing 
indications. The frequencies used for the inspections must be documented 
and must be in the range specified by the manufacturer of the equipment.
    VI. Signal or Wave Type: Torsional and Longitudinal. Both torsional 
and longitudinal waves must be used and use must be documented.
    VII. Distance Amplitude Correction (DAC) Curve and Weld Calibration. 
The distance amplitude correction curve accounts for coating, pipe 
diameter, pipe wall and environmental conditions at the assessment 
location. The DAC curve must be set for each inspection as part of 
establishing the effective range of a GWUT inspection. DAC curves 
provide a means for evaluating the cross-sectional area change of 
reflections at various distances in the test range by assessing signal 
to noise ratio. A DAC curve is a means of taking apparent attenuation 
into account along the time base of a test signal. It is a line of equal 
sensitivity along the trace which allows the amplitudes of signals at 
different axial distances from the collar to be compared.
    VIII. Dead Zone. The dead zone is the area adjacent to the collar in 
which the transmitted signal blinds the received signal, making it 
impossible to obtain reliable results. Because the entire line must be 
inspected, inspection procedures must account for the dead zone by 
requiring the movement of the collar for additional inspections. An 
alternate method of obtaining valid readings in the dead zone is to use 
B-scan ultrasonic equipment and visual examination of the external 
surface. The length of the dead zone and the near field for each 
inspection must be documented.
    IX. Near Field Effects. The near field is the region beyond the dead 
zone where the receiving amplifiers are increasing in power, before the 
wave is properly established. Because the entire line must be inspected, 
inspection procedures must account for the near field by requiring the 
movement of the collar for additional inspections. An alternate method 
of obtaining valid readings in

[[Page 597]]

the near field is to use B-scan ultrasonic equipment and visual 
examination of the external surface. The length of the dead zone and the 
near field for each inspection must be documented.
    X. Coating Type. Coatings can have the effect of attenuating the 
signal. Their thickness and condition are the primary factors that 
affect the rate of signal attenuation. Due to their variability, 
coatings make it difficult to predict the effective inspection distance. 
Several coating types may affect the GWUT results to the point that they 
may reduce the expected inspection distance. For example, concrete 
coated pipe may be problematic when well bonded due to the attenuation 
effects. If an inspection is done and the required sensitivity is not 
achieved for the entire length of the pipe, then another type of 
assessment method must be utilized.
    XI. End Seal. When assessing cased carrier pipe with GWUT, operators 
must remove the end seal from the casing at each GWUT test location to 
facilitate visual inspection. Operators must remove debris and water 
from the casing at the end seals. Any corrosion material observed must 
be removed, collected and reviewed by the operator's corrosion 
technician. The end seal does not interfere with the accuracy of the 
GWUT inspection but may have a dampening effect on the range.
    XII. Weld Calibration to set DAC Curve. Accessible welds, along or 
outside the pipeline segment to be inspected, must be used to set the 
DAC curve. A weld or welds in the access hole (secondary area) may be 
used if welds along the pipeline segment are not accessible. In order to 
use these welds in the secondary area, sufficient distance must be 
allowed to account for the dead zone and near field. There must not be a 
weld between the transducer collar and the calibration weld. A 
conservative estimate of the predicted amplitude for the weld is 25% CSA 
(cross sectional area) and can be used if welds are not accessible. 
Calibrations (setting of the DAC curve) should be on pipe with similar 
properties such as wall thickness and coating. If the actual weld cap 
height is different from the assumed weld cap height, the estimated CSA 
may be inaccurate and adjustments to the DAC curve may be required. 
Alternative means of calibration can be used if justified by a 
documented engineering analysis and evaluation.
    XIII. Validation of Operator Training. Pipeline operators must 
require all guided wave service providers to have equipment-specific 
training and experience for all GWUT Equipment Operators which includes 
training for:
    A. Equipment operation,
    B. field data collection, and
    C. data interpretation on cased and buried pipe.
    Only individuals who have been qualified by the manufacturer or an 
independently assessed evaluation procedure similar to ISO 9712 
(Sections: 5 Responsibilities; 6 Levels of Qualification; 7 Eligibility; 
and 10 Certification), as specified above, may operate the equipment. A 
senior-level GWUT equipment operator with pipeline specific experience 
must provide onsite oversight of the inspection and approve the final 
reports. A senior-level GWUT equipment operator must have additional 
training and experience, including training specific to cased and buried 
pipe, with a quality control program which that conforms to Section 12 
of ASME B31.8S (for availability, see Sec.  192.7).
    XIV. Training and Experience Minimums for Senior Level GWUT 
Equipment Operators:
     Equipment Manufacturer's minimum qualification 
for equipment operation and data collection with specific endorsements 
for casings and buried pipe
     Training, qualification and experience in testing 
procedures and frequency determination
     Training, qualification and experience in 
conversion of guided wave data into pipe features and estimated metal 
loss (estimated cross-sectional area loss and circumferential extent)
     Equipment Manufacturer's minimum qualification 
with specific endorsements for data interpretation of anomaly features 
for pipe within casings and buried pipe.
    XV. Equipment: Traceable from vendor to inspection company. An 
operator must maintain documentation of the version of the GWUT software 
used and the serial number of the other equipment such as collars, 
cables, etc., in the report.
    XVI. Calibration Onsite. The GWUT equipment must be calibrated for 
performance in accordance with the manufacturer's requirements and 
specifications, including the frequency of calibrations. A diagnostic 
check and system check must be performed on-site each time the equipment 
is relocated to a different casing or pipeline segment. If on-site 
diagnostics show a discrepancy with the manufacturer's requirements and 
specifications, testing must cease until the equipment can be restored 
to manufacturer's specifications.
    XVII. Use on Shorted Casings (direct or electrolytic). GWUT may not 
be used to assess shorted casings. GWUT operators must have operations 
and maintenance procedures (see Sec.  192.605) to address the effect of 
shorted casings on the GWUT signal. The equipment operator must clear 
any evidence of interference, other than some slight dampening of the 
GWUT signal from the shorted casing, according to their operating and 
maintenance procedures. All shorted casings found while conducting GWUT 
inspections must be addressed by the operator's standard operating 
procedures.
    XVIII. Direct examination of all indications above the detection 
sensitivity threshold. The

[[Page 598]]

use of GWUT in the ``Go-No Go'' mode requires that all indications (wall 
loss anomalies) above the testing threshold (5% of CSA sensitivity) be 
directly examined (or replaced) prior to completing the integrity 
assessment on the cased carrier pipe or other GWUT application. If this 
cannot be accomplished, then alternative methods of assessment (such as 
hydrostatic pressure tests or ILI) must be utilized.
    XIV. Timing of direct examination of all indications above the 
detection sensitivity threshold. Operators must either replace or 
conduct direct examinations of all indications identified above the 
detection sensitivity threshold according to the table below. Operators 
must conduct leak surveys and reduce operating pressure as specified 
until the pipe is replaced or direct examinations are completed.

[[Page 599]]



                                      Required Response to GWUT Indications
----------------------------------------------------------------------------------------------------------------
                                      Operating pressure   Operating pressure over 30
          GWUT criterion            less than or equal to   and less than or equal to   Operating pressure over
                                           30% SMYS                 50% SMYS                    50% SMYS
----------------------------------------------------------------------------------------------------------------
Over the detection sensitivity      Replace or direct      Replace or direct           Replace or direct
 threshold (maximum of 5% CSA).      examination within     examination within 6        examination within 6
                                     12 months, and         months, instrumented leak   months, instrumented
                                     instrumented leak      survey once every 30        leak survey once every
                                     survey once every 30   calendar days, and          30 calendar days, and
                                     calendar days.         maintain MAOP below the     reduce MAOP to 80% of
                                                            operating pressure at       operating pressure at
                                                            time of discovery.          time of discovery.
----------------------------------------------------------------------------------------------------------------


[[Page 600]]


[Amdt. 192-125, 84 FR 52255, Oct. 1, 2019]



PART 193_LIQUEFIED NATURAL GAS FACILITIES: FEDERAL SAFETY   
             STANDARDS--Table of Contents



                            Subpart A_General

Sec.
193.2001 Scope of part.
193.2003 [Reserved]
193.2005 Applicability.
193.2007 Definitions.
193.2009 Rules of regulatory construction.
193.2011 Reporting.
193.2013 What documents are incorporated by reference partly or wholly 
          in this part?
193.2015 [Reserved]
193.2017 Plans and procedures.
193.2019 Mobile and temporary LNG facilities.

                      Subpart B_Siting Requirements

193.2051 Scope.
193.2055 [Reserved]
193.2057 Thermal radiation protection.
193.2059 Flammable vapor-gas dispersion protection.
193.2061-193.2065 [Reserved]
193.2067 Wind forces.
193.2069-193.2073 [Reserved]

                            Subpart C_Design

193.2101 Scope.

                                Materials

193.2103-193.2117 [Reserved]
193.2119 Records.

                   Design of Components and Buildings

193.2121-193.2153 [Reserved]

                     Impoundment Design and Capacity

193.2155 Structural requirements.
193.2157-193.2159 [Reserved]
193.2161 Dikes, general.
193.2163-193.2165 [Reserved]
193.2167 Covered systems.
193.2169-193.2171 [Reserved]
193.2173 Water removal.
193.2175-193.2179 [Reserved]
193.2181 Impoundment capacity: LNG storage tanks.
193.2183-193.2185 [Reserved]

                            LNG Storage Tanks

193.2187 Nonmetallic membrane liner.
193.2189-193.2233 [Reserved]

                         Subpart D_Construction

193.2301 Scope.
193.2303 Construction acceptance.
193.2304 Corrosion control overview.
193.2305-193.2319 [Reserved]
193.2321 Nondestructive tests.
193.2323-193.2329 [Reserved]

                           Subpart E_Equipment

193.2401 Scope.

                         Vaporization Equipment

193.2403-193.2439 [Reserved]
193.2441 Control center.
193.2443 [Reserved]
193.2445 Sources of power.

                          Subpart F_Operations

193.2501 Scope.
193.2503 Operating procedures.
193.2505 Cooldown.
193.2507 Monitoring operations.
193.2509 Emergency procedures.
193.2511 Personnel safety.
193.2513 Transfer procedures.
193.2515 Investigations of failures.
193.2517 Purging.
193.2519 Communication systems.
193.2521 Operating records.

                          Subpart G_Maintenance

193.2601 Scope.
193.2603 General.
193.2605 Maintenance procedures.
193.2607 Foreign material.
193.2609 Support systems.
193.2611 Fire protection.
193.2613 Auxiliary power sources.
193.2615 Isolating and purging.
193.2617 Repairs.
193.2619 Control systems.
193.2621 Testing transfer hoses.
193.2623 Inspecting LNG storage tanks.
193.2625 Corrosion protection.
193.2627 Atmospheric corrosion control.
193.2629 External corrosion control: buried or submerged components.
193.2631 Internal corrosion control.
193.2633 Interference currents.
193.2635 Monitoring corrosion control.
193.2637 Remedial measures.
193.2639 Maintenance records.

             Subpart H_Personnel Qualifications and Training

193.2701 Scope.
193.2703 Design and fabrication.
193.2705 Construction, installation, inspection, and testing.
193.2707 Operations and maintenance.
193.2709 Security.
193.2711 Personnel health.
193.2713 Training: operations and maintenance.
193.2715 Training: security.
193.2717 Training: fire protection.

[[Page 601]]

193.2719 Training: records.

                        Subpart I_Fire Protection

193.2801 Fire protection.
193.2803-193.2821 [Reserved]

                           Subpart J_Security

193.2901 Scope.
193.2903 Security procedures.
193.2905 Protective enclosures.
193.2907 Protective enclosure construction.
193.2909 Security communications.
193.2911 Security lighting.
193.2913 Security monitoring.
193.2915 Alternative power sources.
193.2917 Warning signs.

    Authority: 49 U.S.C. 5103, 60102, 60103, 60104, 60108, 60109, 60110, 
60113, 60118; and 49 CFR 1.53.

    Source: 45 FR 9203, Feb. 11, 1980, unless otherwise noted.

    Editorial Note: Nomenclature changes to part 193 appear at 71 FR 
33408, June 9, 2006.



                            Subpart A_General



Sec.  193.2001  Scope of part.

    (a) This part prescribes safety standards for LNG facilities used in 
the transportation of gas by pipeline that is subject to the pipeline 
safety laws (49 U.S.C. 60101 et seq.) and Part 192 of this chapter.
    (b) This part does not apply to:
    (1) LNG facilities used by ultimate consumers of LNG or natural gas.
    (2) LNG facilities used in the course of natural gas treatment or 
hydrocarbon extraction which do not store LNG.
    (3) In the case of a marine cargo transfer system and associated 
facilities, any matter other than siting pertaining to the system or 
facilities between the marine vessel and the last manifold (or in the 
absence of a manifold, the last valve) located immediately before a 
storage tank.
    (4) Any LNG facility located in navigable waters (as defined in 
Section 3(8) of the Federal Power Act (16 U.S.C. 796(8)).

[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-1, 45 FR 57418, Aug. 
28, 1980; Amdt. 193-10, 61 FR 18517, Apr. 26, 1996]



Sec.  193.2003  [Reserved]



Sec.  193.2005  Applicability.

    (a) Regulations in this part governing siting, design, installation, 
or construction of LNG facilities (including material incorporated by 
reference in these regulations) do not apply to LNG facilities in 
existence or under construction when the regulations go into effect.
    (b) If an existing LNG facility (or facility under construction 
before March 31, 2000 is replaced, relocated or significantly altered 
after March 31, 2000, the facility must comply with the applicable 
requirements of this part governing, siting, design, installation, and 
construction, except that:
    (1) The siting requirements apply only to LNG storage tanks that are 
significantly altered by increasing the original storage capacity or 
relocated, and
    (2) To the extent compliance with the design, installation, and 
construction requirements would make the replaced, relocated, or altered 
facility incompatible with the other facilities or would otherwise be 
impractical, the replaced, relocated, or significantly altered facility 
may be designed, installed, or constructed in accordance with the 
original specifications for the facility, or in another manner subject 
to the approval of the Administrator.

[Amdt. 193-17, 65 FR 10958, Mar. 1, 2000, as amended by Amdt. 193-18, 69 
FR 11336, Mar. 10, 2004]



Sec.  193.2007  Definitions.

    As used in this part:
    Administrator means the Administrator, Pipeline and Hazardous 
Materials Safety Administration or his or her delegate.
    Ambient vaporizer means a vaporizer which derives heat from 
naturally occurring heat sources, such as the atmosphere, sea water, 
surface waters, or geothermal waters.
    Cargo transfer system means a component, or system of components 
functioning as a unit, used exclusively for transferring hazardous 
fluids in bulk between a tank car, tank truck, or marine vessel and a 
storage tank.

[[Page 602]]

    Component means any part, or system of parts functioning as a unit, 
including, but not limited to, piping, processing equipment, containers, 
control devices, impounding systems, lighting, security devices, fire 
control equipment, and communication equipment, whose integrity or 
reliability is necessary to maintain safety in controlling, processing, 
or containing a hazardous fluid.
    Container means a component other than piping that contains a 
hazardous fluid.
    Control system means a component, or system of components 
functioning as a unit, including control valves and sensing, warning, 
relief, shutdown, and other control devices, which is activated either 
manually or automatically to establish or maintain the performance of 
another component.
    Controllable emergency means an emergency where reasonable and 
prudent action can prevent harm to people or property.
    Design pressure means the pressure used in the design of components 
for the purpose of determining the minimum permissible thickness or 
physical characteristics of its various parts. When applicable, static 
head shall be included in the design pressure to determine the thickness 
of any specific part.
    Determine means make an appropriate investigation using scientific 
methods, reach a decision based on sound engineering judgment, and be 
able to demonstrate the basis of the decision.
    Dike means the perimeter of an impounding space forming a barrier to 
prevent liquid from flowing in an unintended direction.
    Emergency means a deviation from normal operation, a structural 
failure, or severe environmental conditions that probably would cause 
harm to people or property.
    Exclusion zone means an area surrounding an LNG facility in which an 
operator or government agency legally controls all activities in 
accordance with Sec.  193.2057 and Sec.  193.2059 for as long as the 
facility is in operation.
    Fail-safe means a design feature which will maintain or result in a 
safe condition in the event of malfunction or failure of a power supply, 
component, or control device.
    g means the standard acceleration of gravity of 9.806 meters per 
second\2\ (32.17 feet per second\2\).
    Gas, except when designated as inert, means natural gas, other 
flammable gas, or gas which is toxic or corrosive.
    Hazardous fluid means gas or hazardous liquid.
    Hazardous liquid means LNG or a liquid that is flammable or toxic.
    Heated vaporizer means a vaporizer which derives heat from other 
than naturally occurring heat sources.
    Impounding space means a volume of space formed by dikes and floors 
which is designed to confine a spill of hazardous liquid.
    Impounding system includes an impounding space, including dikes and 
floors for conducting the flow of spilled hazardous liquids to an 
impounding space.
    Liquefied natural gas or LNG means natural gas or synthetic gas 
having methane (CH4) as its major constituent which has been 
changed to a liquid.
    LNG facility means a pipeline facility that is used for liquefying 
natural gas or synthetic gas or transferring, storing, or vaporizing 
liquefied natural gas.
    LNG plant means an LNG facility or system of LNG facilities 
functioning as a unit.
    m\3\ means a volumetric unit which is one cubic metre, 6.2898 
barrels, 35.3147 ft.\3\, or 264.1720 U.S. gallons, each volume being 
considered as equal to the other.
    Maximum allowable working pressure means the maximum gage pressure 
permissible at the top of the equipment, containers or pressure vessels 
while operating at design temperature.
    Normal operation means functioning within ranges of pressure, 
temperature, flow, or other operating criteria required by this part.
    Operator means a person who owns or operates an LNG facility.
    Person means any individual, firm, joint venture, partnership, 
corporation, association, state, municipality, cooperative association, 
or joint stock association and includes any trustee, receiver, assignee, 
or personal representative thereof.

[[Page 603]]

    Pipeline facility means new and existing piping, rights-of-way, and 
any equipment, facility, or building used in the transportation of gas 
or in the treatment of gas during the course of transportation.
    Piping means pipe, tubing, hoses, fittings, valves, pumps, 
connections, safety devices or related components for containing the 
flow of hazardous fluids.
    Storage tank means a container for storing a hazardous fluid.
    Transfer piping means a system of permanent and temporary piping 
used for transferring hazardous fluids between any of the following: 
Liquefaction process facilities, storage tanks, vaporizers, compressors, 
cargo transfer systems, and facilities other than pipeline facilities.
    Transfer system includes transfer piping and cargo transfer system.
    Vaporization means an addition of thermal energy changing a liquid 
to a vapor or gaseous state.
    Vaporizer means a heat transfer facility designed to introduce 
thermal energy in a controlled manner for changing a liquid to a vapor 
or gaseous state.
    Waterfront LNG plant means an LNG plant with docks, wharves, piers, 
or other structures in, on, or immediately adjacent to the navigable 
waters of the United States or Puerto Rico and any shore area 
immediately adjacent to those waters to which vessels may be secured and 
at which LNG cargo operations may be conducted.

[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-1, 45 FR 57418, Aug. 
28, 1980; Amdt. 193-2, 45 FR 70404, Oct. 23, 1980; Amdt. 193-10, 61 FR 
18517, Apr. 26, 1996; Amdt. 193-17, 65 FR 10958, Mar. 1, 2000; 68 FR 
11749, Mar. 12, 2003; 70 FR 11140, Mar. 8, 2005]



Sec.  193.2009  Rules of regulatory construction.

    (a) As used in this part:
    (1) Includes means including but not limited to;
    (2) May means is permitted to or is authorized to;
    (3) May not means is not permitted to or is not authorized to; and
    (4) Shall or must is used in the mandatory and imperative sense.
    (b) In this part:
    (1) Words importing the singular include the plural; and
    (2) Words importing the plural include the singular.



Sec.  193.2011  Reporting.

    Incidents, safety-related conditions, and annual pipeline summary 
data for LNG plants or facilities must be reported in accordance with 
the requirements of Part 191 of this subchapter.

[75 FR 72906, Nov. 26, 2010]



Sec.  193.2013  What documents are incorporated by reference partly or 
wholly in this part?

    (a) This part prescribes standards, or portions thereof, 
incorporated by reference into this part with the approval of the 
Director of the Federal Register in 5 U.S.C. 552(a) and 1 CFR part 51. 
The materials listed in this section have the full force of law. To 
enforce any edition other than that specified in this section, PHMSA 
must publish a notice of change in the Federal Register.
    (1) Availability of standards incorporated by reference. All of the 
materials incorporated by reference are available for inspection from 
several sources, including the following:
    (i) The Office of Pipeline Safety, Pipeline and Hazardous Materials 
Safety Administration, 1200 New Jersey Avenue SE., Washington, DC 20590. 
For more information contact 202-366-4046 or go to the PHMSA Web site 
at: http://www.phmsa.dot.gov/pipeline/regs.
    (ii) The National Archives and Records Administration (NARA). For 
information on the availability of this material at NARA, call 202-741-
6030 or go to the NARA Web site at: http://www.archives.gov/
federal_register/code_of_federal_regulations/ibr_locations.html.
    (iii) Copies of standards incorporated by reference in this part can 
also be purchased or are otherwise made available from the respective 
standards-developing organization at the addresses provided in the 
centralized IBR section below.
    (b) American Gas Association (AGA), 400 North Capitol Street NW., 
Washington, DC 20001, and phone: 202-824-7000, Web site: http://
www.aga.org/.
    (1) American Gas Association, ``Purging Principles and Practices,''

[[Page 604]]

3rd edition, June 2001, (Purging Principles and Practices), IBR approved 
for Sec. Sec.  193.2513(b) and (c), 193.2517, and 193.2615(a).
    (2) [Reserved]
    (c) American Petroleum Institute (API), 1220 L Street NW., 
Washington, DC 20005, and phone: 202-682-8000, Web site: http://
api.org/.
    (1) API Standard 620, ``Design and Construction of Large, Welded, 
Low-pressure Storage Tanks,'' 11th edition, February 2008 (including 
addendum 1 (March 2009), addendum 2 (August 2010), and addendum 3 (March 
2012)), (API Std 620), IBR approved for Sec. Sec.  193.2101(b); 
193.2321(b).
    (2) [Reserved]
    (d) American Society of Civil Engineers (ASCE), 1801 Alexander Bell 
Drive, Reston, VA 20191, (800) 548-2723, 703 295-6300 (international), 
Web site: http://www.asce.org.
    (1) ASCE/SEI 7-05, ``Minimum Design Loads for Buildings and Other 
Structures'' 2005 edition (including supplement No. 1 and Errata), 
(ASCE/SEI 7-05), IBR approved for Sec.  193.2067(b).
    (2) [Reserved]
    (e) ASME International (ASME), Three Park Avenue, New York, NY 
10016. 800-843-2763 (U.S/Canada), Web site: http://www.asme.org/.
    (1) ASME Boiler & Pressure Vessel Code, Section VIII, Division 1: 
``Rules for Construction of Pressure Vessels,'' 2007 edition, July 1, 
2007, (ASME BPVC, Section VIII, Division 1), IBR approved for Sec.  
193.2321(a).
    (2) [Reserved]
    (f) Gas Technology Institute (GTI), formerly the Gas Research 
Institute (GRI), 1700 S. Mount Prospect Road, Des Plaines, IL 60018, 
phone: 847-768-0500, Web site: www.gastechnology.org.
    (1) GRI-96/0396.5, ``Evaluation of Mitigation Methods for Accidental 
LNG Releases, Volume 5: Using FEM3A for LNG Accident Consequence 
Analyses,'' April 1997, (GRI-96/0396.5), IBR approved for Sec.  
193.2059(a).
    (2) GTI-04/0032 LNGFIRE3: ``A Thermal Radiation Model for LNG 
Fires'' March 2004, (GTI-04/0032 LNGFIRE3), IBR approved for Sec.  
193.2057(a).
    (3) GTI-04/0049 ``LNG Vapor Dispersion Prediction with the DEGADIS 
2.1: Dense Gas Dispersion Model for LNG Vapor Dispersion,'' April 2004, 
(GTI-04/0049), IBR approved for Sec.  193.2059(a).
    (g) National Fire Protection Association (NFPA), 1 Batterymarch 
Park, Quincy, MA, 02169 phone: 617-984-7275, Web site: http://
www.nfpa.org/.
    (1) NFPA-59A (2001), ``Standard for the Production, Storage, and 
Handling of Liquefied Natural Gas (LNG),'' (NFPA-59A-2001), IBR approved 
for Sec. Sec.  193.2019(a), 193.2051, 193.2057, 193.2059 introductory 
text and (c), 193.2101(a), 193.2301, 193.2303, 193.2401, 193.2521, 
193.2639(a), and 193.2801.
    (2) NFPA 59A (2006), ``Standard for the Production, Storage, and 
Handling of Liquefied Natural Gas (LNG),'' 2006 edition, approved August 
18, 2005, (NFPA-59A-2006), IBR approved for Sec. Sec.  193.2101(b) and 
193.2321(b).

[Amdt. 193-25, 80 FR 182, Jan. 5, 2015]



Sec.  193.2015  [Reserved]



Sec.  193.2017  Plans and procedures.

    (a) Each operator shall maintain at each LNG plant the plans and 
procedures required for that plant by this part. The plans and 
procedures must be available upon request for review and inspection by 
the Administrator or any State Agency that has submitted a current 
certification or agreement with respect to the plant under the pipeline 
safety laws (49 U.S.C. 60101 et seq.). In addition, each change to the 
plans or procedures must be available at the LNG plant for review and 
inspection within 20 days after the change is made.
    (b) The Associate Administrator or the State Agency that has 
submitted a current certification under section 5(a) of the Natural Gas 
Pipeline Safety Act with respect to the pipeline facility governed by an 
operator's plans and procedures may, after notice and opportunity for 
hearing as provided in 49 CFR 190.206 or the relevant State procedures, 
require the operator to amend its plans and procedures as necessary to 
provide a reasonable level of safety.
    (c) Each operator must review and update the plans and procedures 
required by this part--
    (1) When a component is changed significantly or a new component is 
installed; and

[[Page 605]]

    (2) At intervals not exceeding 27 months, but at least once every 2 
calendar years.

[Amdt. 193-2, 45 FR 70404, Oct. 23, 1980, as amended by Amdt. 193-7, 56 
FR 31090, July 9, 1991; Amdt. 193-10, 61 FR 18517, Apr. 26, 1996; Amdt. 
193-18, 69 FR 11336, Mar. 10, 2004; Amdt. 193-24, 78 FR 58915, Sept. 25, 
2013]



Sec.  193.2019  Mobile and temporary LNG facilities.

    (a) Mobile and temporary LNG facilities for peakshaving application, 
for service maintenance during gas pipeline systems repair/alteration, 
or for other short term applications need not meet the requirements of 
this part if the facilities are in compliance with applicable sections 
of NFPA-59A-2001 (incorporated by reference, see Sec.  193.2013).
    (b) The State agency having jurisdiction over pipeline safety in the 
State in which the portable LNG equipment is to be located must be 
provided with a location description for the installation at least 2 
weeks in advance, including to the extent practical, the details of 
siting, leakage containment or control, fire fighting equipment, and 
methods employed to restrict public access, except that in the case of 
emergency where such notice is not possible, as much advance notice as 
possible must be provided.

[Amdt. 193-14, 62 FR 41311, Aug. 1, 1997, as amended by Amdt. 193-18, 69 
FR 11336, Mar. 10, 2004; Amdt. 193-25, 80 FR 182, Jan. 5, 2015]



                      Subpart B_Siting Requirements



Sec.  193.2051  Scope.

    Each LNG facility designed, constructed, replaced, relocated or 
significantly altered after March 31, 2000 must be provided with siting 
requirements in accordance with the requirements of this part and of 
NFPA 59A (incorporated by reference, see Sec.  193.2013). In the event 
of a conflict between this part and NFPA-59A-2001, this part prevails.

[Amdt. 193-17, 65 FR 10958, Mar. 1, 2000, as amended by Amdt. 193-18, 69 
FR 11336, Mar. 10, 2004; Amdt. 193-25, 80 FR 182, Jan. 5, 2015]



Sec.  193.2055  [Reserved]



Sec.  193.2057  Thermal radiation protection.

    Each LNG container and LNG transfer system must have a thermal 
exclusion zone in accordance with section 2.2.3.2 of NFPA-59A-2001 
(incorporated by reference, see Sec.  193.2013) with the following 
exceptions:
    (a) The thermal radiation distances must be calculated using Gas 
Technology Institute's (GTI) report or computer model GTI-04/0032 
LNGFIRE3: A Thermal Radiation Model for LNG Fires (incorporated by 
reference, see Sec.  193.2013). The use of other alternate models which 
take into account the same physical factors and have been validated by 
experimental test data may be permitted subject to the Administrator's 
approval.
    (b) In calculating exclusion distances, the wind speed producing the 
maximum exclusion distances shall be used except for wind speeds that 
occur less than 5 percent of the time based on recorded data for the 
area.
    (c) In calculating exclusion distances, the ambient temperature and 
relative humidity that produce the maximum exclusion distances shall be 
used except for values that occur less than five percent of the time 
based on recorded data for the area.

[Amdt. 193-17, 65 FR 10958, Mar. 1, 2000, as amended by Amdt. 193-18, 69 
FR 11336, Mar. 10, 2004; Amdt. 193-22, 75 FR 48604, Aug. 11, 2010; Amdt. 
193-25, 80 FR 182, Jan. 5, 2015]



Sec.  193.2059  Flammable vapor-gas dispersion protection.

    Each LNG container and LNG transfer system must have a dispersion 
exclusion zone in accordance with sections 2.2.3.3 and 2.2.3.4 of NFPA-
59A-2001 (incorporated by reference, see Sec.  193.2013) with the 
following exceptions:
    (a) Flammable vapor-gas dispersion distances must be determined in 
accordance with the model described in the GTI-04/0049, ``LNG Vapor 
Dispersion Prediction with the DEGADIS 2.1 Dense Gas Dispersion 
Model'''' (incorporated by reference, see Sec.  193.2013).'' 
Alternatively, in order to account for additional cloud dilution which 
may be caused by the complex flow patterns

[[Page 606]]

induced by tank and dike structure, dispersion distances may be 
calculated in accordance with the model described in the Gas Research 
Institute report GRI-96/0396.5 (incorporated by reference, see Sec.  
193.2013), ``Evaluation of Mitigation Methods for Accidental LNG 
Releases. Volume 5: Using FEM3A for LNG Accident Consequence Analyses''. 
The use of alternate models which take into account the same physical 
factors and have been validated by experimental test data shall be 
permitted, subject to the Administrator's approval.
    (b) The following dispersion parameters must be used in computing 
dispersion distances:
    (1) Average gas concentration in air = 2.5 percent.
    (2) Dispersion conditions are a combination of those which result in 
longer predicted downwind dispersion distances than other weather 
conditions at the site at least 90 percent of the time, based on figures 
maintained by National Weather Service of the U.S. Department of 
Commerce, or as an alternative where the model used gives longer 
distances at lower wind speeds, Atmospheric Stability (Pasquill Class) 
F, wind speed = 4.5 miles per hour (2.01 meters/sec) at reference height 
of 10 meters, relative humidity = 50.0 percent, and atmospheric 
temperature = average in the region.
    (3) The elevation for contour (receptor) output H = 0.5 meters.
    (4) A surface roughness factor of 0.03 meters shall be used. Higher 
values for the roughness factor may be used if it can be shown that the 
terrain both upwind and downwind of the vapor cloud has dense vegetation 
and that the vapor cloud height is more than ten times the height of the 
obstacles encountered by the vapor cloud.
    (c) The design spill shall be determined in accordance with section 
2.2.3.5 of NFPA-59A-2001 (incorporated by reference, see Sec.  
193.2013).

[Amdt. 193-17, 65 FR 10959, Mar. 1, 2000, as amended by Amdt. 193-18, 69 
FR 11336, Mar. 10, 2004; Amdt. 193-25, 80 FR 183, Jan. 5, 2015]



Sec. Sec.  193.2061-193.2065  [Reserved]



Sec.  193.2067  Wind forces.

    (a) LNG facilities must be designed to withstand without loss of 
structural or functional integrity:
    (1) The direct effect of wind forces;
    (2) The pressure differential between the interior and exterior of a 
confining, or partially confining, structure; and
    (3) In the case of impounding systems for LNG storage tanks, impact 
forces and potential penetrations by wind borne missiles.
    (b) The wind forces at the location of the specific facility must be 
based on one of the following:
    (1) For shop fabricated containers of LNG or other hazardous fluids 
with a capacity of not more than 70,000 gallons, applicable wind load 
data in ASCE/SEI 7 (incorporated by reference, see Sec.  193.2013).
    (2) For all other LNG facilities:
    (i) An assumed sustained wind velocity of not less than 150 miles 
per hour, unless the Administrator finds a lower velocity is justified 
by adequate supportive data; or
    (ii) The most critical combination of wind velocity and duration, 
with respect to the effect on the structure, having a probability of 
exceedance in a 50-year period of 0.5 percent or less, if adequate wind 
data are available and the probabilistic methodology is reliable.

[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-1, 45 FR 57419, Aug. 
28, 1980; 58 FR 14522, Mar. 18, 1993; Amdt. 193-16, 63 FR 37505, July 
13, 1998; Amdt. 193-17, 65 FR 10959, Mar. 1, 2000; Amdt. 193-19, 71 FR 
33409, June 9, 2006; Amdt. 193-22, 75 FR 48604, Aug. 11, 2010; Amdt. 
193-25, 80 FR 183, Jan. 5, 2015]



Sec. Sec.  193.2069-193.2073  [Reserved]



                            Subpart C_Design



Sec.  193.2101  Scope.

    (a) Each LNG facility designed after March 31, 2000 must comply with 
the requirements of this part and of NFPA-59A-2001 (incorporated by 
reference, see Sec.  193.2013). If there is a conflict between this Part 
and NFPA-59A-2001, the requirements in this part prevail.
    (b) Each stationary LNG storage tank must comply with Section 7.2.2 
of

[[Page 607]]

NFPA-59A-2006 (incorporated by reference, see Sec.  193.2013) for 
seismic design of field fabricated tanks. All other LNG storage tanks 
must comply with API Std-620 (incorporated by reference, see Sec.  
193.2013) for seismic design.

[Amdt. 193-25, 80 FR 183, Jan. 5, 2015]

                                Materials



Sec. Sec.  193.2103-193.2117  [Reserved]



Sec.  193.2119  Records

    Each operator shall keep a record of all materials for components, 
buildings, foundations, and support systems, as necessary to verify that 
material properties meet the requirements of this part. These records 
must be maintained for the life of the item concerned.

                   Design of Components and Buildings



Sec. Sec.  193.2121-193.2153  [Reserved]

                     Impoundment Design and Capacity



Sec.  193.2155  Structural requirements.

    (a) The structural members of an impoundment system must be designed 
and constructed to prevent impairment of the system's performance 
reliability and structural integrity as a result of the following:
    (1) The imposed loading from--
    (i) Full hydrostatic head of impounded LNG;
    (ii) Hydrodynamic action, including the effect of any material 
injected into the system for spill control;
    (iii) The impingement of the trajectory of an LNG jet discharged at 
any predictable angle; and
    (iv) Anticipated hydraulic forces from a credible opening in the 
component or item served, assuming that the discharge pressure equals 
design pressure.
    (2) The erosive action from a spill, including jetting of spilling 
LNG, and any other anticipated erosive action including surface water 
runoff, ice formation, dislodgement of ice formation, and snow removal.
    (3) The effect of the temperature, any thermal gradient, and any 
other anticipated degradation resulting from sudden or localized contact 
with LNG.
    (4) Exposure to fire from impounded LNG or from sources other than 
impounded LNG.
    (5) If applicable, the potential impact and loading on the dike due 
to--
    (i) Collapse of the component or item served or adjacent components; 
and
    (ii) If the LNG facility adjoins the right-of-way of any highway or 
railroad, collision by or explosion of a train, tank car, or tank truck 
that could reasonably be expected to cause the most severe loading.
    (b) An LNG storage tank must not be located within a horizontal 
distance of one mile (1.6 km) from the ends, or \1/4\ mile (0.4 km) from 
the nearest point of a runway, whichever is longer. The height of LNG 
structures in the vicinity of an airport must also comply with Federal 
Aviation Administration requirements in 14 CFR Section 1.1.

[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-17, 65 FR 10959, 
Mar. 1, 2000]



Sec. Sec.  193.2157-193.2159  [Reserved]



Sec.  193.2161  Dikes, general.

    An outer wall of a component served by an impounding system may not 
be used as a dike unless the outer wall is constructed of concrete.

[Amdt. 193-17, 65 FR 10959, Mar. 1, 2000]



Sec. Sec.  193.2163-193.2165  [Reserved]



Sec.  193.2167  Covered systems.

    A covered impounding system is prohibited except for concrete wall 
designed tanks where the concrete wall is an outer wall serving as a 
dike.

[Amdt. 193-17, 65 FR 10959, Mar. 1, 2000]



Sec. Sec.  193.2169-193.2171  [Reserved]



Sec.  193.2173  Water removal.

    (a) Impoundment areas must be constructed such that all areas drain 
completely to prevent water collection. Drainage pumps and piping must 
be provided to remove water from collecting in the impoundment area. 
Alternative means of draining may be acceptable subject to the 
Administrator's approval.
    (b) The water removal system must have adequate capacity to remove 
water at a rate equal to 25% of the

[[Page 608]]

maximum predictable collection rate from a storm of 10-year frequency 
and 1-hour duration, and other natural causes. For rainfall amounts, 
operators must use the ``Rainfall Frequency Atlas of the United States'' 
published by the National Weather Service of the U.S. Department of 
Commerce.
    (c) Sump pumps for water removal must--
    (1) Be operated as necessary to keep the impounding space as dry as 
practical; and
    (2) If sump pumps are designed for automatic operation, have 
redundant automatic shutdown controls to prevent operation when LNG is 
present.

[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-17, 65 FR 10959, 
Mar. 1, 2000]



Sec. Sec.  193.2175-193.2179  [Reserved]



Sec.  193.2181  Impoundment capacity: LNG storage tanks.

    Each impounding system serving an LNG storage tank must have a 
minimum volumetric liquid impoundment capacity of:
    (a) 110 percent of the LNG tank's maximum liquid capacity for an 
impoundment serving a single tank;
    (b) 100 percent of all tanks or 110 percent of the largest tank's 
maximum liquid capacity, whichever is greater, for the impoundment 
serving more than one tank; or
    (c) If the dike is designed to account for a surge in the event of 
catastrophic failure, then the impoundment capacity may be reduced to 
100 percent in lieu of 110 percent.

[Amdt. 193-17, 65 FR 10960, Mar. 1, 2000]



Sec. Sec.  193.2183-193.2185  [Reserved]

                            LNG Storage Tanks



Sec.  193.2187  Nonmetallic membrane liner.

    A flammable nonmetallic membrane liner may not be used as an inner 
container in a storage tank.

[Amdt. 193-17, 65 FR 10960, Mar. 1, 2000]



Sec. Sec.  193.2189-193.2233  [Reserved]



                         Subpart D_Construction



Sec.  193.2301  Scope.

    Each LNG facility constructed after March 31, 2000 must comply with 
requirements of this part and of NFPA-59A-2001 (incorporated by 
reference see Sec.  193.2013). In the event of a conflict between this 
part and NFPA 59A, this part prevails.

[Amdt. 193-17, 65 FR 10960, Mar. 1, 2000, as amended by Amdt. 193-18, 69 
FR 11336, Mar. 10, 2004; Amdt. 193-25, 80 FR 182, Jan. 5, 2015]



Sec.  193.2303  Construction acceptance.

    No person may place in service any component until it passes all 
applicable inspections and tests prescribed by this subpart and NFPA-
59A-2001 (incorporated by reference, see Sec.  193.2013).

[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-17, 65 FR 10960, 
Mar. 1, 2000; Amdt. 193-18, 69 FR 11337, Mar. 10, 2004; Amdt. 193-25, 80 
FR 182, Jan. 5, 2015]



Sec.  193.2304  Corrosion control overview.

    (a) Subject to paragraph (b) of this section, components may not be 
constructed, repaired, replaced, or significantly altered until a person 
qualified under Sec.  193.2707(c) reviews the applicable design drawings 
and materials specifications from a corrosion control viewpoint and 
determines that the materials involved will not impair the safety or 
reliability of the component or any associated components.
    (b) The repair, replacement, or significant alteration of components 
must be reviewed only if the action to be taken--
    (1) Involves a change in the original materials specified;
    (2) Is due to a failure caused by corrosion; or
    (3) Is occasioned by inspection revealing a significant 
deterioration of the component due to corrosion.

[Amdt. 193-2, 45 FR 70404, Oct. 23, 1980]



Sec. Sec.  193.2305-193.2319  [Reserved]



Sec.  193.2321  Nondestructive tests.

    (a) The butt welds in metal shells of storage tanks with internal 
design

[[Page 609]]

pressure above 15 psig must be nondestructively examined in accordance 
with the ASME Boiler and Pressure Vessel Code (BPVC) (Section VIII, 
Division 1)(incorporated by reference, see Sec.  193.2013), except that 
100 percent of welds that are both longitudinal (or meridional) and 
circumferential (or latitudinal) of hydraulic load bearing shells with 
curved surfaces that are subject to cryogenic temperatures must be 
nondestructively examined in accordance with the ASME BPVC (Section 
VIII, Division 1).
    (b) For storage tanks with internal design pressures at 15 psig or 
less, ultrasonic examinations of welds on metal containers must comply 
with the following:
    (1) Section 7.3.1.2 of NFPA Std-59A-2006, (incorporated by 
reference, see Sec.  193. 2013);
    (2) Appendices C and Q of API Std 620, (incorporated by reference, 
see Sec.  193.2013);
    (c) Ultrasonic examination records must be retained for the life of 
the facility. If electronic records are kept, they must be retained in a 
manner so that they cannot be altered by any means; and
    (d) The ultrasonic equipment used in the examination of welds must 
be calibrated at a frequency no longer than eight hours. Such 
calibrations must verify the examination of welds against a calibration 
standard. If the ultrasonic equipment is found to be out of calibration, 
all previous weld inspections that are suspect must be reexamined.

[Amdt. 193-22, 75 FR 48605, Aug. 11, 2010, as amended by Amdt. 193-25, 
80 FR 183, Jan. 5, 2015; 80 FR 46848, Aug. 6, 2015]



Sec. Sec.  193.2323-193.2329  [Reserved]



                           Subpart E_Equipment



Sec.  193.2401  Scope.

    After March 31, 2000, each new, replaced, relocated or significantly 
altered vaporization equipment, liquefaction equipment, and control 
systems must be designed, fabricated, and installed in accordance with 
requirements of this part and of NFPA-59A-2001. In the event of a 
conflict between this part and NFPA 59A (incorporated by reference, see 
Sec.  193.2013), this part prevails.

[Amdt. 193-17, 65 FR 10960, Mar. 1, 2000, as amended by Amdt. 193-18, 69 
FR 11337, Mar. 10, 2004; Amdt. 193-25, 80 FR 182, Jan. 5, 2015]

                         Vaporization Equipment



Sec. Sec.  193.2403-193.2439  [Reserved]



Sec.  193.2441  Control center.

    Each LNG plant must have a control center from which operations and 
warning devices are monitored as required by this part. A control center 
must have the following capabilities and characteristics:
    (a) It must be located apart or protected from other LNG facilities 
so that it is operational during a controllable emergency.
    (b) Each remotely actuated control system and each automatic 
shutdown control system required by this part must be operable from the 
control center.
    (c) Each control center must have personnel in continuous attendance 
while any of the components under its control are in operation, unless 
the control is being performed from another control center which has 
personnel in continuous attendance.
    (d) If more than one control center is located at an LNG Plant, each 
control center must have more than one means of communication with each 
other center.
    (e) Each control center must have a means of communicating a warning 
of hazardous conditions to other locations within the plant frequented 
by personnel.



Sec.  193.2443  [Reserved]



Sec.  193.2445  Sources of power.

    (a) Electrical control systems, means of communication, emergency 
lighting, and firefighting systems must have at least two sources of 
power which function so that failure of one source does not affect the 
capability of the other source.
    (b) Where auxiliary generators are used as a second source of 
electrical power:
    (1) They must be located apart or protected from components so that

[[Page 610]]

they are not unusable during a controllable emergency; and
    (2) Fuel supply must be protected from hazards.



                          Subpart F_Operations

    Source: Amdt. 193-2, 45 FR 70405, Oct. 23, 1980, unless otherwise 
noted.



Sec.  193.2501  Scope.

    This subpart prescribes requirements for the operation of LNG 
facilities.



Sec.  193.2503  Operating procedures.

    Each operator shall follow one or more manuals of written procedures 
to provide safety in normal operation and in responding to an abnormal 
operation that would affect safety. The procedures must include 
provisions for:
    (a) Monitoring components or buildings according to the requirements 
of Sec.  193.2507.
    (b) Startup and shutdown, including for initial startup, performance 
testing to demonstrate that components will operate satisfactory in 
service.
    (c) Recognizing abnormal operating conditions.
    (d) Purging and inerting components according to the requirements of 
Sec.  193.2517.
    (e) In the case of vaporization, maintaining the vaporization rate, 
temperature and pressure so that the resultant gas is within limits 
established for the vaporizer and the downstream piping.
    (f) In the case of liquefaction, maintaining temperatures, 
pressures, pressure differentials and flow rates, as applicable, within 
their design limits for:
    (1) Boilers;
    (2) Turbines and other prime movers;
    (3) Pumps, compressors, and expanders;
    (4) Purification and regeneration equipment; and
    (5) Equipment within cold boxes.
    (g) Cooldown of components according to the requirements of Sec.  
193.2505.

[Amdt. 193-2, 45 FR 70405, Oct. 23, 1980, as amended by Amdt. 193-18, 69 
FR 11337, Mar. 10, 2004]



Sec.  193.2505  Cooldown.

    (a) The cooldown of each system of components that is subjected to 
cryogenic temperatures must be limited to a rate and distribution 
pattern that keeps thermal stresses within design limits during the 
cooldown period, paying particular attention to the performance of 
expansion and contraction devices.
    (b) After cooldown stabilization is reached, cryogenic piping 
systems must be checked for leaks in areas of flanges, valves, and 
seals.



Sec.  193.2507  Monitoring operations.

    Each component in operation or building in which a hazard to persons 
or property could exist must be monitored to detect fire or any 
malfunction or flammable fluid that could cause a hazardous condition. 
Monitoring must be accomplished by watching or listening from an 
attended control center for warning alarms, such as gas, temperature, 
pressure, vacuum, and flow alarms, or by conducting an inspection or 
test at intervals specified in the operating procedures.

[Amdt, 193-2, 45 FR 70405, Oct. 23, 1980, as amended by Amdt. 193-18, 69 
FR 11337, Mar. 10, 2004]



Sec.  193.2509  Emergency procedures.

    (a) Each operator shall determine the types and places of 
emergencies other than fires that may reasonably be expected to occur at 
an LNG plant due to operating malfunctions, structural collapse, 
personnel error, forces of nature, and activities adjacent to the plant.
    (b) To adequately handle each type of emergency identified under 
paragraph (a) of this section and each fire emergency, each operator 
must follow one or more manuals of written procedures. The procedures 
must provide for the following:
    (1) Responding to controllable emergencies, including notifying 
personnel and using equipment appropriate for handling the emergency.
    (2) Recognizing an uncontrollable emergency and taking action to 
minimize harm to the public and personnel, including prompt notification 
of appropriate local officials of the emergency and possible need for 
evacuation of the public in the vicinity of the LNG plant.
    (3) Coordinating with appropriate local officials in preparation of 
an emergency evacuation plan, which sets

[[Page 611]]

forth the steps required to protect the public in the event of an 
emergency, including catastrophic failure of an LNG storage tank.
    (4) Cooperating with appropriate local officials in evacuations and 
emergencies requiring mutual assistance and keeping these officials 
advised of:
    (i) The LNG plant fire control equipment, its location, and quantity 
of units located throughout the plant;
    (ii) Potential hazards at the plant, including fires;
    (iii) Communication and emergency control capabilities at the LNG 
plant; and
    (iv) The status of each emergency.

[Amdt. 193-2, 45 FR 70405, Oct. 23, 1980, as amended by Amdt. 193-18, 69 
FR 11337, Mar. 10, 2004]



Sec.  193.2511  Personnel safety.

    (a) Each operator shall provide any special protective clothing and 
equipment necessary for the safety of personnel while they are 
performing emergency response duties.
    (b) All personnel who are normally on duty at a fixed location, such 
as a building or yard, where they could be harmed by thermal radiation 
from a burning pool of impounded liquid, must be provided a means of 
protection at that location from the harmful effects of thermal 
radiation or a means of escape.
    (c) Each LNG plant must be equipped with suitable first-aid 
material, the location of which is clearly marked and readily available 
to personnel.



Sec.  193.2513  Transfer procedures.

    (a) Each transfer of LNG or other hazardous fluid must be conducted 
in accordance with one or more manuals of written procedures to provide 
for safe transfers.
    (b) The transfer procedures must include provisions for personnel 
to:
    (1) Before transfer, verify that the transfer system is ready for 
use, with connections and controls in proper positions, including if the 
system could contain a combustible mixture, verifying that it has been 
adequately purged in accordance with a procedure which meets the 
requirements of ``Purging Principles and Practices (incorporated by 
reference, see Sec.  193.2013)'';
    (2) Before transfer, verify that each receiving container or tank 
vehicle does not contain any substance that would be incompatible with 
the incoming fluid and that there is sufficient capacity available to 
receive the amount of fluid to be transferred;
    (3) Before transfer, verify the maximum filling volume of each 
receiving container or tank vehicle to ensure that expansion of the 
incoming fluid due to warming will not result in overfilling or 
overpressure;
    (4) When making bulk transfer of LNG into a partially filled 
(excluding cooldown heel) container, determine any differences in 
temperature or specific gravity between the LNG being transferred and 
the LNG already in the container and, if necessary, provide a means to 
prevent rollover due to stratification.
    (5) Verify that the transfer operations are proceeding within design 
conditions and that overpressure or overfilling does not occur by 
monitoring applicable flow rates, liquid levels, and vapor returns.
    (6) Manually terminate the flow before overfilling or overpressure 
occurs; and
    (7) Deactivate cargo transfer systems in a safe manner by 
depressurizing, venting, and disconnecting lines and conducting any 
other appropriate operations.
    (c) In addition to the requirements of paragraph (b) of this 
section, the procedures for cargo transfer must be located at the 
transfer area and include provisions for personnel to:
    (1) Be in constant attendance during all cargo transfer operations;
    (2) Prohibit the backing of tank trucks in the transfer area, except 
when a person is positioned at the rear of the truck giving instructions 
to the driver;
    (3) Before transfer, verify that:
    (i) Each tank car or tank truck complies with applicable regulations 
governing its use;
    (ii) All transfer hoses have been visually inspected for damage and 
defects;
    (iii) Each tank truck is properly immobilized with chock wheels, and 
electrically grounded; and

[[Page 612]]

    (iv) Each tank truck engine is shut off unless it is required for 
transfer operations;
    (4) Prevent a tank truck engine that is off during transfer 
operations from being restarted until the transfer lines have been 
disconnected and any released vapors have dissipated;
    (5) Prevent loading LNG into a tank car or tank truck that is not in 
exclusive LNG service or that does not contain a positive pressure if it 
is in exclusive LNG service, until after the oxygen content in the tank 
is tested and if it exceeds 2 percent by volume, purged in accordance 
with a procedure that meets the requirements of ``Purging Principles and 
Practices (incorporated by reference, see Sec.  193.2013)''.
    (6) Verify that all transfer lines have been disconnected and 
equipment cleared before the tank car or tank truck is moved from the 
transfer position; and
    (7) Verify that transfers into a pipeline system will not exceed the 
pressure or temperature limits of the system.

[Amdt. 193-2, 45 FR 70405, Oct. 23, 1980, as amended by Amdt. 193-25, 80 
FR 183, Jan. 5, 2015]



Sec.  193.2515  Investigations of failures.

    (a) Each operator shall investigate the cause of each explosion, 
fire, or LNG spill or leak which results in:
    (1) Death or injury requiring hospitalization; or
    (2) Property damage exceeding $10,000.
    (b) As a result of the investigation, appropriate action must be 
taken to minimize recurrence of the incident.
    (c) If the Administrator or relevant state agency under the pipeline 
safety laws (49 U.S.C. 60101 et seq.) investigates an incident, the 
operator involved shall make available all relevant information and 
provide reasonable assistance in conducting the investigation. Unless 
necessary to restore or maintain service, or for safety, no component 
involved in the incident may be moved from its location or otherwise 
altered until the investigation is complete or the investigating agency 
otherwise provides. Where components must be moved for operational or 
safety reasons, they must not be removed from the plant site and must be 
maintained intact to the extent practicable until the investigation is 
complete or the investigating agency otherwise provides.

[Amdt. 193-2, 45 FR 70405, Oct. 23, 1980, as amended by Amdt. 193-10, 61 
FR 18517, Apr. 26, 1996]



Sec.  193.2517  Purging.

    When necessary for safety, components that could accumulate 
significant amounts of combustible mixtures must be purged in accordance 
with a procedure which meets the provisions of the ``Purging Principles 
and Practices (incorporated by reference, see Sec.  193.2013)'' after 
being taken out of service and before being returned to service.

[Amdt. 193-2, 45 FR 70405, Oct. 23, 1980, as amended by Amdt. 193-25, 80 
FR 183, Jan. 5, 2015]



Sec.  193.2519  Communication systems.

    (a) Each LNG plant must have a primary communication system that 
provides for verbal communications between all operating personnel at 
their work stations in the LNG plant.
    (b) Each LNG plant in excess of 70,000 gallons (265,000 liters) 
storage capacity must have an emergency communication system that 
provides for verbal communications between all persons and locations 
necessary for the orderly shutdown of operating equipment and the 
operation of safety equipment in time of emergency. The emergency 
communication system must be independent of and physically separated 
from the primary communication system and the security communication 
system under Sec.  193.2909.
    (c) Each communication system required by this part must have an 
auxiliary source of power, except sound-powered equipment.

[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-16, 63 FR 37505, 
July 13, 1998]



Sec.  193.2521  Operating records.

    Each operator shall maintain a record of results of each inspection, 
test and investigation required by this subpart. For each LNG facility 
that is designed and constructed after March

[[Page 613]]

31, 2000 the operator shall also maintain related inspection, testing, 
and investigation records that NFPA-59A-2001 (incorporated by reference, 
see Sec.  193.2013) requires. Such records, whether required by this 
part or NFPA-59A-2001, must be kept for a period of not less than five 
years.

[Amdt. 193-17, 65 FR 10960, Mar. 1, 2000, as amended by Amdt. 193-18, 69 
FR 11337, Mar. 10, 2004; Amdt. 193-25, 80 FR 182, Jan. 5, 2015]



                          Subpart G_Maintenance

    Source: Amdt. 193-2, 45 FR 70407, Oct. 23, 1980, unless otherwise 
noted.



Sec.  193.2601  Scope.

    This subpart prescribes requirements for maintaining components at 
LNG plants.



Sec.  193.2603  General.

    (a) Each component in service, including its support system, must be 
maintained in a condition that is compatible with its operational or 
safety purpose by repair, replacement, or other means.
    (b) An operator may not place, return, or continue in service any 
component which is not maintained in accordance with this subpart.
    (c) Each component taken out of service must be identified in the 
records kept under Sec.  193.2639.
    (d) If a safety device is taken out of service for maintenance, the 
component being served by the device must be taken out of service unless 
the same safety function is provided by an alternate means.
    (e) If the inadvertent operation of a component taken out of service 
could cause a hazardous condition, that component must have a tag 
attached to the controls bearing the words ``do not operate'' or words 
of comparable meaning.



Sec.  193.2605  Maintenance procedures.

    (a) Each operator shall determine and perform, consistent with 
generally accepted engineering practice, the periodic inspections or 
tests needed to meet the applicable requirements of this subpart and to 
verify that components meet the maintenance standards prescribed by this 
subpart.
    (b) Each operator shall follow one or more manuals of written 
procedures for the maintenance of each component, including any required 
corrosion control. The procedures must include:
    (1) The details of the inspections or tests determined under 
paragraph (a) of this section and their frequency of performance; and
    (2) A description of other actions necessary to maintain the LNG 
plant according to the requirements of this subpart.
    (c) Each operator shall include in the manual required by paragraph 
(b) of this section instructions enabling personnel who perform 
operation and maintenance activities to recognize conditions that 
potentially may be safety-related conditions that are subject to the 
reporting requirements of Sec.  191.23 of this subchapter.

[Amdt. 193-2, 45 FR 70407, Oct. 23, 1980, as amended by Amdt. 193-5, 53 
FR 24950, July 1, 1988; 53 FR 26560, July 13, 1988; Amdt. 193-18, 69 FR 
11337, Mar. 10, 2004]



Sec.  193.2607  Foreign material.

    (a) The presence of foreign material, contaminants, or ice shall be 
avoided or controlled to maintain the operational safety of each 
component.
    (b) LNG plant grounds must be free from rubbish, debris, and other 
material which present a fire hazard. Grass areas on the LNG plant 
grounds must be maintained in a manner that does not present a fire 
hazard.



Sec.  193.2609  Support systems.

    Each support system or foundation of each component must be 
inspected for any detrimental change that could impair support.



Sec.  193.2611  Fire protection.

    (a) Maintenance activities on fire control equipment must be 
scheduled so that a minimum of equipment is taken out of service at any 
one time and is returned to service in a reasonable period of time.
    (b) Access routes for movement of fire control equipment within each 
LNG plant must be maintained to reasonably provide for use in all 
weather conditions.

[[Page 614]]



Sec.  193.2613  Auxiliary power sources.

    Each auxiliary power source must be tested monthly to check its 
operational capability and tested annually for capacity. The capacity 
test must take into account the power needed to start up and 
simultaneously operate equipment that would have to be served by that 
power source in an emergency.



Sec.  193.2615  Isolating and purging.

    (a) Before personnel begin maintenance activities on components 
handling flammable fluids which are isolated for maintenance, the 
component must be purged in accordance with a procedure which meets the 
requirements of ``Purging Principles and Practices (incorporated by 
reference, see Sec.  193.2013)''; unless the maintenance procedures 
under Sec.  193.2605 provide that the activity can be safely performed 
without purging.
    (b) If the component or maintenance activity provides an ignition 
source, a technique in addition to isolation valves (such as removing 
spool pieces or valves and blank flanging the piping, or double block 
and bleed valving) must be used to ensure that the work area is free of 
flammable fluids.

[Amdt. 193-2, 45 FR 70405, Oct. 23, 1980, as amended by Amdt. 193-25, 80  
FR 184, Jan. 5, 2015]



Sec.  193.2617  Repairs.

    (a) Repair work on components must be performed and tested in a 
manner which:
    (1) As far as practicable, complies with the applicable requirements 
of Subpart D of this part; and
    (2) Assures the integrity and operational safety of the component 
being repaired.
    (b) For repairs made while a component is operating, each operator 
shall include in the maintenance procedures under Sec.  193.2605 
appropriate precautions to maintain the safety of personnel and property 
during repair activities.



Sec.  193.2619  Control systems.

    (a) Each control system must be properly adjusted to operate within 
design limits.
    (b) If a control system is out of service for 30 days or more, it 
must be inspected and tested for operational capability before returning 
it to service.
    (c) Control systems in service, but not normally in operation, such 
as relief valves and automatic shutdown devices, and control systems for 
internal shutoff valves for bottom penetration tanks must be inspected 
and tested once each calendar year, not exceeding 15 months, with the 
following exceptions:
    (1) Control systems used seasonally, such as for liquefaction or 
vaporization, must be inspected and tested before use each season.
    (2) Control systems that are intended for fire protection must be 
inspected and tested at regular intervals not to exceed 6 months.
    (d) Control systems that are normally in operation, such as required 
by a base load system, must be inspected and tested once each calendar 
year but with intervals not exceeding 15 months.
    (e) Relief valves must be inspected and tested for verification of 
the valve seat lifting pressure and reseating.

[Amdt. 193-2, 45 FR 70407, Oct. 23, 1980, as amended by Amdt. 193-17, 65  
FR 10960, Mar. 1, 2000]



Sec.  193.2621  Testing transfer hoses.

    Hoses used in LNG or flammable refrigerant transfer systems must be:
    (a) Tested once each calendar year, but with intervals not exceeding 
15 months, to the maximum pump pressure or relief valve setting; and
    (b) Visually inspected for damage or defects before each use.



Sec.  193.2623  Inspecting LNG storage tanks.

    Each LNG storage tank must be inspected or tested to verify that 
each of the following conditions does not impair the structural 
integrity or safety of the tank:
    (a) Foundation and tank movement during normal operation and after a 
major meteorological or geophysical disturbance.
    (b) Inner tank leakage.
    (c) Effectiveness of insulation.

[[Page 615]]

    (d) Frost heave.

[Amdt. 193-2, 45 FR 70407, Oct. 23, 1980, as amended at 47 FR 32720, 
July 29, 1982]



Sec.  193.2625  Corrosion protection.

    (a) Each operator shall determine which metallic components could, 
unless corrosion is controlled, have their integrity or reliability 
adversely affected by external, internal, or atmospheric corrosion 
during their intended service life.
    (b) Components whose integrity or reliability could be adversely 
affected by corrosion must be either--
    (1) Protected from corrosion in accordance with Sec. Sec.  193.2627 
through 193.2635, as applicable; or
    (2) Inspected and replaced under a program of scheduled maintenance 
in accordance with procedures established under Sec.  193.2605.



Sec.  193.2627  Atmospheric corrosion control.

    Each exposed component that is subject to atmospheric corrosive 
attack must be protected from atmospheric corrosion by--
    (a) Material that has been designed and selected to resist the 
corrosive atmosphere involved; or
    (b) Suitable coating or jacketing.



Sec.  193.2629  External corrosion control: buried or submerged components.

    (a) Each buried or submerged component that is subject to external 
corrosive attack must be protected from external corrosion by--
    (1) Material that has been designed and selected to resist the 
corrosive environment involved; or
    (2) The following means:
    (i) An external protective coating designed and installed to prevent 
corrosion attack and to meet the requirements of Sec.  192.461 of this 
chapter; and
    (ii) A cathodic protection system designed to protect components in 
their entirety in accordance with the requirements of Sec.  192.463 of 
this chapter and placed in operation before October 23, 1981, or within 
1 year after the component is constructed or installed, whichever is 
later.
    (b) Where cathodic protection is applied, components that are 
electrically interconnected must be protected as a unit.

[Amdt. 193-2, 45 FR 70407, Oct. 23, 1980, as amended at 47 FR 32720, 
July 29, 1982]



Sec.  193.2631  Internal corrosion control.

    Each component that is subject to internal corrosive attack must be 
protected from internal corrosion by--
    (a) Material that has been designed and selected to resist the 
corrosive fluid involved; or
    (b) Suitable coating, inhibitor, or other means.



Sec.  193.2633  Interference currents.

    (a) Each component that is subject to electrical current 
interference must be protected by a continuing program to minimize the 
detrimental effects of currents.
    (b) Each cathodic protection system must be designed and installed 
so as to minimize any adverse effects it might cause to adjacent metal 
components.
    (c) Each impressed current power source must be installed and 
maintained to prevent adverse interference with communications and 
control systems.



Sec.  193.2635  Monitoring corrosion control.

    Corrosion protection provided as required by this subpart must be 
periodically monitored to give early recognition of ineffective 
corrosion protection, including the following, as applicable:
    (a) Each buried or submerged component under cathodic protection 
must be tested at least once each calendar year, but with intervals not 
exceeding 15 months, to determine whether the cathodic protection meets 
the requirements of Sec.  192.463 of this chapter.
    (b) Each cathodic protection rectifier or other impressed current 
power source must be inspected at least 6 times each calendar year, but 
with intervals not exceeding 2\1/2\ months, to ensure that it is 
operating properly.
    (c) Each reverse current switch, each diode, and each interference 
bond whose failure would jeopardize component protection must be 
electrically checked for proper performance at least 6 times each 
calendar year, but with intervals not exceeding 2\1/2\ months. Each 
other interference bond

[[Page 616]]

must be checked at least once each calendar year, but with intervals not 
exceeding 15 months.
    (d) Each component that is protected from atmospheric corrosion must 
be inspected at intervals not exceeding 3 years.
    (e) If a component is protected from internal corrosion, monitoring 
devices designed to detect internal corrosion, such as coupons or 
probes, must be located where corrosion is most likely to occur. 
However, monitoring is not required for corrosion resistant materials if 
the operator can demonstrate that the component will not be adversely 
affected by internal corrosion during its service life. Internal 
corrosion control monitoring devices must be checked at least two times 
each calendar year, but with intervals not exceeding 7\1/2\ months.



Sec.  193.2637  Remedial measures.

    Prompt corrective or remedial action must be taken whenever an 
operator learns by inspection or otherwise that atmospheric, external, 
or internal corrosion is not controlled as required by this subpart.



Sec.  193.2639  Maintenance records.

    (a) Each operator shall keep a record at each LNG plant of the date 
and type of each maintenance activity performed on each component to 
meet the requirements of this part. For each LNG facility that is 
designed and constructed after March 31, 2000 the operator shall also 
maintain related periodic inspection and testing records that NFPA-59A-
2001 (incorporated by reference, see Sec.  193.2013) requires. 
Maintenance records, whether required by this part or NFPA-59A-2001, 
must be kept for a period of not less than five years.
    (b) Each operator shall maintain records or maps to show the 
location of cathodically protected components, neighboring structures 
bonded to the cathodic protection system, and corrosion protection 
equipment.
    (c) Each of the following records must be retained for as long as 
the LNG facility remains in service:
    (1) Each record or map required by paragraph (b) of this section.
    (2) Records of each test, survey, or inspection required by this 
subpart in sufficient detail to demonstrate the adequacy of corrosion 
control measures.

[Amdt. 193-2, 45 FR 70407, Oct. 23, 1980, as amended by Amdt. 193-17, 65 
FR 10960, Mar. 1, 2000; Amdt. 193-18, 69 FR 11337, Mar. 10, 2004; Amdt. 
193-25, 80 FR 182, Jan. 5, 2015]



             Subpart H_Personnel Qualifications and Training

    Source: Sections 193.2707 through 193.2719 appear at Amdt. 193-2, 45 
FR 70404, Oct. 23, 1980, unless otherwise noted.



Sec.  193.2701  Scope.

    This subpart prescribes requirements for personnel qualifications 
and training.

[45 FR 9219, Feb. 11, 1980]



Sec.  193.2703  Design and fabrication.

    For the design and fabrication of components, each operator shall 
use--
    (a) With respect to design, persons who have demonstrated competence 
by training or experience in the design of comparable components.
    (b) With respect to fabrication, persons who have demonstrated 
competence by training or experience in the fabrication of comparable 
components.

[45 FR 9219, Feb. 11, 1980]



Sec.  193.2705  Construction, installation, inspection, and testing.

    (a) Supervisors and other personnel utilized for construction, 
installation, inspection, or testing must have demonstrated their 
capability to perform satisfactorily the assigned function by 
appropriate training in the methods and equipment to be used or related 
experience and accomplishments.
    (b) Each operator must periodically determine whether inspectors 
performing construction, installation, and testing duties required by 
this part are satisfactorily performing their assigned functions.

[45 FR 9219, Feb. 11, 1980, as amended by Amdt. 193-18, 69 FR 11337, 
Mar. 10, 2004]

[[Page 617]]



Sec.  193.2707  Operations and maintenance.

    (a) Each operator shall utilize for operation or maintenance of 
components only those personnel who have demonstrated their capability 
to perform their assigned functions by--
    (1) Successful completion of the training required by Sec. Sec.  
193.2713 and 193.2717; and
    (2) Experience related to the assigned operation or maintenance 
function; and
    (3) Acceptable performance on a proficiency test relevant to the 
assigned function.
    (b) A person who does not meet the requirements of paragraph (a) of 
this section may operate or maintain a component when accompanied and 
directed by an individual who meets the requirements.
    (c) Corrosion control procedures under Sec.  193.2605(b), including 
those for the design, installation, operation, and maintenance of 
cathodic protection systems, must be carried out by, or under the 
direction of, a person qualified by experience and training in corrosion 
control technology.



Sec.  193.2709  Security.

    Personnel having security duties must be qualified to perform their 
assigned duties by successful completion of the training required under 
Sec.  193.2715.



Sec.  193.2711  Personnel health.

    Each operator shall follow a written plan to verify that personnel 
assigned operating, maintenance, security, or fire protection duties at 
the LNG plant do not have any physical condition that would impair 
performance of their assigned duties. The plan must be designed to 
detect both readily observable disorders, such as physical handicaps or 
injury, and conditions requiring professional examination for discovery.



Sec.  193.2713  Training: operations and maintenance.

    (a) Each operator shall provide and implement a written plan of 
initial training to instruct--
    (1) All permanent maintenance, operating, and supervisory 
personnel--
    (i) About the characteristics and hazards of LNG and other flammable 
fluids used or handled at the facility, including, with regard to LNG, 
low temperatures, flammability of mixtures with air, odorless vapor, 
boiloff characteristics, and reaction to water and water spray;
    (ii) About the potential hazards involved in operating and 
maintenance activities; and
    (iii) To carry out aspects of the operating and maintenance 
procedures under Sec. Sec.  193.2503 and 193.2605 that relate to their 
assigned functions; and
    (2) All personnel--
    (i) To carry out the emergency procedures under Sec.  193.2509 that 
relate to their assigned functions; and
    (ii) To give first-aid; and
    (3) All operating and appropriate supervisory personnel--
    (i) To understand detailed instructions on the facility operations, 
including controls, functions, and operating procedures; and
    (ii) To understand the LNG transfer procedures provided under Sec.  
193.2513.
    (b) A written plan of continuing instruction must be conducted at 
intervals of not more than two years to keep all personnel current on 
the knowledge and skills they gained in the program of initial 
instruction.



Sec.  193.2715  Training: security.

    (a) Personnel responsible for security at an LNG plant must be 
trained in accordance with a written plan of initial instruction to:
    (1) Recognize breaches of security;
    (2) Carry out the security procedures under Sec.  193.2903 that 
relate to their assigned duties;
    (3) Be familiar with basic plant operations and emergency 
procedures, as necessary to effectively perform their assigned duties; 
and
    (4) Recognize conditions where security assistance is needed.
    (b) A written plan of continuing instruction must be conducted at 
intervals of not more than two years to keep all personnel having 
security duties current on the knowledge and skills they gained in the 
program of initial instruction.

[[Page 618]]



Sec.  193.2717  Training: fire protection.

    (a) All personnel involved in maintenance and operations of an LNG 
plant, including their immediate supervisors, must be trained according 
to a written plan of initial instruction, including plant fire drills, 
to:
    (1) Know the potential causes and areas of fire;
    (2) Know the types, sizes, and predictable consequences of fire; and
    (3) Know and be able to perform their assigned fire control duties 
according to the procedures established under Sec.  193.2509 and by 
proper use of equipment provided under Sec.  193.2801.
    (b) A written plan of continuing instruction, including plant fire 
drills, must be conducted at intervals of not more than two years to 
keep personnel current on the knowledge and skills they gained in the 
instruction under paragraph (a) of the section.
    (c) Plant fire drills must provide personnel hands-on experience in 
carrying out their duties under the fire emergency procedures required 
by Sec.  193.2509.

[Amdt. 193-2, 45 FR 70404, Oct. 23, 1980, as amended by Amdt. 193-18, 69 
FR 11337, Mar. 10, 2004]



Sec.  193.2719  Training: records.

    (a) Each operator shall maintain a system of records which--
    (1) Provide evidence that the training programs required by this 
subpart have been implemented; and
    (2) Provide evidence that personnel have undergone and 
satisfactorily completed the required training programs.
    (b) Records must be maintained for one year after personnel are no 
longer assigned duties at the LNG plant.



                        Subpart I_Fire Protection

    Source: Amdt. 193-2, 45 FR 70408, Oct. 23, 1980, unless otherwise 
noted.



Sec.  193.2801  Fire protection.

    Each operator must provide and maintain fire protection at LNG 
plants according to sections 9.1 through 9.7 and section 9.9 of NFPA-
59A-2001 (incorporated by reference, see Sec.  193.2013). However, LNG 
plants existing on March 31, 2000, need not comply with provisions on 
emergency shutdown systems, water delivery systems, detection systems, 
and personnel qualification and training until September 12, 2005.

[Amdt. 193-18, 69 FR 11337, Mar. 10, 2004; Amdt. 193-25, 80 FR 182, Jan. 
5, 2015]



Sec. Sec.  193.2803-193.2821  [Reserved]



                           Subpart J_Security

    Source: Amdt. 193-2, 45 FR 70409, Oct. 23, 1980, unless otherwise 
noted.



Sec.  193.2901  Scope.

    This subpart prescribes requirements for security at LNG plants. 
However, the requirements do not apply to existing LNG plants that do 
not contain LNG.

[Amdt. 193-4, 52 FR 675, Jan. 8, 1987]



Sec.  193.2903  Security procedures.

    Each operator shall prepare and follow one or more manuals of 
written procedures to provide security for each LNG plant. The 
procedures must be available at the plant in accordance with Sec.  
193.2017 and include at least:
    (a) A description and schedule of security inspections and patrols 
performed in accordance with Sec.  193.2913;
    (b) A list of security personnel positions or responsibilities 
utilized at the LNG plant;
    (c) A brief description of the duties associated with each security 
personnel position or responsibility;
    (d) Instructions for actions to be taken, including notification of 
other appropriate plant personnel and law enforcement officials, when 
there is any indication of an actual or attempted breach of security;
    (e) Methods for determining which persons are allowed access to the 
LNG plant;
    (f) Positive identification of all persons entering the plant and on 
the plant, including methods at least as effective as picture badges; 
and
    (g) Liaison with local law enforcement officials to keep them 
informed about current security procedures under this section.

[[Page 619]]



Sec.  193.2905  Protective enclosures.

    (a) The following facilities must be surrounded by a protective 
enclosure:
    (1) Storage tanks;
    (2) Impounding systems;
    (3) Vapor barriers;
    (4) Cargo transfer systems;
    (5) Process, liquefaction, and vaporization equipment;
    (6) Control rooms and stations;
    (7) Control systems;
    (8) Fire control equipment;
    (9) Security communications systems; and
    (10) Alternative power sources.

The protective enclosure may be one or more separate enclosures 
surrounding a single facility or multiple facilities.
    (b) Ground elevations outside a protective enclosure must be graded 
in a manner that does not impair the effectiveness of the enclosure.
    (c) Protective enclosures may not be located near features outside 
of the facility, such as trees, poles, or buildings, which could be used 
to breach the security.
    (d) At least two accesses must be provided in each protective 
enclosure and be located to minimize the escape distance in the event of 
emergency.
    (e) Each access must be locked unless it is continuously guarded. 
During normal operations, an access may be unlocked only by persons 
designated in writing by the operator. During an emergency, a means must 
be readily available to all facility personnel within the protective 
enclosure to open each access.



Sec.  193.2907  Protective enclosure construction.

    (a) Each protective enclosure must have sufficient strength and 
configuration to obstruct unauthorized access to the facilities 
enclosed.
    (b) Openings in or under protective enclosures must be secured by 
grates, doors or covers of construction and fastening of sufficient 
strength such that the integrity of the protective enclosure is not 
reduced by any opening.

[Amdt. 193-2, 45 FR 70409, Oct. 23, 1980, as amended by Amdt. 193-12, 61 
FR 27793, June 3, 1996; 61 FR 45905, Aug. 30, 1996]



Sec.  193.2909  Security communications.

    A means must be provided for:
    (a) Prompt communications between personnel having supervisory 
security duties and law enforcement officials; and
    (b) Direct communications between all on-duty personnel having 
security duties and all control rooms and control stations.



Sec.  193.2911  Security lighting.

    Where security warning systems are not provided for security 
monitoring under Sec.  193.2913, the area around the facilities listed 
under Sec.  193.2905(a) and each protective enclosure must be 
illuminated with a minimum in service lighting intensity of not less 
than 2.2 lux (0.2 ft\c\) between sunset and sunrise.



Sec.  193.2913  Security monitoring.

    Each protective enclosure and the area around each facility listed 
in Sec.  193.2905(a) must be monitored for the presence of unauthorized 
persons. Monitoring must be by visual observation in accordance with the 
schedule in the security procedures under Sec.  193.2903(a) or by 
security warning systems that continuously transmit data to an attended 
location. At an LNG plant with less than 40,000 m\3\ (250,000 bbl) of 
storage capacity, only the protective enclosure must be monitored.



Sec.  193.2915  Alternative power sources.

    An alternative source of power that meets the requirements of Sec.  
193.2445 must be provided for security lighting and security monitoring 
and warning systems required under Sec. Sec.  193.2911 and 193.2913.



Sec.  193.2917  Warning signs.

    (a) Warning signs must be conspicuously placed along each protective 
enclosure at intervals so that at least one sign is recognizable at 
night from a distance of 30m (100 ft.) from any way that could 
reasonably be used to approach the enclosure.
    (b) Signs must be marked with at least the following on a background 
of sharply contrasting color:

[[Page 620]]


The words ``NO TRESPASSING,'' or words of comparable meaning.

[Amdt. 193-2, 45 FR 70409, Oct. 23, 1980, as amended at 47 FR 32720, 
July 29, 1982]



PART 194_RESPONSE PLANS FOR ONSHORE OIL PIPELINES--Table of Contents



                            Subpart A_General

Sec.
194.1 Purpose.
194.3 Applicability.
194.5 Definitions.
194.7 Operating restrictions and interim operating authorization.

                        Subpart B_Response Plans

194.101 Operators required to submit plans.
194.103 Significant and substantial harm; operator's statement.
194.105 Worst case discharge.
194.107 General response plan requirements.
194.109 Submission of state response plans.
194.111 Response plan retention.
194.113 Information summary.
194.115 Response resources.
194.117 Training.
194.119 Submission and approval procedures.
194.121 Response plan review and update procedures.

Appendix A to Part 194--Guidelines for the Preparation of Response Plans
Appendix B to Part 194--High Volume Areas

    Authority: 33 U.S.C. 1231, 1321(j)(1)(C), (j)(5) and (j)(6); sec. 2, 
E.O. 12777, 56 FR 54757, 3 CFR, 1991 Comp., p. 351; 49 CFR 1.53.

    Source: 58 FR 253, Jan. 5, 1993, unless otherwise noted.



                            Subpart A_General



Sec.  194.1  Purpose.

    This part contains requirements for oil spill response plans to 
reduce the environmental impact of oil discharged from onshore oil 
pipelines.



Sec.  194.3  Applicability.

    This part applies to an operator of an onshore oil pipeline that, 
because of its location, could reasonably be expected to cause 
substantial harm, or significant and substantial harm to the environment 
by discharging oil into or on any navigable waters of the United States 
or adjoining shorelines.



Sec.  194.5  Definitions.

    Adverse weather means the weather conditions that the operator will 
consider when identifying response systems and equipment to be deployed 
in accordance with a response plan. Factors to consider include ice 
conditions, temperature ranges, weather-related visibility, significant 
wave height as specified in 33 CFR Part 154, Appendix C, Table 1, and 
currents within the areas in which those systems or equipment are 
intended to function.
    Barrel means 42 United States gallons (159 liters) at 60 
[deg]Fahrenheit (15.6 [deg]Celsius).
    Breakout tank means a tank used to:
    (1) Relieve surges in an oil pipeline system or
    (2) Receive and store oil transported by a pipeline for reinjection 
and continued transportation by pipeline.
    Contract or other approved means is:
    (1) A written contract or other legally binding agreement between 
the operator and a response contractor or other spill response 
organization identifying and ensuring the availability of the specified 
personnel and equipment within stipulated response times for a specified 
geographic area;
    (2) Certification that specified equipment is owned or operated by 
the pipeline operator, and operator personnel and equipment are 
available within stipulated response times for a specified geographic 
area; or
    (3) Active membership in a local or regional oil spill removal 
organization that has identified specified personnel and equipment to be 
available within stipulated response times for a specified geographic 
area.
    Environmentally sensitive area means an area of environmental 
importance which is in or adjacent to navigable waters.
    High volume area means an area which an oil pipeline having a 
nominal outside diameter of 20 inches (508 millimeters) or more crosses 
a major river or other navigable waters, which, because of the velocity 
of the river flow and vessel traffic on the river, would require a more 
rapid response in case of a worst case discharge or substantial threat 
of such a discharge. Appendix B to this part contains a list of some of

[[Page 621]]

the high volume areas in the United States.
    Line section means a continuous run of pipe that is contained 
between adjacent pressure pump stations, between a pressure pump station 
and a terminal or breakout tank, between a pressure pump station and a 
block valve, or between adjacent block valves.
    Major river means a river that, because of its velocity and vessel 
traffic, would require a more rapid response in case of a worst case 
discharge. For a list of rivers see ``Rolling Rivers, An Encyclopedia of 
America's Rivers,'' Richard A. Bartlett, Editor, McGraw-Hill Book 
Company, 1984.
    Maximum extent practicable means the limits of available technology 
and the practical and technical limits on a pipeline operator in 
planning the response resources required to provide the on-water 
recovery capability and the shoreline protection and cleanup capability 
to conduct response activities for a worst case discharge from a 
pipeline in adverse weather.
    Navigable waters means the waters of the United States, including 
the territorial sea and such waters as lakes, rivers, streams; waters 
which are used for recreation; and waters from which fish or shellfish 
are taken and sold in interstate or foreign commerce.
    Oil means oil of any kind or in any form, including, but not limited 
to, petroleum, fuel oil, vegetable oil, animal oil, sludge, oil refuse, 
oil mixed with wastes other than dredged spoil.
    Oil spill removal organization means an entity that provides 
response resources.
    On-Scene Coordinator (OSC) means the federal official designated by 
the Administrator of the EPA or by the Commandant of the USCG to 
coordinate and direct federal response under subpart D of the National 
Contingency Plan (40 CFR part 300).
    Onshore oil pipeline facilities means new and existing pipe, rights-
of-way and any equipment, facility, or building used in the 
transportation of oil located in, on, or under, any land within the 
United States other than submerged land.
    Operator means a person who owns or operates onshore oil pipeline 
facilities.
    Pipeline means all parts of an onshore pipeline facility through 
which oil moves including, but not limited to, line pipe, valves, and 
other appurtenances connected to line pipe, pumping units, fabricated 
assemblies associated with pumping units, metering and delivery stations 
and fabricated assemblies therein, and breakout tanks.
    Qualified individual means an English-speaking representative of an 
operator, located in the United States, available on a 24-hour basis, 
with full authority to: activate and contract with required oil spill 
removal organization(s); activate personnel and equipment maintained by 
the operator; act as liaison with the OSC; and obligate any funds 
required to carry out all required or directed oil response activities.
    Response activities means the containment and removal of oil from 
the water and shorelines, the temporary storage and disposal of 
recovered oil, or the taking of other actions as necessary to minimize 
or mitigate damage to the environment.
    Response plan means the operator's core plan and the response zone 
appendices for responding, to the maximum extent practicable, to a worse 
case discharge of oil, or the substantial threat of such a discharge.
    Response resources means the personnel, equipment, supplies, and 
other resources necessary to conduct response activities.
    Response zone means a geographic area either along a length of 
pipeline or including multiple pipelines, containing one or more 
adjacent line sections, for which the operator must plan for the 
deployment of, and provide, spill response capabilities. The size of the 
zone is determined by the operator after considering available 
capability, resources, and geographic characteristics.
    Specified minimum yield strength means the minimum yield strength, 
expressed in pounds per square inch, prescribed by the specification 
under which the material is purchased from the manufacturer.
    Stress level means the level of tangential or hoop stress, usually 
expressed as a percentage of specified minimum yield strength.

[[Page 622]]

    Worst case discharge means the largest foreseeable discharge of oil, 
including a discharge from fire or explosion, in adverse weather 
conditions. This volume will be determined by each pipeline operator for 
each response zone and is calculated according to Sec.  194.105.

[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-3, 63 FR 37505, July 
13, 1998; Amdt. 194-4, 70 FR 8746, Feb. 23, 2005]



Sec.  194.7  Operating restrictions and interim operating authorization.

    (a) An operator of a pipeline for which a response plan is required 
under Sec.  194.101, may not handle, store, or transport oil in that 
pipeline unless the operator has submitted a response plan meeting the 
requirements of this part.
    (b) An operator must operate its onshore pipeline facilities in 
accordance with the applicable response plan.
    (c) The operator of a pipeline line section described in Sec.  
194.103(c), may continue to operate the pipeline for two years after the 
date of submission of a response plan, pending approval or disapproval 
of that plan, only if the operator has submitted the certification 
required by Sec.  194.119(e).

[Amdt. 194-4, 70 FR 8746, Feb. 23, 2005]



                        Subpart B_Response Plans



Sec.  194.101  Operators required to submit plans.

    (a) Except as provided in paragraph (b) of this section, unless OPS 
grants a request from an Federal On-Scene Coordinator (FOSC) to require 
an operator of a pipeline in paragraph (b) to submit a response plan, 
each operator of an onshore pipeline facility shall prepare and submit a 
response plan to PHMSA as provided in Sec.  194.119. A pipeline which 
does not meet the criteria for significant and substantial harm as 
defined in Sec.  194.103(c) and is not eligible for an exception under 
Sec.  194.101(b), can be expected to cause substantial harm. Operators 
of substantial harm pipeline facilities must prepare and submit plans to 
PHMSA for review.
    (b) Exception. An operator need not submit a response plan for:
    (1) A pipeline that is 6\5/8\ inches (168 millimeters) or less in 
outside nominal diameter, is 10 miles (16 kilometers) or less in length, 
and all of the following conditions apply to the pipeline:
    (i) The pipeline has not experienced a release greater than 1,000 
barrels (159 cubic meters) within the previous five years,
    (ii) The pipeline has not experienced at least two reportable 
releases, as defined in Sec.  195.50, within the previous five years,
    (iii) A pipeline containing any electric resistance welded pipe, 
manufactured prior to 1970, does not operate at a maximum operating 
pressure established under Sec.  195.406 that corresponds to a stress 
level greater than 50 percent of the specified minimum yield strength of 
the pipe, and
    (iv) The pipeline is not in proximity to navigable waters, public 
drinking water intakes, or environmentally sensitive areas.
    (2)(i) A line section that is greater than 6\5/8\ inches in outside 
nominal diameter and is greater than 10 miles in length, where the 
operator determines that it is unlikely that the worst case discharge 
from any point on the line section would adversely affect, within 12 
hours after the initiation of the discharge, any navigable waters, 
public drinking water intake, or environmentally sensitive areas.
    (ii) A line section that is 6\5/8\ inches (168 millimeters) or less 
in outside nominal diameter and is 10 miles (16 kilometers) or less in 
length, where the operator determines that it is unlikely that the worst 
case discharge from any point on the line section would adversely 
affect, within 4 hours after the initiation of the discharge, any 
navigable waters, public drinking water intake, or environmentally 
sensitive areas.

[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-3, 63 FR 37505, July 
13, 1998; Amdt. 194-4, 70 FR 8747, Feb. 23, 2005; 70 FR 11140, Mar. 8, 
2005]



Sec.  194.103  Significant and substantial harm; operator's statement.

    (a) Each operator shall submit a statement with its response plan, 
as required by Sec. Sec.  194.107 and 194.113, identifying which line 
sections in a response

[[Page 623]]

zone can be expected to cause significant and substantial harm to the 
environment in the event of a discharge of oil into or on the navigable 
waters or adjoining shorelines.
    (b) If an operator expects a line section in a response zone to 
cause significant and substantial harm, then the entire response zone 
must, for the purpose of response plan review and approval, be treated 
as if it is expected to cause significant and substantial harm. However, 
an operator will not have to submit separate plans for each line 
section.
    (c) A line section can be expected to cause significant and 
substantial harm to the environment in the event of a discharge of oil 
into or on the navigable waters or adjoining shorelines if; the pipeline 
is greater than 6\5/8\ inches (168 millimeters) in outside nominal 
diameter, greater than 10 miles (16 kilometers) in length, and the line 
section--
    (1) Has experienced a release greater than 1,000 barrels (159 cubic 
meters) within the previous five years,
    (2) Has experienced two or more reportable releases, as defined in 
Sec.  195.50, within the previous five years,
    (3) Containing any electric resistance welded pipe, manufactured 
prior to 1970, operates at a maximum operating pressure established 
under Sec.  195.406 that corresponds to a stress level greater than 50 
percent of the specified minimum yield strength of the pipe,
    (4) Is located within a 5 mile (8 kilometer) radius of potentially 
affected public drinking water intakes and could reasonably be expected 
to reach public drinking water intakes, or
    (5) Is located within a 1 mile (1.6 kilometer) radius of potentially 
affected environmentally sensitive areas, and could reasonably be 
expected to reach these areas.

[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-3, 63 FR 37505, July 
13, 1998]



Sec.  194.105  Worst case discharge.

    (a) Each operator shall determine the worst case discharge for each 
of its response zones and provide the methodology, including 
calculations, used to arrive at the volume.
    (b) The worst case discharge is the largest volume, in barrels 
(cubic meters), of the following:
    (1) The pipeline's maximum release time in hours, plus the maximum 
shutdown response time in hours (based on historic discharge data or in 
the absence of such historic data, the operator's best estimate), 
multiplied by the maximum flow rate expressed in barrels per hour (based 
on the maximum daily capacity of the pipeline), plus the largest line 
drainage volume after shutdown of the line section(s) in the response 
zone expressed in barrels (cubic meters); or
    (2) The largest foreseeable discharge for the line section(s) within 
a response zone, expressed in barrels (cubic meters), based on the 
maximum historic discharge, if one exists, adjusted for any subsequent 
corrective or preventive action taken; or
    (3) If the response zone contains one or more breakout tanks, the 
capacity of the single largest tank or battery of tanks within a single 
secondary containment system, adjusted for the capacity or size of the 
secondary containment system, expressed in barrels (cubic meters).
    (4) Operators may claim prevention credits for breakout tank 
secondary containment and other specific spill prevention measures as 
follows:

------------------------------------------------------------------------
                                                               Credit
        Prevention measure                 Standard           (percent)
------------------------------------------------------------------------
Secondary containment 100%.
Built/repaired to API standards...  API STD 620/650/653...            10
Overfill protection standards.....  API RP 2350...........             5
Testing/cathodic protection.......  API STD 650/651/653...             5
Tertiary containment/drainage/      NFPA 30...............             5
 treatment.
Maximum allowable credit..........  ......................            75
------------------------------------------------------------------------


[[Page 624]]


[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-3, 63 FR 37505, July 
13, 1998; Amdt. 194-4, 70 FR 8747, Feb. 23, 2005; Amdt. 194-5, 70 FR 
35042, June 16, 2005]



Sec.  194.107  General response plan requirements.

    (a) Each response plan must include procedures and a list of 
resources for responding, to the maximum extent practicable, to a worst 
case discharge and to a substantial threat of such a discharge. The 
``substantial threat'' term is equivalent to abnormal operations 
outlined in 49 CFR 195.402(d). To comply with this requirement, an 
operator can incorporate by reference into the response plan the 
appropriate procedures from its manual for operations, maintenance, and 
emergencies, which is prepared in compliance with 49 CFR 195.402.
    (b) An operator must certify in the response plan that it reviewed 
the NCP and each applicable ACP and that its response plan is consistent 
with the NCP and each applicable ACP as follows:
    (1) As a minimum to be consistent with the NCP a facility response 
plan must:
    (i) Demonstrate an operator's clear understanding of the function of 
the Federal response structure, including procedures to notify the 
National Response Center reflecting the relationship between the 
operator's response organization's role and the Federal On Scene 
Coordinator's role in pollution response;
    (ii) Establish provisions to ensure the protection of safety at the 
response site; and
    (iii) Identify the procedures to obtain any required Federal and 
State permissions for using alternative response strategies such as in-
situ burning and dispersants as provided for in the applicable ACPs; and
    (2) As a minimum, to be consistent with the applicable ACP the plan 
must:
    (i) Address the removal of a worst case discharge and the mitigation 
or prevention of a substantial threat of a worst case discharge;
    (ii) Identify environmentally and economically sensitive areas;
    (iii) Describe the responsibilities of the operator and of Federal, 
State and local agencies in removing a discharge and in mitigating or 
preventing a substantial threat of a discharge; and
    (iv) Establish the procedures for obtaining an expedited decision on 
use of dispersants or other chemicals.
    (c) Each response plan must include:
    (1) A core plan consisting of--
    (i) An information summary as required in Sec.  194.113,
    (ii) Immediate notification procedures,
    (iii) Spill detection and mitigation procedures,
    (iv) The name, address, and telephone number of the oil spill 
response organization, if appropriate,
    (v) Response activities and response resources,
    (vi) Names and telephone numbers of Federal, State and local 
agencies which the operator expects to have pollution control 
responsibilities or support,
    (vii) Training procedures,
    (viii) Equipment testing,
    (ix) Drill program--an operator will satisfy the requirement for a 
drill program by following the National Preparedness for Response 
Exercise Program (PREP) guidelines. An operator choosing not to follow 
PREP guidelines must have a drill program that is equivalent to PREP. 
The operator must describe the drill program in the response plan and 
OPS will determine if the program is equivalent to PREP.
    (x) Plan review and update procedures;
    (2) An appendix for each response zone that includes the information 
required in paragraph (c)(1)(i)-(ix) of this section and the worst case 
discharge calculations that are specific to that response zone. An 
operator submitting a response plan for a single response zone does not 
need to have a core plan and a response zone appendix. The operator of a 
single response zone onshore pipeline shall have a single summary in the 
plan that contains the required information in Sec.  194.113.7; and
    (3) A description of the operator's response management system 
including the functional areas of finance, logistics, operations, 
planning, and command. The plan must demonstrate that the operator's 
response management system uses common terminology and has a manageable 
span of control, a

[[Page 625]]

clearly defined chain of command, and sufficient trained personnel to 
fill each position.

[Amdt. 194-4, 70 FR 8747, Feb. 23, 2005]



Sec.  194.109  Submission of state response plans.

    (a) In lieu of submitting a response plan required by Sec.  194.103, 
an operator may submit a response plan that complies with a state law or 
regulation, if the state law or regulation requires a plan that provides 
equivalent or greater spill protection than a plan required under this 
part.
    (b) A plan submitted under this section must
    (1) Have an information summary required by Sec.  194.113;
    (2) List the names or titles and 24-hour telephone numbers of the 
qualified individual(s) and at least one alternate qualified 
individual(s); and
    (3) Ensure through contract or other approved means the necessary 
private personnel and equipment to respond to a worst case discharge or 
a substantial threat of such a discharge.

[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-4, 70 FR 8748, Feb. 
23, 2005]



Sec.  194.111  Response plan retention.

    (a) Each operator shall maintain relevant portions of its response 
plan at the operator's headquarters and at other locations from which 
response activities may be conducted, for example, in field offices, 
supervisors' vehicles, or spill response trailers.
    (b) Each operator shall provide a copy of its response plan to each 
qualified individual.

[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-4, 70 FR 8748, Feb. 
23, 2005]



Sec.  194.113  Information summary.

    (a) The information summary for the core plan, required by Sec.  
194.107, must include:
    (1) The name and address of the operator; and
    (2) For each response zone which contains one or more line sections 
that meet the criteria for determining significant and substantial harm 
as described in Sec.  194.103, a listing and description of the response 
zones, including county(s) and state(s).
    (b) The information summary for the response zone appendix, required 
in Sec.  194.107, must include:
    (1) The information summary for the core plan;
    (2) The names or titles and 24-hour telephone numbers of the 
qualified individual(s) and at least one alternate qualified 
individual(s);
    (3) The description of the response zone, including county(s) and 
state(s), for those zones in which a worst case discharge could cause 
substantial harm to the environment;
    (4) A list of line sections for each pipeline contained in the 
response zone, identified by milepost or survey station number, or other 
operator designation;
    (5) The basis for the operator's determination of significant and 
substantial harm; and
    (6) The type of oil and volume of the worst case discharge.

[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-4, 70 FR 8748, Feb. 
23, 2005]



Sec.  194.115  Response resources.

    (a) Each operator shall identify and ensure, by contract or other 
approved means, the resources necessary to remove, to the maximum extent 
practicable, a worst case discharge and to mitigate or prevent a 
substantial threat of a worst case discharge.
    (b) An operator shall identify in the response plan the response 
resources which are available to respond within the time specified, 
after discovery of a worst case discharge, or to mitigate the 
substantial threat of such a discharge, as follows:

----------------------------------------------------------------------------------------------------------------
                                                Tier 1                   Tier 2                   Tier 3
----------------------------------------------------------------------------------------------------------------
High volume area.....................  6 hrs..................  30 hrs.................  54 hrs.
All other areas......................  12 hrs.................  36 hrs.................  60 hrs.
----------------------------------------------------------------------------------------------------------------



Sec.  194.117  Training.

    (a) Each operator shall conduct training to ensure that:
    (1) All personnel know--
    (i) Their responsibilities under the response plan,
    (ii) The name and address of, and the procedure for contacting, the 
operator on a 24-hour basis, and

[[Page 626]]

    (iii) The name of, and procedures for contacting, the qualified 
individual on a 24-hour basis;
    (2) Reporting personnel know--
    (i) The content of the information summary of the response plan,
    (ii) The toll-free telephone number of the National Response Center, 
and
    (iii) The notification process; and
    (3) Personnel engaged in response activities know--
    (i) The characteristics and hazards of the oil discharged,
    (ii) The conditions that are likely to worsen emergencies, including 
the consequences of facility malfunctions or failures, and the 
appropriate corrective actions,
    (iii) The steps necessary to control any accidental discharge of oil 
and to minimize the potential for fire, explosion, toxicity, or 
environmental damage, and
    (iv) The proper firefighting procedures and use of equipment, fire 
suits, and breathing apparatus.
    (b) Each operator shall maintain a training record for each 
individual that has been trained as required by this section. These 
records must be maintained in the following manner as long as the 
individual is assigned duties under the response plan:
    (1) Records for operator personnel must be maintained at the 
operator's headquarters; and
    (2) Records for personnel engaged in response, other than operator 
personnel, shall be maintained as determined by the operator.
    (c) Nothing in this section relieves an operator from the 
responsibility to ensure that all response personnel are trained to meet 
the Occupational Safety and Health Administration (OSHA) standards for 
emergency response operations in 29 CFR 1910.120, including volunteers 
or casual laborers employed during a response who are subject to those 
standards pursuant to 40 CFR part 311.



Sec.  194.119  Submission and approval procedures.

    (a) Each operator shall submit two copies of the response plan 
required by this part. Copies of the response plan shall be submitted 
to: Office of Pipeline Safety, Pipeline and Hazardous Materials Safety 
Administration, Department of Transportation, PHP 80, 1200 New Jersey 
Avenue, SE., Washington, DC 20590-0001. Note: Submission of plans in 
electronic format is preferred.
    (b) If PHMSA determines that a response plan requiring approval does 
not meet all the requirements of this part, PHMSA will notify the 
operator of any alleged deficiencies, and to provide the operator an 
opportunity to respond, including the opportunity for an informal 
conference, on any proposed plan revisions and an opportunity to correct 
any deficiencies.
    (c) An operator who disagrees with the PHMSA determination that a 
plan contains alleged deficiencies may petition PHMSA for 
reconsideration within 30 days from the date of receipt of PHMSA's 
notice. After considering all relevant material presented in writing or 
at an informal conference, PHMSA will notify the operator of its final 
decision. The operator must comply with the final decision within 30 
days of issuance unless PHMSA allows additional time.
    (d) For response zones of pipelines described in Sec.  194.103(c) 
OPS will approve the response plan if OPS determines that the response 
plan meets all requirements of this part. OPS may consult with the U.S. 
Environmental Protection Agency (EPA) or the U.S. Coast Guard (USCG) if 
a Federal on-scene coordinator (FOSC) has concerns about the operator's 
ability to respond to a worst case discharge.
    (e) If OPS has not approved a response plan for a pipeline described 
in Sec.  194.103(c), the operator may submit a certification to OPS that 
the operator has obtained, through contract or other approved means, the 
necessary personnel and equipment to respond, to the maximum extent 
practicable, to a worst case discharge or a substantial threat of such a 
discharge. The certificate must be signed by the qualified individual or 
an appropriate corporate officer.
    (f) If OPS receives a request from a FOSC to review a response plan, 
OPS may require an operator to give a copy of the response plan to the 
FOSC. OPS may consider FOSC comments on response techniques, protecting 
fish,

[[Page 627]]

wildlife and sensitive environments, and on consistency with the ACP. 
OPS remains the approving authority for the response plan.

[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-4, 70 FR 8748, Feb. 
23, 2005; 70 FR 1140, Mar. 8, 2005; 73 FR 16570, Mar. 28, 2008; 74 FR 
2894, Jan. 16, 2009]



Sec.  194.121  Response plan review and update procedures.

    (a) Each operator shall update its response plan to address new or 
different operating conditions or information. In addition, each 
operator shall review its response plan in full at least every 5 years 
from the date of the last submission or the last approval as follows:
    (1) For substantial harm plans, an operator shall resubmit its 
response plan to OPS every 5 years from the last submission date.
    (2) For significant and substantial harm plans, an operator shall 
resubmit every 5 years from the last approval date.
    (b) If a new or different operating condition or information would 
substantially affect the implementation of a response plan, the operator 
must immediately modify its response plan to address such a change and, 
within 30 days of making such a change, submit the change to PHMSA. 
Examples of changes in operating conditions that would cause a 
significant change to an operator's response plan are:
    (1) An extension of the existing pipeline or construction of a new 
pipeline in a response zone not covered by the previously approved plan;
    (2) Relocation or replacement of the pipeline in a way that 
substantially affects the information included in the response plan, 
such as a change to the worst case discharge volume;
    (3) The type of oil transported, if the type affects the required 
response resources, such as a change from crude oil to gasoline;
    (4) The name of the oil spill removal organization;
    (5) Emergency response procedures;
    (6) The qualified individual;
    (7) A change in the NCP or an ACP that has significant impact on the 
equipment appropriate for response activities; and
    (8) Any other information relating to circumstances that may affect 
full implementation of the plan.
    (c) If PHMSA determines that a change to a response plan does not 
meet the requirements of this part, PHMSA will notify the operator of 
any alleged deficiencies, and provide the operator an opportunity to 
respond, including an opportunity for an informal conference, to any 
proposed plan revisions and an opportunity to correct any deficiencies.
    (d) An operator who disagrees with a determination that proposed 
revisions to a plan are deficient may petition PHMSA for 
reconsideration, within 30 days from the date of receipt of PHMSA's 
notice. After considering all relevant material presented in writing or 
at the conference, PHMSA will notify the operator of its final decision. 
The operator must comply with the final decision within 30 days of 
issuance unless PHMSA allows additional time.

[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-1, 62 FR 67293, Dec. 
24, 1997; Amdt. 194-4, 70 FR 8748, Feb. 23, 2005; 70 FR 11140, Mar. 8, 
2005]





Sec. Appendix A to Part 194--Guidelines for the Preparation of Response 
                                  Plans

    This appendix provides a recommended format for the preparation and 
submission of the response plans required by 49 CFR Part 194. Operators 
are referenced to the most current version of the guidance documents 
listed below. Although these documents contain guidance to assist in 
preparing response plans, their use is not mandatory:
    (1) The ``National Preparedness for Response Exercise Program (PREP) 
Guidelines'' (PREP), which can be found using the search function on the 
USCG's PREP Web page, http://www.uscg.mil;
    (2) The National Response Team's ``Integrated Contingency Plan 
Guidance,'' which can be found using the search function at the National 
Response Center's Web site, http://www.nrt.org and;
    (3) 33 CFR Part 154, Appendix C, ``Guidelines for Determining and 
Evaluating Required Response Resources for Facility Response Plans.''

              Response Plan: Section 1. Information Summary

    Section 1 would include the following:

[[Page 628]]

    (a) For the core plan:
    (1) The name and address of the operator; and
    (2) For each response zone which contains one or more line sections 
that meet the criteria for determining significant and substantial harm 
as described in Sec.  194.103, a listing and description of the response 
zones, including county(s) and state(s).
    (b) For each response zone appendix:
    (1) The information summary for the core plan;
    (2) The name and telephone number of the qualified individual, 
available on a 24-hour basis;
    (3) A description of the response zone, including county(s) and 
state(s) in which a worst case discharge could cause substantial harm to 
the environment;
    (4) A list of line sections contained in the response zone, 
identified by milepost or survey station number or other operator 
designation.
    (5) The basis for the operator's determination of significant and 
substantial harm; and
    (6) The type of oil and volume of the worst case discharge.
    (c) The certification that the operator has obtained, through 
contract or other approved means, the necessary private personnel and 
equipment to respond, to the maximum extent practicable, to a worst case 
discharge or a substantial threat of such a discharge.

            Response Plan: Section 2. Notification Procedures

    Section 2 would include the following:
    (a) Notification requirements that apply in each area of operation 
of pipelines covered by the plan, including applicable State or local 
requirements;
    (b) A checklist of notifications the operator or qualified 
individual is required to make under the response plan, listed in the 
order of priority;
    (c) Names of persons (individuals or organizations) to be notified 
of a discharge, indicating whether notification is to be performed by 
operating personnel or other personnel;
    (d) Procedures for notifying qualified individuals;
    (e) The primary and secondary communication methods by which 
notifications can be made; and
    (f) The information to be provided in the initial and each follow-up 
notification, including the following:
    (1) Name of pipeline;
    (2) Time of discharge;
    (3) Location of discharge;
    (4) Name of oil involved;
    (5) Reason for discharge (e.g., material failure, excavation damage, 
corrosion);
    (6) Estimated volume of oil discharged;
    (7) Weather conditions on scene; and
    (8) Actions taken or planned by persons on scene.

Response Plan: Section 3. Spill Detection and On-Scene Spill Mitigation 
                               Procedures

    Section 3 would include the following:
    (a) Methods of initial discharge detection;
    (b) Procedures, listed in the order of priority, that personnel are 
required to follow in responding to a pipeline emergency to mitigate or 
prevent any discharge from the pipeline;
    (c) A list of equipment that may be needed in response activities on 
land and navigable waters, including--
    (1) Transfer hoses and connection equipment;
    (2) Portable pumps and ancillary equipment; and
    (3) Facilities available to transport and receive oil from a leaking 
pipeline;
    (d) Identification of the availability, location, and contact 
telephone numbers to obtain equipment for response activities on a 24-
hour basis; and
    (e) Identification of personnel and their location, telephone 
numbers, and responsibilities for use of equipment in response 
activities on a 24-hour basis.

              Response Plan: Section 4. Response Activities

    Section 4 would include the following:
    (a) Responsibilities of, and actions to be taken by, operating 
personnel to initiate and supervise response actions pending the arrival 
of the qualified individual or other response resources identified in 
the response plan;
    (b) The qualified individual's responsibilities and authority, 
including notification of the response resources identified in the plan;
    (c) Procedures for coordinating the actions of the operator or 
qualified individual with the action of the OSC responsible for 
monitoring or directing those actions;
    (d) Oil spill response organizations available, through contract or 
other approved means, to respond to a worst case discharge to the 
maximum extent practicable; and
    (e) For each organization identified under paragraph (d) of this 
section, a listing of:
    (1) Equipment and supplies available; and
    (2) Trained personnel necessary to continue operation of the 
equipment and staff the oil spill removal organization for the first 7 
days of the response.

               Response Plan: Section 5. List of Contacts

    Section 5 would include the names and addresses of the following 
individuals or organizations, with telephone numbers at which they can 
be contacted on a 24-hour basis:
    (a) A list of persons the plan requires the operator to contact;
    (b) Qualified individuals for the operator's areas of operation;

[[Page 629]]

    (c) Applicable insurance representatives or surveyors for the 
operator's areas of operation; and
    (d) Persons or organizations to notify for activation of response 
resources.

              Response plan: Section 6. Training Procedures

    Section 6 would include a description of the training procedures and 
programs of the operator.

               Response plan: Section 7. Drill Procedures

    Section 7 would include a description of the drill procedures and 
programs the operator uses to assess whether its response plan will 
function as planned. It would include:
    (a) Announced and unannounced drills;
    (b) The types of drills and their frequencies. For example, drills 
could be described as follows:
    (1) Manned pipeline emergency procedures and qualified individual 
notification drills conducted quarterly.
    (2) Drills involving emergency actions by assigned operating or 
maintenance personnel and notification of the qualified individual on 
pipeline facilities which are normally unmanned, conducted quarterly.
    (3) Shore-based spill management team tabletop drills conducted 
yearly.
    (4) Oil spill removal organization field equipment deployment drills 
conducted yearly.
    (5) A drill that exercises the entire response plan for each 
response zone, would be conducted at least once every 3 years.

  Response plan: Section 8. Response Plan Review and Update Procedures

    Section 8 would include the following:
    (a) Procedures to meet Sec.  194.121; and
    (b) Procedures to review the plan after a worst case discharge and 
to evaluate and record the plan's effectiveness.

           Response plan: Section 9. Response Zone Appendices.

    Each response zone appendix would provide the following information:
    (a) The name and telephone number of the qualified individual;
    (b) Notification procedures;
    (c) Spill detection and mitigation procedures;
    (d) Name, address, and telephone number of oil spill response 
organization;
    (e) Response activities and response resources including--
    (1) Equipment and supplies necessary to meet Sec.  194.115, and
    (2) The trained personnel necessary to sustain operation of the 
equipment and to staff the oil spill removal organization and spill 
management team for the first 7 days of the response;
    (f) Names and telephone numbers of Federal, state and local agencies 
which the operator expects to assume pollution response 
responsibilities;
    (g) The worst case discharge volume;
    (h) The method used to determine the worst case discharge volume, 
with calculations;
    (i) A map that clearly shows--
    (1) The location of the worst case discharge, and
    (2) The distance between each line section in the response zone 
and--
    (i) Each potentially affected public drinking water intake, lake, 
river, and stream within a radius of 5 miles (8 kilometers) of the line 
section, and
    (ii) Each potentially affected environmentally sensitive area within 
a radius of 1 mile (1.6 kilometer) of the line section;
    (j) A piping diagram and plan-profile drawing of each line section, 
which may be kept separate from the response plan if the location is 
identified; and
    (k) For every oil transported by each pipeline in the response zone, 
emergency response data that--
    (1) Include the name, description, physical and chemical 
characteristics, health and safety hazards, and initial spill-handling 
and firefighting methods; and
    (2) Meet 29 CFR 1910.1200 or 49 CFR 172.602.

[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-3, 63 FR 37505, July 
13, 1998; Amdt. 194-4, 70 FR 8748, Feb. 23, 2005]



             Sec. Appendix B to Part 194--High Volume Areas

    As of January 5, 1993 the following areas are high volume areas:

------------------------------------------------------------------------
               Major rivers                    Nearest town and state
------------------------------------------------------------------------
Arkansas River............................  N. Little Rock, AR.
Arkansas River............................  Jenks, OK.
Arkansas River............................  Little Rock, AR.
Black Warrior River.......................  Moundville, AL.
Black Warrior River.......................  Akron, AL.
Brazos River..............................  Glen Rose, TX.
Brazos River..............................  Sealy, TX.
Catawba River.............................  Mount Holly, NC.
Chattahoochee River.......................  Sandy Springs, GA.
Colorado River............................  Yuma, AZ.
Colorado River............................  LaPaz, AZ.
Connecticut River.........................  Lancaster, NH.
Coosa River...............................  Vincent, AL.
Cumberland River..........................  Clarksville, TN.
Delaware River............................  Frenchtown, NJ.
Delaware River............................  Lower Chichester, NJ.
Gila River................................  Gila Bend, AZ.
Grand River...............................  Bosworth, MO.
Illinois River............................  Chillicothe, IL.
Illinois River............................  Havanna, IL.
James River...............................  Arvonia, VA.
Kankakee River............................  Kankakee, IL.
Kankakee River............................  South Bend, IN.
Kankakee River............................  Wilmington, IL.
Kentucky River............................  Salvisa, KY.
Kentucky River............................  Worthville, KY.

[[Page 630]]

 
Maumee River..............................  Defiance, OH.
Maumee River..............................  Toledo, OH.
Mississippi River.........................  Myrtle Grove, LA.
Mississippi River.........................  Woodriver, IL.
Mississippi River.........................  Chester, IL.
Mississippi River.........................  Cape Girardeau, MO.
Mississippi River.........................  Woodriver, IL.
Mississippi River.........................  St. James, LA.
Mississippi River.........................  New Roads, LA.
Mississippi River.........................  Ball Club, MN.
Mississippi River.........................  Mayersville, MS.
Mississippi River.........................  New Roads, LA.
Mississippi River.........................  Quincy, IL.
Mississippi River.........................  Ft. Madison, IA.
Missouri River............................  Waverly, MO.
Missouri River............................  St. Joseph, MO.
Missouri River............................  Weldon Springs, MO.
Missouri River............................  New Frankfort, MO.
Naches River..............................  Beaumont, TX.
Ohio River................................  Joppa, IL.
Ohio River................................  Cincinnati, OH.
Ohio River................................  Owensboro, KY.
Pascagoula River..........................  Lucedale, MS.
Pascagoula River..........................  Wiggins, MS.
Pearl River...............................  Columbia, MS.
Pearl River...............................  Oria, TX.
Platte River..............................  Ogaliala, NE.
Potomac River.............................  Reston, VA.
Rappahannock River........................  Midland, VA.
Raritan River.............................  South Bound Brook, NJ.
Raritan River.............................  Highland Park, NJ.
Red River (of the South)..................  Hanna, LA.
Red River (of the South)..................  Bonham, TX.
Red River (of the South)..................  Dekalb, TX.
Red River (of the South)..................  Sentell Plantation, LA.
Red River (of the North)..................  Wahpeton, ND.
Rio Grande................................  Anthony, NM.
Sabine River..............................  Edgewood, TX.
Sabine River..............................  Leesville, LA.
Sabine River..............................  Orange, TX.
Sabine River..............................  Echo, TX.
Savannah River............................  Hartwell, GA.
Smokey Hill River.........................  Abilene, KS.
Susquehanna River.........................  Darlington, MD.
Tenessee River............................  New Johnsonville, TN.
Wabash River..............................  Harmony, IN.
Wabash River..............................  Terre Haute, IN.
Wabash River..............................  Mt. Carmel, IL.
White River...............................  Batesville, AR.
White River...............................  Grand Glaise, AR.
Wisconsin River...........................  Wisconsin Rapids, WI.
Yukon River...............................  Fairbanks, AK.
------------------------------------------------------------------------

                         Other Navigable Waters

Arthur Kill Channel, NY
Cook Inlet, AK
Freeport, TX
Los Angeles/Long Beach Harbor, CA
Port Lavaca, TX
San Fransico/San Pablo Bay, CA



PART 195_TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE--Table of  
                                 Contents



                            Subpart A_General

Sec.
195.0 Scope.
195.1 Which pipelines are covered by this part?
195.2 Definitions.
195.3 What documents are incorporated by reference partly or wholly in 
          this part?
195.4 Compatibility necessary for transportation of hazardous liquids or 
          carbon dioxide.
195.5 Conversion to service subject to this part.
195.6 Unusually Sensitive Areas (USAs).
195.8 Transportation of hazardous liquid or carbon dioxide in pipelines 
          constructed with other than steel pipe.
195.9 Outer continental shelf pipelines.
195.10 Responsibility of operator for compliance with this part.
195.11 What is a regulated rural gathering line and what requirements 
          apply?
195.12 What requirements apply to low-stress pipelines in rural areas?
195.13 What requirements apply to pipelines transporting hazardous 
          liquids by gravity?
195.15 What requirements apply to reporting-regulated-only gathering 
          lines?
195.18 Valves: Onshore valve shut-off for rupture mitigation.

   Subpart B_Annual, Accident, and Safety-Related Condition Reporting

195.48 Scope.
195.49 Annual report.
195.50 Reporting accidents.
195.52 Immediate notice of certain accidents.
195.54 Accident reports.
195.55 Reporting safety-related conditions.
195.56 Filing safety-related condition reports.
195.58 Report submission requirements.
195.59 Abandonment or deactivation of facilities.
195.60 Operator assistance in investigation.
195.61 National pipeline mapping system.
195.63 OMB control number assigned to information collection.
195.64 National Registry of Operators.
195.65 Safety data sheets.

                      Subpart C_Design Requirements

195.100 Scope.
195.101 Qualifying metallic components other than pipe.
195.102 Design temperature.
195.104 Variations in pressure.
195.106 Internal design pressure.
195.108 External pressure.
195.110 External loads.
195.111 Fracture propagation.
195.112 New pipe.
195.114 Used pipe.
195.116 Valves.
195.118 Fittings.
195.120 Passage of internal inspection devices.
195.122 Fabricated branch connections.

[[Page 631]]

195.124 Closures.
195.126 Flange connection.
195.128 Station piping.
195.130 Fabricated assemblies.
195.132 Design and construction of aboveground breakout tanks.
195.134 Leak detection.

                         Subpart D_Construction

195.200 Scope.
195.202 Compliance with specifications or standards.
195.204 Inspection--general.
195.205 Repair, alteration and reconstruction of aboveground breakout 
          tanks that have been in service.
195.206 Material inspection.
195.207 Transportation of pipe.
195.208 Welding of supports and braces.
195.210 Pipeline location.
195.212 Bending of pipe.
195.214 Welding: General.
195.216 Welding: Miter joints.
195.222 Welders and welding operators: Qualification of welders and 
          welding operators.
195.224 Welding: Weather.
195.226 Welding: Arc burns.
195.228 Welds and welding inspection: Standards of acceptability.
195.230 Welds: Repair or removal of defects.
195.234 Welds: Nondestructive testing.
195.236-195.244 [Reserved]
195.246 Installation of pipe in a ditch.
195.248 Cover over buried pipeline.
195.250 Clearance between pipe and underground structures.
195.252 Backfilling.
195.254 Above ground components.
195.256 Crossing of railroads and highways.
195.258 Valves: General.
195.260 Valves: Location.
195.262 Pumping equipment.
195.264 Impoundment, protection against entry, normal/emergency venting 
          or pressure/vacuum relief for aboveground breakout tanks.
195.266 Construction records.

                       Subpart E_Pressure Testing

195.300 Scope.
195.302 General requirements.
195.303 Risk-based alternative to pressure testing older hazardous 
          liquid and carbon dioxide pipelines.
195.304 Test pressure.
195.305 Testing of components.
195.306 Test medium.
195.307 Pressure testing aboveground breakout tanks.
195.308 Testing of tie-ins.
195.310 Records.

                   Subpart F_Operation and Maintenance

195.400 Scope.
195.401 General requirements.
195.402 Procedural manual for operations, maintenance, and emergencies.
195.403 Emergency response training.
195.404 Maps and records.
195.405 Protection against ignitions and safe access/egress involving 
          floating roofs.
195.406 Maximum operating pressure.
195.408 Communications.
195.410 Line markers.
195.412 Inspection of rights-of-way and crossings under navigable 
          waters.
195.413 Underwater inspection and reburial of pipelines in the Gulf of 
          Mexico and its inlets.
195.414 Inspections of pipelines in areas affected by extreme weather 
          and natural disasters.
195.415 [Reserved]
195.416 Pipeline assessments.
195.417 Notification of potential rupture.
195.418 Valves: Onshore valve shut-off for rupture mitigation.
195.419 Valve capabilities.
195.420 Valve maintenance.
195.422 Pipeline repairs.
195.424 Pipe movement.
195.426 Scraper and sphere facilities.
195.428 Overpressure safety devices and overfill protection systems.
195.430 Firefighting equipment.
195.432 Inspection of in-service breakout tanks.
195.434 Signs.
195.436 Security of facilities.
195.438 Smoking or open flames.
195.440 Public awareness.
195.442 Damage prevention program.
195.444 Leak detection.
195.446 Control room management.

                         High Consequence Areas

195.450 Definitions.

                      Pipeline Integrity Management

195.452 Pipeline integrity management in high consequence areas.
195.454 Integrity assessments for certain underwater hazardous liquid 
          pipeline facilities located in high consequence areas.

              Subpart G_Qualification of Pipeline Personnel

195.501 Scope.
195.503 Definitions.
195.505 Qualification program.
195.507 Recordkeeping.
195.509 General.

                       Subpart H_Corrosion Control

195.551 What do the regulations in this subpart cover?
195.553 What special definitions apply to this subpart?

[[Page 632]]

195.555 What are the qualifications for supervisors?
195.557 Which pipelines must have coating for external corrosion 
          control?
195.559 What coating material may I use for external corrosion control?
195.561 When must I inspect pipe coating used for external corrosion 
          control?
195.563 Which pipelines must have cathodic protection?
195.565 How do I install cathodic protection on breakout tanks?
195.567 Which pipelines must have test leads and what must I do to 
          install and maintain the leads?
195.569 Do I have to examine exposed portions of buried pipelines?
195.571 What criteria must I use to determine the adequacy of cathodic 
          protection?
195.573 What must I do to monitor external corrosion control?
195.575 Which facilities must I electrically isolate and what 
          inspections, tests, and safeguards are required?
195.577 What must I do to alleviate interference currents?
195.579 What must I do to mitigate internal corrosion?
195.581 Which pipelines must I protect against atmospheric corrosion and 
          what coating material may I use?
195.583 What must I do to monitor atmospheric corrosion control?
195.585 What must I do to correct corroded pipe?
195.587 What methods are available to determine the strength of corroded 
          pipe?
195.588 What standards apply to direct assessment?
195.589 What corrosion control information do I have to maintain?
195.591 In-Line inspection of pipelines.

Appendix A to Part 195--Delineation Between Federal and State 
          Jurisdiction--Statement of Agency Policy and Interpretation
Appendix B to Part 195--Risk-Based Alternative to Pressure Testing Older 
          Hazardous Liquid and Carbon Dioxide Pipelines
Appendix C to Part 195--Guidance for Implementation of an Integrity 
          Management Program

    Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et seq., and 
49 CFR 1.97.

    Source: Amdt. 195-22, 46 FR 38360, July 27, 1981, unless otherwise 
noted.

    Editorial Note: Nomenclature changes to part 195 appear at 71 FR 
33409, June 9, 2006.



                            Subpart A_General



Sec.  195.0  Scope.

    This part prescribes safety standards and reporting requirements for 
pipeline facilities used in the transportation of hazardous liquids or 
carbon dioxide.

[Amdt. 195-45, 56 FR 26925, June 12, 1991]



Sec.  195.1  Which pipelines are covered by this Part?

    (a) Covered. Except for the pipelines listed in paragraph (b) of 
this Section, this Part applies to pipeline facilities and the 
transportation of hazardous liquids or carbon dioxide associated with 
those facilities in or affecting interstate or foreign commerce, 
including pipeline facilities on the Outer Continental Shelf (OCS). 
Covered pipelines include, but are not limited to:
    (1) Any pipeline that transports a highly volatile liquid;
    (2) Any pipeline segment that crosses a waterway currently used for 
commercial navigation;
    (3) Except for a gathering line not covered by paragraph (a)(4) of 
this Section, any pipeline located in a rural or non-rural area of any 
diameter regardless of operating pressure;
    (4) Any of the following onshore gathering lines used for 
transportation of petroleum:
    (i) A pipeline located in a non-rural area;
    (ii) A regulated rural gathering line as provided in Sec.  195.11; 
or
    (iii) A pipeline located in an inlet of the Gulf of Mexico as 
provided in Sec.  195.413.
    (5) For purposes of the reporting requirements in subpart B of this 
part, any gathering line not already covered under paragraphs (a)(1), 
(2), (3) or (4) of this section.
    (b) Excepted. This Part does not apply to any of the following:
    (1) Transportation of a hazardous liquid transported in a gaseous 
state;
    (2) Except for the reporting requirements of subpart B of this part, 
see Sec.  195.13, transportation of a hazardous liquid through a 
pipeline by gravity.
    (3) Transportation of a hazardous liquid through any of the 
following low-stress pipelines:
    (i) A pipeline subject to safety regulations of the U.S. Coast 
Guard; or

[[Page 633]]

    (ii) A pipeline that serves refining, manufacturing, or truck, rail, 
or vessel terminal facilities, if the pipeline is less than one mile 
long (measured outside facility grounds) and does not cross an offshore 
area or a waterway currently used for commercial navigation;
    (4) Except for the reporting requirements of subpart B of this part, 
see Sec.  195.15, transportation of petroleum through an onshore rural 
gathering line that does not meet the definition of a ``regulated rural 
gathering line'' as provided in Sec.  195.11. This exception does not 
apply to gathering lines in the inlets of the Gulf of Mexico subject to 
Sec.  195.413.
    (5) Transportation of hazardous liquid or carbon dioxide in an 
offshore pipeline in state waters where the pipeline is located upstream 
from the outlet flange of the following farthest downstream facility: 
The facility where hydrocarbons or carbon dioxide are produced or the 
facility where produced hydrocarbons or carbon dioxide are first 
separated, dehydrated, or otherwise processed;
    (6) Transportation of hazardous liquid or carbon dioxide in a 
pipeline on the OCS where the pipeline is located upstream of the point 
at which operating responsibility transfers from a producing operator to 
a transporting operator;
    (7) A pipeline segment upstream (generally seaward) of the last 
valve on the last production facility on the OCS where a pipeline on the 
OCS is producer-operated and crosses into state waters without first 
connecting to a transporting operator's facility on the OCS. Safety 
equipment protecting PHMSA-regulated pipeline segments is not excluded. 
A producing operator of a segment falling within this exception may 
petition the Administrator, under Sec.  190.9 of this chapter, for 
approval to operate under PHMSA regulations governing pipeline design, 
construction, operation, and maintenance;
    (8) Transportation of hazardous liquid or carbon dioxide through 
onshore production (including flow lines), refining, or manufacturing 
facilities or storage or in-plant piping systems associated with such 
facilities;
    (9) Transportation of hazardous liquid or carbon dioxide:
    (i) By vessel, aircraft, tank truck, tank car, or other non-pipeline 
mode of transportation; or
    (ii) Through facilities located on the grounds of a materials 
transportation terminal if the facilities are used exclusively to 
transfer hazardous liquid or carbon dioxide between non-pipeline modes 
of transportation or between a non-pipeline mode and a pipeline. These 
facilities do not include any device and associated piping that are 
necessary to control pressure in the pipeline under Sec.  195.406(b); or
    (10) Transportation of carbon dioxide downstream from the applicable 
following point:
    (i) The inlet of a compressor used in the injection of carbon 
dioxide for oil recovery operations, or the point where recycled carbon 
dioxide enters the injection system, whichever is farther upstream; or
    (ii) The connection of the first branch pipeline in the production 
field where the pipeline transports carbon dioxide to an injection well 
or to a header or manifold from which a pipeline branches to an 
injection well.
    (c) Breakout tanks. Breakout tanks subject to this Part must comply 
with requirements that apply specifically to breakout tanks and, to the 
extent applicable, with requirements that apply to pipeline systems and 
pipeline facilities. If a conflict exists between a requirement that 
applies specifically to breakout tanks and a requirement that applies to 
pipeline systems or pipeline facilities, the requirement that applies 
specifically to breakout tanks prevails. Anhydrous ammonia breakout 
tanks need not comply with Sec. Sec.  195.132(b), 195.205(b), 195.242(c) 
and (d), 195.264(b) and (e), 195.307, 195.428(c) and (d), and 195.432(b) 
and (c).

    Editorial Note: For Federal Register citations affecting Sec.  
195.1, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.govinfo.gov.



Sec.  195.2  Definitions.

    As used in this part--
    Abandoned means permanently removed from service.

[[Page 634]]

    Administrator means the Administrator, Pipeline and Hazardous 
Materials Safety Administration or his or her delegate.
    Alarm means an audible or visible means of indicating to the 
controller that equipment or processes are outside operator-defined, 
safety-related parameters.
    Barrel means a unit of measurement equal to 42 U.S. standard 
gallons.
    Breakout tank means a tank used to (a) relieve surges in a hazardous 
liquid pipeline system or (b) receive and store hazardous liquid 
transported by a pipeline for reinjection and continued transportation 
by pipeline.
    Carbon dioxide means a fluid consisting of more than 90 percent 
carbon dioxide molecules compressed to a supercritical state.
    Component means any part of a pipeline which may be subjected to 
pump pressure including, but not limited to, pipe, valves, elbows, tees, 
flanges, and closures.
    Computation Pipeline Monitoring (CPM) means a software-based 
monitoring tool that alerts the pipeline dispatcher of a possible 
pipeline operating anomaly that may be indicative of a commodity 
release.
    Confirmed Discovery means when it can be reasonably determined, 
based on information available to the operator at the time a reportable 
event has occurred, even if only based on a preliminary evaluation.
    Control room means an operations center staffed by personnel charged 
with the responsibility for remotely monitoring and controlling a 
pipeline facility.
    Controller means a qualified individual who remotely monitors and 
controls the safety-related operations of a pipeline facility via a 
SCADA system from a control room, and who has operational authority and 
accountability for the remote operational functions of the pipeline 
facility.
    Corrosive product means ``corrosive material'' as defined by Sec.  
173.136 Class 8-Definitions of this chapter.
    Entirely replaced onshore hazardous liquid or carbon dioxide 
pipeline segments, for the purposes of Sec. Sec.  195.258, 195.260, and 
195.418, means where 2 or more miles of pipe, in the aggregate, have 
been replaced within any 5 contiguous miles within any 24-month period. 
This definition does not apply to any gathering line.
    Exposed underwater pipeline means an underwater pipeline where the 
top of the pipe protrudes above the underwater natural bottom (as 
determined by recognized and generally accepted practices) in waters 
less than 15 feet (4.6 meters) deep, as measured from mean low water.
    Flammable product means ``flammable liquid'' as defined by Sec.  
173.120 Class 3-Definitions of this chapter.
    Gathering line means a pipeline 219.1 mm (8\5/8\ in) or less nominal 
outside diameter that transports petroleum from a production facility.
    Gulf of Mexico and its inlets means the waters from the mean high 
water mark of the coast of the Gulf of Mexico and its inlets open to the 
sea (excluding rivers, tidal marshes, lakes, and canals) seaward to 
include the territorial sea and Outer Continental Shelf to a depth of 15 
feet (4.6 meters), as measured from the mean low water.
    Hazard to navigation means, for the purposes of this part, a 
pipeline where the top of the pipe is less than 12 inches (305 
millimeters) below the underwater natural bottom (as determined by 
recognized and generally accepted practices) in waters less than 15 feet 
(4.6 meters) deep, as measured from the mean low water.
    Hazardous liquid means petroleum, petroleum products, anhydrous 
ammonia, and ethanol or other non-petroleum fuel, including biofuel, 
which is flammable, toxic, or would be harmful to the environment if 
released in significant quantities.
    Highly volatile liquid or HVL means a hazardous liquid which will 
form a vapor cloud when released to the atmosphere and which has a vapor 
pressure exceeding 276 kPa (40 psia) at 37.8 [deg]C (100 [deg]F).
    In-Line Inspection (ILI) means the inspection of a pipeline from the 
interior of the pipe using an in-line inspection tool. Also called 
intelligent or smart pigging.
    In-Line Inspection Tool or Instrumented Internal Inspection Device 
means a device or vehicle that uses a non-destructive testing technique 
to inspect

[[Page 635]]

the pipeline from the inside. Also known as intelligent or smart pig.
    In-plant piping system means piping that is located on the grounds 
of a plant and used to transfer hazardous liquid or carbon dioxide 
between plant facilities or between plant facilities and a pipeline or 
other mode of transportation, not including any device and associated 
piping that are necessary to control pressure in the pipeline under 
Sec.  195.406(b).
    Interstate pipeline means a pipeline or that part of a pipeline that 
is used in the transportation of hazardous liquids or carbon dioxide in 
interstate or foreign commerce.
    Intrastate pipeline means a pipeline or that part of a pipeline to 
which this part applies that is not an interstate pipeline.
    Line section means a continuous run of pipe between adjacent 
pressure pump stations, between a pressure pump station and terminal or 
breakout tanks, between a pressure pump station and a block valve, or 
between adjacent block valves.
    Low-stress pipeline means a hazardous liquid pipeline that is 
operated in its entirety at a stress level of 20 percent or less of the 
specified minimum yield strength of the line pipe.
    Maximum operating pressure (MOP) means the maximum pressure at which 
a pipeline or segment of a pipeline may be normally operated under this 
part.
    Nominal wall thickness means the wall thickness listed in the pipe 
specifications.
    Notification of potential rupture means the notification to, or 
observation by, an operator of indicia identified in Sec.  195.417 of a 
potential unintentional or uncontrolled release of a large volume of 
commodity from a pipeline. This definition does not apply to any 
gathering line.
    Offshore means beyond the line of ordinary low water along that 
portion of the coast of the United States that is in direct contact with 
the open seas and beyond the line marking the seaward limit of inland 
waters.
    Operator means a person who owns or operates pipeline facilities.
    Outer Continental Shelf means all submerged lands lying seaward and 
outside the area of lands beneath navigable waters as defined in Section 
2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil 
and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Person means any individual, firm, joint venture, partnership, 
corporation, association, State, municipality, cooperative association, 
or joint stock association, and includes any trustee, receiver, 
assignee, or personal representative thereof.
    Petroleum means crude oil, condensate, natural gasoline, natural gas 
liquids, and liquefied petroleum gas.
    Petroleum product means flammable, toxic, or corrosive products 
obtained from distilling and processing of crude oil, unfinished oils, 
natural gas liquids, blend stocks and other miscellaneous hydrocarbon 
compounds.
    Pipe or line pipe means a tube, usually cylindrical, through which a 
hazardous liquid or carbon dioxide flows from one point to another.
    Pipeline or pipeline system means all parts of a pipeline facility 
through which a hazardous liquid or carbon dioxide moves in 
transportation, including, but not limited to, line pipe, valves, and 
other appurtenances connected to line pipe, pumping units, fabricated 
assemblies associated with pumping units, metering and delivery stations 
and fabricated assemblies therein, and breakout tanks.
    Pipeline facility means new and existing pipe, rights-of-way and any 
equipment, facility, or building used in the transportation of hazardous 
liquids or carbon dioxide.
    Production facility means piping or equipment used in the 
production, extraction, recovery, lifting, stabilization, separation or 
treating of petroleum or carbon dioxide, or associated storage or 
measurement. (To be a production facility under this definition, piping 
or equipment must be used in the process of extracting petroleum or 
carbon dioxide from the ground or from facilities where CO2 
is produced, and preparing it for transportation by pipeline. This 
includes piping between treatment plants which extract carbon dioxide, 
and facilities utilized for the injection of carbon dioxide for recovery 
operations.)

[[Page 636]]

    Rupture-mitigation valve (RMV) means an automatic shut-off valve 
(ASV) or a remote-control valve (RCV) that a pipeline operator uses to 
minimize the volume of hazardous liquid or carbon dioxide released from 
the pipeline and to mitigate the consequences of a rupture. This 
definition does not apply to any gathering line.
    Rural area means outside the limits of any incorporated or 
unincorpated city, town, village, or any other designated residential or 
commercial area such as a subdivision, a business or shopping center, or 
community development.
    Significant Stress Corrosion Cracking means a stress corrosion 
cracking (SCC) cluster in which the deepest crack, in a series of 
interacting cracks, is greater than 10% of the wall thickness and the 
total interacting length of the cracks is equal to or greater than 75% 
of the critical length of a 50% through-wall flaw that would fail at a 
stress level of 110% of SMYS.
    Specified minimum yield strength means the minimum yield strength, 
expressed in p.s.i. (kPa) gage, prescribed by the specification under 
which the material is purchased from the manufacturer.
    Stress level means the level of tangential or hoop stress, usually 
expressed as a percentage of specified minimum yield strength.
    Supervisory Control and Data Acquisition (SCADA) system means a 
computer-based system or systems used by a controller in a control room 
that collects and displays information about a pipeline facility and may 
have the ability to send commands back to the pipeline facility.
    Surge pressure means pressure produced by a change in velocity of 
the moving stream that results from shutting down a pump station or 
pumping unit, closure of a valve, or any other blockage of the moving 
stream.
    Toxic product means ``poisonous material'' as defined by Sec.  
173.132 Class 6, Division 6.1-Definitions of this chapter.
    Unusually Sensitive Area (USA) means a drinking water or ecological 
resource area that is unusually sensitive to environmental damage from a 
hazardous liquid pipeline release, as identified under Sec.  195.6.
    Welder means a person who performs manual or semi-automatic welding.
    Welding operator means a person who operates machine or automatic 
welding equipment.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982]

    Editorial Note: For Federal Register citations affecting Sec.  
195.2, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.govinfo.gov.



Sec.  195.3  What documents are incorporated by reference partly or wholly 
in this part?

    (a) This part prescribes standards, or portions thereof, 
incorporated by reference into this part with the approval of the 
Director of the Federal Register in 5 U.S.C. 552(a) and 1 CFR part 51. 
The materials listed in this section have the full force of law. To 
enforce any edition other than that specified in this section, PHMSA 
must publish a notice of change in the Federal Register.
    (1) Availability of standards incorporated by reference. All of the 
materials incorporated by reference are available for inspection from 
several sources, including the following:
    (i) The Office of Pipeline Safety, Pipeline and Hazardous Materials 
Safety Administration, 1200 New Jersey Avenue SE., Washington, DC 20590. 
For more information contact 202-366-4046 or go to the PHMSA Web site 
at: http://www.phmsa.dot.gov/pipeline/regs.
    (ii) The National Archives and Records Administration (NARA). For 
information on the availability of this material at NARA, call 202-741-
6030 or go to the NARA Web site at: http://www.archives.gov/
federal_register/code_of_federal_regulations/ibr_locations.html.
    (iii) Copies of standards incorporated by reference in this part can 
also be purchased from the respective standards-developing organization 
at the addresses provided in the centralized IBR section below.
    (b) American Petroleum Institute (API), 1220 L Street NW., 
Washington, DC 20005, and phone: 202-682-8000, Web site: http://
api.org/.
    (1) API Publication 2026, ``Safe Access/Egress Involving Floating 
Roofs of

[[Page 637]]

Storage Tanks in Petroleum Service,'' 2nd edition, April 1998 
(reaffirmed June 2006) (API Pub 2026), IBR approved for Sec.  
195.405(b).
    (2) API Recommended Practice 5L1, ``Recommended Practice for 
Railroad Transportation of Line Pipe,'' 7th edition, September 2009, 
(API RP 5L1), IBR approved for Sec.  195.207(a).
    (3) API Recommended Practice 5LT, ``Recommended Practice for Truck 
Transportation of Line Pipe,'' First edition, March 12, 2012, (API RP 
5LT), IBR approved for Sec.  195.207(c).
    (4) API Recommended Practice 5LW, ``Recommended Practice 
Transportation of Line Pipe on Barges and Marine Vessels,'' 3rd edition, 
September 2009, (API RP 5LW), IBR approved for Sec.  195.207(b).
    (5) ANSI/API Recommended Practice 651, ``Cathodic Protection of 
Aboveground Petroleum Storage Tanks,'' 3rd edition, January 2007, (ANSI/
API RP 651), IBR approved for Sec. Sec.  195.565 and 195.573(d).
    (6) ANSI/API Recommended Practice 652, ``Linings of Aboveground 
Petroleum Storage Tank Bottoms,'' 3rd edition, October 2005, (API RP 
652), IBR approved for Sec.  195.579(d).
    (7) API Recommended Practice 1130, ``Computational Pipeline 
Monitoring for Liquids: Pipeline Segment,'' 3rd edition, September 2007, 
(API RP 1130), IBR approved for Sec. Sec.  195.134 and 195.444.
    (8) API Recommended Practice 1162, ``Public Awareness Programs for 
Pipeline Operators,'' 1st edition, December 2003, (API RP 1162), IBR 
approved for Sec.  195.440(a), (b), and (c).
    (9) API Recommended Practice 1165, ``Recommended Practice for 
Pipeline SCADA Displays,'' First edition, January 2007, (API RP 1165), 
IBR approved for Sec.  195.446(c).
    (10) API Recommended Practice 1168, ``Pipeline Control Room 
Management,'' First edition, September 2008, (API RP 1168), IBR approved 
for Sec.  195.446(c) and (f).
    (11) API Recommended Practice 2003, ``Protection against Ignitions 
Arising out of Static, Lightning, and Stray Currents,'' 7th edition, 
January 2008, (API RP 2003), IBR approved for Sec.  195.405(a).
    (12) API Recommended Practice 2350, ``Overfill Protection for 
Storage Tanks in Petroleum Facilities,'' 3rd edition, January 2005, (API 
RP 2350), IBR approved for Sec.  195.428(c).
    (13) API Specification 5L, ``Specification for Line Pipe,'' 45th 
edition, effective July 1, 2013, (ANSI/API Spec 5L), IBR approved for 
Sec.  195.106(b) and (e).
    (14) ANSI/API Specification 6D, ``Specification for Pipeline 
Valves,'' 23rd edition, effective October 1, 2008, (including Errata 1 
(June 2008), Errata 2 (November 2008), Errata 3 (February 2009), Errata 
4 (April 2010), Errata 5 (November 2010), and Errata 6 (August 2011); 
Addendum 1 (October 2009), Addendum 2 (August 2011), and Addendum 3 
(October 2012)); (ANSI/API Spec 6D), IBR approved for Sec.  195.116(d).
    (15) API Specification 12F, ``Specification for Shop Welded Tanks 
for Storage of Production Liquids,'' 12th edition, October 2008, 
effective April 1, 2009, (API Spec 12F), IBR approved for Sec. Sec.  
195.132(b); 195.205(b); 195.264(b) and (e); 195.307(a); 195.565; 
195.579(d).
    (16) API Standard 510, ``Pressure Vessel Inspection Code: In-Service 
Inspection, Rating, Repair, and Alteration,'' 9th edition, June 2006, 
(API Std 510), IBR approved for Sec. Sec.  195.205(b); 195.432(c).
    (17) API Standard 620, ``Design and Construction of Large, Welded, 
Low-Pressure Storage Tanks,'' 11th edition February 2008 (including 
addendum 1 (March 2009), addendum 2 (August 2010), and addendum 3 (March 
2012)), (API Std 620), IBR approved for Sec. Sec.  195.132(b); 
195.205(b); 195.264(b) and (e); 195.307(b); 195.565, 195.579(d).
    (18) API Standard 650, ``Welded Steel Tanks for Oil Storage,'' 11th 
edition, June 2007, effective February 1, 2012, (including addendum 1 
(November 2008), addendum 2 (November 2009), addendum 3 (August 2011), 
and errata (October 2011)), (API Std 650), IBR approved for Sec. Sec.  
195.132(b); 195.205(b); 195.264(b), (e); 195.307(c) and (d); 195.565; 
195.579(d).
    (19) API Standard 653, ``Tank Inspection, Repair, Alteration, and 
Reconstruction,'' 3rd edition, December 2001, (including addendum 1 
(September 2003), addendum 2 (November 2005), addendum 3 (February 
2008), and errata (April 2008)), (API Std 653), IBR approved for 
Sec. Sec.  195.205(b), 195.307(d), and 195.432(b).

[[Page 638]]

    (20) API Standard 1104, ``Welding of Pipelines and Related 
Facilities,'' 20th edition, October 2005, (including errata/addendum 
(July 2007) and errata 2 (2008), (API Std 1104)), IBR approved for 
Sec. Sec.  195.214(a), 195.222(a) and (b), 195.228(b).
    (21) ANSI/API Standard 2000, ``Venting Atmospheric and Low-pressure 
Storage Tanks,'' 6th edition, November 2009, (ANSI/API Std 2000), IBR 
approved for Sec.  195.264(e).
    (22) API Standard 2510, ``Design and Construction of LPG 
Installations,'' 8th edition, 2001, (API Std 2510), IBR approved for 
Sec. Sec.  195.132(b), 195.205(b), 195.264 (b), (e); 195.307 (e), 
195.428 (c); and 195.432 (c).
    (23) API Standard 1163, ``In-Line Inspection Systems Qualification'' 
Second edition, April 2013, (API Std 1163), IBR approved for Sec.  
195.591.
    (c) ASME International (ASME), Two Park Avenue, New York, NY 10016, 
800-843-2763 (U.S/Canada), Web site: http://www.asme.org/.
    (1) ASME/ANSI B16.9-2007, ``Factory-Made Wrought Buttwelding 
Fittings,'' December 7, 2007, (ASME/ANSI B16.9), IBR approved for Sec.  
195.118(a).
    (2) ASME/ANSI B31G-1991 (Reaffirmed 2004), ``Manual for Determining 
the Remaining Strength of Corroded Pipelines,'' 2004, (ASME/ANSI B31G), 
IBR approved for Sec. Sec.  195.452(h); 195.587; and 195.588(c).
    (3) ASME/ANSI B31.4-2006, ``Pipeline Transportation Systems for 
Liquid Hydrocarbons and Other Liquids'' October 20, 2006, (ASME/ANSI 
B31.4), IBR approved for Sec. Sec.  195.110(a); 195.452(h).
    (4) ASME/ANSI B31.8-2007, ``Gas Transmission and Distribution Piping 
Systems,'' November 30, 2007, (ASME/ANSI B31.8), IBR approved for 
Sec. Sec.  195.5(a) and 195.406(a).
    (5) ASME Boiler & Pressure Vessel Code, Section VIII, Division 1, 
``Rules for Construction of Pressure Vessels,'' 2007 edition, July 1, 
2007, (ASME BPVC, Section VIII, Division 1), IBR approved for Sec. Sec.  
195.124 and 195.307(e).
    (6) ASME Boiler & Pressure Vessel Code, Section VIII, Division 2, 
``Alternate Rules, Rules for Construction of Pressure Vessels,'' 2007 
edition, July 1, 2007, (ASME BPVC, Section VIII, Division 2), IBR 
approved for Sec.  195.307(e).
    (7) ASME Boiler & Pressure Vessel Code, Section IX: ``Qualification 
Standard for Welding and Brazing Procedures, Welders, Brazers, and 
Welding and Brazing Operators,'' 2007 edition, July 1, 2007, (ASME BPVC, 
Section IX), IBR approved for Sec.  195.222(a).
    (d) American Society for Nondestructive Testing, P.O. Box 28518, 
1711 Arlingate Lane, Columbus, OH 43228. https://asnt.org.
    (1) ANSI/ASNT ILI-PQ-2005(2010), ``In-line Inspection Personnel 
Qualification and Certification'' reapproved October 11, 2010, (ANSI/
ASNT ILI-PQ), IBR approved for Sec.  195.591.
    (2) [Reserved]
    (e) American Society for Testing and Materials (ASTM), 100 Barr 
Harbor Drive, P.O. Box C700, West Conshohocken, PA 119428, phone: 610-
832-9585, Web site: http://www.astm.org/.
    (1) ASTM A53/A53M-10, ``Standard Specification for Pipe, Steel, 
Black and Hot-Dipped, Zinc-Coated, Welded and Seamless,'' approved 
October 1, 2010, (ASTM A53/A53M), IBR approved for Sec.  195.106(e).
    (2) ASTM A106/A106M-10, ``Standard Specification for Seamless Carbon 
Steel Pipe for High-Temperature Service,'' approved April 1, 2010, (ASTM 
A106/A106M), IBR approved for Sec.  195.106(e).
    (3) ASTM A333/A333M-11, ``Standard Specification for Seamless and 
Welded Steel Pipe for Low-Temperature Service,'' approved April 1, 2011, 
(ASTM A333/A333M), IBR approved for Sec.  195.106(e).
    (4) ASTM A381-96 (Reapproved 2005), ``Standard Specification for 
Metal-Arc Welded Steel Pipe for Use with High-Pressure Transmission 
Systems,'' approved October 1, 2005, (ASTM A381), IBR approved for Sec.  
195.106(e).
    (5) ASTM A671/A671M-10, ``Standard Specification for Electric-
Fusion-Welded Steel Pipe for Atmospheric and Lower Temperatures,'' 
approved April 1, 2010, (ASTM A671/A671M), IBR approved for Sec.  
195.106(e).
    (6) ASTM A672/A672M-09, ``Standard Specification for Electric-
Fusion-Welded Steel Pipe for High-Pressure Service at Moderate 
Temperatures,'' approved October 1, 2009, (ASTM A672/A672M), IBR 
approved for Sec.  195.106(e).
    (7) ASTM A691/A691M-09, ``Standard Specification for Carbon and 
Alloy Steel Pipe, Electric-Fusion-Welded for

[[Page 639]]

High-Pressure Service at High Temperatures,'' approved October 1, 2009, 
(ASTM A691), IBR approved for Sec.  195.106(e).
    (f) Manufacturers Standardization Society of the Valve and Fittings 
Industry, Inc. (MSS), 127 Park St. NE., Vienna, VA 22180, phone: 703-
281-6613, Web site: http://www.mss-hq.org/.
    (1) MSS SP-75-2008 Standard Practice, ``Specification for High-Test, 
Wrought, Butt-Welding Fittings,'' 2008 edition, (MSS SP 75), IBR 
approved for Sec.  195.118(a).
    (2) [Reserved]
    (g) NACE International (NACE), 1440 South Creek Drive, Houston, TX 
77084, phone: 281-228-6223 or 800-797-6223, Web site: http://
www.nace.org/Publications/.
    (1) NACE SP0169-2007, Standard Practice, ``Control of External 
Corrosion on Underground or Submerged Metallic Piping Systems'' 
reaffirmed March 15, 2007, (NACE SP0169), IBR approved for Sec. Sec.  
195.571 and 195.573(a).
    (2) ANSI/NACE SP0502-2010, Standard Practice, ``Pipeline External 
Corrosion Direct Assessment Methodology,'' June 24, 2010, (NACE SP0502), 
IBR approved for Sec.  195.588(b).
    (3) NACE SP0102-2010, ``Standard Practice, Inline Inspection of 
Pipelines'' revised March 13, 2010, (NACE SP0102), IBR approved for 
Sec. Sec.  195.120 and 195.591.
    (4) NACE SP0204-2008, ``Standard Practice, Stress Corrosion Cracking 
(SSC) Direct Assessment Methodology'' reaffirmed September 18, 2008, 
(NACE SP0204), IBR approved for Sec.  195.588(c).
    (h) National Fire Protection Association (NFPA), 1 Batterymarch 
Park, Quincy, MA 02169, phone: 617-984-7275, Web site: http://
www.nfpa.org/.
    (1) NFPA-30 (2012), ``Flammable and Combustible Liquids Code,'' 
including Errata 30-12-1 (9/27/11), and Errata 30-12-2 (11/14/11), 2012 
edition, copyright 2011, (NFPA-30), IBR approved for Sec.  195.264(b).
    (2) [Reserved]
    (i) Pipeline Research Council International, Inc. (PRCI), c/o 
Technical Toolboxes, 3801 Kirby Drive, Suite 520, P.O. Box 980550, 
Houston, TX 77098, phone: 713-630-0505, toll free: 866-866-6766, Web 
site: http://www.ttoolboxes.com/.
    (1) AGA Pipeline Research Committee, Project PR-3-805 ``A Modified 
Criterion for Evaluating the Remaining Strength of Corroded Pipe,'' 
December 22, 1989, (PR-3-805 (RSTRING)). IBR approved for Sec. Sec.  
195.452(h); 195.587; and 195.588(c).
    (2) [Reserved]

[Amdt. 195-99, 80 FR 184, Jan. 5, 2015, as amended by Amdt. 195-101, 82 
FR 7998, Jan. 23, 2017; Amdt. 195-102, 84 FR 52294, Oct. 1, 2019]



Sec.  195.4  Compatibility necessary for transportation of hazardous  
liquids or carbon dioxide.

    No person may transport any hazardous liquid or carbon dioxide 
unless the hazardous liquid or carbon dioxide is chemically compatible 
with both the pipeline, including all components, and any other 
commodity that it may come into contact with while in the pipeline.

[Amdt. 195-45, 56 FR 26925, June 12, 1991]



Sec.  195.5  Conversion to service subject to this part.

    (a) A steel pipeline previously used in service not subject to this 
part qualifies for use under this part if the operator prepares and 
follows a written procedure to accomplish the following:
    (1) The design, construction, operation, and maintenance history of 
the pipeline must be reviewed and, where sufficient historical records 
are not available, appropriate tests must be performed to determine if 
the pipeline is in satisfactory condition for safe operation. If one or 
more of the variables necessary to verify the design pressure under 
Sec.  195.106 or to perform the testing under paragraph (a)(4) of this 
section is unknown, the design pressure may be verified and the maximum 
operating pressure determined by--
    (i) Testing the pipeline in accordance with ASME/ANSI B31.8 
(incorporated by reference, see Sec.  195.3), Appendix N, to produce a 
stress equal to the yield strength; and
    (ii) Applying, to not more than 80 percent of the first pressure 
that produces a yielding, the design factor F in Sec.  195.106(a) and 
the appropriate factors in Sec.  195.106(e).
    (2) The pipeline right-of-way, all aboveground segments of the 
pipeline,

[[Page 640]]

and appropriately selected underground segments must be visually 
inspected for physical defects and operating conditions which reasonably 
could be expected to impair the strength or tightness of the pipeline.
    (3) All known unsafe defects and conditions must be corrected in 
accordance with this part.
    (4) The pipeline must be tested in accordance with subpart E of this 
part to substantiate the maximum operating pressure permitted by Sec.  
195.406.
    (b) A pipeline that qualifies for use under this section need not 
comply with the corrosion control requirements of subpart H of this part 
until 12 months after it is placed into service, notwithstanding any 
previous deadlines for compliance.
    (c) Each operator must keep for the life of the pipeline a record of 
the investigations, tests, repairs, replacements, and alterations made 
under the requirements of paragraph (a) of this section.
    (d) An operator converting a pipeline from service not previously 
covered by this part must notify PHMSA 60 days before the conversion 
occurs as required by Sec.  195.64.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52, 
59 FR 33396, June 28, 1994; Amdt. 195-173, 66 FR 67004, Dec. 27, 2001; 
Amdt. 195-99, 80 FR 184, Jan. 5, 2015; Amdt. 195-101, 82 FR 7999, Jan. 
23, 2017]



Sec.  195.6  Unusually Sensitive Areas (USAs).

    As used in this part, a USA means a drinking water or ecological 
resource area that is unusually sensitive to environmental damage from a 
hazardous liquid pipeline release.
    (a) An USA drinking water resource is:
    (1) The water intake for a Community Water System (CWS) or a Non-
transient Non-community Water System (NTNCWS) that obtains its water 
supply primarily from a surface water source and does not have an 
adequate alternative drinking water source;
    (2) The Source Water Protection Area (SWPA) for a CWS or a NTNCWS 
that obtains its water supply from a Class I or Class IIA aquifer and 
does not have an adequate alternative drinking water source. Where a 
state has not yet identified the SWPA, the Wellhead Protection Area 
(WHPA) will be used until the state has identified the SWPA; or
    (3) The sole source aquifer recharge area where the sole source 
aquifer is a karst aquifer in nature.
    (b) An USA ecological resource is:
    (1) An area containing a critically imperiled species or ecological 
community;
    (2) A multi-species assemblage area;
    (3) A migratory waterbird concentration area;
    (4) An area containing an imperiled species, threatened or 
endangered species, depleted marine mammal species, or an imperiled 
ecological community where the species or community is aquatic, aquatic 
dependent, or terrestrial with a limited range;
    (5) An area containing an imperiled species, threatened or 
endangered species, depleted marine mammal species, or imperiled 
ecological community where the species or community occurrence is 
considered to be one of the most viable, highest quality, or in the best 
condition, as identified by an element occurrence ranking (EORANK) of A 
(excellent quality) or B (good quality) or
    (6) A coastal beach; or
    (7) Certain coastal waters.
    (c) Definitions used in this part--
    Adequate Alternative Drinking Water Source means a source of water 
that currently exists, can be used almost immediately with a minimal 
amount of effort and cost, involves no decline in water quality, and 
will meet the consumptive, hygiene, and fire fighting requirements of 
the existing population of impacted customers for at least one month for 
a surface water source of water and at least six months for a 
groundwater source.
    Aquatic or Aquatic Dependent Species or Community means a species or 
community that primarily occurs in aquatic, marine, or wetland habitats, 
as well as species that may use terrestrial habitats during all or some 
portion of their life cycle, but that are still closely associated with 
or dependent upon aquatic, marine, or wetland habitats for some critical 
component or portion of their life-history (i.e., reproduction, rearing 
and development, feeding, etc).

[[Page 641]]

    Class I Aquifer means an aquifer that is surficial or shallow, 
permeable, and is highly vulnerable to contamination. Class I aquifers 
include:
    (1) Unconsolidated Aquifers (Class Ia) that consist of surficial, 
unconsolidated, and permeable alluvial, terrace, outwash, beach, dune 
and other similar deposits. These aquifers generally contain layers of 
sand and gravel that, commonly, are interbedded to some degree with silt 
and clay. Not all Class Ia aquifers are important water-bearing units, 
but they are likely to be both permeable and vulnerable. The only 
natural protection of these aquifers is the thickness of the unsaturated 
zone and the presence of fine-grained material;
    (2) Soluble and Fractured Bedrock Aquifers (Class Ib). Lithologies 
in this class include limestone, dolomite, and, locally, evaporitic 
units that contain documented karst features or solution channels, 
regardless of size. Generally these aquifers have a wide range of 
permeability. Also included in this class are sedimentary strata, and 
metamorphic and igneous (intrusive and extrusive) rocks that are 
significantly faulted, fractured, or jointed. In all cases groundwater 
movement is largely controlled by secondary openings. Well yields range 
widely, but the important feature is the potential for rapid vertical 
and lateral ground water movement along preferred pathways, which result 
in a high degree of vulnerability;
    (3) Semiconsolidated Aquifers (Class Ic) that generally contain 
poorly to moderately indurated sand and gravel that is interbedded with 
clay and silt. This group is intermediate to the unconsolidated and 
consolidated end members. These systems are common in the Tertiary age 
rocks that are exposed throughout the Gulf and Atlantic coastal states. 
Semiconsolidated conditions also arise from the presence of intercalated 
clay and caliche within primarily unconsolidated to poorly consolidated 
units, such as occurs in parts of the High Plains Aquifer; or
    (4) Covered Aquifers (Class Id) that are any Class I aquifer 
overlain by less than 50 feet of low permeability, unconsolidated 
material, such as glacial till, lacustrian, and loess deposits.
    Certain coastal waters means the territorial sea of the United 
States; the Great Lakes and their connecting waters; and the marine and 
estuarine waters of the United States up to the head of tidal influence.
    Class IIa aquifer means a Higher Yield Bedrock Aquifer that is 
consolidated and is moderately vulnerable to contamination. These 
aquifers generally consist of fairly permeable sandstone or conglomerate 
that contain lesser amounts of interbedded fine grained clastics (shale, 
siltstone, mudstone) and occasionally carbonate units. In general, well 
yields must exceed 50 gallons per minute to be included in this class. 
Local fracturing may contribute to the dominant primary porosity and 
permeability of these systems.
    Coastal beach means any land between the high- and low-water marks 
of certain coastal waters.
    Community Water System (CWS) means a public water system that serves 
at least 15 service connections used by year-round residents of the area 
or regularly serves at least 25 year-round residents.
    Critically imperiled species or ecological community (habitat) means 
an animal or plant species or an ecological community of extreme rarity, 
based on The Nature Conservancy's Global Conservation Status Rank. There 
are generally 5 or fewer occurrences, or very few remaining individuals 
(less than 1,000) or acres (less than 2,000). These species and 
ecological communities are extremely vulnerable to extinction due to 
some natural or man-made factor.
    Depleted marine mammal species means a species that has been 
identified and is protected under the Marine Mammal Protection Act of 
1972, as amended (MMPA) (16 U.S.C. 1361 et seq.). The term ``depleted'' 
refers to marine mammal species that are listed as threatened or 
endangered, or are below their optimum sustainable populations (16 
U.S.C. 1362). The term ``marine mammal'' means ``any mammal which is 
morphologically adapted to the marine environment (including sea otters 
and members of the orders Sirenia, Pinnipedia, and Cetacea), or 
primarily inhabits the marine environment (such as the polar bear)'' (16 
U.S.C. 1362). The order Sirenia includes manatees, the

[[Page 642]]

order Pinnipedia includes seals, sea lions, and walruses, and the order 
Cetacea includes dolphins, porpoises, and whales.
    Ecological community means an interacting assemblage of plants and 
animals that recur under similar environmental conditions across the 
landscape.
    Element occurrence rank (EORANK) means the condition or viability of 
a species or ecological community occurrence, based on a population's 
size, condition, and landscape context. EORANKs are assigned by the 
Natural Heritage Programs. An EORANK of A means an excellent quality and 
an EORANK of B means good quality.
    Imperiled species or ecological community (habitat) means a rare 
species or ecological community, based on The Nature Conservancy's 
Global Conservation Status Rank. There are generally 6 to 20 
occurrences, or few remaining individuals (1,000 to 3,000) or acres 
(2,000 to 10,000). These species and ecological communities are 
vulnerable to extinction due to some natural or man-made factor.
    Karst aquifer means an aquifer that is composed of limestone or 
dolomite where the porosity is derived from connected solution cavities. 
Karst aquifers are often cavernous with high rates of flow.
    Migratory waterbird concentration area means a designated Ramsar 
site or a Western Hemisphere Shorebird Reserve Network site.
    Multi-species assemblage area means an area where three or more 
different critically imperiled or imperiled species or ecological 
communities, threatened or endangered species, depleted marine mammals, 
or migratory waterbird concentrations co-occur.
    Non-transient Non-community Water System (NTNCWS) means a public 
water system that regularly serves at least 25 of the same persons over 
six months per year. Examples of these systems include schools, 
factories, and hospitals that have their own water supplies.
    Public Water System (PWS) means a system that provides the public 
water for human consumption through pipes or other constructed 
conveyances, if such system has at least 15 service connections or 
regularly serves an average of at least 25 individuals daily at least 60 
days out of the year. These systems include the sources of the water 
supplies--i.e., surface or ground. PWS can be community, non-transient 
non-community, or transient non-community systems.
    Ramsar site means a site that has been designated under The 
Convention on Wetlands of International Importance Especially as 
Waterfowl Habitat program. Ramsar sites are globally critical wetland 
areas that support migratory waterfowl. These include wetland areas that 
regularly support 20,000 waterfowl; wetland areas that regularly support 
substantial numbers of individuals from particular groups of waterfowl, 
indicative of wetland values, productivity, or diversity; and wetland 
areas that regularly support 1% of the individuals in a population of 
one species or subspecies of waterfowl.
    Sole source aquifer (SSA) means an area designated by the U.S. 
Environmental Protection Agency under the Sole Source Aquifer program as 
the ``sole or principal'' source of drinking water for an area. Such 
designations are made if the aquifer's ground water supplies 50% or more 
of the drinking water for an area, and if that aquifer were to become 
contaminated, it would pose a public health hazard. A sole source 
aquifer that is karst in nature is one composed of limestone where the 
porosity is derived from connected solution cavities. They are often 
cavernous, with high rates of flow.
    Source Water Protection Area (SWPA) means the area delineated by the 
state for a public water supply system (PWS) or including numerous PWSs, 
whether the source is ground water or surface water or both, as part of 
the state source water assessment program (SWAP) approved by EPA under 
section 1453 of the Safe Drinking Water Act.
    Species means species, subspecies, population stocks, or distinct 
vertebrate populations.
    Terrestrial ecological community with a limited range means a non-
aquatic or non-aquatic dependent ecological community that covers less 
than five (5) acres.

[[Page 643]]

    Terrestrial species with a limited range means a non-aquatic or non-
aquatic dependent animal or plant species that has a range of no more 
than five (5) acres.
    Threatened and endangered species (T&E) means an animal or plant 
species that has been listed and is protected under the Endangered 
Species Act of 1973, as amended (ESA73) (16 U.S.C. 1531 et seq.). 
``Endangered species'' is defined as ``any species which is in danger of 
extinction throughout all or a significant portion of its range'' (16 
U.S.C. 1532). ``Threatened species'' is defined as ``any species which 
is likely to become an endangered species within the foreseeable future 
throughout all or a significant portion of its range'' (16 U.S.C. 1532).
    Transient Non-community Water System (TNCWS) means a public water 
system that does not regularly serve at least 25 of the same persons 
over six months per year. This type of water system serves a transient 
population found at rest stops, campgrounds, restaurants, and parks with 
their own source of water.
    Wellhead Protection Area (WHPA) means the surface and subsurface 
area surrounding a well or well field that supplies a public water 
system through which contaminants are likely to pass and eventually 
reach the water well or well field.
    Western Hemisphere Shorebird Reserve Network (WHSRN) site means an 
area that contains migratory shorebird concentrations and has been 
designated as a hemispheric reserve, international reserve, regional 
reserve, or endangered species reserve. Hemispheric reserves host at 
least 500,000 shorebirds annually or 30% of a species flyway population. 
International reserves host 100,000 shorebirds annually or 15% of a 
species flyway population. Regional reserves host 20,000 shorebirds 
annually or 5% of a species flyway population. Endangered species 
reserves are critical to the survival of endangered species and no 
minimum number of birds is required.

[Amdt. 195-71, 65 FR 80544, Dec. 21, 2000, as amended at 86 FR 73186, 
Dec. 27, 2021]



Sec.  195.8  Transportation of hazardous liquid or carbon dioxide in 
pipelines constructed with other than steel pipe.

    No person may transport any hazardous liquid or carbon dioxide 
through a pipe that is constructed after October 1, 1970, for hazardous 
liquids or after July 12, 1991 for carbon dioxide of material other than 
steel unless the person has notified the Administrator in writing at 
least 90 days before the transportation is to begin. The notice must 
state whether carbon dioxide or a hazardous liquid is to be transported 
and the chemical name, common name, properties and characteristics of 
the hazardous liquid to be transported and the material used in 
construction of the pipeline. If the Administrator determines that the 
transportation of the hazardous liquid or carbon dioxide in the manner 
proposed would be unduly hazardous, he will, within 90 days after 
receipt of the notice, order the person that gave the notice, in 
writing, not to transport the hazardous liquid or carbon dioxide in the 
proposed manner until further notice.

[Amdt. 195-45, 56 FR 26925, June 12, 1991, as amended by Amdt. 195-50, 
59 FR 17281, Apr. 12, 1994]



Sec.  195.9  Outer continental shelf pipelines.

    Operators of transportation pipelines on the Outer Continental Shelf 
must identify on all their respective pipelines the specific points at 
which operating responsibility transfers to a producing operator. For 
those instances in which the transfer points are not identifiable by a 
durable marking, each operator will have until September 15, 1998 to 
identify the transfer points. If it is not practicable to durably mark a 
transfer point and the transfer point is located above water, the 
operator must depict the transfer point on a schematic maintained near 
the transfer point. If a transfer point is located subsea, the operator 
must identify the transfer point on a schematic which must be maintained 
at the nearest upstream facility and provided to PHMSA upon request. For 
those cases in which adjoining operators have not agreed on a transfer 
point by September 15, 1998 the Regional Director and the MMS

[[Page 644]]

Regional Supervisor will make a joint determination of the transfer 
point.

[Amdt. 195-59, 62 FR 61695, Nov. 19, 1997, as amended at 70 FR 11140, 
Mar. 8, 2005]



Sec.  195.10  Responsibility of operator for compliance with this part.

    An operator may make arrangements with another person for the 
performance of any action required by this part. However, the operator 
is not thereby relieved from the responsibility for compliance with any 
requirement of this part.



Sec.  195.11  What is a regulated rural gathering line and what  
requirements apply?

    Each operator of a regulated rural gathering line, as defined in 
paragraph (a) of this section, must comply with the safety requirements 
described in paragraph (b) of this section.
    (a) Definition. As used in this section, a regulated rural gathering 
line means an onshore gathering line in a rural area that meets all of 
the following criteria--
    (1) Has a nominal diameter from 6\5/8\ inches (168 mm) to 8\5/8\ 
inches (219.1 mm);
    (2) Is located in or within one-quarter mile (.40 km) of an 
unusually sensitive area as defined in Sec.  195.6; and
    (3) Operates at a maximum pressure established under Sec.  195.406 
corresponding to--
    (i) A stress level greater than 20-percent of the specified minimum 
yield strength of the line pipe; or
    (ii) If the stress level is unknown or the pipeline is not 
constructed with steel pipe, a pressure of more than 125 psi (861 kPa) 
gage.
    (b) Safety requirements. Each operator must prepare, follow, and 
maintain written procedures to carry out the requirements of this 
section. Except for the requirements in paragraphs (b)(2), (b)(3), 
(b)(9) and (b)(10) of this section, the safety requirements apply to all 
materials of construction.
    (1) Identify all segments of pipeline meeting the criteria in 
paragraph (a) of this section before April 3, 2009.
    (2) For steel pipelines constructed, replaced, relocated, or 
otherwise changed after July 3, 2009:
    (i) Design, install, construct, initially inspect, and initially 
test the pipeline in compliance with this part, unless the pipeline is 
converted under Sec.  195.5.
    (ii) [Reserved]
    (3) For non-steel pipelines constructed after July 3, 2009, notify 
the Administrator according to Sec.  195.8.
    (4) Beginning no later than January 3, 2009, comply with the 
reporting requirements in subpart B of this part.
    (5) Establish the maximum operating pressure of the pipeline 
according to Sec.  195.406 before transportation begins, or if the 
pipeline exists on July 3, 2008, before July 3, 2009.
    (6) Install line markers according to Sec.  195.410 before 
transportation begins, or if the pipeline exists on July 3, 2008, before 
July 3, 2009. Continue to maintain line markers in compliance with Sec.  
195.410.
    (7) Establish a continuing public education program in compliance 
with Sec.  195.440 before transportation begins, or if the pipeline 
exists on July 3, 2008, before January 3, 2010. Continue to carry out 
such program in compliance with Sec.  195.440.
    (8) Establish a damage prevention program in compliance with Sec.  
195.442 before transportation begins, or if the pipeline exists on July 
3, 2008, before July 3, 2009. Continue to carry out such program in 
compliance with Sec.  195.442.
    (9) For steel pipelines, comply with subpart H of this part, except 
corrosion control is not required for pipelines existing on July 3, 2008 
before July 3, 2011.
    (10) For steel pipelines, establish and follow a comprehensive and 
effective program to continuously identify operating conditions that 
could contribute to internal corrosion. The program must include 
measures to prevent and mitigate internal corrosion, such as cleaning 
the pipeline and using inhibitors. This program must be established 
before transportation begins or if the pipeline exists on July 3, 2008, 
before July 3, 2009.
    (11) To comply with the Operator Qualification program requirements 
in subpart G of this part, have a written description of the processes 
used to carry out the requirements in Sec.  195.505

[[Page 645]]

to determine the qualification of persons performing operations and 
maintenance tasks. These processes must be established before 
transportation begins or if the pipeline exists on July 3, 2008, before 
July 3, 2009.
    (c) New unusually sensitive areas. If, after July 3, 2008, a new 
unusually sensitive area is identified and a segment of pipeline becomes 
regulated as a result, except for the requirements of paragraphs (b)(9) 
and (b)(10) of this section, the operator must implement the 
requirements in paragraphs (b)(2) through (b)(11) of this section for 
the affected segment within 6 months of identification. For steel 
pipelines, comply with the deadlines in paragraph (b)(9) and (b)(10).
    (d) Record Retention. An operator must maintain records 
demonstrating compliance with each requirement according to the 
following schedule.
    (1) An operator must maintain the segment identification records 
required in paragraph (b)(1) of this section and the records required to 
comply with (b)(10) of this section, for the life of the pipe.
    (2) An operator must maintain the records necessary to demonstrate 
compliance with each requirement in paragraphs (b)(2) through (b)(9), 
and (b)(11) of this section according to the record retention 
requirements of the referenced section or subpart.

[73 FR 31644, June 3, 2008, as amended by Amdt. 195-105, 87 FR 20987, 
Apr. 8, 2022; Amdt. 195-106, 88 FR 50062, Aug. 1, 2023]



Sec.  195.12  What requirements apply to low-stress pipelines in rural 
areas?

    (a) General. This Section sets forth the requirements for each 
category of low-stress pipeline in a rural area set forth in paragraph 
(b) of this Section. This Section does not apply to a rural low-stress 
pipeline regulated under this Part as a low-stress pipeline that crosses 
a waterway currently used for commercial navigation; these pipelines are 
regulated pursuant to Sec.  195.1(a)(2).
    (b) Categories. An operator of a rural low-stress pipeline must meet 
the applicable requirements and compliance deadlines for the category of 
pipeline set forth in paragraph (c) of this Section. For purposes of 
this Section, a rural low-stress pipeline is a Category 1, 2, or 3 
pipeline based on the following criteria:
    (1) A Category 1 rural low-stress pipeline:
    (i) Has a nominal diameter of 8\5/8\ inches (219.1 mm) or more;
    (ii) Is located in or within one-half mile (.80 km) of an unusually 
sensitive area (USA) as defined in Sec.  195.6; and
    (iii) Operates at a maximum pressure established under Sec.  195.406 
corresponding to:
    (A) A stress level equal to or less than 20-percent of the specified 
minimum yield strength of the line pipe; or
    (B) If the stress level is unknown or the pipeline is not 
constructed with steel pipe, a pressure equal to or less than 125 psi 
(861 kPa) gauge.
    (2) A Category 2 rural pipeline:
    (i) Has a nominal diameter of less than 8\5/8\ inches (219.1mm);
    (ii) Is located in or within one-half mile (.80 km) of an unusually 
sensitive area (USA) as defined in Sec.  195.6; and
    (iii) Operates at a maximum pressure established under Sec.  195.406 
corresponding to:
    (A) A stress level equal to or less than 20-percent of the specified 
minimum yield strength of the line pipe; or
    (B) If the stress level is unknown or the pipeline is not 
constructed with steel pipe, a pressure equal to or less than 125 psi 
(861 kPa) gage.
    (3) A Category 3 rural low-stress pipeline:
    (i) Has a nominal diameter of any size and is not located in or 
within one-half mile (.80 km) of an unusually sensitive area (USA) as 
defined in Sec.  195.6; and
    (ii) Operates at a maximum pressure established under Sec.  195.406 
corresponding to a stress level equal to or less than 20-percent of the 
specified minimum yield strength of the line pipe; or
    (iii) If the stress level is unknown or the pipeline is not 
constructed with steel pipe, a pressure equal to or less than 125 psi 
(861 kPa) gage.
    (c) Applicable requirements and deadlines for compliance. An 
operator must comply with the following compliance dates depending on 
the category of pipeline determined by the criteria in paragraph (b):

[[Page 646]]

    (1) An operator of a Category 1 pipeline must:
    (i) Identify all segments of pipeline meeting the criteria in 
paragraph (b)(1) of this Section before April 3, 2009.
    (ii) Beginning no later than January 3, 2009, comply with the 
reporting requirements of Subpart B for the identified segments.
    (iii) IM requirements--
    (A) Establish a written program that complies with Sec.  195.452 
before July 3, 2009, to assure the integrity of the pipeline segments. 
Continue to carry out such program in compliance with Sec.  195.452.
    (B) An operator may conduct a determination per Sec.  195.452(a) in 
lieu of the one-half mile buffer.
    (C) Complete the baseline assessment of all segments in accordance 
with Sec.  195.452(c) before July 3, 2015, and complete at least 50-
percent of the assessments, beginning with the highest risk pipe, before 
January 3, 2012.
    (iv) Comply with all other safety requirements of this Part, except 
Subpart H, before July 3, 2009. Comply with the requirements of Subpart 
H before July 3, 2011.
    (2) An operator of a Category 2 pipeline must:
    (i) Identify all segments of pipeline meeting the criteria in 
paragraph (b)(2) of this Section before July 1, 2012.
    (ii) Beginning no later than January 3, 2009, comply with the 
reporting requirements of Subpart B for the identified segments.
    (iii) IM--
    (A) Establish a written IM program that complies with Sec.  195.452 
before October 1, 2012 to assure the integrity of the pipeline segments. 
Continue to carry out such program in compliance with Sec.  195.452.
    (B) An operator may conduct a determination per Sec.  195.452(a) in 
lieu of the one-half mile buffer.
    (C) Complete the baseline assessment of all segments in accordance 
with Sec.  195.452(c) before October 1, 2016 and complete at least 50-
percent of the assessments, beginning with the highest risk pipe, before 
April 1, 2014.
    (iv) Comply with all other safety requirements of this Part, except 
Subpart H, before October 1, 2012. Comply with Subpart H of this Part 
before October 1, 2014.
    (3) An operator of a Category 3 pipeline must:
    (i) Identify all segments of pipeline meeting the criteria in 
paragraph (b)(3) of this Section before July 1, 2012.
    (ii) Beginning no later than January 3, 2009, comply with the 
reporting requirements of Subpart B for the identified segments.
    (A)(iii) Comply with all safety requirements of this Part, except 
the requirements in Sec.  195.452, Subpart B, and the requirements in 
Subpart H, before October 1, 2012. Comply with Subpart H of this Part 
before October 1, 2014.
    (d) Economic compliance burden. (1) An operator may notify PHMSA in 
accordance with Sec.  195.452(m) of a situation meeting the following 
criteria:
    (i) The pipeline is a Category 1 rural low-stress pipeline;
    (ii) The pipeline carries crude oil from a production facility;
    (iii) The pipeline, when in operation, operates at a flow rate less 
than or equal to 14,000 barrels per day; and
    (iv) The operator determines it would abandon or shut-down the 
pipeline as a result of the economic burden to comply with the 
assessment requirements in Sec.  195.452(d) or 195.452(j).
    (2) A notification submitted under this provision must include, at 
minimum, the following information about the pipeline: its operating, 
maintenance and leak history; the estimated cost to comply with the 
integrity assessment requirements (with a brief description of the basis 
for the estimate); the estimated amount of production from affected 
wells per year, whether wells will be shut in or alternate 
transportation used, and if alternate transportation will be used, the 
estimated cost to do so.
    (3) When an operator notifies PHMSA in accordance with paragraph 
(d)(1) of this Section, PHMSA will stay compliance with Sec. Sec.  
195.452(d) and 195.452(j)(3) until it has completed an analysis of the 
notification. PHMSA will consult the Department of Energy, as 
appropriate, to help analyze the potential energy impact of loss of the 
pipeline. Based on the analysis, PHMSA may grant the operator a special 
permit to

[[Page 647]]

allow continued operation of the pipeline subject to alternative safety 
requirements.
    (e) Changes in unusually sensitive areas. (1) If, after June 3, 
2008, for Category 1 rural low-stress pipelines or October 1, 2011 for 
Category 2 rural low-stress pipelines, an operator identifies a new USA 
that causes a segment of pipeline to meet the criteria in paragraph (b) 
of this Section as a Category 1 or Category 2 rural low-stress pipeline, 
the operator must:
    (i) Comply with the IM program requirement in paragraph 
(c)(1)(iii)(A) or (c)(2)(iii)(A) of this Section, as appropriate, within 
12 months following the date the area is identified regardless of the 
prior categorization of the pipeline; and
    (ii) Complete the baseline assessment required by paragraph 
(c)(1)(iii)(C) or (c)(2)(iii)(C) of this Section, as appropriate, 
according to the schedule in Sec.  195.452(d)(3).
    (2) If a change to the boundaries of a USA causes a Category 1 or 
Category 2 pipeline segment to no longer be within one-half mile of a 
USA, an operator must continue to comply with paragraph (c)(1)(iii) or 
paragraph (c)(2)(iii) of this section, as applicable, with respect to 
that segment unless the operator determines that a release from the 
pipeline could not affect the USA.
    (f) Record Retention. An operator must maintain records 
demonstrating compliance with each requirement applicable to the 
category of pipeline according to the following schedule.
    (1) An operator must maintain the segment identification records 
required in paragraph (c)(1)(i), (c)(2)(i) or (c)(3)(i) of this Section 
for the life of the pipe.
    (2) Except for the segment identification records, an operator must 
maintain the records necessary to demonstrate compliance with each 
applicable requirement set forth in paragraph (c) of this section 
according to the record retention requirements of the referenced section 
or subpart.

[76 FR 25587, May 5, 2011, as amended at 76 FR 43605, July 21, 2011]



Sec.  195.13  What requirements apply to pipelines transporting hazardous 
liquids by gravity?

    (a) Scope. Pipelines transporting hazardous liquids by gravity must 
comply with the reporting requirements of subpart B of this part.
    (b) Implementation period--(1) Annual reporting. Comply with the 
annual reporting requirements in subpart B of this part by March 31, 
2021.
    (2) Accident and safety-related reporting. Comply with the accident 
and safety-related condition reporting requirements in subpart B of this 
part by January 1, 2021.
    (c) Exceptions. (1) This section does not apply to the 
transportation of a hazardous liquid in a gravity line that meets the 
definition of a low-stress pipeline, travels no farther than 1 mile from 
a facility boundary, and does not cross any waterways used for 
commercial navigation.
    (2) The reporting requirements in Sec. Sec.  195.52, 195.61, and 
195.65 do not apply to the transportation of a hazardous liquid in a 
gravity line.
    (3) The drug and alcohol testing requirements in part 199 of this 
subchapter do not apply to the transportation of a hazardous liquid in a 
gravity line.

[Amdt. 195-102, 84 FR 52294, Oct. 1, 2019]



Sec.  195.15  What requirements apply to reporting-regulated-only 
gathering lines?

    (a) Scope. Gathering lines that do not otherwise meet the definition 
of a regulated rural gathering line in Sec.  195.11 and any gathering 
line not already covered under Sec.  195.1(a)(1), (2), (3) or (4) must 
comply with the reporting requirements of subpart B of this part.
    (b) Implementation period--(1) Annual reporting. Operators must 
comply with the annual reporting requirements in subpart B of this part 
by March 31, 2021.
    (2) Accident and safety-related condition reporting. Operators must 
comply with the accident and safety-related condition reporting 
requirements in subpart B of this part by January 1, 2021.
    (c) Exceptions. (1) This section does not apply to those gathering 
lines that

[[Page 648]]

are otherwise excepted under Sec.  195.1(b)(3), (7), (8), (9), or (10).
    (2) The reporting requirements in Sec. Sec.  195.52, 195.61, and 
195.65 do not apply to the transportation of a hazardous liquid in a 
gathering line that is specified in paragraph (a) of this section.
    (3) The drug and alcohol testing requirements in part 199 of this 
subchapter do not apply to the transportation of a hazardous liquid in a 
gathering line that is specified in paragraph (a) of this section.

[Amdt. 195-102, 84 FR 52294, Oct. 1, 2019]



Sec.  195.18  How to notify PHMSA.

    (a) An operator must provide any notification required by this part 
by:
    (1) Sending the notification by electronic mail to 
[email protected]; or
    (2) Sending the notification by mail to ATTN: Information Resources 
Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New 
Jersey Ave. SE, Washington, DC 20590.
    (b) An operator must also notify the appropriate State or local 
pipeline safety authority when an applicable pipeline segment is located 
in a State where OPS has an interstate agent agreement, or an intrastate 
pipeline segment is regulated by that State.
    (c) Unless otherwise specified, if an operator submits, pursuant to 
Sec.  195.258, Sec.  195.260, Sec.  195.418, Sec.  195.419, Sec.  
195.420 or Sec.  195.452 a notification requesting use of a different 
integrity assessment method, analytical method, sampling approach, 
compliance timeline, or technique (e.g., ``other technology'' or 
``alternative equivalent technology'') than otherwise prescribed in 
those sections, that notification must be submitted to PHMSA for review 
at least 90 days in advance of using that other method, approach, 
compliance timeline, or technique. An operator may proceed to use the 
other method, approach, compliance timeline, or technique 91 days after 
submittal of the notification unless it receives a letter from the 
Associate Administrator of Pipeline Safety informing the operator that 
PHMSA objects to the proposal, or that PHMSA requires additional time 
and/or information to conduct its review.

[Amdt. 195-105, 87 FR 20987, Apr. 8, 2022]



   Subpart B_Annual, Accident, and Safety-Related Condition Reporting



Sec.  195.48  Scope.

    This Subpart prescribes requirements for periodic reporting and for 
reporting of accidents and safety-related conditions. This Subpart 
applies to all pipelines subject to this Part. An operator of a Category 
3 rural low-stress pipeline meeting the criteria in Sec.  195.12 is not 
required to complete those parts of the hazardous liquid annual report 
form PHMSA F 7000-1.1 associated with IM or high consequence areas.

[76 FR 25588, May 5, 2011]



Sec.  195.49  Annual report.

    Each operator must annually complete and submit DOT Form PHMSA F 
7000-1.1 for each type of hazardous liquid pipeline facility operated at 
the end of the previous year. An operator must submit the annual report 
by June 15 each year, except that for the 2010 reporting year the report 
must be submitted by August 15, 2011. A separate report is required for 
crude oil, HVL (including anhydrous ammonia), petroleum products, carbon 
dioxide pipelines, and fuel grade ethanol pipelines. For each state a 
pipeline traverses, an operator must separately complete those sections 
on the form requiring information to be reported for each state.

[75 FR 72907, Nov. 26, 2010]



Sec.  195.50  Reporting accidents.

    An accident report is required for each failure in a pipeline system 
subject to this part in which there is a release of the hazardous liquid 
or carbon dioxide transported resulting in any of the following:
    (a) Explosion or fire not intentionally set by the operator.
    (b) Release of 5 gallons (19 liters) or more of hazardous liquid or 
carbon dioxide, except that no report is required for a release of less 
than 5 barrels (0.8

[[Page 649]]

cubic meters) resulting from a pipeline maintenance activity if the 
release is:
    (1) Not otherwise reportable under this section;
    (2) Not one described in Sec.  195.52(a)(4);
    (3) Confined to company property or pipeline right-of-way; and
    (4) Cleaned up promptly;
    (c) Death of any person;
    (d) Personal injury necessitating hospitalization;
    (e) Estimated property damage, including cost of clean-up and 
recovery, value of lost product, and damage to the property of the 
operator or others, or both, exceeding $50,000.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-39, 
53 FR 24950, July 1, 1988; Amdt. 195-45, 56 FR 26925, June 12, 1991; 
Amdt. 195-52, 59 FR 33396, June 28, 1994; Amdt. 195-63, 63 FR 37506, 
July 13, 1998; Amdt. 195-75, 67 FR 836, Jan. 8, 2002]



Sec.  195.52  Immediate notice of certain accidents.

    (a) Notice requirements. At the earliest practicable moment 
following discovery, of a release of the hazardous liquid or carbon 
dioxide transported resulting in an event described in Sec.  195.50, but 
no later than one hour after confirmed discovery, the operator of the 
system must give notice, in accordance with paragraph (b) of this 
section of any failure that:
    (1) Caused a death or a personal injury requiring hospitalization;
    (2) Resulted in either a fire or explosion not intentionally set by 
the operator;
    (3) Caused estimated property damage, including cost of cleanup and 
recovery, value of lost product, and damage to the property of the 
operator or others, or both, exceeding $50,000;
    (4) Resulted in pollution of any stream, river, lake, reservoir, or 
other similar body of water that violated applicable water quality 
standards, caused a discoloration of the surface of the water or 
adjoining shoreline, or deposited a sludge or emulsion beneath the 
surface of the water or upon adjoining shorelines; or
    (5) In the judgment of the operator was significant even though it 
did not meet the criteria of any other paragraph of this section.
    (b) Information required. Each notice required by paragraph (a) of 
this section must be made to the National Response Center either by 
telephone to 800-424-8802 (in Washington, DC, 202-267-2675) or 
electronically at http://www.nrc.uscg.mil and must include the following 
information:
    (1) Name, address and identification number of the operator.
    (2) Name and telephone number of the reporter.
    (3) The location of the failure.
    (4) The time of the failure.
    (5) The fatalities and personal injuries, if any.
    (6) Initial estimate of amount of product released in accordance 
with paragraph (c) of this section.
    (7) All other significant facts known by the operator that are 
relevant to the cause of the failure or extent of the damages.
    (c) Calculation. A pipeline operator must have a written procedure 
to calculate and provide a reasonable initial estimate of the amount of 
released product.
    (d) New information. Within 48 hours after the confirmed discovery 
of an accident, to the extent practicable, an operator must revise or 
confirm its initial telephonic notice required in paragraph (b) of this 
section with a revised estimate of the amount of product released, 
location of the failure, time of the failure, a revised estimate of the 
number of fatalities and injuries, and all other significant facts that 
are known by the operator that are relevant to the cause of the accident 
or extent of the damages. If there are no changes or revisions to the 
initial report, the operator must confirm the estimates in its initial 
report.

[75 FR 72907, Nov. 26, 2010, as amended by Amdt. 195-101, 82 FR 7999, 
Jan. 23, 2017]



Sec.  195.54  Accident reports.

    (a) Each operator that experiences an accident that is required to 
be reported under Sec.  195.50 must, as soon as practicable, but not 
later than 30 days after discovery of the accident, file an accident 
report on DOT Form 7000-1.

[[Page 650]]

    (b) Whenever an operator receives any changes in the information 
reported or additions to the original report on DOT Form 7000-1, it 
shall file a supplemental report within 30 days.

[Amdt. 195-39, 53 FR 24950, July 1, 1988, as amended by Amdt. 195-95, 75 
FR 72907, Nov. 26, 2010]



Sec.  195.55  Reporting safety-related conditions.

    (a) Except as provided in paragraph (b) of this section, each 
operator shall report in accordance with Sec.  195.56 the existence of 
any of the following safety-related conditions involving pipelines in 
service:
    (1) General corrosion that has reduced the wall thickness to less 
than that required for the maximum operating pressure, and localized 
corrosion pitting to a degree where leakage might result.
    (2) Unintended movement or abnormal loading of a pipeline by 
environmental causes, such as an earthquake, landslide, or flood, that 
impairs its serviceability.
    (3) Any material defect or physical damage that impairs the 
serviceability of a pipeline.
    (4) Any malfunction or operating error that causes the pressure of a 
pipeline to rise above 110 percent of its maximum operating pressure.
    (5) A leak in a pipeline that constitutes an emergency.
    (6) Any safety-related condition that could lead to an imminent 
hazard and causes (either directly or indirectly by remedial action of 
the operator), for purposes other than abandonment, a 20 percent or more 
reduction in operating pressure or shutdown of operation of a pipeline.
    (b) A report is not required for any safety-related condition that--
    (1) Exists on a pipeline that is more than 220 yards (200 meters) 
from any building intended for human occupancy or outdoor place of 
assembly, except that reports are required for conditions within the 
right-of-way of an active railroad, paved road, street, or highway, or 
that occur offshore or at onshore locations where a loss of hazardous 
liquid could reasonably be expected to pollute any stream, river, lake, 
reservoir, or other body of water;
    (2) Is an accident that is required to be reported under Sec.  
195.50 or results in such an accident before the deadline for filing the 
safety-related condition report; or
    (3) Is corrected by repair or replacement in accordance with 
applicable safety standards before the deadline for filing the safety-
related condition report, except that reports are required for all 
conditions under paragraph (a)(1) of this section other than localized 
corrosion pitting on an effectively coated and cathodically protected 
pipeline.

[Amdt. 195-39, 53 FR 24950, July 1, 1988; 53 FR 29800, Aug. 8, 1988, as 
amended by Amdt. 195-63, 63 FR 37506, July 13, 1998]



Sec.  195.56  Filing safety-related condition reports.

    (a) Each report of a safety-related condition under Sec.  195.55(a) 
must be filed (received by OPS) within five working days (not including 
Saturday, Sunday, or Federal Holidays) after the day a representative of 
the operator first determines that the condition exists, but not later 
than 10 working days after the day a representative of the operator 
discovers the condition. Separate conditions may be described in a 
single report if they are closely related. Reports may be transmitted by 
electronic mail to [email protected], or by facsimile 
at (202) 366-7128.
    (b) The report must be headed ``Safety-Related Condition Report'' 
and provide the following information:
    (1) Name and principal address of operator.
    (2) Date of report.
    (3) Name, job title, and business telephone number of person 
submitting the report.
    (4) Name, job title, and business telephone number of person who 
determined that the condition exists.
    (5) Date condition was discovered and date condition was first 
determined to exist.
    (6) Location of condition, with reference to the State (and town, 
city, or county) or offshore site, and as appropriate nearest street 
address, offshore platform, survey station number, milepost, landmark, 
or name of pipeline.

[[Page 651]]

    (7) Description of the condition, including circumstances leading to 
its discovery, any significant effects of the condition on safety, and 
the name of the commodity transported or stored.
    (8) The corrective action taken (including reduction of pressure or 
shutdown) before the report is submitted and the planned follow-up or 
future corrective action, including the anticipated schedule for 
starting and concluding such action.

[Amdt. 195-39, 53 FR 24950, July 1, 1988; 53 FR 29800, Aug. 8, 1988, as 
amended by Amdt. 195-42, 54 FR 32344, Aug. 7, 1989; Amdt. 195-44, 54 FR 
40878, Oct. 4, 1989; Amdt. 195-50, 59 FR 17281, Apr. 12, 1994; Amdt. 
195-61, 63 FR 7723, Feb. 17, 1998; Amdt. 195-100, 80 FR 12780, Mar. 11, 
2015]



Sec.  195.58  Report submission requirements.

    (a) General. Except as provided in paragraphs (b) and (e) of this 
section, an operator must submit each report required by this part 
electronically to PHMSA at http://opsweb.phmsa.dot.gov unless an 
alternative reporting method is authorized in accordance with paragraph 
(d) of this section.
    (b) Exceptions: An operator is not required to submit a safety-
related condition report (Sec.  195.56) electronically.
    (c) Safety-related conditions. An operator must submit concurrently 
to the applicable State agency a safety-related condition report 
required by Sec.  195.55 for an intrastate pipeline or when the State 
agency acts as an agent of the Secretary with respect to interstate 
pipelines.
    (d) Alternate Reporting Method. If electronic reporting imposes an 
undue burden and hardship, the operator may submit a written request for 
an alternative reporting method to the Information Resources Manager, 
Office of Pipeline Safety, Pipeline and Hazardous Materials Safety 
Administration, PHP-20, 1200 New Jersey Avenue, SE., Washington DC 
20590. The request must describe the undue burden and hardship. PHMSA 
will review the request and may authorize, in writing, an alternative 
reporting method. An authorization will state the period for which it is 
valid, which may be indefinite. An operator must contact PHMSA at 202-
366-8075, or electronically to ``[email protected]'' 
to make arrangements for submitting a report that is due after a request 
for alternative reporting is submitted but before an authorization or 
denial is received.
    (e) National Pipeline Mapping System (NPMS). An operator must 
provide NPMS data to the address identified in the NPMS Operator 
Standards Manual available at www.npms.phmsa.dot.gov or by contacting 
the PHMSA Geographic Information Systems Manager at (202) 366-4595.

[Amdt. 195-95, 75 FR 72907, Nov. 26, 2010, as amended by ; Amdt. 195-
100, 80 FR 12780, Mar. 11, 2015]



Sec.  195.59  Abandonment or deactivation of facilities.

    For each abandoned offshore pipeline facility or each abandoned 
onshore pipeline facility that crosses over, under or through a 
commercially navigable waterway, the last operator of that facility must 
file a report upon abandonment of that facility.
    (a) The preferred method to submit data on pipeline facilities 
abandoned after October 10, 2000 is to the National Pipeline Mapping 
System (NPMS) in accordance with the NPMS ``Standards for Pipeline and 
Liquefied Natural Gas Operator Submissions.'' To obtain a copy of the 
NPMS Standards, please refer to the NPMS homepage at http://
www.npms.phmsa.dot.gov or contact the NPMS National Repository at 703-
317-3073. A digital data format is preferred, but hard copy submissions 
are acceptable if they comply with the NPMS Standards. In addition to 
the NPMS-required attributes, operators must submit the date of 
abandonment, diameter, method of abandonment, and certification that, to 
the best of the operator's knowledge, all of the reasonably available 
information requested was provided and, to the best of the operator's 
knowledge, the abandonment was completed in accordance with applicable 
laws. Refer to the NPMS Standards for details in preparing your data for 
submission. The NPMS Standards also include details of how to submit 
data. Alternatively, operators may submit reports by mail, fax or e-mail 
to the Office of Pipeline Safety, Pipeline and

[[Page 652]]

Hazardous Materials Safety Administration, U.S. Department of 
Transportation, Information Resources Manager, PHP-10, 1200 New Jersey 
Avenue, SE., Washington, DC 20590-0001; fax (202) 366-4566; e-mail, 
``InformationResourcesManager@phmsa.

dot.gov. The information in the report must contain all reasonably 
available information related to the facility, including information in 
the possession of a third party. The report must contain the location, 
size, date, method of abandonment, and a certification that the facility 
has been abandoned in accordance with all applicable laws.
    (b) [Reserved]

[Amdt. 195-69, 65 FR 54444, Sept. 8, 2000, as amended at 70 FR 11140, 
Mar. 8, 2005; Amdt. 195-86, 72 FR 4657, Feb. 1, 2007; 73 FR 16570, Mar. 
28, 2008; 74 FR 2894, Jan. 16, 2009]



Sec.  195.60  Operator assistance in investigation.

    If the Department of Transportation investigates an accident, the 
operator involved shall make available to the representative of the 
Department all records and information that in any way pertain to the 
accident, and shall afford all reasonable assistance in the 
investigation of the accident.



Sec.  195.61  National Pipeline Mapping System.

    (a) Each operator of a hazardous liquid pipeline facility must 
provide the following geospatial data to PHMSA for that facility:
    (1) Geospatial data, attributes, metadata and transmittal letter 
appropriate for use in the National Pipeline Mapping System. Acceptable 
formats and additional information are specified in the NPMS Operator 
Standards manual available at www.npms.phmsa.dot.gov or by contacting 
the PHMSA Geographic Information Systems Manager at (202) 366-4595.
    (2) The name of and address for the operator.
    (3) The name and contact information of a pipeline company employee, 
to be displayed on a public Web site, who will serve as a contact for 
questions from the general public about the operator's NPMS data.
    (b) This information must be submitted each year, on or before June 
15, representing assets as of December 31 of the previous year. If no 
changes have occurred since the previous year's submission, the operator 
must refer to the information provided in the NPMS Operator Standards 
manual available at www.npms.phmsa.dot.gov or contact the PHMSA 
Geographic Information Systems Manager at (202) 366-4595.

[Amdt. 195-100, 80 FR 12780, Mar. 11, 2015]



Sec.  195.63  OMB control number assigned to information collection.

    The control numbers assigned by the Office of Management and Budget 
to the hazardous liquid pipeline information collection pursuant to the 
Paperwork Reduction Act are 2137-0047, 2137-0601, 2137-0604, 2137-0605, 
2137-0618, and 2137-0622.

[Amdt. 195-95, 75 FR 72907, Nov. 26, 2010]



Sec.  195.64  National Registry of Operators.

    (a) OPID Request. Effective January 1, 2012, each operator of a 
hazardous liquid or carbon dioxide pipeline or pipeline facility must 
obtain from PHMSA an Operator Identification Number (OPID). An OPID is 
assigned to an operator for the pipeline or pipeline system for which 
the operator has primary responsibility. To obtain an OPID or a change 
to an OPID, an operator must complete an OPID Assignment Request DOT 
Form PHMSA F 1000.1 through the National Registry of Operators in 
accordance with Sec.  195.58.
    (b) OPID validation. An operator who has already been assigned one 
or more OPID by January 1, 2011 must validate the information associated 
with each such OPID through the National Registry of Operators at 
https://portal.phmsa.dot.gov, and correct that information as necessary, 
no later than June 30, 2012.
    (c) Changes. Each operator must notify PHMSA electronically through 
the National Registry of Operators at https://portal.phmsa.dot.gov, of 
certain events.
    (1) An operator must notify PHMSA of any of the following events not 
later than 60 days before the event occurs:

[[Page 653]]

    (i) Construction or any planned rehabilitation, replacement, 
modification, upgrade, uprate, or update of a facility, other than a 
section of line pipe, that costs $10 million or more. If 60 day notice 
is not feasible because of an emergency, an operator must notify PHMSA 
as soon as practicable;
    (ii) Construction of 10 or more miles of a new or replacement 
hazardous liquid or carbon dioxide pipeline;
    (iii) Reversal of product flow direction when the reversal is 
expected to last more than 30 days. This notification is not required 
for pipeline systems already designed for bi-directional flow; or
    (iv) A pipeline converted for service under Sec.  195.5, or a change 
in commodity as reported on the annual report as required by Sec.  
195.49.
    (2) An operator must notify PHMSA of any following event not later 
than 60 days after the event occurs:
    (i) A change in the primary entity responsible (i.e., with an 
assigned OPID) for managing or administering a safety program required 
by this part covering pipeline facilities operated under multiple OPIDs.
    (ii) A change in the name of the operator;
    (iii) A change in the entity (e.g., company, municipality) 
responsible for operating an existing pipeline, pipeline segment, or 
pipeline facility;
    (iv) The acquisition or divestiture of 50 or more miles of pipeline 
or pipeline system subject to this part; or
    (v) The acquisition or divestiture of an existing pipeline facility 
subject to this part.
    (d) Reporting. An operator must use the OPID issued by PHMSA for all 
reporting requirements covered under this subchapter and for submissions 
to the National Pipeline Mapping System.

[Amdt. 195-95, 75 FR 72907, Nov. 26, 2010, as amended by Amdt. 195-100, 
80 FR 12780, Mar. 11, 2015; Amdt. 195-101, 82 FR 7999, Jan. 23, 2017; 
Amdt. 195-103, 85 FR 8127, Feb. 12, 2020]



Sec.  195.65  Safety data sheets.

    (a) Each owner or operator of a hazardous liquid pipeline facility, 
following an accident involving a pipeline facility that results in a 
hazardous liquid spill, must provide safety data sheets on any spilled 
hazardous liquid to the designated Federal On-Scene Coordinator and 
appropriate State and local emergency responders within 6 hours of a 
telephonic or electronic notice of the accident to the National Response 
Center.
    (b) Definitions. In this section:
    (1) Federal On-Scene Coordinator. The term ``Federal On-Scene 
Coordinator'' has the meaning given such term in section 311(a) of the 
Federal Water Pollution Control Act (33 U.S.C. 1321(a)).
    (2) National Response Center. The term ``National Response Center'' 
means the center described under 40 CFR 300.125(a).
    (3) Safety data sheet. The term ``safety data sheet'' means a safety 
data sheet required under 29 CFR 1910.1200.

[Amdt. 195-102, 84 FR 52294, Oct. 1, 2019]



                      Subpart C_Design Requirements



Sec.  195.100  Scope.

    This subpart prescribes minimum design requirements for new pipeline 
systems constructed with steel pipe and for relocating, replacing, or 
otherwise changing existing systems constructed with steel pipe. 
However, it does not apply to the movement of line pipe covered by Sec.  
195.424.



Sec.  195.101  Qualifying metallic components other than pipe.

    Notwithstanding any requirement of the subpart which incorporates by 
reference an edition of a document listed in Sec.  195.3, a metallic 
component other than pipe manufactured in accordance with any other 
edition of that document is qualified for use if--
    (a) It can be shown through visual inspection of the cleaned 
component that no defect exists which might impair the strength or 
tightness of the component: and
    (b) The edition of the document under which the component was 
manufactured has equal or more stringent requirements for the following 
as an edition of that document currently or previously listed in Sec.  
195.3:
    (1) Pressure testing;
    (2) Materials; and
    (3) Pressure and temperature ratings.

[Amdt. 195-28, 48 FR 30639, July 5, 1983]

[[Page 654]]



Sec.  195.102  Design temperature.

    (a) Material for components of the system must be chosen for the 
temperature environment in which the components will be used so that the 
pipeline will maintain its structural integrity.
    (b) Components of carbon dioxide pipelines that are subject to low 
temperatures during normal operation because of rapid pressure reduction 
or during the initial fill of the line must be made of materials that 
are suitable for those low temperatures.

[Amdt. 195-45, 56 FR 26925, June 12, 1991]



Sec.  195.104  Variations in pressure.

    If, within a pipeline system, two or more components are to be 
connected at a place where one will operate at a higher pressure than 
another, the system must be designed so that any component operating at 
the lower pressure will not be overstressed.



Sec.  195.106  Internal design pressure.

    (a) Internal design pressure for the pipe in a pipeline is 
determined in accordance with the following formula:
P = (2St/D) x E x F

P = Internal design pressure in p.s.i. (kPa) gage.
S = Yield strength in pounds per square inch (kPa) determined in 
          accordance with paragraph (b) of this section.
t = Nominal wall thickness of the pipe in inches (millimeters). If this 
          is unknown, it is determined in accordance with paragraph (c) 
          of this section.
D = Nominal outside diameter of the pipe in inches (millimeters).
E = Seam joint factor determined in accordance with paragraph (e) of 
          this section.
F = A design factor of 0.72, except that a design factor of 0.60 is used 
          for pipe, including risers, on a platform located offshore or 
          on a platform in inland navigable waters, and 0.54 is used for 
          pipe that has been subjected to cold expansion to meet the 
          specified minimum yield strength and is subsequently heated, 
          other than by welding or stress relieving as a part of 
          welding, to a temperature higher than 900 [deg]F (482 [deg]C) 
          for any period of time or over 600 [deg]F (316 [deg]C) for 
          more than 1 hour.

    (b) The yield strength to be used in determining the internal design 
pressure under paragraph (a) of this section is the specified minimum 
yield strength. If the specified minimum yield strength is not known, 
the yield strength to be used in the design formula is one of the 
following:
    (1)(i) The yield strength determined by performing all of the 
tensile tests of ANSI/API Spec 5L (incorporated by reference, see Sec.  
195.3) on randomly selected specimens with the following number of 
tests:

------------------------------------------------------------------------
                 Pipe size                          No. of tests
------------------------------------------------------------------------
Less than 6\5/8\ in (168 mm) nominal        One test for each 200
 outside diameter.                           lengths.
6 \5/8\ in through 12\3/4\ in (168 mm       One test for each 100
 through 324 mm) nominal outside diameter.   lengths.
Larger than 12\3/4\ in (324 mm) nominal     One test for each 50
 outside diameter.                           lengths.
------------------------------------------------------------------------

    (ii) If the average yield-tensile ratio exceeds 0.85, the yield 
strength shall be taken as 24,000 p.s.i. (165,474 kPa). If the average 
yield-tensile ratio is 0.85 or less, the yield strength of the pipe is 
taken as the lower of the following:
    (A) Eighty percent of the average yield strength determined by the 
tensile tests.
    (B) The lowest yield strength determined by the tensile tests.
    (2) If the pipe is not tensile tested as provided in paragraph (b) 
of this section, the yield strength shall be taken as 24,000 p.s.i. 
(165,474 kPa).
    (c) If the nominal wall thickness to be used in determining internal 
design pressure under paragraph (a) of this section is not known, it is 
determined by measuring the thickness of each piece of pipe at quarter 
points on one end. However, if the pipe is of uniform grade, size, and 
thickness, only 10 individual lengths or 5 percent of all lengths, 
whichever is greater, need be measured. The thickness of the lengths 
that are not measured must be verified by applying a gage set to the 
minimum thickness found by the measurement. The nominal wall thickness 
to be used is the next wall thickness found in commercial specifications 
that is below the average of all the measurements taken. However, the 
nominal wall thickness may not be more than 1.14 times the smallest 
measurement taken on pipe that is less than 20 inches (508 mm) nominal 
outside diameter, nor more than 1.11 times the smallest measurement 
taken on pipe that is 20 inches (508 mm) or more in nominal outside 
diameter.

[[Page 655]]

    (d) The minimum wall thickness of the pipe may not be less than 87.5 
percent of the value used for nominal wall thickness in determining the 
internal design pressure under paragraph (a) of this section. In 
addition, the anticipated external loads and external pressures that are 
concurrent with internal pressure must be considered in accordance with 
Sec. Sec.  195.108 and 195.110 and, after determining the internal 
design pressure, the nominal wall thickness must be increased as 
necessary to compensate for these concurrent loads and pressures.
    (e)(1) The seam joint factor used in paragraph (a) of this section 
is determined in accordance with the following standards incorporated by 
reference (see Sec.  195.3):

------------------------------------------------------------------------
                                                              Seam joint
          Specification                   Pipe class            factor
------------------------------------------------------------------------
ASTM A53/A53M....................  Seamless................         1.00
                                   Electric resistance              1.00
                                    welded.
                                   Furnace lap welded......         0.80
                                   Furnace butt welded.....         0.60
ASTM A106/A106M..................  Seamless................         1.00
ASTM A333/A333M..................  Seamless................         1.00
                                   Welded..................         1.00
ASTM A381........................  Double submerged arc             1.00
                                    welded.
ASTM A671/A671M..................  Electric-fusion-welded..         1.00
ASTM A672/A672M..................  Electric-fusion-welded..         1.00
ASTM A691/A691M..................  Electric-fusion-welded..         1.00
ANSI/API Spec 5L.................  Seamless................         1.00
                                   Electric resistance              1.00
                                    welded.
                                   Electric flash welded...         1.00
                                   Submerged arc welded....         1.00
                                   Furnace lap welded......         0.80
                                   Furnace butt welded.....         0.60
------------------------------------------------------------------------


(2) The seam joint factor for pipe that is not covered by this paragraph 
must be approved by the Administrator.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, 
as amended by Amdt. 195-30, 49 FR 7569, Mar. 1, 1984; Amdt. 195-37, 51 
FR 15335, Apr. 23, 1986; Amdt. 195-40, 54 FR 5628, Feb. 6, 1989; 58 FR 
14524, Mar. 18, 1993; Amdt. 195-50, 59 FR 17281, Apr. 12, 1994; Amdt. 
195-52, 59 FR 33396, 33397, June 28, 1994; Amdt. 195-63, 63 FR 37506, 
July 13, 1998; Amdt. 195-99, 80 FR 185, Jan. 5, 2015]



Sec.  195.108  External pressure.

    Any external pressure that will be exerted on the pipe must be 
provided for in designing a pipeline system.



Sec.  195.110  External loads.

    (a) Anticipated external loads (e.g.), earthquakes, vibration, 
thermal expansion, and contraction must be provided for in designing a 
pipeline system. In providing for expansion and flexibility, section 419 
of ASME/ANSI B31.4 must be followed.
    (b) The pipe and other components must be supported in such a way 
that the support does not cause excess localized stresses. In designing 
attachments to pipe, the added stress to the wall of the pipe must be 
computed and compensated for.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended at 58 FR 14524, 
Mar. 18, 1993]



Sec.  195.111  Fracture propagation.

    A carbon dioxide pipeline system must be designed to mitigate the 
effects of fracture propagation.

[Amdt. 195-45, 56 FR 26926, June 12, 1991]



Sec.  195.112  New pipe.

    Any new pipe installed in a pipeline system must comply with the 
following:
    (a) The pipe must be made of steel of the carbon, low alloy-high 
strength, or alloy type that is able to withstand the internal pressures 
and external loads and pressures anticipated for the pipeline system.
    (b) The pipe must be made in accordance with a written pipe 
specification that sets forth the chemical requirements for the pipe 
steel and mechanical tests for the pipe to provide pipe suitable for the 
use intended.
    (c) Each length of pipe with a nominal outside diameter of 4 \1/2\ 
in (114.3

[[Page 656]]

mm) or more must be marked on the pipe or pipe coating with the 
specification to which it was made, the specified minimum yield strength 
or grade, and the pipe size. The marking must be applied in a manner 
that does not damage the pipe or pipe coating and must remain visible 
until the pipe is installed.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52, 
59 FR 33396, June 28, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998]



Sec.  195.114  Used pipe.

    Any used pipe installed in a pipeline system must comply with Sec.  
195.112 (a) and (b) and the following:
    (a) The pipe must be of a known specification and the seam joint 
factor must be determined in accordance with Sec.  195.106(e). If the 
specified minimum yield strength or the wall thickness is not known, it 
is determined in accordance with Sec.  195.106 (b) or (c) as 
appropriate.
    (b) There may not be any:
    (1) Buckles;
    (2) Cracks, grooves, gouges, dents, or other surface defects that 
exceed the maximum depth of such a defect permitted by the specification 
to which the pipe was manufactured; or
    (3) Corroded areas where the remaining wall thickness is less than 
the minimum thickness required by the tolerances in the specification to 
which the pipe was manufactured.

However, pipe that does not meet the requirements of paragraph (b)(3) of 
this section may be used if the operating pressure is reduced to be 
commensurate with the remaining wall thickness.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982]



Sec.  195.116  Valves.

    Each valve installed in a pipeline system must comply with the 
following:
    (a) The valve must be of a sound engineering design.
    (b) Materials subject to the internal pressure of the pipeline 
system, including welded and flanged ends, must be compatible with the 
pipe or fittings to which the valve is attached.
    (c) Each part of the valve that will be in contact with the carbon 
dioxide or hazardous liquid stream must be made of materials that are 
compatible with carbon dioxide or each hazardous liquid that it is 
anticipated will flow through the pipeline system.
    (d) Each valve must be both hydrostatically shell tested and 
hydrostatically seat tested without leakage to at least the requirements 
set forth in Section 11 of ANSI/API Spec 6D (incorporated by reference, 
see Sec.  195.3).
    (e) Each valve other than a check valve must be equipped with a 
means for clearly indicating the position of the valve (open, closed, 
etc.).
    (f) Each valve must be marked on the body or the nameplate, with at 
least the following:
    (1) Manufacturer's name or trademark.
    (2) Class designation or the maximum working pressure to which the 
valve may be subjected.
    (3) Body material designation (the end connection material, if more 
than one type is used).
    (4) Nominal valve size.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-45, 
56 FR 26926, June 12, 1991; Amdt. 195-86, 71 FR 33410, June 9, 2006; 
Amdt. 195-94, 75 FR 48606, Aug. 11, 2010; Amdt. 195-99, 80 FR 186, Jan. 
5, 2015]



Sec.  195.118  Fittings.

    (a) Butt-welding type fittings must meet the marking, end 
preparation, and the bursting strength requirements of ASME/ANSI B16.9 
or MSS SP-75 (incorporated by reference, see Sec.  195.3).
    (b) There may not be any buckles, dents, cracks, gouges, or other 
defects in the fitting that might reduce the strength of the fitting.
    (c) The fitting must be suitable for the intended service and be at 
least as strong as the pipe and other fittings in the pipeline system to 
which it is attached.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, 
as amended at 58 FR 14524, Mar. 18, 1993; Amdt. 195-99, 80 FR 186, Jan. 
5, 2015]

[[Page 657]]



Sec.  195.120  Passage of internal inspection devices.

    (a) General. Except as provided in paragraphs (b) and (c) of this 
section, each new pipeline and each main line section of a pipeline 
where the line pipe, valve, fitting or other line component is replaced 
must be designed and constructed to accommodate the passage of 
instrumented internal inspection devices in accordance with NACE SP0102 
(incorporated by reference, see Sec.  195.3).
    (b) Exceptions. This section does not apply to:
    (1) Manifolds;
    (2) Station piping such as at pump stations, meter stations, or 
pressure reducing stations;
    (3) Piping associated with tank farms and other storage facilities;
    (4) Cross-overs;
    (5) Pipe for which an instrumented internal inspection device is not 
commercially available; and
    (6) Offshore pipelines, other than lines 10 inches (254 millimeters) 
or greater in nominal diameter, that transport liquids to onshore 
facilities.
    (c) Impracticability. An operator may file a petition under Sec.  
190.9 for a finding that the requirements in paragraph (a) of this 
section should not be applied to a pipeline for reasons of 
impracticability.
    (d) Emergencies. An operator need not comply with paragraph (a) of 
this section in constructing a new or replacement segment of a pipeline 
in an emergency. Within 30 days after discovering the emergency, the 
operator must file a petition under Sec.  190.9 for a finding that 
requiring the design and construction of the new or replacement pipeline 
segment to accommodate passage of instrumented internal inspection 
devices would be impracticable as a result of the emergency. If PHMSA 
denies the petition, within 1 year after the date of the notice of the 
denial, the operator must modify the new or replacement pipeline segment 
to allow passage of instrumented internal inspection devices.

[Amdt. 195-102, 84 FR 52294, Oct. 1, 2019]



Sec.  195.122  Fabricated branch connections.

    Each pipeline system must be designed so that the addition of any 
fabricated branch connections will not reduce the strength of the 
pipeline system.



Sec.  195.124  Closures.

    Each closure to be installed in a pipeline system must comply with 
the 2007 ASME Boiler and Pressure Vessel Code (BPVC) (Section VIII, 
Division 1) (incorporated by reference, see Sec.  195.3) and must have 
pressure and temperature ratings at least equal to those of the pipe to 
which the closure is attached.

[Amdt. 195-99, 80 FR 186, Jan. 5, 2015]



Sec.  195.126  Flange connection.

    Each component of a flange connection must be compatible with each 
other component and the connection as a unit must be suitable for the 
service in which it is to be used.



Sec.  195.128  Station piping.

    Any pipe to be installed in a station that is subject to system 
pressure must meet the applicable requirements of this subpart.



Sec.  195.130  Fabricated assemblies.

    Each fabricated assembly to be installed in a pipeline system must 
meet the applicable requirements of this subpart.



Sec.  195.132  Design and construction of aboveground breakout tanks.

    (a) Each aboveground breakout tank must be designed and constructed 
to withstand the internal pressure produced by the hazardous liquid to 
be stored therein and any anticipated external loads.
    (b) For aboveground breakout tanks first placed in service after 
October 2, 2000, compliance with paragraph (a) of this section requires 
one of the following:
    (1) Shop-fabricated, vertical, cylindrical, closed top, welded steel 
tanks with nominal capacities of 90 to 750 barrels (14.3 to 119.2 m \3\) 
and with internal vapor space pressures that are approximately 
atmospheric must be designed and constructed in accordance

[[Page 658]]

with API Spec 12F (incorporated by reference, see Sec.  195.3) .
    (2) Welded, low-pressure (i.e., internal vapor space pressure not 
greater than 15 psig (103.4 kPa)), carbon steel tanks that have wall 
shapes that can be generated by a single vertical axis of revolution 
must be designed and constructed in accordance with API Std 620 
(incorporated by reference, see Sec.  195.3).
    (3) Vertical, cylindrical, welded steel tanks with internal 
pressures at the tank top approximating atmospheric pressures (i.e., 
internal vapor space pressures not greater than 2.5 psig (17.2 kPa), or 
not greater than the pressure developed by the weight of the tank roof) 
must be designed and constructed in accordance with API Std 650 
(incorporated by reference, see Sec.  195.3).
    (4) High pressure steel tanks (i.e., internal gas or vapor space 
pressures greater than 15 psig (103.4 kPa)) with a nominal capacity of 
2000 gallons (7571 liters) or more of liquefied petroleum gas (LPG) must 
be designed and constructed in accordance with API Std 2510 
(incorporated by reference, see Sec.  195.3).

[Amdt. 195-66, 64 FR 15935, Apr. 2, 1999, as amended by Amdt. 195-99, 80 
FR 186, Jan. 5, 2015; 80 FR 46848, Aug. 6, 2015]



Sec.  195.134  Leak detection.

    (a) Scope. This section applies to each hazardous liquid pipeline 
transporting liquid in single phase (without gas in the liquid).
    (b) General. (1) For each pipeline constructed prior to October 1, 
2019. Each pipeline must have a system for detecting leaks that complies 
with the requirements in Sec.  195.444 by October 1, 2024.
    (2) For each pipeline constructed on or after October 1, 2019. Each 
pipeline must have a system for detecting leaks that complies with the 
requirements in Sec.  195.444 by October 1, 2020.
    (c) CPM leak detection systems. A new computational pipeline 
monitoring (CPM) leak detection system or replaced component of an 
existing CPM system must be designed in accordance with the requirements 
in section 4.2 of API RP 1130 (incorporated by reference, see Sec.  
195.3) and any other applicable design criteria in that standard.
    (d) Exception. The requirements of paragraph (b) of this section do 
not apply to offshore gathering or regulated rural gathering lines.

[Amdt. 195-102, 84 FR 52295, Oct. 1, 2019]



                         Subpart D_Construction



Sec.  195.200  Scope.

    This subpart prescribes minimum requirements for constructing new 
pipeline systems with steel pipe, and for relocating, replacing, or 
otherwise changing existing pipeline systems that are constructed with 
steel pipe. However, this subpart does not apply to the movement of pipe 
covered by Sec.  195.424.



Sec.  195.202  Compliance with specifications or standards.

    Each pipeline system must be constructed in accordance with 
comprehensive written specifications or standards that are consistent 
with the requirements of this part.



Sec.  195.204  Inspection--general.

    Inspection must be provided to ensure that the installation of pipe 
or pipeline systems is in accordance with the requirements of this 
subpart. Any operator personnel used to perform the inspection must be 
trained and qualified in the phase of construction to be inspected. An 
operator must not use operator personnel to perform a required 
inspection if the operator personnel performed the construction task 
requiring inspection. Nothing in this section prohibits the operator 
from inspecting construction tasks with operator personnel who are 
involved in other construction tasks.

[Amdt. 195-100, 80 FR 12780, Mar. 11, 2015]



Sec.  195.205  Repair, alteration and reconstruction of aboveground 
breakout tanks that have been in service.

    (a) Aboveground breakout tanks that have been repaired, altered, or 
reconstructed and returned to service must be capable of withstanding 
the internal pressure produced by the hazardous liquid to be stored 
therein and any anticipated external loads.

[[Page 659]]

    (b) After October 2, 2000, compliance with paragraph (a) of this 
section requires the following:
    (1) For tanks designed for approximate atmospheric pressure, 
constructed of carbon and low alloy steel, welded or riveted, and non-
refrigerated; and for tanks built to API Std 650 (incorporated by 
reference, see Sec.  195.3) or its predecessor Standard 12C; repair, 
alteration; and reconstruction must be in accordance with API Std 653 
(except section 6.4.3) (incorporated by reference, see Sec.  195.3).
    (2) For tanks built to API Spec 12F (incorporated by reference, see 
Sec.  195.3) or API Std 620 (incorporated by reference, see Sec.  
195.3), repair, alteration, and reconstruction must be in accordance 
with the design, welding, examination, and material requirements of 
those respective standards.
    (3) For high-pressure tanks built to API Std 2510 (incorporated by 
reference, see Sec.  195.3), repairs, alterations, and reconstruction 
must be in accordance with API Std 510 (incorporated by reference, see 
Sec.  195.3).

[Amdt. 195-66, 64 FR 15935, Apr. 2, 1999, as amended by Amdt. 195-99, 80 
FR 186, Jan. 5, 2015; 80 FR 46848, Aug. 6, 2015]



Sec.  195.206  Material inspection.

    No pipe or other component may be installed in a pipeline system 
unless it has been visually inspected at the site of installation to 
ensure that it is not damaged in a manner that could impair its strength 
or reduce its serviceability.



Sec.  195.207  Transportation of pipe.

    (a) Railroad. In a pipeline operated at a hoop stress of 20 percent 
or more of SMYS, an operator may not use pipe having an outer diameter 
to wall thickness ratio of 70 to 1, or more, that is transported by 
railroad unless the transportation is performed in accordance with API 
RP 5L1 (incorporated by reference, see Sec.  195.3).
    (b) Ship or barge. In a pipeline operated at a hoop stress of 20 
percent or more of SMYS, an operator may not use pipe having an outer 
diameter to wall thickness ratio of 70 to 1, or more, that is 
transported by ship or barge on both inland and marine waterways, unless 
the transportation is performed in accordance with API RP 5LW 
(incorporated by reference, see Sec.  195.3).
    (c) Truck. In a pipeline to be operated at a hoop stress of 20 
percent or more of SMYS, an operator may not use pipe having an outer 
diameter to wall thickness ratio of 70 to 1, or more, that is 
transported by truck unless the transportation is performed in 
accordance with API RP 5LT (incorporated by reference, see Sec.  195.3).

[Amdt. 195-94, 75 FR 48606, Aug. 11, 2010, as amended by Amdt. 195-99, 
80 FR 186, Jan. 5, 2015]



Sec.  195.208  Welding of supports and braces.

    Supports or braces may not be welded directly to pipe that will be 
operated at a pressure of more than 100 p.s.i. (689 kPa) gage.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-63, 
63 FR 37506, July 13, 1998]



Sec.  195.210  Pipeline location.

    (a) Pipeline right-of-way must be selected to avoid, as far as 
practicable, areas containing private dwellings, industrial buildings, 
and places of public assembly.
    (b) No pipeline may be located within 50 feet (15 meters) of any 
private dwelling, or any industrial building or place of public assembly 
in which persons work, congregate, or assemble, unless it is provided 
with at least 12 inches (305 millimeters) of cover in addition to that 
prescribed in Sec.  195.248.

[Amdt. 195-22, 46 FR 39360, July 27, 1981, as amended by Amdt. 195-63, 
63 FR 37506, July 13, 1998]



Sec.  195.212  Bending of pipe.

    (a) Pipe must not have a wrinkle bend.
    (b) Each field bend must comply with the following:
    (1) A bend must not impair the serviceability of the pipe.
    (2) Each bend must have a smooth contour and be free from buckling, 
cracks, or any other mechanical damage.
    (3) On pipe containing a longitudinal weld, the longitudinal weld 
must be as near as practicable to the neutral axis of the bend unless--

[[Page 660]]

    (i) The bend is made with an internal bending mandrel; or
    (ii) The pipe is 12\3/4\ in (324 mm) or less nominal outside 
diameter or has a diameter to wall thickness ratio less than 70.
    (c) Each circumferential weld which is located where the stress 
during bending causes a permanent deformation in the pipe must be 
nondestructively tested either before or after the bending process.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52, 
59 FR 33396, June 28, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998]



Sec.  195.214  Welding procedures.

    (a) Welding must be performed by a qualified welder or welding 
operator in accordance with welding procedures qualified under section 
5, section 12, Appendix A or Appendix B of API Std 1104 (incorporated by 
reference, see Sec.  195.3), or Section IX of the ASME Boiler and 
Pressure Vessel Code (ASME BPVC) (incorporated by reference, see Sec.  
195.3). The quality of the test welds used to qualify the welding 
procedures must be determined by destructive testing.
    (b) Each welding procedure must be recorded in detail, including the 
results of the qualifying tests. This record must be retained and 
followed whenever the procedure is used.

[Amdt. 195-38, 51 FR 20297, June 4, 1986, as amended at Amdt. 195-81, 69 
FR 32897, June 14, 2004; Amdt. 195-99, 80 FR 186, Jan. 5, 2015; Amdt. 
195-100, 80 FR 12780, Mar. 11, 2015; Amdt. 195-101, 82 FR 7999, Jan. 23, 
2017]



Sec.  195.216  Welding: Miter joints.

    A miter joint is not permitted (not including deflections up to 3 
degrees that are caused by misalignment).



Sec.  195.222  Welders and welding operators: Qualification of welders and 
welding operators.

    (a) Each welder or welding operator must be qualified in accordance 
with section 6, section 12, Appendix A or Appendix B of API Std 1104 
(incorporated by reference, see Sec.  195.3), or section IX of the ASME 
Boiler and Pressure Vessel Code (ASME BPVC), (incorporated by reference, 
see Sec.  195.3) except that a welder or welding operator qualified 
under an earlier edition than listed in Sec.  195.3, may weld but may 
not requalify under that earlier edition.
    (b) No welder or welding operator may weld with a welding process 
unless, within the preceding 6 calendar months, the welder or welding 
operator has--
    (1) Engaged in welding with that process; and
    (2) Had one weld tested and found acceptable under section 9 or 
Appendix A of API Std 1104 (incorporated by reference, see Sec.  195.3).

[Amdt. 195-81, 69 FR 54593, Sept. 9, 2004, as amended by Amdt. 195-86, 
71 FR 33409, June 9, 2006; Amdt. 195-99, 80 FR 186, Jan. 5, 2015; Amdt. 
195-100, 80 FR 12780, Mar. 11, 2015; Amdt. 195-101, 82 FR 7999, Jan. 23, 
2017]



Sec.  195.224  Welding: Weather.

    Welding must be protected from weather conditions that would impair 
the quality of the completed weld.



Sec.  195.226  Welding: Arc burns.

    (a) Each arc burn must be repaired.
    (b) An arc burn may be repaired by completely removing the notch by 
grinding, if the grinding does not reduce the remaining wall thickness 
to less than the minimum thickness required by the tolerances in the 
specification to which the pipe is manufactured. If a notch is not 
repairable by grinding, a cylinder of the pipe containing the entire 
notch must be removed.
    (c) A ground may not be welded to the pipe or fitting that is being 
welded.



Sec.  195.228  Welds and welding inspection: Standards of acceptability.

    (a) Each weld and welding must be inspected to insure compliance 
with the requirements of this subpart. Visual inspection must be 
supplemented by nondestructive testing.
    (b) The acceptability of a weld is determined according to the 
standards in section 9 or Appendix A of API Std 1104 (incorporated by 
reference, see Sec.  195.3). Appendix A of API Std 1104 may not be used 
to accept cracks.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52, 
59 FR 33397, June 28, 1994; Amdt. 195-81, 69 FR 32898, June 14, 2004; 
Amdt. 195-99, 80 FR 186, Jan. 5, 2015; Amdt. 195-100, 80 FR 12780, Mar. 
11, 2015]

[[Page 661]]



Sec.  195.230  Welds: Repair or removal of defects.

    (a) Each weld that is unacceptable under Sec.  195.228 must be 
removed or repaired. Except for welds on an offshore pipeline being 
installed from a pipelay vessel, a weld must be removed if it has a 
crack that is more than 8 percent of the weld length.
    (b) Each weld that is repaired must have the defect removed down to 
sound metal and the segment to be repaired must be preheated if 
conditions exist which would adversely affect the quality of the weld 
repair. After repair, the segment of the weld that was repaired must be 
inspected to ensure its acceptability.
    (c) Repair of a crack, or of any defect in a previously repaired 
area must be in accordance with written weld repair procedures that have 
been qualified under Sec.  195.214. Repair procedures must provide that 
the minimum mechanical properties specified for the welding procedure 
used to make the original weld are met upon completion of the final weld 
repair.

[Amdt. 195-29, 48 FR 48674, Oct. 20, 1983]



Sec.  195.234  Welds: Nondestructive testing.

    (a) A weld may be nondestructively tested by any process that will 
clearly indicate any defects that may affect the integrity of the weld.
    (b) Any nondestructive testing of welds must be performed--
    (1) In accordance with a written set of procedures for 
nondestructive testing; and
    (2) With personnel that have been trained in the established 
procedures and in the use of the equipment employed in the testing.
    (c) Procedures for the proper interpretation of each weld inspection 
must be established to ensure the acceptability of the weld under Sec.  
195.228.
    (d) During construction, at least 10 percent of the girth welds made 
by each welder and welding operator during each welding day must be 
nondestructively tested over the entire circumference of the weld.
    (e) All girth welds installed each day in the following locations 
must be nondestructively tested over their entire circumference, except 
that when nondestructive testing is impracticable for a girth weld, it 
need not be tested if the number of girth welds for which testing is 
impracticable does not exceed 10 percent of the girth welds installed 
that day:
    (1) At any onshore location where a loss of hazardous liquid could 
reasonably be expected to pollute any stream, river, lake, reservoir, or 
other body of water, and any offshore area;
    (2) Within railroad or public road rights-of-way;
    (3) At overhead road crossings and within tunnels;
    (4) Within the limits of any incorporated subdivision of a State 
government; and
    (5) Within populated areas, including, but not limited to, 
residential subdivisions, shopping centers, schools, designated 
commercial areas, industrial facilities, public institutions, and places 
of public assembly.
    (f) When installing used pipe, 100 percent of the old girth welds 
must be nondestructively tested.
    (g) At pipeline tie-ins, including tie-ins of replacement sections, 
100 percent of the girth welds must be nondestructively tested.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-35, 
50 FR 37192, Sept. 21, 1985; Amdt. 195-52, 59 FR 33397, June 28, 1994; 
Amdt. 195-100, 80 FR 12780, Mar. 11, 2015]



Sec. Sec.  195.236-195.244  [Reserved]



Sec.  195.246  Installation of pipe in a ditch.

    (a) All pipe installed in a ditch must be installed in a manner that 
minimizes the introduction of secondary stresses and the possibility of 
damage to the pipe.
    (b) Except for pipe in the Gulf of Mexico and its inlets in waters 
less than 15 feet deep, all offshore pipe in water at least 12 feet deep 
(3.7 meters) but not more than 200 feet deep (61 meters) deep as 
measured from the mean low water must be installed so that the top of 
the pipe is below the underwater natural bottom (as determined by 
recognized and generally accepted practices) unless the pipe is 
supported by stanchions held in place by anchors or

[[Page 662]]

heavy concrete coating or protected by an equivalent means.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52, 
59 FR 33397, June 28, 1994; 59 FR 36256, July 15, 1994; Amdt. 195-85, 69 
FR 48407, Aug. 10, 2004]



Sec.  195.248  Cover over buried pipeline.

    (a) Unless specifically exempted in this subpart, all pipe must be 
buried so that it is below the level of cultivation. Except as provided 
in paragraph (b) of this section, the pipe must be installed so that the 
cover between the top of the pipe and the ground level, road bed, river 
bottom, or underwater natural bottom (as determined by recognized and 
generally accepted practices), as applicable, complies with the 
following table:

------------------------------------------------------------------------
                                            Cover inches (millimeters)
                                         -------------------------------
                Location                    For normal       For rock
                                            excavation    excavation \1\
------------------------------------------------------------------------
Industrial, commercial, and residential         36 (914)        30 (762)
 areas..................................
Crossing of inland bodies of water with        48 (1219)        18 (457)
 a width of at least 100 feet (30.5
 meters) from high water mark to high
 water mark.............................
Drainage ditches at public roads and            36 (914)        36 (914)
 railroads..............................
Deepwater port safety zones.............       48 (1219)        24 (610)
Gulf of Mexico and its inlets in waters         36 (914)        18 (457)
 less than 15 feet (4.6 meters) deep as
 measured from mean low water...........
Other offshore areas under water less           36 (914)        18 (457)
 than 12 ft (3.7 meters) deep as
 measured from mean low water...........
Any other area..........................        30 (762)        18 (457)
------------------------------------------------------------------------
\1\ Rock excavation is any excavation that requires blasting or removal
  by equivalent means.

    (b) Except for the Gulf of Mexico and its inlets in waters less than 
15 feet (4.6 meters) deep, less cover than the minimum required by 
paragraph (a) of this section and Sec.  195.210 may be used if--
    (1) It is impracticable to comply with the minimum cover 
requirements; and
    (2) Additional protection is provided that is equivalent to the 
minimum required cover.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, 
as amended by Amdt. 195-52, 59 FR 33397, June 28, 1994; 59 FR 36256, 
July 15, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998; Amdt. 195-95, 
69 FR 48407, Aug. 10, 2004; Amdt. 195-101, 82 FR 7999, Jan. 23, 2017]



Sec.  195.250  Clearance between pipe and underground structures.

    Any pipe installed underground must have at least 12 inches (305 
millimeters) of clearance between the outside of the pipe and the 
extremity of any other underground structure, except that for drainage 
tile the minimum clearance may be less than 12 inches (305 millimeters) 
but not less than 2 inches (51 millimeters). However, where 12 inches 
(305 millimeters) of clearance is impracticable, the clearance may be 
reduced if adequate provisions are made for corrosion control.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-63, 
63 FR 37506, July 13, 1998]



Sec.  195.252  Backfilling.

    When a ditch for a pipeline is backfilled, it must be backfilled in 
a manner that:
    (a) Provides firm support under the pipe; and
    (b) Prevents damage to the pipe and pipe coating from equipment or 
from the backfill material.

[Amdt. 195-78, 68 FR 53528, Sept. 11, 2003]



Sec.  195.254  Above ground components.

    (a) Any component may be installed above ground in the following 
situations, if the other applicable requirements of this part are 
complied with:
    (1) Overhead crossings of highways, railroads, or a body of water.
    (2) Spans over ditches and gullies.
    (3) Scraper traps or block valves.
    (4) Areas under the direct control of the operator.
    (5) In any area inaccessible to the public.
    (b) Each component covered by this section must be protected from 
the forces exerted by the anticipated loads.

[[Page 663]]



Sec.  195.256  Crossing of railroads and highways.

    The pipe at each railroad or highway crossing must be installed so 
as to adequately withstand the dynamic forces exerted by anticipated 
traffic loads.



Sec.  195.258  Valves: General.

    (a) Each valve must be installed in a location that is accessible to 
authorized employees and that is protected from damage or tampering.
    (b) Each submerged valve located offshore or in inland navigable 
waters must be marked, or located by conventional survey techniques, to 
facilitate quick location when operation of the valve is required.
    (c) For all onshore hazardous liquid or carbon dioxide pipeline 
segments with diameters greater than or equal to 6 inches that are 
constructed after April 10, 2023, the operator must install rupture-
mitigation valves (RMV) or an alternative equivalent technology whenever 
a valve must be installed to meet the appropriate valve spacing 
requirements of this section and Sec.  195.260. An operator using 
alternative equivalent technology must notify PHMSA in accordance with 
the procedure in paragraph (e) of this section. All RMVs and alternative 
equivalent technology installed as required by this section must meet 
the requirements of Sec.  195.419. An operator may request an extension 
of the installation compliance deadline requirements of this paragraph 
if it can demonstrate to PHMSA, in accordance with the notification 
procedures in Sec.  195.18, that those installation deadline 
requirements would be economically, technically, or operationally 
infeasible for a particular new pipeline.
    (d) For all entirely replaced onshore hazardous liquid or carbon 
dioxide pipeline segments with diameters greater than or equal to 6 
inches that have been replaced after April 10, 2023, the operator must 
install RMVs or an alternative equivalent technology whenever a valve 
must be installed to meet the appropriate valve spacing requirements of 
this section. An operator using alternative equivalent technology must 
notify PHMSA in accordance with the procedure in paragraph (e) of this 
section. All valves installed as required by this section must meet the 
requirements of Sec.  195.419. The requirements of this paragraph (d) 
apply when the applicable pipeline replacement project involves a valve, 
either through addition, replacement, or removal. An operator may 
request an extension of the installation compliance deadline 
requirements of this paragraph if it can demonstrate to PHMSA, in 
accordance with the notification procedures in Sec.  195.18, that those 
installation deadline requirements would be economically, technically, 
or operationally infeasible for a particular pipeline replacement 
project.
    (e) If an operator elects to use alternative equivalent technology 
in accordance with paragraph (c) or (d) of this section, the operator 
must notify PHMSA in accordance with Sec.  195.18. The operator must 
include a technical and safety evaluation in its notice to PHMSA. Valves 
that are installed as alternative equivalent technology must comply with 
Sec. Sec.  195.418, 195.419, and 195.420. An operator requesting use of 
manual valves as an alternative equivalent technology must also include 
within the notification submitted to PHMSA a demonstration that 
installation of an RMV as otherwise required would be economically, 
technically, or operationally infeasible. An operator may use a manual 
pump station valve at a continuously manned station as an alternative 
equivalent technology. Such a valve used as an alternative equivalent 
technology would not require a notification to PHMSA in accordance with 
Sec.  195.18, but it must comply with Sec. Sec.  195.419 and 195.420.
    (f) The requirements of paragraphs (c) through (e) of this section 
do not apply to gathering lines.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-105, 
87 FR 20987, Apr. 8, 2022; Amdt. 195-106, 88 FR 50062, Aug. 1, 2023]



Sec.  195.260  Valves: Location.

    A valve must be installed at each of the following locations:
    (a) On the suction end and the discharge end of a pump station in a 
manner that permits isolation of the pump station equipment in the event 
of an emergency.
    (b) On each pipeline entering or leaving a breakout storage tank 
area in a

[[Page 664]]

manner that permits isolation of the tank from other facilities.
    (c) On each pipeline at locations along the pipeline system that 
will minimize or prevent safety risks, property damage, or environmental 
harm from accidental hazardous liquid or carbon dioxide discharges, as 
appropriate for onshore areas, offshore areas, and high-consequence 
areas (HCA). For newly constructed or entirely replaced onshore 
hazardous liquid or carbon dioxide pipeline segments, as that term is 
defined at Sec.  195.2, that are installed after April 10, 2023, valve 
spacing must not exceed 15 miles for pipeline segments that could affect 
or are in HCAs, as defined in Sec.  195.450, and 20 miles for pipeline 
segments that could not affect HCAs. Valves on pipeline segments that 
are located in HCAs or which could affect HCAs must be installed at 
locations as determined by the operator's process for identifying 
preventive and mitigative measures established pursuant to Sec.  
195.452(i) and by using the selection process in section I.B of appendix 
C of part 195, but with a maximum distance that does not exceed 7\1/2\ 
miles from the endpoints of the HCA segment or the segment that could 
affect an HCA. An operator may request an exemption from the compliance 
deadline requirements of this section for valve installation at the 
specified valve spacing if it can demonstrate to PHMSA, in accordance 
with the notification procedures in Sec.  195.18, that those compliance 
deadline requirements would be economically, technically, or 
operationally infeasible.
    (d) On each lateral takeoff from a pipeline in a manner that permits 
shutting off the lateral without interrupting flow in the pipeline.
    (e) On each side of one or more adjacent water crossings that are 
more than 100 feet (30 meters) wide from high water mark to high water 
mark, as follows:
    (1) Valves must be installed at locations outside of the 100-year 
flood plain or be equipped with actuators or other control equipment 
that is installed so as not to be impacted by flood conditions; and
    (2) The maximum spacing interval between valves that protect 
multiple adjacent water crossings cannot exceed 1 mile in length.
    (f) On each side of a reservoir holding water for human consumption.
    (g) On each highly volatile liquid (HVL) pipeline that is located in 
a high-population area or other populated area, as defined in Sec.  
195.450, and that is constructed, or where 2 or more miles of pipe have 
been replaced within any 5 contiguous miles within any 24-month period, 
after April 10, 2023, with a maximum valve spacing of 7\1/2\ miles. The 
maximum valve spacing intervals may be increased by 1.25 times the 
distance up to a 9 \3/8\-mile spacing, provided the operator:
    (1) Submits for PHMSA review a notification pursuant to Sec.  195.18 
requesting alternative spacing because installation of a valve at a 
particular location between a 7-mile to a 7\1/2\-mile spacing would be 
economically, technically, or operationally infeasible, and that an 
alternative spacing would not adversely impact safety; and
    (2) Keeps the records necessary to support that determination for 
the useful life of the pipeline.
    (h) An operator may submit for PHMSA review, in accordance with 
Sec.  195.18, a notification requesting site-specific exemption from the 
valve installation requirements or valve spacing requirements of 
paragraph (c), (e), or (f) of this section and demonstrating such 
exemption would not adversely affect safety. An operator may also submit 
for PHMSA review, in accordance with Sec.  195.18, a notification 
requesting an extension of the compliance deadline requirements for 
valve installation and spacing of this section because those compliance 
deadline requirements would be economically, technically, or 
operationally infeasible for a particular new construction or pipeline 
replacement project.
    (i) An operator of a gathering line must only comply with the 
requirements of 49 CFR 195.260 effective as of October 4, 2022, and need 
not comply with the other requirements of this section.

[Amdt. 195-105, 87 FR 20987, Apr. 8, 2022, as amended by Amdt. 195-106, 
88 FR 50062, Aug. 1, 2023]

[[Page 665]]



Sec.  195.262  Pumping equipment.

    (a) Adequate ventilation must be provided in pump station buildings 
to prevent the accumulation of hazardous vapors. Warning devices must be 
installed to warn of the presence of hazardous vapors in the pumping 
station building.
    (b) The following must be provided in each pump station:
    (1) Safety devices that prevent overpressuring of pumping equipment, 
including the auxiliary pumping equipment within the pumping station.
    (2) A device for the emergency shutdown of each pumping station.
    (3) If power is necessary to actuate the safety devices, an 
auxiliary power supply.
    (c) Each safety device must be tested under conditions approximating 
actual operations and found to function properly before the pumping 
station may be used.
    (d) Except for offshore pipelines, pumping equipment must be 
installed on property that is under the control of the operator and at 
least 15.2 m (50 ft) from the boundary of the pump station.
    (e) Adequate fire protection must be installed at each pump station. 
If the fire protection system installed requires the use of pumps, 
motive power must be provided for those pumps that is separate from the 
power that operates the station.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52, 
59 FR 33397, June 28, 1994]



Sec.  195.264  Impoundment, protection against entry, normal/emergency 
venting or pressure/vacuum relief for aboveground breakout tanks.

    (a) A means must be provided for containing hazardous liquids in the 
event of spillage or failure of an aboveground breakout tank.
    (b) After October 2, 2000, compliance with paragraph (a) of this 
section requires the following for the aboveground breakout tanks 
specified:
    (1) For tanks built to API Spec 12F, API Std 620, and others (such 
as API Std 650 (or its predecessor Standard 12C)), the installation of 
impoundment must be in accordance with the following sections of NFPA-30 
(incorporated by reference, see Sec.  195.3);
    (i) Impoundment around a breakout tank must be installed in 
accordance with section 22.11.2; and
    (ii) Impoundment by drainage to a remote impounding area must be 
installed in accordance with section 22.11.1.
    (2) For tanks built to API Std 2510 (incorporated by reference, see 
Sec.  195.3) , the installation of impoundment must be in accordance 
with section 5 or 11 of API Std 2510.
    (c) Aboveground breakout tank areas must be adequately protected 
against unauthorized entry.
    (d) Normal/emergency relief venting must be provided for each 
atmospheric pressure breakout tank. Pressure/vacuum-relieving devices 
must be provided for each low-pressure and high-pressure breakout tank.
    (e) For normal/emergency relief venting and pressure/vacuum-
relieving devices installed on aboveground breakout tanks after October 
2, 2000, compliance with paragraph (d) of this section requires the 
following for the tanks specified:
    (1) Normal/emergency relief venting installed on atmospheric 
pressure tanks built to API Spec 12F must be in accordance with section 
4 and Appendices B and C of API Spec 12F (incorporated by reference, see 
Sec.  195.3) .
    (2) Normal/emergency relief venting installed on atmospheric 
pressure tanks (such as those built to API Std 650 or its predecessor 
Standard 12C) must be in accordance with API Std 2000 (incorporated by 
reference, see Sec.  195.3).
    (3) Pressure-relieving and emergency vacuum-relieving devices 
installed on low-pressure tanks built to API Std 620 must be in 
accordance with Section 9 of API Std 620 (incorporated by reference, see 
Sec.  195.3) and its references to the normal and emergency venting 
requirements in API Std 2000 (incorporated by reference, see Sec.  
195.3).
    (4) Pressure and vacuum-relieving devices installed on high-pressure 
tanks built to API Std 2510 must be in accordance with sections 7 or 11 
of API

[[Page 666]]

Std 2510 (incorporated by reference, see Sec.  195.3).

[Amdt. 195-66, 64 FR 15935, Apr. 2, 1999, as amended by Amdt. 195-86, 71 
FR 33410, June 9, 2006; Amd .t195-94, 75 FR 48606, Aug. 11, 2010; Amdt. 
195-99, 80 FR 186, Jan. 5, 2015; 80 FR 46848, Aug. 6, 2015]



Sec.  195.266  Construction records.

    A complete record that shows the following must be maintained by the 
operator involved for the life of each pipeline facility:
    (a) The total number of girth welds and the number nondestructively 
tested, including the number rejected and the disposition of each 
rejected weld.
    (b) The amount, location; and cover of each size of pipe installed.
    (c) The location of each crossing of another pipeline.
    (d) The location of each buried utility crossing.
    (e) The location of each overhead crossing.
    (f) The location of each valve and corrosion test station.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-34, 
50 FR 34474, Aug. 26, 1985]



                       Subpart E_Pressure Testing



Sec.  195.300  Scope.

    This subpart prescribes minimum requirements for the pressure 
testing of steel pipelines. However, this subpart does not apply to the 
movement of pipe under Sec.  195.424.

[Amdt. 195-51, 59 FR 29384, June 7, 1994]



Sec.  195.302  General requirements.

    (a) Except as otherwise provided in this section and in Sec.  
195.305(b), no operator may operate a pipeline unless it has been 
pressure tested under this subpart without leakage. In addition, no 
operator may return to service a segment of pipeline that has been 
replaced, relocated, or otherwise changed until it has been pressure 
tested under this subpart without leakage.
    (b) Except for pipelines converted under Sec.  195.5, the following 
pipelines may be operated without pressure testing under this subpart:
    (1) Any hazardous liquid pipeline whose maximum operating pressure 
is established under Sec.  195.406(a)(5) that is--
    (i) An interstate pipeline constructed before January 8, 1971;
    (ii) An interstate offshore gathering line constructed before August 
1, 1977;
    (iii) An intrastate pipeline constructed before October 21, 1985; or
    (iv) A low-stress pipeline constructed before August 11, 1994 that 
transports HVL.
    (2) Any carbon dioxide pipeline constructed before July 12, 1991, 
that--
    (i) Has its maximum operating pressure established under Sec.  
195.406(a)(5); or
    (ii) Is located in a rural area as part of a production field 
distribution system.
    (3) Any low-stress pipeline constructed before August 11, 1994 that 
does not transport HVL.
    (4) Those portions of older hazardous liquid and carbon dioxide 
pipelines for which an operator has elected the risk-based alternative 
under Sec.  195.303 and which are not required to be tested based on the 
risk-based criteria.
    (c) Except for pipelines that transport HVL onshore, low-stress 
pipelines, and pipelines covered under Sec.  195.303, the following 
compliance deadlines apply to pipelines under paragraphs (b)(1) and 
(b)(2)(i) of this section that have not been pressure tested under this 
subpart:
    (1) Before December 7, 1998, for each pipeline each operator shall--
    (i) Plan and schedule testing according to this paragraph; or
    (ii) Establish the pipeline's maximum operating pressure under Sec.  
195.406(a)(5).
    (2) For pipelines scheduled for testing, each operator shall--
    (i) Before December 7, 2000, pressure test--
    (A) Each pipeline identified by name, symbol, or otherwise that 
existing records show contains more than 50 percent by mileage (length) 
of electric resistance welded pipe manufactured before 1970; and
    (B) At least 50 percent of the mileage (length) of all other 
pipelines; and

[[Page 667]]

    (ii) Before December 7, 2003, pressure test the remainder of the 
pipeline mileage (length).

[Amdt. 195-51, 59 FR 29384, June 7, 1994, as amended by Amdt. 195-53, 59 
FR 35471, July 12, 1994; Amdt. 195-51B, 61 FR 43027, Aug. 20, 1996; 
Amdt. 195-58, 62 FR 54592, Oct. 21, 1997; Amdt. 195-63, 63 FR 37506, 
July 13, 1998; Amdt. 195-65, 63 FR 59479, Nov. 4, 1998]



Sec.  195.303  Risk-based alternative to pressure testing older hazardous 
liquid and carbon dioxide pipelines.

    (a) An operator may elect to follow a program for testing a pipeline 
on risk-based criteria as an alternative to the pressure testing in 
Sec.  195.302(b)(1)(i)-(iii) and Sec.  195.302(b)(2)(i) of this subpart. 
Appendix B provides guidance on how this program will work. An operator 
electing such a program shall assign a risk classification to each 
pipeline segment according to the indicators described in paragraph (b) 
of this section as follows:
    (1) Risk Classification A if the location indicator is ranked as low 
or medium risk, the product and volume indicators are ranked as low 
risk, and the probability of failure indicator is ranked as low risk;
    (2) Risk Classification C if the location indicator is ranked as 
high risk; or
    (3) Risk Classification B.
    (b) An operator shall evaluate each pipeline segment in the program 
according to the following indicators of risk:
    (1) The location indicator is--
    (i) High risk if an area is non-rural or environmentally sensitive 
\1\; or
    (ii) Medium risk; or
    (iii) Low risk if an area is not high or medium risk.
    (2) The product indicator is \1\
---------------------------------------------------------------------------

    \1\ (See Appendix B, Table C).
---------------------------------------------------------------------------

    (i) High risk if the product transported is highly toxic or is both 
highly volatile and flammable;
    (ii) Medium risk if the product transported is flammable with a 
flashpoint of less than 100 [deg]F, but not highly volatile; or
    (iii) Low risk if the product transported is not high or medium 
risk.
    (3) The volume indicator is--
    (i) High risk if the line is at least 18 inches in nominal diameter;
    (ii) Medium risk if the line is at least 10 inches, but less than 18 
inches, in nominal diameter; or
    (iii) Low risk if the line is not high or medium risk.
    (4) The probability of failure indicator is--
    (i) High risk if the segment has experienced more than three 
failures in the last 10 years due to time-dependent defects (e.g., 
corrosion, gouges, or problems developed during manufacture, 
construction or operation, etc.); or
    (ii) Low risk if the segment has experienced three failures or less 
in the last 10 years due to time-dependent defects.
    (c) The program under paragraph (a) of this section shall provide 
for pressure testing for a segment constructed of electric resistance-
welded (ERW) pipe and lapwelded pipe manufactured prior to 1970 
susceptible to longitudinal seam failures as determined through 
paragraph (d) of this section. The timing of such pressure test may be 
determined based on risk classifications discussed under paragraph (b) 
of this section. For other segments, the program may provide for use of 
a magnetic flux leakage or ultrasonic internal inspection survey as an 
alternative to pressure testing and, in the case of such segments in 
Risk Classification A, may provide for no additional measures under this 
subpart.
    (d) All pre-1970 ERW pipe and lapwelded pipe is deemed susceptible 
to longitudinal seam failures unless an engineering analysis shows 
otherwise. In conducting an engineering analysis an operator must 
consider the seam-related leak history of the pipe and pipe 
manufacturing information as available, which may include the pipe 
steel's mechanical properties, including fracture toughness; the 
manufacturing process and controls related to seam properties, including 
whether the ERW process was high-frequency or low-frequency, whether the 
weld seam was heat treated, whether the seam was inspected, the test 
pressure and duration during mill hydrotest; the quality control of the 
steel-making process; and other factors pertinent to seam properties and 
quality.

[[Page 668]]

    (e) Pressure testing done under this section must be conducted in 
accordance with this subpart. Except for segments in Risk Classification 
B which are not constructed with pre-1970 ERW pipe, water must be the 
test medium.
    (f) An operator electing to follow a program under paragraph (a) 
must develop plans that include the method of testing and a schedule for 
the testing by December 7, 1998. The compliance deadlines for completion 
of testing are as shown in the table below:

                     Sec.   195.303--Test Deadlines
------------------------------------------------------------------------
                                         Risk
        Pipeline Segment            classification       Test deadline
------------------------------------------------------------------------
Pre-1970 Pipe susceptible to      C or B............  12/7/2000
 longitudinal seam failures       A.................  12/7/2002
 [defined in Sec.   195.303(c) &
 (d)].
All Other Pipeline Segments.....  C.................  12/7/2002
                                  B.................  12/7//2004
                                  A.................  Additional testing
                                                       not required
------------------------------------------------------------------------

    (g) An operator must review the risk classifications for those 
pipeline segments which have not yet been tested under paragraph (a) of 
this section or otherwise inspected under paragraph (c) of this section 
at intervals not to exceed 15 months. If the risk classification of an 
untested or uninspected segment changes, an operator must take 
appropriate action within two years, or establish the maximum operating 
pressure under Sec.  195.406(a)(5).
    (h) An operator must maintain records establishing compliance with 
this section, including records verifying the risk classifications, the 
plans and schedule for testing, the conduct of the testing, and the 
review of the risk classifications.
    (i) An operator may discontinue a program under this section only 
after written notification to the Administrator and approval, if needed, 
of a schedule for pressure testing.

[Amdt. 195-65, 63 FR 59480, Nov. 4, 1998]



Sec.  195.304  Test pressure.

    The test pressure for each pressure test conducted under this 
subpart must be maintained throughout the part of the system being 
tested for at least 4 continuous hours at a pressure equal to 125 
percent, or more, of the maximum operating pressure and, in the case of 
a pipeline that is not visually inspected for leakage during the test, 
for at least an additional 4 continuous hours at a pressure equal to 110 
percent, or more, of the maximum operating pressure.

[Amdt. 195-51, 59 FR 29384, June 7, 1994. Redesignated by Amdt. 195-65, 
63 FR 59480, Nov. 4, 1998]



Sec.  195.305  Testing of components.

    (a) Each pressure test under Sec.  195.302 must test all pipe and 
attached fittings, including components, unless otherwise permitted by 
paragraph (b) of this section.
    (b) A component, other than pipe, that is the only item being 
replaced or added to the pipeline system need not be hydrostatically 
tested under paragraph (a) of this section if the manufacturer certifies 
that either--
    (1) The component was hydrostatically tested at the factory; or
    (2) The component was manufactured under a quality control system 
that ensures each component is at least equal in strength to a prototype 
that was hydrostatically tested at the factory.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-51, 
59 FR 29385, June 7, 1994; Amdt. 195-52, 59 FR 33397, June 28, 1994. 
Redesignated by Amdt. 195-65, 63 FR 59480, Nov. 4, 1998]



Sec.  195.306  Test medium.

    (a) Except as provided in paragraphs (b), (c), and (d) of this 
section, water must be used as the test medium.
    (b) Except for offshore pipelines, liquid petroleum that does not 
vaporize rapidly may be used as the test medium if--
    (1) The entire pipeline section under test is outside of cities and 
other populated areas;
    (2) Each building within 300 feet (91 meters) of the test section is 
unoccupied while the test pressure is equal to or greater than a 
pressure which produces a hoop stress of 50 percent of specified minimum 
yield strength;
    (3) The test section is kept under surveillance by regular patrols 
during the test; and
    (4) Continuous communication is maintained along entire test 
section.

[[Page 669]]

    (c) Carbon dioxide pipelines may use inert gas or carbon dioxide as 
the test medium if--
    (1) The entire pipeline section under test is outside of cities and 
other populated areas;
    (2) Each building within 300 feet (91 meters) of the test section is 
unoccupied while the test pressure is equal to or greater than a 
pressure that produces a hoop stress of 50 percent of specified minimum 
yield strength;
    (3) The maximum hoop stress during the test does not exceed 80 
percent of specified minimum yield strength;
    (4) Continuous communication is maintained along entire test 
section; and
    (5) The pipe involved is new pipe having a longitudinal joint factor 
of 1.00.
    (d) Air or inert gas may be used as the test medium in low-stress 
pipelines.

[Amdt. 195-22, 46 FR 38360, July 27, 1991, as amended by Amdt. 195-45, 
56 FR 26926, June 12, 1991; Amdt. 195-51, 59 FR 29385, June 7, 1994; 
Amdt. 195-53, 59 FR 35471, July 12, 1994; Amdt. 195-51A, 59 FR 41260, 
Aug. 11, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998]



Sec.  195.307  Pressure testing aboveground breakout tanks.

    (a) For aboveground breakout tanks built to API Spec 12F 
(incorporated by reference, see Sec.  195.3) and first placed in service 
after October 2, 2000, pneumatic testing must be performed in accordance 
with section 5.3 of API Spec 12 F.
    (b) For aboveground breakout tanks built to API Std 620 
(incorporated by reference, see Sec.  195.3) and first placed in service 
after October 2, 2000, hydrostatic and pneumatic testing must be 
performed in accordance with section 7.18 of API Std 620.
    (c) For aboveground breakout tanks built to API Std 650 
(incorporated by reference, see Sec.  195.3) and first placed in service 
after October 2, 2000, testing must be in accordance with sections 7.3.5 
and 7.3.6 of API Standard 650 (incorporated by reference, see Sec.  
195.3).
    (d) For aboveground atmospheric pressure breakout tanks constructed 
of carbon and low alloy steel, welded or riveted, and non-refrigerated 
tanks built to API Std 650 or its predecessor Standard 12 C that are 
returned to service after October 2, 2000, the necessity for the 
hydrostatic testing of repair, alteration, and reconstruction is covered 
in section 12.3 of API Standard 653 (incorporated by reference, see 
Sec.  195.3).
    (e) For aboveground breakout tanks built to API Std 2510 
(incorporated by reference, see Sec.  195.3) and first placed in service 
after October 2, 2000, pressure testing must be performed in accordance 
with 2007 ASME Boiler and Pressure Vessel Code (BPVC) (Section VIII, 
Division 1 or 2).

[Amdt. 195-99, 80 FR 187, Jan. 5, 2015, as amended by Amdt. 195-100, 80 
FR 12780, Mar. 11, 2015]



Sec.  195.308  Testing of tie-ins.

    Pipe associated with tie-ins must be pressure tested, either with 
the section to be tied in or separately.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-51, 
59 FR 29385, June 7, 1994]



Sec.  195.310  Records.

    (a) A record must be made of each pressure test required by this 
subpart, and the record of the latest test must be retained as long as 
the facility tested is in use.
    (b) The record required by paragraph (a) of this section must 
include:
    (1) The pressure recording charts;
    (2) Test instrument calibration data;
    (3) The name of the operator, the name of the person responsible for 
making the test, and the name of the test company used, if any;
    (4) The date and time of the test;
    (5) The minimum test pressure;
    (6) The test medium;
    (7) A description of the facility tested and the test apparatus;
    (8) An explanation of any pressure discontinuities, including test 
failures, that appear on the pressure recording charts;
    (9) Where elevation differences in the section under test exceed 100 
feet (30 meters), a profile of the pipeline that shows the elevation and 
test sites over the entire length of the test section; and

[[Page 670]]

    (10) Temperature of the test medium or pipe during the test period.

[Amdt. 195-34, 50 FR 34474, Aug. 26, 1985, as amended by Amdt. 195-51, 
59 FR 29385, June 7, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998; 
Amdt. 195-78, 68 FR 53528, Sept. 11, 2003]



                   Subpart F_Operation and Maintenance



Sec.  195.400  Scope.

    This subpart prescribes minimum requirements for operating and 
maintaining pipeline systems constructed with steel pipe.



Sec.  195.401  General requirements.

    (a) No operator may operate or maintain its pipeline systems at a 
level of safety lower than that required by this subpart and the 
procedures it is required to establish under Sec.  195.402(a) of this 
subpart.
    (b) An operator must make repairs on its pipeline system according 
to the following requirements:
    (1) Non Integrity management repairs. Whenever an operator discovers 
any condition that could adversely affect the safe operation of its 
pipeline system, it must correct the condition within a reasonable time. 
However, if the condition is of such a nature that it presents an 
immediate hazard to persons or property, the operator may not operate 
the affected part of the system until it has corrected the unsafe 
condition.
    (2) Integrity management repairs. When an operator discovers a 
condition on a pipeline covered under Sec.  195.452, the operator must 
correct the condition as prescribed in Sec.  195.452(h).
    (3) Prioritizing repairs. An operator must consider the risk to 
people, property, and the environment in prioritizing the correction of 
any conditions referenced in paragraphs (b)(1) and (2) of this section.
    (c) Except as provided in Sec.  195.5, no operator may operate any 
part of any of the following pipelines unless it was designed and 
constructed as required by this part:
    (1) An interstate pipeline, other than a low-stress pipeline, on 
which construction was begun after March 31, 1970, that transports 
hazardous liquid.
    (2) An interstate offshore gathering line, other than a low-stress 
pipeline, on which construction was begun after July 31, 1977, that 
transports hazardous liquid.
    (3) An intrastate pipeline, other than a low-stress pipeline, on 
which construction was begun after October 20, 1985, that transports 
hazardous liquid.
    (4) A pipeline on which construction was begun after July 11, 1991, 
that transports carbon dioxide.
    (5) A low-stress pipeline on which construction was begun after 
August 10, 1994.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-33, 
50 FR 15899, Apr. 23, 1985; Amdt. 195-33A, 50 FR 39008, Sept. 26, 1985; 
Amdt. 195-36, 51 FR 15008, Apr. 22, 1986; Amdt. 195-45, 56 FR 26926, 
June 12, 1991; Amdt. 195-53, 59 FR 35471, July 12, 1994; Amdt. 195-94, 
75 FR 48607, Aug. 11, 2010; Amdt. 195-102, 84 FR 52295, Oct. 1, 2019]



Sec.  195.402  Procedural manual for operations, maintenance, and 
emergencies.

    (a) General. Each operator shall prepare and follow for each 
pipeline system a manual of written procedures for conducting normal 
operations and maintenance activities and handling abnormal operations 
and emergencies. This manual shall be reviewed at intervals not 
exceeding 15 months, but at least once each calendar year, and 
appropriate changes made as necessary to insure that the manual is 
effective. This manual shall be prepared before initial operations of a 
pipeline system commence, and appropriate parts shall be kept at 
locations where operations and maintenance activities are conducted.
    (b) The Associate Administrator or the State Agency that has 
submitted a current certification under the pipeline safety laws (49 
U.S.C. 60101 et seq.) with respect to the pipeline facility governed by 
an operator's plans and procedures may, after notice and opportunity for 
hearing as provided in 49 CFR 190.206 or the relevant State procedures, 
require the operator to amend its plans and procedures as necessary to 
provide a reasonable level of safety.
    (c) Maintenance and normal operations. The manual required by 
paragraph (a) of this section must include procedures

[[Page 671]]

for the following to provide safety during maintenance and normal 
operations:
    (1) Making construction records, maps, and operating history 
available as necessary for safe operation and maintenance.
    (2) Gathering of data needed for reporting accidents under subpart B 
of this part in a timely and effective manner.
    (3) Operating, maintaining, and repairing the pipeline system in 
accordance with each of the requirements of this subpart and subpart H 
of this part.
    (4) Determining which pipeline facilities are in areas that would 
require an immediate response by the operator to prevent hazards to the 
public, property, or the environment if the facilities failed or 
malfunctioned, including segments that could affect high-consequence 
areas (HCA) or are in HCAs, and valves specified in Sec.  195.418 or 
Sec.  195.452(i)(4).
    (5) Investigating and analyzing pipeline accidents and failures, 
including sending the failed pipe, component, or equipment for 
laboratory testing or examination where appropriate, to determine the 
cause(s) and contributing factors of the failure and to minimize the 
possibility of a recurrence.
    (i) Post-failure and -accident lessons learned. Each operator must 
develop, implement, and incorporate lessons learned from a post-failure 
and accident review into its written procedures, including in pertinent 
operator personnel training and qualifications programs, and in design, 
construction, testing, maintenance, operations, and emergency procedure 
manuals and specifications.
    (ii) Analysis of rupture and valve shut-offs; preventive and 
mitigative measures. If a failure or accident on an onshore hazardous 
liquid or carbon dioxide pipeline involves the closure of a rupture-
mitigation valve (RMV), as defined in Sec.  195.2, or the closure of an 
alternative equivalent technology, the operator of the pipeline must 
also conduct a post-failure or post-accident analysis of all the factors 
that may have impacted the release volume and the consequences of the 
release, and identify and implement operations and maintenance measures 
to minimize the consequences of a future failure or accident. The 
analysis must include all relevant factors impacting the release volume 
and the consequences, including, but not limited to, the following:
    (A) Detection, identification, operational response, system shut-
off, and emergency-response communications, based on the type and volume 
of the release or failure event;
    (B) Appropriateness and effectiveness of procedures and pipeline 
systems, including supervisory control and data acquisition (SCADA), 
communications, valve shut-off, and operator personnel;
    (C) Actual response time from identifying a rupture following a 
notification of potential rupture, as defined at Sec.  195.2, to 
initiation of mitigative actions and isolation of the segment, and the 
appropriateness and effectiveness of the mitigative actions taken;
    (D) Location and timeliness of actuation of all RMVs or alternative 
equivalent technologies; and
    (E) All other factors the operator deems appropriate.
    (iii) Rupture post-failure and accident summary. If a failure or 
accident on an onshore hazardous liquid or carbon dioxide pipeline 
involves the identification of a rupture following a notification of 
potential rupture; the closure of an RMV, as those terms are defined in 
Sec.  195.2; or the closure of an alternative equivalent technology, the 
operator must complete a summary of the post-failure or -accident review 
required by paragraph (c)(5)(ii) of this section within 90 days of the 
failure or accident. While the investigation is pending, the operator 
must conduct quarterly status reviews until the investigation is 
completed and a final post-failure or -accident review is prepared. The 
final post-failure or -accident summary and all other reviews and 
analyses produced under the requirements of this section must be 
reviewed, dated, and signed by the operator's appropriate senior 
executive officer. An operator must keep, for the useful life of the 
pipeline, the final post-failure or -accident summary, all investigation 
and analysis documents used to prepare it, and records of lessons 
learned.
    (6) Minimizing the potential for hazards identified under paragraph 
(c)(4)

[[Page 672]]

of this section and the possibility of recurrence of accidents analyzed 
under paragraph (c)(5) of this section.
    (7) Starting up and shutting down any part of the pipeline system in 
a manner designed to assure operation within the limits prescribed by 
Sec.  195.406, consider the hazardous liquid or carbon dioxide in 
transportation, variations in altitude along the pipeline, and pressure 
monitoring and control devices.
    (8) In the case of a pipeline that is not equipped to fail safe, 
monitoring from an attended location pipeline pressure during startup 
until steady state pressure and flow conditions are reached and during 
shut-in to assure operation within limits prescribed by Sec.  195.406.
    (9) In the case of facilities not equipped to fail safe that are 
identified under paragraph 195.402(c)(4) or that control receipt and 
delivery of the hazardous liquid or carbon dioxide, detecting abnormal 
operating conditions by monitoring pressure, temperature, flow or other 
appropriate operational data and transmitting this data to an attended 
location.
    (10) Abandoning pipeline facilities, including safe disconnection 
from an operating pipeline system, purging of combustibles, and sealing 
abandoned facilities left in place to minimize safety and environmental 
hazards. For each abandoned offshore pipeline facility or each abandoned 
onshore pipeline facility that crosses over, under or through 
commercially navigable waterways the last operator of that facility must 
file a report upon abandonment of that facility in accordance with Sec.  
195.59 of this part.
    (11) Minimizing the likelihood of accidental ignition of vapors in 
areas near facilities identified under paragraph (c)(4) of this section 
where the potential exists for the presence of flammable liquids or 
gases.
    (12) Establishing and maintaining adequate means of communication 
with the appropriate public safety answering point (i.e., 9-1-1 
emergency call center), where direct access to a 9-1-1 emergency call 
center is available from the location of the pipeline, and fire, police, 
and other public officials. Operators must determine the 
responsibilities, resources, jurisdictional area(s), and emergency 
contact telephone numbers for both local and out-of-area calls of each 
Federal, State, and local government organization that may respond to a 
pipeline emergency, and inform the officials about the operator's 
ability to respond to the pipeline emergency and means of communication 
during emergencies. Operators may establish liaison with the appropriate 
local emergency coordinating agencies, such as 9-1-1 emergency call 
centers or county emergency managers, in lieu of communicating 
individually with each fire, police, or other public entity.
    (13) Periodically reviewing the work done by operator personnel to 
determine the effectiveness of the procedures used in normal operation 
and maintenance and taking corrective action where deficiencies are 
found.
    (14) Taking adequate precautions in excavated trenches to protect 
personnel from the hazards of unsafe accumulations of vapor or gas, and 
making available when needed at the excavation, emergency rescue 
equipment, including a breathing apparatus and, a rescue harness and 
line.
    (15) Implementing the applicable control room management procedures 
required by Sec.  195.446.
    (d) Abnormal operation. The manual required by paragraph (a) of this 
section must include procedures for the following to provide safety when 
operating design limits have been exceeded:
    (1) Responding to, investigating, and correcting the cause of:
    (i) Unintended closure of valves or shutdowns;
    (ii) Increase or decrease in pressure or flow rate outside normal 
operating limits;
    (iii) Loss of communications;
    (iv) Operation of any safety device;
    (v) Any other malfunction of a component, deviation from normal 
operation, or personnel error which could cause a hazard to persons or 
property.
    (2) Checking variations from normal operation after abnormal 
operation has ended at sufficient critical locations in the system to 
determine continued integrity and safe operation.
    (3) Correcting variations from normal operation of pressure and flow 
equipment and controls.

[[Page 673]]

    (4) Notifying responsible operator personnel when notice of an 
abnormal operation is received.
    (5) Periodically reviewing the response of operator personnel to 
determine the effectiveness of the procedures controlling abnormal 
operation and taking corrective action where deficiencies are found.
    (e) Emergencies. The manual required by paragraph (a) of this 
section must include procedures for the following to provide safety when 
an emergency condition occurs:
    (1) Receiving, identifying, and classifying notices of events that 
need immediate response by the operator or notice to the appropriate 
public safety answering point (i.e., 9-1-1 emergency call center), where 
direct access to a 9-1-1 emergency call center is available from the 
location of the pipeline, and fire, police, and other appropriate public 
officials, and communicating this information to appropriate operator 
personnel for prompt corrective action. Operators may establish liaison 
with the appropriate local emergency coordinating agencies, such as 9-1-
1 emergency call centers or county emergency managers, in lieu of 
communicating individually with each fire, police, or other public 
entity.
    (2) Prompt and effective response to a notice of each type 
emergency, including fire or explosion occurring near or directly 
involving a pipeline facility, accidental release of hazardous liquid or 
carbon dioxide from a pipeline facility, operational failure causing a 
hazardous condition, and natural disaster affecting pipeline facilities.
    (3) Having personnel, equipment, instruments, tools, and material 
available as needed at the scene of an emergency.
    (4) Taking necessary actions, including but not limited to, 
emergency shutdown, valve shut-off, or pressure reduction, in any 
section of the operator's pipeline system, to minimize hazards of 
released hazardous liquid or carbon dioxide to life, property, or the 
environment. Each operator must also develop written rupture 
identification procedures to evaluate and identify whether a 
notification of potential rupture, as defined in Sec.  195.2, is an 
actual rupture event or non-rupture event. These procedures must, at a 
minimum, specify the sources of information, operational factors, and 
other criteria that operator personnel use to evaluate a notification of 
potential rupture, as defined at Sec.  195.2. For operators installing 
valves in accordance with Sec.  195.258(c), Sec.  195.258(d), or that 
are subject to the requirements in Sec.  195.418, those procedures 
should provide for rupture identification as soon as practicable.
    (5) Control of released hazardous liquid or carbon dioxide at an 
accident scene to minimize the hazards, including possible intentional 
ignition in the cases of flammable highly volatile liquid.
    (6) Minimization of public exposure to injury and probability of 
accidental ignition by assisting with evacuation of residents and 
assisting with halting traffic on roads and railroads in the affected 
area, or taking other appropriate action.
    (7) Notifying the appropriate public safety answering point (i.e., 
9-1-1 emergency call center), where direct access to a 9-1-1 emergency 
call center is available from the location of the pipeline, and fire, 
police, and other public officials, of hazardous liquid or carbon 
dioxide pipeline emergencies to coordinate and share information to 
determine the location of the release, including both planned responses 
and actual responses during an emergency, and any additional precautions 
necessary for an emergency involving a pipeline transporting a highly 
volatile liquid (HVL). The operator must immediately and directly notify 
the appropriate public safety answering point or other coordinating 
agency for the communities and jurisdiction(s) in which the pipeline is 
located after notification of potential rupture, as defined at Sec.  
195.2, has occurred to coordinate and share information to determine the 
location of the release, regardless of whether the segment is subject to 
the requirements of Sec.  195.258 (c) or (d), Sec.  195.418, or Sec.  
195.419.
    (8) In the case of failure of a pipeline system transporting a 
highly volatile liquid, use of appropriate instruments to assess the 
extent and coverage of the vapor cloud and determine the hazardous 
areas.

[[Page 674]]

    (9) Providing for a post accident review of employee activities to 
determine whether the procedures were effective in each emergency and 
taking corrective action where deficiencies are found.
    (10) Actions required to be taken by a controller during an 
emergency, in accordance with the operator's emergency plans and 
Sec. Sec.  195.418 and 195.446.
    (f) Safety-related condition reports. The manual required by 
paragraph (a) of this section must include instructions enabling 
personnel who perform operation and maintenance activities to recognize 
conditions that potentially may be safety-related conditions that are 
subject to the reporting requirements of Sec.  195.55.
    (g) Exception. An operator of a gathering line must only comply with 
the requirements of 49 CFR 195.402 effective as of October 4, 2022, and 
need not comply with the other requirements of this section.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, 
as amended by Amdt. 195-24, 47 FR 46852, Oct. 21, 1982; Amdt. 195-39, 53 
FR 24951, July 1, 1988; Amdt. 195-45, 56 FR 26926, June 12, 1991; Amdt. 
195-46, 56 FR 31090, July 9, 1991; Amdt. 195-49, 59 FR 6585, Feb. 11, 
1994; Amdt. 195-55, 61 FR 18518, Apr. 26, 1996; Amdt. 195-69, 65 FR 
54444, Sept. 8, 2000; Amdt. 195-173, 66 FR 67004, Dec. 27, 2001; Amdt. 
195-93, 74 FR 63329, Dec. 3, 2009; Amdt. 195-98, 78 FR 58915, Sept. 25, 
2013; Amdt. 195-105, 87 FR 20988, Apr. 7, 2022; Amdt. 195-106, 88 FR 
50062, Aug. 1, 2023]



Sec.  195.403  Emergency response training.

    (a) Each operator shall establish and conduct a continuing training 
program to instruct emergency response personnel to:
    (1) Carry out the emergency procedures established under 195.402 
that relate to their assignments;
    (2) Know the characteristics and hazards of the hazardous liquids or 
carbon dioxide transported, including, in case of flammable HVL, 
flammability of mixtures with air, odorless vapors, and water reactions;
    (3) Recognize conditions that are likely to cause emergencies, 
predict the consequences of facility malfunctions or failures and 
hazardous liquids or carbon dioxide spills, and take appropriate 
corrective action;
    (4) Take steps necessary to control any accidental release of 
hazardous liquid or carbon dioxide and to minimize the potential for 
fire, explosion, toxicity, or environmental damage; and
    (5) Learn the potential causes, types, sizes, and consequences of 
fire and the appropriate use of portable fire extinguishers and other 
on-site fire control equipment, involving, where feasible, a simulated 
pipeline emergency condition.
    (b) At the intervals not exceeding 15 months, but at least once each 
calendar year, each operator shall:
    (1) Review with personnel their performance in meeting the 
objectives of the emergency response training program set forth in 
paragraph (a) of this section; and
    (2) Make appropriate changes to the emergency response training 
program as necessary to ensure that it is effective.
    (c) Each operator shall require and verify that its supervisors 
maintain a thorough knowledge of that portion of the emergency response 
procedures established under 195.402 for which they are responsible to 
ensure compliance.

[Amdt. 195-67, 64 FR 46866, Aug. 27, 1999, as amended at Amdt. 195-78, 
68 FR 53528, Sept. 11, 2003]



Sec.  195.404  Maps and records.

    (a) Each operator shall maintain current maps and records of its 
pipeline systems that include at least the following information:
    (1) Location and identification of the following pipeline 
facilities:
    (i) Breakout tanks;
    (ii) Pump stations;
    (iii) Scraper and sphere facilities;
    (iv) Pipeline valves;
    (v) Facilities to which Sec.  195.402(c)(9) applies;
    (vi) Rights-of-way; and
    (vii) Safety devices to which Sec.  195.428 applies.
    (2) All crossings of public roads, railroads, rivers, buried 
utilities, and foreign pipelines.
    (3) The maximum operating pressure of each pipeline.
    (4) The diameter, grade, type, and nominal wall thickness of all 
pipe.

[[Page 675]]

    (b) Each operator shall maintain for at least 3 years daily 
operating records that indicate--
    (1) The discharge pressure at each pump station; and
    (2) Any emergency or abnormal operation to which the procedures 
under Sec.  195.402 apply.
    (c) Each operator shall maintain the following records for the 
periods specified:
    (1) The date, location, and description of each repair made to pipe 
shall be maintained for the useful life of the pipe.
    (2) The date, location, and description of each repair made to parts 
of the pipeline system other than pipe shall be maintained for at least 
1 year.
    (3) A record of each inspection and test required by this subpart 
shall be maintained for at least 2 years or until the next inspection or 
test is performed, whichever is longer.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-34, 
50 FR 34474, Aug. 26, 1985; Amdt. 195-173, 66 FR 67004, Dec. 27, 2001]



Sec.  195.405  Protection against ignitions and safe access/egress  
involving floating roofs.

    (a) After October 2, 2000, protection provided against ignitions 
arising out of static electricity, lightning, and stray currents during 
operation and maintenance activities involving aboveground breakout 
tanks must be in accordance with API RP 2003 (incorporated by reference, 
see Sec.  195.3), unless the operator notes in the procedural manual 
(Sec.  195.402(c)) why compliance with all or certain provisions of API 
RP 2003 is not necessary for the safety of a particular breakout tank.
    (b) The hazards associated with access/egress onto floating roofs of 
in-service aboveground breakout tanks to perform inspection, service, 
maintenance, or repair activities (other than specified general 
considerations, specified routine tasks or entering tanks removed from 
service for cleaning) are addressed in API Pub 2026 (incorporated by 
reference, see Sec.  195.3) . After October 2, 2000, the operator must 
review and consider the potentially hazardous conditions, safety 
practices, and procedures in API Pub 2026 for inclusion in the procedure 
manual (Sec.  195.402(c)).

[Amdt. 195-99,80 FR 187, Jan. 5, 2015; 80 FR 46848, Aug. 6, 2015]



Sec.  195.406  Maximum operating pressure.

    (a) Except for surge pressures and other variations from normal 
operations, no operator may operate a pipeline at a pressure that 
exceeds any of the following:
    (1) The internal design pressure of the pipe determined in 
accordance with Sec.  195.106. However, for steel pipe in pipelines 
being converted under Sec.  195.5, if one or more factors of the design 
formula (Sec.  195.106) are unknown, one of the following pressures is 
to be used as design pressure:
    (i) Eighty percent of the first test pressure that produces yield 
under section N5.0 of appendix N of ASME/ANSI B31.8 (incorporated by 
reference, see Sec.  195.3), reduced by the appropriate factors in 
Sec. Sec.  195.106 (a) and (e); or
    (ii) If the pipe is 12 \3/4\ inch (324 mm) or less outside diameter 
and is not tested to yield under this paragraph, 200 p.s.i. (1379 kPa) 
gage.
    (2) The design pressure of any other component of the pipeline.
    (3) Eighty percent of the test pressure for any part of the pipeline 
which has been pressure tested under subpart E of this part.
    (4) Eighty percent of the factory test pressure or of the prototype 
test pressure for any individually installed component which is excepted 
from testing under Sec.  195.305.
    (5) For pipelines under Sec. Sec.  195.302(b)(1) and (b)(2)(i) that 
have not been pressure tested under subpart E of this part, 80 percent 
of the test pressure or highest operating pressure to which the pipeline 
was subjected for 4 or more continuous hours that can be demonstrated by 
recording charts or logs made at the time the test or operations were 
conducted.
    (b) No operator may permit the pressure in a pipeline during surges 
or other variations from normal operations to exceed 110 percent of the 
operating pressure limit established under paragraph (a) of this 
section. Each operator must provide adequate

[[Page 676]]

controls and protective equipment to control the pressure within this 
limit.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-33, 
50 FR 15899, Apr. 23, 1985; 50 FR 38660, Sept. 24, 1985; Amdt. 195-51, 
59 FR 29385, June 7, 1994; Amdt. 195-52, 59 FR 33397, June 28, 1994; 
Amdt. 195-63, 63 FR 37506, July 13, 1998; Amdt. 195-65, 63 FR 59480, 
Nov. 4, 1998; Amdt. 195-99, 80 FR 184, Jan. 5, 2015]



Sec.  195.408  Communications.

    (a) Each operator must have a communication system to provide for 
the transmission of information needed for the safe operation of its 
pipeline system.
    (b) The communication system required by paragraph (a) of this 
section must, as a minimum, include means for:
    (1) Monitoring operational data as required by Sec.  195.402(c)(9);
    (2) Receiving notices from operator personnel, the public, and 
public authorities of abnormal or emergency conditions and sending this 
information to appropriate personnel or government agencies for 
corrective action;
    (3) Conducting two-way vocal communication between a control center 
and the scene of abnormal operations and emergencies; and
    (4) Providing communication with fire, police, and other appropriate 
public officials during emergency conditions, including a natural 
disaster.



Sec.  195.410  Line markers.

    (a) Except as provided in paragraph (b) of this section, each 
operator shall place and maintain line markers over each buried pipeline 
in accordance with the following:
    (1) Markers must be located at each public road crossing, at each 
railroad crossing, and in sufficient number along the remainder of each 
buried line so that its location is accurately known.
    (2) The marker must state at least the following on a background of 
sharply contrasting color:
    (i) The word ``Warning,'' ``Caution,'' or ``Danger'' followed by the 
words ``Petroleum (or the name of the hazardous liquid transported) 
Pipeline'', or ``Carbon Dioxide Pipeline,'' all of which, except for 
markers in heavily developed urban areas, must be in letters at least 1 
inch (25 millimeters) high with an approximate stroke of \1/4\ inch (6.4 
millimeters).
    (ii) The name of the operator and a telephone number (including area 
code) where the operator can be reached at all times.
    (b) Line markers are not required for buried pipelines located--
    (1) Offshore or at crossings of or under waterways and other bodies 
of water; or
    (2) In heavily developed urban areas such as downtown business 
centers where--
    (i) The placement of markers is impractical and would not serve the 
purpose for which markers are intended; and
    (ii) The local government maintains current substructure records.
    (c) Each operator shall provide line marking at locations where the 
line is above ground in areas that are accessible to the public.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-27, 
48 FR 25208, June 6, 1983; Amdt. 195-54, 60 FR 14650, Mar. 20, 1995; 
Amdt. 195-63, 63 FR 37506, July 13, 1998]



Sec.  195.412  Inspection of rights-of-way and crossings under navigable 
waters.

    (a) Each operator shall, at intervals not exceeding 3 weeks, but at 
least 26 times each calendar year, inspect the surface conditions on or 
adjacent to each pipeline right-of-way. Methods of inspection include 
walking, driving, flying or other appropriate means of traversing the 
right-of-way.
    (b) Except for offshore pipelines, each operator shall, at intervals 
not exceeding 5 years, inspect each crossing under a navigable waterway 
to determine the condition of the crossing.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-24, 
47 FR 46852, Oct. 21, 1982; Amdt. 195-52, 59 FR 33397, June 28, 1994]



Sec.  195.413  Underwater inspection and reburial of pipelines in the 
Gulf of Mexico and its inlets.

    (a) Except for gathering lines of 4\1/2\ inches (114mm) nominal 
outside diameter or smaller, each operator shall prepare and follow a 
procedure to identify

[[Page 677]]

its pipelines in the Gulf of Mexico and its inlets in waters less than 
15 feet (4.6 meters) deep as measured from mean low water that are at 
risk of being an exposed underwater pipeline or a hazard to navigation. 
The procedures must be in effect August 10, 2005.
    (b) Each operator shall conduct appropriate periodic underwater 
inspections of its pipelines in the Gulf of Mexico and its inlets in 
waters less than 15 feet (4.6 meters) deep as measured from mean low 
water based on the identified risk.
    (c) If an operator discovers that its pipeline is an exposed 
underwater pipeline or poses a hazard to navigation, the operator 
shall--
    (1) Promptly, but not later than 24 hours after discovery, notify 
the National Response Center, telephone: 1-800-424-8802, of the location 
and, if available, the geographic coordinates of that pipeline.
    (2) Promptly, but not later than 7 days after discovery, mark the 
location of the pipeline in accordance with 33 CFR Part 64 at the ends 
of the pipeline segment and at intervals of not over 500 yards (457 
meters) long, except that a pipeline segment less than 200 yards (183 
meters) long need only be marked at the center; and
    (3) Within 6 months after discovery, or not later than November 1 of 
the following year if the 6 month period is later than November 1 of the 
year of discovery, bury the pipeline so that the top of the pipe is 36 
inches (914 millimeters) below the underwater natural bottom (as 
determined by recognized and generally accepted practices) for normal 
excavation or 18 inches (457 millimeters) for rock excavation.
    (i) An operator may employ engineered alternatives to burial that 
meet or exceed the level of protection provided by burial.
    (ii) If an operator cannot obtain required state or Federal permits 
in time to comply with this section, it must notify OPS; specify whether 
the required permit is State or Federal; and, justify the delay.

[Amdt. 195-82, 69 FR 48407, Aug. 10, 2004]



Sec.  195.414  Inspections of pipelines in areas affected by extreme 
weather and natural disasters.

    (a) General. Following an extreme weather event or natural disaster 
that has the likelihood of damage to infrastructure by the scouring or 
movement of the soil surrounding the pipeline, such as a named tropical 
storm or hurricane; a flood that exceeds the river, shoreline, or creek 
high-water banks in the area of the pipeline; a landslide in the area of 
the pipeline; or an earthquake in the area of the pipeline, an operator 
must inspect all potentially affected pipeline facilities to detect 
conditions that could adversely affect the safe operation of that 
pipeline.
    (b) Inspection method. An operator must consider the nature of the 
event and the physical characteristics, operating conditions, location, 
and prior history of the affected pipeline in determining the 
appropriate method for performing the initial inspection to determine 
the extent of any damage and the need for the additional assessments 
required under paragraph (a) of this section.
    (c) Time period. The inspection required under paragraph (a) of this 
section must commence within 72 hours after the cessation of the event, 
defined as the point in time when the affected area can be safely 
accessed by the personnel and equipment required to perform the 
inspection as determined under paragraph (b) of this section. In the 
event that the operator is unable to commence the inspection due to the 
unavailability of personnel or equipment, the operator must notify the 
appropriate PHMSA Region Director as soon as practicable.
    (d) Remedial action. An operator must take prompt and appropriate 
remedial action to ensure the safe operation of a pipeline based on the 
information obtained as a result of performing the inspection required 
under paragraph (a) of this section. Such actions might include, but are 
not limited to:
    (1) Reducing the operating pressure or shutting down the pipeline;
    (2) Modifying, repairing, or replacing any damaged pipeline 
facilities;
    (3) Preventing, mitigating, or eliminating any unsafe conditions in 
the pipeline right-of-way;

[[Page 678]]

    (4) Performing additional patrols, surveys, tests, or inspections;
    (5) Implementing emergency response activities with Federal, State, 
or local personnel; and
    (6) Notifying affected communities of the steps that can be taken to 
ensure public safety.

[Amdt. 195-102, 84 FR 52295, Oct. 1, 2019]



Sec.  195.415  [Reserved]



Sec.  195.416  Pipeline assessments.

    (a) Scope. This section applies to onshore line pipe that can 
accommodate inspection by means of in-line inspection tools and is not 
subject to the integrity management requirements in Sec.  195.452.
    (b) General. An operator must perform an initial assessment of each 
of its pipeline segments by October 1, 2029, and perform periodic 
assessments of its pipeline segments at least once every 10 calendar 
years from the year of the prior assessment or as otherwise necessary to 
ensure public safety or the protection of the environment.
    (c) Method. Except as specified in paragraph (d) of this section, an 
operator must perform the integrity assessment for the range of relevant 
threats to the pipeline segment by the use of an appropriate in-line 
inspection tool(s). When performing an assessment using an in-line 
inspection tool, an operator must comply with Sec.  195.591. An operator 
must explicitly consider uncertainties in reported results (including 
tool tolerance, anomaly findings, and unity chart plots or other 
equivalent methods for determining uncertainties) in identifying 
anomalies. If this is impracticable based on operational limits, 
including operating pressure, low flow, and pipeline length or 
availability of in-line inspection tool technology for the pipe 
diameter, then the operator must perform the assessment using the 
appropriate method(s) in paragraphs (c)(1), (2), or (3) of this section 
for the range of relevant threats being assessed. The methods an 
operator selects to assess low-frequency electric resistance welded 
pipe, pipe with a seam factor less than 1.0 as defined in Sec.  
195.106(e) or lap-welded pipe susceptible to longitudinal seam failure 
must be capable of assessing seam integrity, cracking, and of detecting 
corrosion and deformation anomalies. The following alternative 
assessment methods may be used as specified in this paragraph:
    (1) A pressure test conducted in accordance with subpart E of this 
part;
    (2) External corrosion direct assessment in accordance with Sec.  
195.588; or
    (3) Other technology in accordance with paragraph (d).
    (d) Other technology. Operators may elect to use other technologies 
if the operator can demonstrate the technology can provide an equivalent 
understanding of the condition of the line pipe for threat being 
assessed. An operator choosing this option must notify the Office of 
Pipeline Safety (OPS) 90 days before conducting the assessment by:
    (1) Sending the notification, along with the information required to 
demonstrate compliance with this paragraph, to the Information Resources 
Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials 
Safety Administration, 1200 New Jersey Avenue SE, Washington, DC 20590; 
or
    (2) Sending the notification, along with the information required to 
demonstrate compliance with this paragraph, to the Information Resources 
Manager by facsimile to (202) 366-7128.
    (3) Prior to conducting the ``other technology'' assessments, the 
operator must receive a notice of ``no objection'' from the PHMSA 
Information Services Manager or Designee.
    (e) Data analysis. A person qualified by knowledge, training, and 
experience must analyze the data obtained from an assessment performed 
under paragraph (b) of this section to determine if a condition could 
adversely affect the safe operation of the pipeline. Operators must 
consider uncertainties in any reported results (including tool 
tolerance) as part of that analysis.
    (f) Discovery of condition. For purposes of Sec.  195.401(b)(1), 
discovery of a condition occurs when an operator has adequate 
information to determine that a condition presenting a potential threat 
to the integrity of the pipeline exists. An operator must promptly, but 
no later than 180 days after an assessment, obtain sufficient 
information

[[Page 679]]

about a condition to make that determination required under paragraph 
(e) of this section, unless the operator can demonstrate the 180-day 
interval is impracticable. If the operator believes that 180 days are 
impracticable to make a determination about a condition found during an 
assessment, the pipeline operator must notify PHMSA and provide an 
expected date when adequate information will become available. This 
notification must be made in accordance with Sec.  195.452 (m).
    (g) Remediation. An operator must comply with the requirements in 
Sec.  195.401 if a condition that could adversely affect the safe 
operation of a pipeline is discovered in complying with paragraphs (e) 
and (f) of this section.
    (h) Consideration of information. An operator must consider all 
relevant information about a pipeline in complying with the requirements 
in paragraphs (a) through (g) of this section.

[Amdt. 195-102, 84 FR 52295, Oct. 1, 2019]



Sec.  195.417  Notification of potential rupture.

    (a) As used in this part, a notification of potential rupture means 
the notification to, or observation by, an operator (e.g., by or to its 
controller(s) in a control room, field personnel, nearby pipeline or 
utility personnel, the public, local responders, or public authorities) 
of one or more of the below indicia of a potential unintentional or 
uncontrolled release of a large volume of hazardous liquids or carbon 
dioxide from a pipeline:
    (1) An unanticipated or unexplained pressure loss outside of the 
pipeline's normal operating pressures, as defined in the operator's 
written procedures. The operator must establish in its written 
procedures that an unanticipated or unplanned pressure loss is outside 
of the pipeline's normal operating pressures when there is a pressure 
loss greater than 10 percent occurring within a time interval of 15 
minutes or less, unless the operator has documented in its written 
procedures the operational need for a greater pressure-change threshold 
due to pipeline flow dynamics (including changes in operating pressure, 
flow rate, or volume), that are caused by fluctuations in product 
demand, receipts, or deliveries;
    (2) An unanticipated or unexplained flow rate change, pressure 
change, equipment function, or other pipeline instrumentation indication 
at the upstream or downstream station that may be representative of an 
event meeting paragraph (a)(1) of this section; or
    (3) Any unanticipated or unexplained rapid release of a large volume 
of hazardous liquid or carbon dioxide, a fire, or an explosion, in the 
immediate vicinity of the pipeline.
    (b) A notification of potential rupture occurs when an operator 
first receives notice of or observes an event specified in paragraph (a) 
of this section.
    (c) The requirements of this section do not apply to gathering 
lines.

[Amdt. 195-105, 87 FR 20989, Apr. 8, 2022, as amended by Amdt. 195-106, 
88 FR 50062, Aug. 1, 2023]



Sec.  195.418  Valves: Onshore valve shut-off for rupture mitigation.

    (a) Applicability. For newly constructed and entirely replaced 
onshore hazardous liquid or carbon dioxide pipeline segments, as defined 
at Sec.  195.2, with diameters of 6 inches or greater that could affect 
high-consequence areas or are located in high consequence areas (HCA), 
and that have been installed after April 10, 2023, an operator must 
install or use existing rupture-mitigation valves (RMV), as defined at 
Sec.  195.2, or alternative equivalent technologies according to the 
requirements of this section and Sec.  195.419. RMVs and alternative 
equivalent technologies must be operational within 14 days of placing 
the new or replaced pipeline segment in service. An operator may request 
an extension of this 14-day operation requirement if it can demonstrate 
to PHMSA, in accordance with the notification procedures in Sec.  
195.18, that application of that requirement would be economically, 
technically, or operationally infeasible. The requirements of this 
section apply to all applicable pipe replacements, even those that do 
not otherwise directly involve the addition or replacement of a valve.

[[Page 680]]

    (b) Maximum spacing between valves. RMVs and alternative equivalent 
technology must be installed in accordance with the following 
requirements:
    (1) Shut-off Segment. For purposes of this section, a ``shut-off 
segment'' means the segment of pipeline located between the upstream 
valve closest to the upstream endpoint of the replaced pipeline segment 
in the HCA or the pipeline segment that could affect an HCA and the 
downstream valve closest to the downstream endpoint of the replaced 
pipeline segment of the HCA or the pipeline segment that could affect an 
HCA so that the entirety of the segment that could affect the HCA or the 
segment within the HCA is between at least two RMVs or alternative 
equivalent technologies. If any crossover or lateral pipe for commodity 
receipts or deliveries connects to the replaced segment between the 
upstream and downstream valves, the shut-off segment also extends to a 
valve on the crossover connection(s) or lateral(s), such that, when all 
valves are closed, there is no flow path for commodity to be transported 
to the rupture site (except for residual liquids already in the shut-off 
segment). Multiple segments that could affect HCAs or are in HCAs may be 
contained within a single shut-off segment. All entirely replaced 
onshore hazardous liquid or carbon dioxide pipeline segments, as defined 
in Sec.  195.2, that could affect or are in an HCA must include a 
minimum of one valve that meets the requirements of this section and 
section 195.419. The operator is not required to select the closest 
valve to the shut-off segment as the RMV or alternative equivalent 
technology. An operator may use a manual pump station valve at a 
continuously manned station as an alternative equivalent technology. 
Such a manual valve used as an alternative equivalent technology would 
not require a notification to PHMSA in accordance with Sec.  195.18.
    (2) Shut-off segment valve spacing. Pipeline segments subject to 
paragraph (a) of this section must be protected on the upstream and 
downstream side with RMVs or alternative equivalent technologies. The 
distance between RMVs or alternative equivalent technologies must not 
exceed:
    (i) For pipeline segments carrying non-highly volatile liquids 
(HVL): 15 miles, with a maximum distance not to exceed 7\1/2\ miles from 
the endpoints of a shut-off segment: or
    (ii) For pipeline segments carrying HVLs: 7\1/2\ miles. The maximum 
valve spacing intervals for these valves may be increased by 1.25 times 
the spacing distance, up to a 9\3/8\-mile spacing at an endpoint, 
provided the operator notify PHMSA in accordance with Sec.  195.260 (g).
    (3) Laterals. Laterals extending from shut-off segments that 
contribute less than 5 percent of the total shut-off segment volume may 
have RMVs or alternative equivalent technologies that meet the actuation 
requirements of this section at locations other than mainline receipt/
delivery points, as long as all of these laterals contributing hazardous 
liquid or carbon dioxide volumes to the shut-off segment do not 
contribute more than 5 percent of the total shut-off segment volume, 
based upon maximum flow volume at the operating pressure. A check valve 
may be used as an alternative equivalent technology where it is 
positioned to stop flow into the lateral. Check valves used as an 
alternative equivalent technology in accordance with this paragraph 
(b)(3) are not subject to Sec.  195.419 but must be inspected, operated, 
and remediated in accordance with Sec.  195.420, including for closure 
and leakage, to ensure operational reliability. An operator using such a 
valve as an alternative equivalent technology must submit a request to 
PHMSA in accordance with Sec.  195.18.
    (4) Crossovers. An operator may use a manual valve as an alternative 
equivalent technology for a crossover connection if, during normal 
operations, the valve is closed to prevent the flow of hazardous liquid 
or carbon dioxide with a locking device or other means designed to 
prevent the opening of the valve by persons other than those authorized 
by the operator. The operator must document that the valve has been 
closed and locked in accordance with the operator's lock-out and tag-out

[[Page 681]]

procedures to prevent the flow of hazardous liquid or carbon dioxide. An 
operator using a such a valve as an alternative equivalent technology 
must submit a request to PHMSA in accordance with Sec.  195.18.
    (c) Manual operation upon identification of a rupture. Operators 
using a manual valve as an alternative equivalent technology pursuant to 
paragraph (a) of this section must develop and implement operating 
procedures and appropriately designate and locate nearby personnel to 
ensure valve shut-off in accordance with this section and Sec.  195.419. 
Manual operation of valves must include time for the assembly of 
necessary operating personnel, the acquisition of necessary tools and 
equipment, driving time under heavy traffic conditions and at the posted 
speed limit, walking time to access the valve, and time to manually shut 
off all valves, not to exceed the response time in Sec.  195.419(b).
    (d) Exception. The requirements of this section do not apply to 
gathering lines.

[Amdt. 195-105, 87 FR 20989, Apr. 8, 2022, as amended by Amdt. 195-106, 
88 FR 50063, Aug. 1, 2023]



Sec.  195.419  Valve capabilities.

    (a) Scope. The requirements in this section apply to rupture-
mitigation valves (RMV), as defined in Sec.  195.2, or alternative 
equivalent technology, installed pursuant to Sec. Sec.  195.258 and 
195.418.
    (b) Rupture identification and valve shut-off time. If an operator 
observes or is notified of a release of hazardous liquid or carbon 
dioxide that may be representative of an unintentional or uncontrolled 
release event meeting a notification of potential rupture (see 
Sec. Sec.  195.2 and 195.417), including any unexplained flow rate 
changes, pressure changes, equipment functions, or other pipeline 
instrumentation indications observed by the operator, the operator must, 
as soon as practicable but within 30 minutes of rupture identification 
(see Sec.  195.402(e)(4)), identify the rupture and fully close any RMVs 
or alternative equivalent technologies necessary to minimize the volume 
of hazardous liquid or carbon dioxide released from a pipeline and 
mitigate the consequences of a rupture.
    (c) Valve shut-off capability. A valve must have the actuation 
capability necessary to close an RMV or alternative equivalent 
technology to mitigate the consequences of a rupture in accordance with 
the requirements of this section.
    (d) Valve monitoring and operational capabilities. An RMV, as 
defined in Sec.  195.2, or alternative equivalent technology, must be 
capable of being monitored or controlled by either remote or onsite 
personnel as follows:
    (1) Operated during normal, abnormal, and emergency operating 
conditions;
    (2) Monitored for valve status (i.e., open, closed, or partial 
closed/open), upstream pressure, and downstream pressure. For automatic 
shut-off valves (ASV), an operator does not need to monitor remotely a 
valve's status if the operator has the capability to monitor pressures 
or flow rate within each pipeline segment located between RMVs or 
alternative equivalent technologies to identify and locate a rupture. 
Pipeline segments that use an alternative equivalent technology must 
have the capability to monitor pressures and hazardous liquid or carbon 
dioxide flow rates on the pipeline in order to identify and locate a 
rupture; and
    (3) Have a back-up power source to maintain supervisory control and 
data acquisition (SCADA) systems or other remote communications for 
remote-control valve (RCV) or ASV operational status or be monitored and 
controlled by on-site personnel.
    (e) Monitoring of valve shut-off response status. The position and 
operational status of an RMV must be appropriately monitored through 
electronic communication with remote instrumentation or other equivalent 
means. An operator does not need to monitor remotely an ASV's status if 
the operator has the capability to monitor pressures or hazardous liquid 
or carbon dioxide s flow rate on the pipeline to identify and locate a 
rupture.
    (f) Flow modeling for automatic shut-off valves. Prior to using an 
ASV as an RMV, the operator must conduct flow modeling for the shut-off 
segment and

[[Page 682]]

any laterals that feed the shut-off segment, so that the valve will 
close within 30 minutes or less following rupture identification, 
consistent with the operator's procedures, and in accordance with Sec.  
195.2 and this section. The flow modeling must include the anticipated 
maximum, normal, or any other flow volumes, pressures, or other 
operating conditions that may be encountered during the year, not to 
exceed a period of 15 months, and it must be modeled for the flow 
between the RMVs or alternative equivalent technologies, and any looped 
pipelines or hazardous liquid or carbon dioxide receipt tie-ins. If 
operating conditions change that could affect the ASV set pressures and 
the 30-minute valve closure time following a notification of potential 
rupture, as defined at Sec.  195.2, an operator must conduct a new flow 
model and reset the ASV set pressures prior to the next review for ASV 
set pressures in accordance with Sec.  195.420. The flow model must 
include a time/pressure chart for the segment containing the ASV if a 
rupture event occurs. An operator must conduct this flow modeling prior 
to making flow condition changes in a manner that could render the 30-
minute valve closure time unachievable.
    (g) Pipelines not affecting HCAs. For pipeline segments that are not 
in a high-consequence area (HCA) or that could not affect an HCA, an 
operator submitting a notification pursuant to Sec. Sec.  195.18 and 
195.258 for use of manual valves as an alternative equivalent technology 
may also request an exemption from the valve operation requirements of 
Sec.  195.419(b).
    (h) Exception. The requirements of this section do not apply to 
gathering lines.

[Amdt. 195-105, 87 FR 20989, Apr. 8, 2022, as amended by Amdt. 195-106, 
88 FR 50063, Aug. 1, 2023]



Sec.  195.420  Valve maintenance.

    (a) Each operator shall maintain each valve that is necessary for 
the safe operation of its pipeline systems in good working order at all 
times.
    (b) Each operator must, at least twice each calendar year, but at 
intervals not exceeding 7\1/2\ months, inspect each mainline valve to 
determine that it is functioning properly. Each rupture-mitigation valve 
(RMV), as defined in Sec.  195.2 and not contained in a gathering line, 
or alternative equivalent technology that is installed under Sec.  
195.258(c) or Sec.  195.418, must also be partially operated. Operators 
are not required to close the valve fully during the inspection; a 
minimum 25 percent valve closure is sufficient to demonstrate 
compliance, unless the operator has operational information that 
requires an additional closure percentage for maintaining reliability.
    (c) Each operator shall provide protection for each valve from 
unauthorized operation and from vandalism.
    (d) For each remote-control valve (RCV) installed in accordance with 
Sec.  195.258(c) or Sec.  195.418, an operator must conduct a point-to-
point verification between SCADA system displays and the installed 
valves, sensors, and communications equipment, in accordance with Sec.  
195.446(c) and (e).
    (e) For each alternative equivalent technology installed under Sec.  
195.258(c) or (d) or Sec.  195.418(a) that is manually or locally 
operated (i.e., not an RMV, as that term is defined in Sec.  195.2):
    (1) Operators must achieve a response time of 30 minutes or less, as 
required by Sec.  195.419(b), through an initial drill and through 
periodic validation as required by paragraph (e)(2) of this section. An 
operator must review each phase of the drill response and document the 
results to validate the total response time, including the 
identification of a rupture, and valve shut-off time as being less than 
or equal to 30 minutes after rupture identification.
    (2) Within each pipeline system, and within each operating or 
maintenance field work unit, operators must randomly select an 
authorized rupture-mitigation alternative equivalent technology for an 
annual 30-minute-total response time validation drill simulating worst-
case conditions for that location to ensure compliance with Sec.  
195.419. Operators are not required to close the alternative equivalent 
technology fully during the drill; a minimum 25 percent valve closure is 
sufficient to demonstrate compliance with the drill requirements unless 
the operator has operational information that

[[Page 683]]

requires an additional closure percentage for maintaining reliability. 
The response drill must occur at least once each calendar year, at 
intervals not to exceed 15 months. Operators must include in their 
written procedures the method they use to randomly select which 
alternative equivalent technology is tested in accordance with this 
paragraph.
    (3) If the 30-minute-maximum response time cannot be achieved in the 
drill, the operator must revise response efforts to achieve compliance 
with Sec.  195.419 no later than 12 months after the drill. Alternative 
valve shut-off measures must be in accordance with paragraph (f) of this 
section within 7 days of the drill.
    (4) Based on the results of the response-time drills, the operator 
must include lessons learned in:
    (i) Training and qualifications programs;
    (ii) Design, construction, testing, maintenance, operating, and 
emergency procedures manuals; and
    (iii) Any other areas identified by the operator as needing 
improvement.
    (f) Each operator must implement remedial measures as follows to 
correct any valve installed on an onshore pipeline in accordance with 
Sec.  195.258(c), or an RMV or alternative equivalent technology 
installed in accordance with Sec.  195.418, that is indicated to be 
inoperable or unable to maintain effective shut-off:
    (1) Repair or replace the valve as soon as practicable but no later 
than 12 months after finding that the valve is inoperable or unable to 
maintain shut-off. An operator may request an extension of the 
compliance deadline requirements of this section if it can demonstrate 
to PHMSA, in accordance with the notification procedures in Sec.  
195.18, that repairing or replacing a valve within 12 months would be 
economically, technically, or operationally infeasible; and
    (2) Designate an alternative compliant valve within 7 calendar days 
of the finding while repairs are being made and document an interim 
response plan to maintain safety. Alternative compliant valves are not 
required to comply with valve spacing requirements of this part.
    (g) An operator using an ASV as an RMV, in accordance with 
Sec. Sec.  195.2, 195.260, 195.418, and 195.419, must document, in 
accordance with Sec.  195.419(f), and confirm the ASV shut-in pressures 
on a calendar year basis not to exceed 15 months. ASV shut-in set 
pressures must be proven and reset individually at each ASV, as required 
by Sec.  195.419(f), at least each calendar year, but at intervals not 
to exceed 15 months.
    (h) The requirements of paragraphs (d) through (g) of this section 
do not apply to gathering lines.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, 
as amended by Amdt. 195-24, 47 FR 46852, Oct. 21, 1982; Amdt. 195-105, 
87 FR 20991, Apr. 8, 2022; Amdt. 195-106, 88 FR 50063, Aug. 1, 2023]



Sec.  195.422  Pipeline repairs.

    (a) Each operator shall, in repairing its pipeline systems, insure 
that the repairs are made in a safe manner and are made so as to prevent 
damage to persons or property.
    (b) No operator may use any pipe, valve, or fitting, for replacement 
in repairing pipeline facilities, unless it is designed and constructed 
as required by this part.



Sec.  195.424  Pipe movement.

    (a) No operator may move any line pipe, unless the pressure in the 
line section involved is reduced to not more than 50 percent of the 
maximum operating pressure.
    (b) No operator may move any pipeline containing highly volatile 
liquids where materials in the line section involved are joined by 
welding unless--
    (1) Movement when the pipeline does not contain highly volatile 
liquids is impractical;
    (2) The procedures of the operator under Sec.  195.402 contain 
precautions to protect the public against the hazard in moving pipelines 
containing highly volatile liquids, including the use of warnings, where 
necessary, to evacuate the area close to the pipeline; and
    (3) The pressure in that line section is reduced to the lower of the 
following:
    (i) Fifty percent or less of the maximum operating pressure; or
    (ii) The lowest practical level that will maintain the highly 
volatile liquid

[[Page 684]]

in a liquid state with continuous flow, but not less than 50 p.s.i. (345 
kPa) gage above the vapor pressure of the commodity.
    (c) No operator may move any pipeline containing highly volatile 
liquids where materials in the line section involved are not joined by 
welding unless--
    (1) The operator complies with paragraphs (b) (1) and (2) of this 
section; and
    (2) That line section is isolated to prevent the flow of highly 
volatile liquid.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 46 FR 38922, July 30, 1981, 
as amended by Amdt. 195-63, 63 FR 37506, July 13, 1998]



Sec.  195.426  Scraper and sphere facilities.

    No operator may use a launcher or receiver that is not equipped with 
a relief device capable of safely relieving pressure in the barrel 
before insertion or removal of scrapers or spheres. The operator must 
use a suitable device to indicate that pressure has been relieved in the 
barrel or must provide a means to prevent insertion or removal of 
scrapers or spheres if pressure has not been relieved in the barrel.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982]



Sec.  195.428  Overpressure safety devices and overfill protection systems.

    (a) Except as provided in paragraph (b) of this section, each 
operator shall, at intervals not exceeding 15 months, but at least once 
each calendar year, or in the case of pipelines used to carry highly 
volatile liquids, at intervals not to exceed 7\1/2\ months, but at least 
twice each calendar year, inspect and test each pressure limiting 
device, relief valve, pressure regulator, or other item of pressure 
control equipment to determine that it is functioning properly, is in 
good mechanical condition, and is adequate from the standpoint of 
capacity and reliability of operation for the service in which it is 
used.
    (b) In the case of relief valves on pressure breakout tanks 
containing highly volatile liquids, each operator shall test each valve 
at intervals not exceeding 5 years.
    (c) Aboveground breakout tanks that are constructed or significantly 
altered according to API Std 2510 (incorporated by reference, see Sec.  
195.3) after October 2, 2000, must have an overfill protection system 
installed according to API Std 2510, section 7.1.2. Other aboveground 
breakout tanks with 600 gallons (2271 liters) or more of storage 
capacity that are constructed or significantly altered after October 2, 
2000, must have an overfill protection system installed according to API 
RP 2350 (incorporated by reference, see Sec.  195.3). However, an 
operator need not comply with any part of API RP 2350 for a particular 
breakout tank if the operator describes in the manual required by Sec.  
195.402 why compliance with that part is not necessary for safety of the 
tank.
    (d) After October 2, 2000, the requirements of paragraphs (a) and 
(b) of this section for inspection and testing of pressure control 
equipment apply to the inspection and testing of overfill protection 
systems.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-24, 
47 FR 46852, Oct. 21, 1982; Amdt. 195-66, 64 FR 15936, Apr. 2, 1999, as 
amended by Amdt. 195-100, 80 FR 12780, Mar. 11, 2015]



Sec.  195.430  Firefighting equipment.

    Each operator shall maintain adequate firefighting equipment at each 
pump station and breakout tank area. The equipment must be--
    (a) In proper operating condition at all times;
    (b) Plainly marked so that its identity as firefighting equipment is 
clear; and
    (c) Located so that it is easily accessible during a fire.



Sec.  195.432  Inspection of in-service breakout tanks.

    (a) Except for breakout tanks inspected under paragraphs (b) and (c) 
of this section, each operator shall, at intervals not exceeding 15 
months, but at least once each calendar year, inspect each in-service 
breakout tank.
    (b) Each operator must inspect the physical integrity of in-service 
atmospheric and low-pressure steel above-ground breakout tanks according 
to API Std 653 (except section 6.4.3, Alternative Internal Inspection 
Interval) (incorporated by reference, see Sec.  195.3).

[[Page 685]]

However, if structural conditions prevent access to the tank bottom, its 
integrity may be assessed according to a plan included in the operations 
and maintenance manual under Sec.  195.402(c)(3). The risk-based 
internal inspection procedures in API Std 653, section 6.4.3 cannot be 
used to determine the internal inspection interval.
    (1) Operators who established internal inspection intervals based on 
risk-based inspection procedures prior to March 6, 2015 must re-
establish internal inspection intervals based on API Std 653, section 
6.4.2 (incorporated by reference, see Sec.  195.3).
    (i) If the internal inspection interval was determined by the prior 
risk-based inspection procedure using API Std 653, section 6.4.3 and the 
resulting calculation exceeded 20 years, and it has been more than 20 
years since an internal inspection was performed, the operator must 
complete a new internal inspection in accordance with Sec.  
195.432(b)(1) by January 5, 2017.
    (ii) If the internal inspection interval was determined by the prior 
risk-based inspection procedure using API Std 653, section 6.4.3 and the 
resulting calculation was less than or equal to 20 years, and the time 
since the most recent internal inspection exceeds the re-established 
inspection interval in accordance with Sec.  195.432(b)(1), the operator 
must complete a new internal inspection by January 5, 2017.
    (iii) If the internal inspection interval was not based upon current 
engineering and operational information (i.e., actual corrosion rate of 
floor plates, actual remaining thickness of the floor plates, etc.), the 
operator must complete a new internal inspection by January 5, 2017 and 
re-establish a new internal inspection interval in accordance with Sec.  
195.432(b)(1).
    (2) [Reserved]
    (c) Each operator must inspect the physical integrity of in-service 
steel aboveground breakout tanks built to API Std 2510 (incorporated by 
reference, see Sec.  195.3) according to section 6 of API Std 510 
(incorporated by reference, see Sec.  195.3).
    (d) The intervals of inspection specified by documents referenced in 
paragraphs (b) and (c) of this section begin on May 3, 1999, or on the 
operator's last recorded date of the inspection, whichever is earlier.

[Amdt. 195-66, 64 FR 15936, Apr. 2, 1999, as amended by Amdt. 195-94, 75 
FR 48607, Aug. 11, 2010, Amdt. 195-99, 80 FR 187, Jan. 5, 2015; 80 FR 
46848, Aug. 6, 2015]



Sec.  195.434  Signs.

    Each operator must maintain signs visible to the public around each 
pumping station and breakout tank area. Each sign must contain the name 
of the operator and a telephone number (including area code) where the 
operator can be reached at all times.

[Amdt. 195-78, 68 FR 53528, Sept. 11, 2003]



Sec.  195.436  Security of facilities.

    Each operator shall provide protection for each pumping station and 
breakout tank area and other exposed facility (such as scraper traps) 
from vandalism and unauthorized entry.



Sec.  195.438  Smoking or open flames.

    Each operator shall prohibit smoking and open flames in each pump 
station area and each breakout tank area where there is a possibility of 
the leakage of a flammable hazardous liquid or of the presence of 
flammable vapors.



Sec.  195.440  Public awareness.

    (a) Each pipeline operator must develop and implement a written 
continuing public education program that follows the guidance provided 
in the American Petroleum Institute's (API) Recommended Practice (RP) 
1162 (incorporated by reference, see Sec.  195.3).
    (b) The operator's program must follow the general program 
recommendations of API RP 1162 and assess the unique attributes and 
characteristics of the operator's pipeline and facilities.
    (c) The operator must follow the general program recommendations, 
including baseline and supplemental requirements of API RP 1162, unless 
the operator provides justification in its program or procedural manual 
as to why compliance with all or certain provisions of the recommended 
practice is not practicable and not necessary for safety.
    (d) The operator's program must specifically include provisions to 
educate

[[Page 686]]

the public, appropriate government organizations, and persons engaged in 
excavation related activities on:
    (1) Use of a one-call notification system prior to excavation and 
other damage prevention activities;
    (2) Possible hazards associated with unintended releases from a 
hazardous liquid or carbon dioxide pipeline facility;
    (3) Physical indications that such a release may have occurred;
    (4) Steps that should be taken for public safety in the event of a 
hazardous liquid or carbon dioxide pipeline release; and
    (5) Procedures to report such an event.
    (e) The program must include activities to advise affected 
municipalities, school districts, businesses, and residents of pipeline 
facility locations.
    (f) The program and the media used must be as comprehensive as 
necessary to reach all areas in which the operator transports hazardous 
liquid or carbon dioxide.
    (g) The program must be conducted in English and in other languages 
commonly understood by a significant number and concentration of the 
non-English speaking population in the operator's area.
    (h) Operators in existence on June 20, 2005, must have completed 
their written programs no later than June 20, 2006. Upon request, 
operators must submit their completed programs to PHMSA or, in the case 
of an intrastate pipeline facility operator, the appropriate State 
agency.
    (i) The operator's program documentation and evaluation results must 
be available for periodic review by appropriate regulatory agencies.

[Amdt. 195-84, 70 FR 28843, May 19, 2005]



Sec.  195.442  Damage prevention program.

    (a) Except as provided in paragraph (d) of this section, each 
operator of a buried pipeline must carry out, in accordance with this 
section, a written program to prevent damage to that pipeline from 
excavation activities. For the purpose of this section, the term 
``excavation activities'' includes excavation, blasting, boring, 
tunneling, backfilling, the removal of aboveground structures by either 
explosive or mechanical means, and other earthmoving operations.
    (b) An operator may comply with any of the requirements of paragraph 
(c) of this section through participation in a public service program, 
such as a one-call system, but such participation does not relieve the 
operator of the responsibility for compliance with this section. 
However, an operator must perform the duties of paragraph (c)(3) of this 
section through participation in a one-call system, if that one-call 
system is a qualified one-call system. In areas that are covered by more 
than one qualified one-call system, an operator need only join one of 
the qualified one-call systems if there is a central telephone number 
for excavators to call for excavation activities, or if the one-call 
systems in those areas communicate with one another. An operator's 
pipeline system must be covered by a qualified one-call system where 
there is one in place. For the purpose of this section, a one-call 
system is considered a ``qualified one-call system'' if it meets the 
requirements of section (b)(1) or (b)(2) or this section.
    (1) The state has adopted a one-call damage prevention program under 
Sec.  198.37 of this chapter; or
    (2) The one-call system:
    (i) Is operated in accordance with Sec.  198.39 of this chapter;
    (ii) Provides a pipeline operator an opportunity similar to a 
voluntary participant to have a part in management responsibilities; and
    (iii) Assesses a participating pipeline operator a fee that is 
proportionate to the costs of the one-call system's coverage of the 
operator's pipeline.
    (c) The damage prevention program required by paragraph (a) of this 
section must, at a minimum:
    (1) Include the identity, on a current basis, of persons who 
normally engage in excavation activities in the area in which the 
pipeline is located.
    (2) Provides for notification of the public in the vicinity of the 
pipeline and actual notification of persons identified in paragraph 
(c)(1) of this section of the following as often as needed to make them 
aware of the damage prevention program:
    (i) The program's existence and purpose; and

[[Page 687]]

    (ii) How to learn the location of underground pipelines before 
excavation activities are begun.
    (3) Provide a means of receiving and recording notification of 
planned excavation activities.
    (4) If the operator has buried pipelines in the area of excavation 
activity, provide for actual notification of persons who give notice of 
their intent to excavate of the type of temporary marking to be provided 
and how to identify the markings.
    (5) Provide for temporary marking of buried pipelines in the area of 
excavation activity before, as far as practical, the activity begins.
    (6) Provide as follows for inspection of pipelines that an operator 
has reason to believe could be damaged by excavation activities:
    (i) The inspection must be done as frequently as necessary during 
and after the activities to verify the integrity of the pipeline; and
    (ii) In the case of blasting, any inspection must include leakage 
surveys.
    (d) A damage prevention program under this section is not required 
for the following pipelines:
    (1) Pipelines located offshore.
    (2) Pipelines to which access is physically controlled by the 
operator.

[Amdt. 195-54, 60 FR 14651, Mar. 20, 1995, as amended by Amdt. 195-60, 
62 FR 61699, Nov. 19, 1997]



Sec.  195.444  Leak detection.

    (a) Scope. Except for offshore gathering and regulated rural 
gathering pipelines, this section applies to all hazardous liquid 
pipelines transporting liquid in single phase (without gas in the 
liquid).
    (b) General. A pipeline must have an effective system for detecting 
leaks in accordance with Sec. Sec.  195.134 or 195.452, as appropriate. 
An operator must evaluate the capability of its leak detection system to 
protect the public, property, and the environment and modify it as 
necessary to do so. At a minimum, an operator's evaluation must consider 
the following factors--length and size of the pipeline, type of product 
carried, the swiftness of leak detection, location of nearest response 
personnel, and leak history.
    (c) CPM leak detection systems. Each computational pipeline 
monitoring (CPM) leak detection system installed on a hazardous liquid 
pipeline must comply with API RP 1130 (incorporated by reference, see 
Sec.  195.3) in operating, maintaining, testing, record keeping, and 
dispatcher training of the system.

[Amdt. 195-102, 84 FR 52296, Oct. 1, 2019]



Sec.  195.446  Control room management.

    (a) General. This section applies to each operator of a pipeline 
facility with a controller working in a control room who monitors and 
controls all or part of a pipeline facility through a SCADA system. Each 
operator must have and follow written control room management procedures 
that implement the requirements of this section. The procedures required 
by this section must be integrated, as appropriate, with the operator's 
written procedures required by Sec.  195.402. An operator must develop 
the procedures no later than August 1, 2011, and must implement the 
procedures according to the following schedule. The procedures required 
by paragraphs (b), (c)(5), (d)(2) and (d)(3), (f) and (g) of this 
section must be implemented no later than October 1, 2011. The 
procedures required by paragraphs (c)(1) through (4), (d)(1), (d)(4), 
and (e) must be implemented no later than August 1, 2012. The training 
procedures required by paragraph (h) must be implemented no later than 
August 1, 2012, except that any training required by another paragraph 
of this section must be implemented no later than the deadline for that 
paragraph.
    (b) Roles and responsibilities. Each operator must define the roles 
and responsibilities of a controller during normal, abnormal, and 
emergency operating conditions. To provide for a controller's prompt and 
appropriate response to operating conditions, an operator must define 
each of the following:
    (1) A controller's authority and responsibility to make decisions 
and take actions during normal operations;
    (2) A controller's role when an abnormal operating condition is 
detected, even if the controller is not the first to detect the 
condition, including the controller's responsibility to take specific

[[Page 688]]

actions and to communicate with others;
    (3) A controller's role during an emergency, even if the controller 
is not the first to detect the emergency, including the controller's 
responsibility to take specific actions and to communicate with others;
    (4) A method of recording controller shift-changes and any hand-over 
of responsibility between controllers; and
    (5) The roles, responsibilities and qualifications of others who 
have the authority to direct or supersede the specific technical actions 
of controllers.
    (c) Provide adequate information. Each operator must provide its 
controllers with the information, tools, processes and procedures 
necessary for the controllers to carry out the roles and 
responsibilities the operator has defined by performing each of the 
following:
    (1) Implement API RP 1165 (incorporated by reference, see Sec.  
195.3) whenever a SCADA system is added, expanded or replaced, unless 
the operator demonstrates that certain provisions of API RP 1165 are not 
practical for the SCADA system used;
    (2) Conduct a point-to-point verification between SCADA displays and 
related field equipment when field equipment is added or moved and when 
other changes that affect pipeline safety are made to field equipment or 
SCADA displays;
    (3) Test and verify an internal communication plan to provide 
adequate means for manual operation of the pipeline safely, at least 
once each calendar year, but at intervals not to exceed 15 months;
    (4) Test any backup SCADA systems at least once each calendar year, 
but at intervals not to exceed 15 months; and
    (5) Implement section 5 of API RP 1168 (incorporated by reference, 
see Sec.  195.3) to establish procedures for when a different controller 
assumes responsibility, including the content of information to be 
exchanged.
    (d) Fatigue mitigation. Each operator must implement the following 
methods to reduce the risk associated with controller fatigue that could 
inhibit a controller's ability to carry out the roles and 
responsibilities the operator has defined:
    (1) Establish shift lengths and schedule rotations that provide 
controllers off-duty time sufficient to achieve eight hours of 
continuous sleep;
    (2) Educate controllers and supervisors in fatigue mitigation 
strategies and how off-duty activities contribute to fatigue;
    (3) Train controllers and supervisors to recognize the effects of 
fatigue; and
    (4) Establish a maximum limit on controller hours-of-service, which 
may provide for an emergency deviation from the maximum limit if 
necessary for the safe operation of a pipeline facility.
    (e) Alarm management. Each operator using a SCADA system must have a 
written alarm management plan to provide for effective controller 
response to alarms. An operator's plan must include provisions to:
    (1) Review SCADA safety-related alarm operations using a process 
that ensures alarms are accurate and support safe pipeline operations;
    (2) Identify at least once each calendar month points affecting 
safety that have been taken off scan in the SCADA host, have had alarms 
inhibited, generated false alarms, or that have had forced or manual 
values for periods of time exceeding that required for associated 
maintenance or operating activities;
    (3) Verify the correct safety-related alarm set-point values and 
alarm descriptions when associated field instruments are calibrated or 
changed and at least once each calendar year, but at intervals not to 
exceed 15 months;
    (4) Review the alarm management plan required by this paragraph at 
least once each calendar year, but at intervals not exceeding 15 months, 
to determine the effectiveness of the plan;
    (5) Monitor the content and volume of general activity being 
directed to and required of each controller at least once each calendar 
year, but at intervals not exceeding 15 months, that will assure 
controllers have sufficient time to analyze and react to incoming 
alarms; and
    (6) Address deficiencies identified through the implementation of 
paragraphs (e)(1) through (e)(5) of this section.

[[Page 689]]

    (f) Change management. Each operator must assure that changes that 
could affect control room operations are coordinated with the control 
room personnel by performing each of the following:
    (1) Implement section 7 of API RP 1168 (incorporated by reference, 
see Sec.  195.3) for control room management change and require 
coordination between control room representatives, operator's 
management, and associated field personnel when planning and 
implementing physical changes to pipeline equipment or configuration; 
and
    (2) Require its field personnel to contact the control room when 
emergency conditions exist and when making field changes that affect 
control room operations.
    (g) Operating experience. Each operator must assure that lessons 
learned from its operating experience are incorporated, as appropriate, 
into its control room management procedures by performing each of the 
following:
    (1) Review accidents that must be reported pursuant to Sec.  195.50 
and 195.52 to determine if control room actions contributed to the event 
and, if so, correct, where necessary, deficiencies related to:
    (i) Controller fatigue;
    (ii) Field equipment;
    (iii) The operation of any relief device;
    (iv) Procedures;
    (v) SCADA system configuration; and
    (vi) SCADA system performance.
    (2) Include lessons learned from the operator's experience in the 
training program required by this section.
    (h) Training. Each operator must establish a controller training 
program and review the training program content to identify potential 
improvements at least once each calendar year, but at intervals not to 
exceed 15 months. An operator's program must provide for training each 
controller to carry out the roles and responsibilities defined by the 
operator. In addition, the training program must include the following 
elements:
    (1) Responding to abnormal operating conditions likely to occur 
simultaneously or in sequence;
    (2) Use of a computerized simulator or non-computerized (tabletop) 
method for training controllers to recognize abnormal operating 
conditions;
    (3) Training controllers on their responsibilities for communication 
under the operator's emergency response procedures;
    (4) Training that will provide a controller a working knowledge of 
the pipeline system, especially during the development of abnormal 
operating conditions;
    (5) For pipeline operating setups that are periodically, but 
infrequently used, providing an opportunity for controllers to review 
relevant procedures in advance of their application; and
    (6) Control room team training and exercises that include both 
controllers and other individuals, defined by the operator, who would 
reasonably be expected to operationally collaborate with controllers 
(control room personnel) during normal, abnormal or emergency 
situations. Operators must comply with the team training requirements 
under this paragraph no later than January 23, 2018.
    (i) Compliance validation. Upon request, operators must submit their 
procedures to PHMSA or, in the case of an intrastate pipeline facility 
regulated by a State, to the appropriate State agency.
    (j) Compliance and deviations. An operator must maintain for review 
during inspection:
    (1) Records that demonstrate compliance with the requirements of 
this section; and
    (2) Documentation to demonstrate that any deviation from the 
procedures required by this section was necessary for the safe operation 
of the pipeline facility.

[Amdt. 195-93, 74 FR 63329, Dec. 3, 2009, as amended at 75 FR 5537, Feb. 
3, 2010; 76 FR 35135, June 16, 2011; Amdt. 195-101, 82 FR 7999, Jan. 23, 
2017]

                         High Consequence Areas



Sec.  195.450  Definitions.

    The following definitions apply to this section and Sec.  195.452:
    Emergency flow restricting device or EFRD means a check valve or 
remote control valve as follows:

[[Page 690]]

    (1) Check valve means a valve that permits fluid to flow freely in 
one direction and contains a mechanism to automatically prevent flow in 
the other direction.
    (2) Remote control valve or RCV means any valve that is operated 
from a location remote from where the valve is installed. The RCV is 
usually operated by the supervisory control and data acquisition (SCADA) 
system. The linkage between the pipeline control center and the RCV may 
be by fiber optics, microwave, telephone lines, or satellite.
    High consequence area means:
    (1) A commercially navigable waterway, which means a waterway where 
a substantial likelihood of commercial navigation exists;
    (2) A high population area, which means an urbanized area, as 
defined and delineated by the Census Bureau, that contains 50,000 or 
more people and has a population density of at least 1,000 people per 
square mile;
    (3) An other populated area, which means a place, as defined and 
delineated by the Census Bureau, that contains a concentrated 
population, such as an incorporated or unincorporated city, town, 
village, or other designated residential or commercial area;
    (4) An unusually sensitive area, as defined in Sec.  195.6.

[Amdt. 195-70, 65 FR 75405, Dec. 1, 2000]

                      Pipeline Integrity Management



Sec.  195.452  Pipeline integrity management in high consequence areas.

    (a) Which pipelines are covered by this section? This section 
applies to each hazardous liquid pipeline and carbon dioxide pipeline 
that could affect a high consequence area, including any pipeline 
located in a high consequence area unless the operator effectively 
demonstrates by risk assessment that the pipeline could not affect the 
area. (Appendix C of this part provides guidance on determining if a 
pipeline could affect a high consequence area.) Covered pipelines are 
categorized as follows:
    (1) Category 1 includes pipelines existing on May 29, 2001, that 
were owned or operated by an operator who owned or operated a total of 
500 or more miles of pipeline subject to this part.
    (2) Category 2 includes pipelines existing on May 29, 2001, that 
were owned or operated by an operator who owned or operated less than 
500 miles of pipeline subject to this part.
    (3) Category 3 includes pipelines constructed or converted after May 
29, 2001, and low-stress pipelines in rural areas under Sec.  195.12.
    (4) Low stress pipelines as specified in Sec.  195.12.
    (b) What program and practices must operators use to manage pipeline 
integrity? Each operator of a pipeline covered by this section must:
    (1) Develop a written integrity management program that addresses 
the risks on each segment of pipeline in the first column of the 
following table no later than the date in the second column:

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
Category 1................................  March 31, 2002.
Category 2................................  February 18, 2003.
Category 3................................  Date the pipeline begins
                                             operation or as provided in
                                             Sec.   195.12 for low
                                             stress pipelines in rural
                                             areas.
------------------------------------------------------------------------

    (2) Include in the program an identification of each pipeline or 
pipeline segment in the first column of the following table not later 
than the date in the second column:

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
Category 1................................  December 31, 2001.
Category 2................................  November 18, 2002.
Category 3................................  Date the pipeline begins
                                             operation.
------------------------------------------------------------------------

    (3) Include in the program a plan to carry out baseline assessments 
of line pipe as required by paragraph (c) of this section.
    (4) Include in the program a framework that--
    (i) Addresses each element of the integrity management program under 
paragraph (f) of this section, including continual integrity assessment 
and evaluation under paragraph (j) of this section; and
    (ii) Initially indicates how decisions will be made to implement 
each element.
    (5) Implement and follow the program.
    (6) Follow recognized industry practices in carrying out this 
section, unless--

[[Page 691]]

    (i) This section specifies otherwise; or
    (ii) The operator demonstrates that an alternative practice is 
supported by a reliable engineering evaluation and provides an 
equivalent level of public safety and environmental protection.
    (c) What must be in the baseline assessment plan? (1) An operator 
must include each of the following elements in its written baseline 
assessment plan:
    (i) The methods selected to assess the integrity of the line pipe. 
An operator must assess the integrity of the line pipe by in-line 
inspection tool(s) described in paragraph (c)(1)(i)(A) of this section 
for the range of relevant threats to the pipeline segment. If it is 
impracticable based upon the construction of the pipeline (e.g., 
diameter changes, sharp bends, and elbows) or operational limits 
including operating pressure, low flow, pipeline length, or availability 
of in-line inspection tool technology for the pipe diameter, then the 
operator must use the appropriate method(s) in paragraphs (c)(1)(i)(B), 
(C), or (D) of this section for the range of relevant threats to the 
pipeline segment. The methods an operator selects to assess low-
frequency electric resistance welded pipe, pipe with a seam factor less 
than 1.0 as defined in Sec.  195.106(e) or lap-welded pipe susceptible 
to longitudinal seam failure, must be capable of assessing seam 
integrity, cracking, and of detecting corrosion and deformation 
anomalies.
    (A) In-line inspection tool or tools capable of detecting corrosion 
and deformation anomalies including dents, gouges, and grooves. For 
pipeline segments with an identified or probable risk or threat related 
to cracks (such as at pipe body or weld seams) based on the risk factors 
specified in paragraph (e), an operator must use an in-line inspection 
tool or tools capable of detecting crack anomalies. When performing an 
assessment using an in-line inspection tool, an operator must comply 
with Sec.  195.591. An operator using this method must explicitly 
consider uncertainties in reported results (including tool tolerance, 
anomaly findings, and unity chart plots or equivalent for determining 
uncertainties) in identifying anomalies;
    (B) Pressure test conducted in accordance with subpart E of this 
part;
    (C) External corrosion direct assessment in accordance with Sec.  
195.588; or
    (D) Other technology that the operator demonstrates can provide an 
equivalent understanding of the condition of the line pipe. An operator 
choosing this option must notify the Office of Pipeline Safety (OPS) 90 
days before conducting the assessment, by sending a notice to the 
address or facsimile number specified in paragraph (m) of this section.
    (ii) A schedule for completing the integrity assessment;
    (iii) An explanation of the assessment methods selected and 
evaluation of risk factors considered in establishing the assessment 
schedule.
    (2) An operator must document, prior to implementing any changes to 
the plan, any modification to the plan, and reasons for the 
modification.
    (d) When must operators complete baseline assessments?
    (1) All pipelines. An operator must complete the baseline assessment 
before a new or conversion-to-service pipeline begins operation through 
the development of procedures, identification of high consequence areas, 
and pressure testing of could-affect high consequence areas in 
accordance with Sec.  195.304.
    (2) Newly identified areas. If an operator obtains information 
(whether from the information analysis required under paragraph (g) of 
this section, Census Bureau maps, or any other source) demonstrating 
that the area around a pipeline segment has changed to meet the 
definition of a high consequence area (see Sec.  195.450), that area 
must be incorporated into the operator's baseline assessment plan within 
1 year from the date that the information is obtained. An operator must 
complete the baseline assessment of any pipeline segment that could 
affect a newly identified high consequence area within 5 years from the 
date an operator identifies the area.
    (e) What are the risk factors for establishing an assessment 
schedule (for both the baseline and continual integrity assessments)? 
(1) An operator must establish an integrity assessment schedule that 
prioritizes pipeline segments for

[[Page 692]]

assessment (see paragraphs (d)(1) and (j)(3) of this section). An 
operator must base the assessment schedule on all risk factors that 
reflect the risk conditions on the pipeline segment. The factors an 
operator must consider include, but are not limited to:
    (i) Results of the previous integrity assessment, defect type and 
size that the assessment method can detect, and defect growth rate;
    (ii) Pipe size, material, manufacturing information, coating type 
and condition, and seam type;
    (iii) Leak history, repair history and cathodic protection history;
    (iv) Product transported;
    (v) Operating stress level;
    (vi) Existing or projected activities in the area;
    (vii) Local environmental factors that could affect the pipeline 
(e.g., seismicity, corrosivity of soil, subsidence, climatic);
    (viii) geo-technical hazards; and
    (ix) Physical support of the segment such as by a cable suspension 
bridge.
    (2) Appendix C of this part provides further guidance on risk 
factors.
    (f) What are the elements of an integrity management program? An 
integrity management program begins with the initial framework. An 
operator must continually change the program to reflect operating 
experience, conclusions drawn from results of the integrity assessments, 
and other maintenance and surveillance data, and evaluation of 
consequences of a failure on the high consequence area. An operator must 
include, at minimum, each of the following elements in its written 
integrity management program:
    (1) A process for identifying which pipeline segments could affect a 
high consequence area;
    (2) A baseline assessment plan meeting the requirements of paragraph 
(c) of this section;
    (3) An analysis that integrates all available information about the 
integrity of the entire pipeline and the consequences of a failure (see 
paragraph (g) of this section);
    (4) Criteria for remedial actions to address integrity issues raised 
by the assessment methods and information analysis (see paragraph (h) of 
this section);
    (5) A continual process of assessment and evaluation to maintain a 
pipeline's integrity (see paragraph (j) of this section);
    (6) Identification of preventive and mitigative measures to protect 
the high consequence area (see paragraph (i) of this section);
    (7) Methods to measure the program's effectiveness (see paragraph 
(k) of this section);
    (8) A process for review of integrity assessment results and 
information analysis by a person qualified to evaluate the results and 
information (see paragraph (h)(2) of this section).
    (g) What is an information analysis? In periodically evaluating the 
integrity of each pipeline segment (see paragraph (j) of this section), 
an operator must analyze all available information about the integrity 
of its entire pipeline and the consequences of a possible failure along 
the pipeline. Operators must continue to comply with the data 
integration elements specified in Sec.  195.452(g) that were in effect 
on October 1, 2018, until October 1, 2022. Operators must begin to 
integrate all the data elements specified in this section starting 
October 1, 2020, with all attributes integrated by October 1, 2022. This 
analysis must:
    (1) Integrate information and attributes about the pipeline that 
include, but are not limited to:
    (i) Pipe diameter, wall thickness, grade, and seam type;
    (ii) Pipe coating, including girth weld coating;
    (iii) Maximum operating pressure (MOP) and temperature;
    (iv) Endpoints of segments that could affect high consequence areas 
(HCAs);
    (v) Hydrostatic test pressure including any test failures or leaks--
if known;
    (vi) Location of casings and if shorted;
    (vii) Any in-service ruptures or leaks--including identified causes;
    (viii) Data gathered through integrity assessments required under 
this section;
    (ix) Close interval survey (CIS) survey results;
    (x) Depth of cover surveys;
    (xi) Corrosion protection (CP) rectifier readings;

[[Page 693]]

    (xii) CP test point survey readings and locations;
    (xiii) AC/DC and foreign structure interference surveys;
    (xiv) Pipe coating surveys and cathodic protection surveys.
    (xv) Results of examinations of exposed portions of buried pipelines 
(i.e., pipe and pipe coating condition, see Sec.  195.569);
    (xvi) Stress corrosion cracking (SCC) and other cracking (pipe body 
or weld) excavations and findings, including in-situ non-destructive 
examinations and analysis results for failure stress pressures and 
cyclic fatigue crack growth analysis to estimate the remaining life of 
the pipeline;
    (xvii) Aerial photography;
    (xviii) Location of foreign line crossings;
    (xix) Pipe exposures resulting from repairs and encroachments;
    (xx) Seismicity of the area; and
    (xxi) Other pertinent information derived from operations and 
maintenance activities and any additional tests, inspections, surveys, 
patrols, or monitoring required under this part.
    (2) Consider information critical to determining the potential for, 
and preventing, damage due to excavation, including current and planned 
damage prevention activities, and development or planned development 
along the pipeline;
    (3) Consider how a potential failure would affect high consequence 
areas, such as location of a water intake.
    (4) Identify spatial relationships among anomalous information 
(e.g., corrosion coincident with foreign line crossings; evidence of 
pipeline damage where aerial photography shows evidence of 
encroachment). Storing the information in a geographic information 
system (GIS), alone, is not sufficient. An operator must analyze for 
interrelationships among the data.
    (h) What actions must an operator take to address integrity 
issues?--(1) General requirements. An operator must take prompt action 
to address all anomalous conditions in the pipeline that the operator 
discovers through the integrity assessment or information analysis. In 
addressing all conditions, an operator must evaluate all anomalous 
conditions and remediate those that could reduce a pipeline's integrity, 
as required by this part. An operator must be able to demonstrate that 
the remediation of the condition will ensure that the condition is 
unlikely to pose a threat to the long-term integrity of the pipeline. An 
operator must comply with all other applicable requirements in this part 
in remediating a condition. Each operator must, in repairing its 
pipeline systems, ensure that the repairs are made in a safe and timely 
manner and are made so as to prevent damage to persons, property, or the 
environment. The calculation method(s) used for anomaly evaluation must 
be applicable for the range of relevant threats.
    (i) Temporary pressure reduction. An operator must notify PHMSA, in 
accordance with paragraph (m) of this section, if the operator cannot 
meet the schedule for evaluation and remediation required under 
paragraph (h)(3) of this section and cannot provide safety through a 
temporary reduction in operating pressure.
    (ii) Long-term pressure reduction. When a pressure reduction exceeds 
365 days, the operator must notify PHMSA in accordance with paragraph 
(m) of this section and explain the reasons for the delay. An operator 
must also take further remedial action to ensure the safety of the 
pipeline.
    (2) Discovery of condition. Discovery of a condition occurs when an 
operator has adequate information to determine that a condition 
presenting a potential threat to the integrity of the pipeline exists. 
An operator must promptly, but no later than 180 days after an 
assessment, obtain sufficient information about a condition to make that 
determination, unless the operator can demonstrate the 180-day interval 
is impracticable. If the operator believes that 180 days are 
impracticable to make a determination about a condition found during an 
assessment, the pipeline operator must notify PHMSA in accordance with 
paragraph (m) of this section and provide an expected date when adequate 
information will become available.
    (3) Schedule for evaluation and remediation. An operator must 
complete remediation of a condition according to a schedule prioritizing 
the conditions for

[[Page 694]]

evaluation and remediation. If an operator cannot meet the schedule for 
any condition, the operator must explain the reasons why it cannot meet 
the schedule and how the changed schedule will not jeopardize public 
safety or environmental protection.
    (4) Special requirements for scheduling remediation--(i) Immediate 
repair conditions. An operator's evaluation and remediation schedule 
must provide for immediate repair conditions. To maintain safety, an 
operator must temporarily reduce the operating pressure or shut down the 
pipeline until the operator completes the repair of these conditions. An 
operator must calculate the temporary reduction in operating pressure 
using the formulas referenced in paragraph (h)(4)(i)(B) of this section. 
If no suitable remaining strength calculation method can be identified, 
an operator must implement a minimum 20 percent or greater operating 
pressure reduction, based on actual operating pressure for two months 
prior to the date of inspection, until the anomaly is repaired. An 
operator must treat the following conditions as immediate repair 
conditions:
    (A) Metal loss greater than 80% of nominal wall regardless of 
dimensions.
    (B) A calculation of the remaining strength of the pipe shows a 
predicted burst pressure less than the established maximum operating 
pressure at the location of the anomaly. Suitable remaining strength 
calculation methods include, but are not limited to, ASME/ANSI B31G 
(incorporated by reference, see Sec.  195.3) and PRCI PR-3-805 (R-
STRENG) (incorporated by reference, see Sec.  195.3).
    (C) A dent located on the top of the pipeline (above the 4 and 8 
o'clock positions) that has any indication of metal loss, cracking or a 
stress riser.
    (D) A dent located on the top of the pipeline (above the 4 and 8 
o'clock positions) with a depth greater than 6% of the nominal pipe 
diameter.
    (E) An anomaly that in the judgment of the person designated by the 
operator to evaluate the assessment results requires immediate action.
    (ii) 60-day conditions. Except for conditions listed in paragraph 
(h)(4)(i) of this section, an operator must schedule evaluation and 
remediation of the following conditions within 60 days of discovery of 
condition.
    (A) A dent located on the top of the pipeline (above the 4 and 8 
o'clock positions) with a depth greater than 3% of the pipeline diameter 
(greater than 0.250 inches in depth for a pipeline diameter less than 
Nominal Pipe Size (NPS) 12).
    (B) A dent located on the bottom of the pipeline that has any 
indication of metal loss, cracking or a stress riser.
    (iii) 180-day conditions. Except for conditions listed in paragraph 
(h)(4)(i) or (ii) of this section, an operator must schedule evaluation 
and remediation of the following within 180 days of discovery of the 
condition:
    (A) A dent with a depth greater than 2% of the pipeline's diameter 
(0.250 inches in depth for a pipeline diameter less than NPS 12) that 
affects pipe curvature at a girth weld or a longitudinal seam weld.
    (B) A dent located on the top of the pipeline (above 4 and 8 o'clock 
position) with a depth greater than 2% of the pipeline's diameter (0.250 
inches in depth for a pipeline diameter less than NPS 12).
    (C) A dent located on the bottom of the pipeline with a depth 
greater than 6% of the pipeline's diameter.
    (D) A calculation of the remaining strength of the pipe shows an 
operating pressure that is less than the current established maximum 
operating pressure at the location of the anomaly. Suitable remaining 
strength calculation methods include, but are not limited to, ASME/ANSI 
B31G and PRCI PR-3-805 (R-STRENG).
    (E) An area of general corrosion with a predicted metal loss greater 
than 50% of nominal wall.
    (F) Predicted metal loss greater than 50% of nominal wall that is 
located at a crossing of another pipeline, or is in an area with 
widespread circumferential corrosion, or is in an area that could affect 
a girth weld.
    (G) A potential crack indication that when excavated is determined 
to be a crack.
    (H) Corrosion of or along a longitudinal seam weld.
    (I) A gouge or groove greater than 12.5% of nominal wall.

[[Page 695]]

    (iv) Other conditions. In addition to the conditions listed in 
paragraphs (h)(4)(i) through (iii) of this section, an operator must 
evaluate any condition identified by an integrity assessment or 
information analysis that could impair the integrity of the pipeline, 
and as appropriate, schedule the condition for remediation. Appendix C 
of this part contains guidance concerning other conditions that an 
operator should evaluate.
    (i) What preventive and mitigative measures must an operator take to 
protect the high consequence area?--(1) General requirements. An 
operator must take measures to prevent and mitigate the consequences of 
a pipeline failure that could affect a high consequence area. These 
measures include conducting a risk analysis of the pipeline segment to 
identify additional actions to enhance public safety or environmental 
protection. Such actions may include, but are not limited to, 
implementing damage prevention best practices, better monitoring of 
cathodic protection where corrosion is a concern, establishing shorter 
inspection intervals, installing EFRDs on the pipeline segment, 
modifying the systems that monitor pressure and detect leaks, providing 
additional training to personnel on response procedures, conducting 
drills with local emergency responders and adopting other management 
controls.
    (2) Risk analysis criteria. In identifying the need for additional 
preventive and mitigative measures, an operator must evaluate the 
likelihood of a pipeline release occurring and how a release could 
affect the high consequence area. This determination must consider all 
relevant risk factors, including, but not limited to:
    (i) Terrain surrounding the pipeline segment, including drainage 
systems such as small streams and other smaller waterways that could act 
as a conduit to the high consequence area;
    (ii) Elevation profile;
    (iii) Characteristics of the product transported;
    (iv) Amount of product that could be released;
    (v) Possibility of a spillage in a farm field following the drain 
tile into a waterway;
    (vi) Ditches along side a roadway the pipeline crosses;
    (vii) Physical support of the pipeline segment such as by a cable 
suspension bridge;
    (viii) Exposure of the pipeline to operating pressure exceeding 
established maximum operating pressure;
    (ix) Seismicity of the area.
    (3) Leak detection. An operator must have a means to detect leaks on 
its pipeline system. An operator must evaluate the capability of its 
leak detection means and modify, as necessary, to protect the high 
consequence area. An operator's evaluation must, at least, consider, the 
following factors--length and size of the pipeline, type of product 
carried, the pipeline's proximity to the high consequence area, the 
swiftness of leak detection, location of nearest response personnel, 
leak history, and risk assessment results.
    (4) Emergency Flow Restricting Devices (EFRD). If an operator 
determines that an EFRD is needed on a pipeline segment that is located 
in, or which could affect, a high-consequence area (HCA) in the event of 
a hazardous liquid pipeline release, an operator must install the EFRD. 
In making this determination, an operator must, at least, evaluate the 
following factors--the swiftness of leak detection and pipeline shutdown 
capabilities, the type of commodity carried, the rate of potential 
leakage, the volume that can be released, topography or pipeline 
profile, the potential for ignition, proximity to power sources, 
location of nearest response personnel, specific terrain within the HCA 
or between the pipeline segment and the HCA it could affect, and 
benefits expected by reducing the spill size. An RMV installed under 
this paragraph (i)(4) must meet all of the other applicable requirements 
in this part, provided that the requirement of this sentence does not 
apply to gathering lines.
    (i) Where EFRDs are installed on pipeline segments in HCAs and that 
could affect HCAs with diameters of 6 inches or greater and that are 
placed into service or that have had 2 or more miles of pipe replaced 
within 5 contiguous miles within a 24-month period

[[Page 696]]

after April 10, 2023, the location, installation, actuation, operation, 
and maintenance of such EFRDs (including valve actuators, personnel 
response, operational control centers, supervisory control and data 
acquisition (SCADA), communications, and procedures) must meet the 
design, operation, testing, maintenance, and rupture-mitigation 
requirements of Sec. Sec.  195.258, 195.260, 195.402, 195.418, 195.419, 
and 195.420.
    (ii) The EFRD analysis and assessments specified in this paragraph 
(i)(4) must be completed prior to placing into service all onshore 
pipelines with diameters of 6 inches or greater and that are constructed 
or that have had 2 or more miles of pipe within any 5 contiguous miles 
within any 24-month period replaced after April 10, 2023. Implementation 
of EFRD findings for RMVs must meet Sec.  195.418.
    (iii) An operator may request an exemption from the compliance 
deadline requirements of this section if it can demonstrate to PHMSA, in 
accordance with the notification procedures in Sec.  195.18, that 
installing an EFRD by that compliance deadline would be economically, 
technically, or operationally infeasible.
    (iv) The requirements of paragraphs (i)(4)(i) through (iii) of this 
section do not apply to gathering lines.
    (j) What is a continual process of evaluation and assessment to 
maintain a pipeline's integrity?--(1) General. After completing the 
baseline integrity assessment, an operator must continue to assess the 
line pipe at specified intervals and periodically evaluate the integrity 
of each pipeline segment that could affect a high consequence area.
    (2) Verifying covered segments. An operator must verify the risk 
factors used in identifying pipeline segments that could affect a high 
consequence area on at least an annual basis not to exceed 15 months 
(Appendix C of this part provides additional guidance on factors that 
can influence whether a pipeline segment could affect a high consequence 
area). If a change in circumstance indicates that the prior 
consideration of a risk factor is no longer valid or that an operator 
should consider new risk factors, an operator must perform a new 
integrity analysis and evaluation to establish the endpoints of any 
previously identified covered segments. The integrity analysis and 
evaluation must include consideration of the results of any baseline and 
periodic integrity assessments (see paragraphs (b), (c), (d), and (e) of 
this section), information analyses (see paragraph (g) of this section), 
and decisions about remediation and preventive and mitigative actions 
(see paragraphs (h) and (i) of this section). An operator must complete 
the first annual verification under this paragraph no later than July 1, 
2021.
    (3) Assessment intervals. An operator must establish five-year 
intervals, not to exceed 68 months, for continually assessing the line 
pipe's integrity. An operator must base the assessment intervals on the 
risk the line pipe poses to the high consequence area to determine the 
priority for assessing the pipeline segments. An operator must establish 
the assessment intervals based on the factors specified in paragraph (e) 
of this section, the analysis of the results from the last integrity 
assessment, and the information analysis required by paragraph (g) of 
this section.
    (4) Variance from the 5-year intervals in limited situations--(i) 
Engineering basis. An operator may be able to justify an engineering 
basis for a longer assessment interval on a segment of line pipe. The 
justification must be supported by a reliable engineering evaluation 
combined with the use of other technology, such as external monitoring 
technology, that provides an understanding of the condition of the line 
pipe equivalent to that which can be obtained from the assessment 
methods allowed in paragraph (j)(5) of this section. An operator must 
notify OPS 270 days before the end of the five-year (or less) interval 
of the justification for a longer interval, and propose an alternative 
interval. An operator must send the notice to the address specified in 
paragraph (m) of this section.
    (ii) Unavailable technology. An operator may require a longer 
assessment period for a segment of line pipe (for

[[Page 697]]

example, because sophisticated internal inspection technology is not 
available). An operator must justify the reasons why it cannot comply 
with the required assessment period and must also demonstrate the 
actions it is taking to evaluate the integrity of the pipeline segment 
in the interim. An operator must notify OPS 180 days before the end of 
the five-year (or less) interval that the operator may require a longer 
assessment interval, and provide an estimate of when the assessment can 
be completed. An operator must send a notice to the address specified in 
paragraph (m) of this section.
    (5) Assessment methods. An operator must assess the integrity of the 
line pipe by any of the following methods. The methods an operator 
selects to assess low frequency electric resistance welded pipe or lap 
welded pipe susceptible to longitudinal seam failure must be capable of 
assessing seam integrity and of detecting corrosion and deformation 
anomalies.
    (i) In-Line Inspection tool or tools capable of detecting corrosion 
and deformation anomalies, including dents, gouges, and grooves. For 
pipeline segments that are susceptible to cracks (pipe body and weld 
seams), an operator must use an in-line inspection tool or tools capable 
of detecting crack anomalies. When performing an assessment using an In-
Line Inspection tool, an operator must comply with Sec.  195.591;
    (ii) Pressure test conducted in accordance with subpart E of this 
part;
    (iii) External corrosion direct assessment in accordance with Sec.  
195.588; or
    (iv) Other technology that the operator demonstrates can provide an 
equivalent understanding of the condition of the line pipe. An operator 
choosing this option must notify OPS 90 days before conducting the 
assessment, by sending a notice to the address or facsimile number 
specified in paragraph (m) of this section.
    (k) What methods to measure program effectiveness must be used? An 
operator's program must include methods to measure whether the program 
is effective in assessing and evaluating the integrity of each pipeline 
segment and in protecting the high consequence areas. See Appendix C of 
this part for guidance on methods that can be used to evaluate a 
program's effectiveness.
    (l) What records must an operator keep to demonstrate compliance? 
(1) An operator must maintain, for the useful life of the pipeline, 
records that demonstrate compliance with the requirements of this 
subpart. At a minimum, an operator must maintain the following records 
for review during an inspection:
    (i) A written integrity management program in accordance with 
paragraph (b) of this section.
    (ii) Documents to support the decisions and analyses, including any 
modifications, justifications, deviations and determinations made, 
variances, and actions taken, to implement and evaluate each element of 
the integrity management program listed in paragraph (f) of this 
section.
    (2) See Appendix C of this part for examples of records an operator 
would be required to keep.
    (m) How does an operator notify PHMSA? An operator must provide any 
notification required by this section by:
    (1) Sending the notification by electronic mail to 
[email protected]; or
    (2) Sending the notification by mail to ATTN: Information Resources 
Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New 
Jersey Ave SE., Washington, DC 20590.
    (n) Accommodation of instrumented internal inspection devices--
    (1) Scope. This paragraph does not apply to any pipeline facilities 
listed in Sec.  195.120(b).
    (2) General. An operator must ensure that each pipeline is modified 
to accommodate the passage of an instrumented internal inspection device 
by July 2, 2040.
    (3) Newly identified areas. If a pipeline could affect a newly 
identified high consequence area (see paragraph (d)(2) of this section) 
after July 2, 2035, an operator must modify the pipeline to accommodate 
the passage of an instrumented internal inspection device within 5 years 
of the date of identification or before performing the baseline 
assessment, whichever is sooner.

[[Page 698]]

    (4) Lack of accommodation. An operator may file a petition under 
Sec.  190.9 of this chapter for a finding that the basic construction 
(i.e., length, diameter, operating pressure, or location) of a pipeline 
cannot be modified to accommodate the passage of an instrumented 
internal inspection device or that the operator determines it would 
abandon or shut-down a pipeline as a result of the cost to comply with 
the requirement of this section.
    (5) Emergencies. An operator may file a petition under Sec.  190.9 
of this chapter for a finding that a pipeline cannot be modified to 
accommodate the passage of an instrumented internal inspection device as 
a result of an emergency. An operator must file such a petition within 
30 days after discovering the emergency. If the petition is denied, the 
operator must modify the pipeline to allow the passage of an 
instrumented internal inspection device within 1 year after the date of 
the notice of the denial.

[Amdt. 195-70, 65 FR 75406, Dec. 1, 2000]

    Editorial Notes: 1. For Federal Register citations affecting Sec.  
195.452, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and at www.govinfo.gov.

    2. At 84 FR 52296, Oct. 1, 2019, Sec.  195.452 was amended by adding 
paragraph (o); however, the amendment could not be incorporated because 
the added text was not provided.



Sec.  195.454  Integrity assessments for certain underwater hazardous 
liquid pipeline facilities located in high consequence areas.

    Notwithstanding any pipeline integrity management program or 
integrity assessment schedule otherwise required under Sec.  195.452, 
each operator of any underwater hazardous liquid pipeline facility 
located in a high consequence area that is not an offshore pipeline 
facility and any portion of which is located at depths greater than 150 
feet under the surface of the water must ensure that:
    (a) Pipeline integrity assessments using internal inspection 
technology appropriate for the integrity threats to the pipeline are 
completed not less often than once every 12 months, and;
    (b) Pipeline integrity assessments using pipeline route surveys, 
depth of cover surveys, pressure tests, external corrosion direct 
assessment, or other technology that the operator demonstrates can 
further the understanding of the condition of the pipeline facility, are 
completed on a schedule based on the risk that the pipeline facility 
poses to the high consequence area in which the pipeline facility is 
located.

[Amdt. 195-102, 84 FR 52298, Oct. 1, 2019]



              Subpart G_Qualification of Pipeline Personnel

    Source: Amdt. 195-67, 64 FR 46866, Aug. 27, 1999, unless otherwise 
noted.



Sec.  195.501  Scope.

    (a) This subpart prescribes the minimum requirements for operator 
qualification of individuals performing covered tasks on a pipeline 
facility.
    (b) For the purpose of this subpart, a covered task is an activity, 
identified by the operator, that:
    (1) Is performed on a pipeline facility;
    (2) Is an operations or maintenance task;
    (3) Is performed as a requirement of this part; and
    (4) Affects the operation or integrity of the pipeline.



Sec.  195.503  Definitions.

    Abnormal operating condition means a condition identified by the 
operator that may indicate a malfunction of a component or deviation 
from normal operations that may:
    (a) Indicate a condition exceeding design limits; or
    (b) Result in a hazard(s) to persons, property, or the environment.
    Evaluation means a process, established and documented by the 
operator, to determine an individual's ability to perform a covered task 
by any of the following:
    (a) Written examination;
    (b) Oral examination;
    (c) Work performance history review;
    (d) Observation during:
    (1) performance on the job,
    (2) on the job training, or
    (3) simulations;
    (e) Other forms of assessment.

[[Page 699]]

    Qualified means that an individual has been evaluated and can:
    (a) Perform assigned covered tasks and
    (b) Recognize and react to abnormal operating conditions.

[Amdt. 195-67, 64 FR 46866, Aug. 27, 1999, as amended by Amdt. 195-72, 
66 FR 43524, Aug. 20, 2001]



Sec.  195.505  Qualification program.

    Each operator shall have and follow a written qualification program. 
The program shall include provisions to:
    (a) Identify covered tasks;
    (b) Ensure through evaluation that individuals performing covered 
tasks are qualified;
    (c) Allow individuals that are not qualified pursuant to this 
subpart to perform a covered task if directed and observed by an 
individual that is qualified;
    (d) Evaluate an individual if the operator has reason to believe 
that the individual's performance of a covered task contributed to an 
accident as defined in Part 195;
    (e) Evaluate an individual if the operator has reason to believe 
that the individual is no longer qualified to perform a covered task;
    (f) Communicate changes that affect covered tasks to individuals 
performing those covered tasks;
    (g) Identify those covered tasks and the intervals at which 
evaluation of the individual's qualifications is needed;
    (h) After December 16, 2004, provide training, as appropriate, to 
ensure that individuals performing covered tasks have the necessary 
knowledge and skills to perform the tasks in a manner that ensures the 
safe operation of pipeline facilities; and
    (i) After December 16, 2004, notify the Administrator or a state 
agency participating under 49 U.S.C. Chapter 601 if the operator 
significantly modifies the program after the administrator or state 
agency has verified that it complies with this section. Notifications to 
PHMSA may be submitted by electronic mail to 
[email protected], or by mail to ATTN: Information 
Resources Manager DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, New 
Jersey Avenue SE., Washington, DC 20590.

[Amdt. 195-67, 64 FR 46866, Aug. 27, 1999, as amended by Amdt. 195-84, 
70 FR 10336, Mar. 3, 2005; Amdt. 195-100, 80 FR 12780, Mar. 11, 2015]



Sec.  195.507  Recordkeeping.

    Each operator shall maintain records that demonstrate compliance 
with this subpart.
    (a) Qualification records shall include:
    (1) Identification of qualified individual(s);
    (2) Identification of the covered tasks the individual is qualified 
to perform;
    (3) Date(s) of current qualification; and
    (4) Qualification method(s).
    (b) Records supporting an individual's current qualification shall 
be maintained while the individual is performing the covered task. 
Records of prior qualification and records of individuals no longer 
performing covered tasks shall be retained for a period of five years.



Sec.  195.509  General.

    (a) Operators must have a written qualification program by April 27, 
2001. The program must be available for review by the Administrator or 
by a state agency participating under 49 U.S.C. Chapter 601 if the 
program is under the authority of that state agency.
    (b) Operators must complete the qualification of individuals 
performing covered tasks by October 28, 2002.
    (c) Work performance history review may be used as a sole evaluation 
method for individuals who were performing a covered task prior to 
October 26, 1999.
    (d) After October 28, 2002, work performance history may not be used 
as a sole evaluation method.
    (e) After December 16, 2004, observation of on-the-job performance 
may not be used as the sole method of evaluation.

[Amdt. 195-67, 64 FR 46866, Aug. 27, 1999, as amended by Amdt. 195-72, 
66 FR 43524, Aug. 20, 2001; Amdt. 195-84, 70 FR 10336, Mar. 3, 2005]

[[Page 700]]



                       Subpart H_Corrosion Control

    Source: Amdt. 195-73, 66 FR 67004, Dec. 27, 2001, unless otherwise 
noted.



Sec.  195.551  What do the regulations in this subpart cover?

    This subpart prescribes minimum requirements for protecting steel 
pipelines against corrosion.



Sec.  195.553  What special definitions apply to this subpart?

    As used in this subpart--
    Active corrosion means continuing corrosion which, unless 
controlled, could result in a condition that is detrimental to public 
safety or the environment.
    Buried means covered or in contact with soil.
    Direct assessment means an integrity assessment method that utilizes 
a process to evaluate certain threats (i.e., external corrosion, 
internal corrosion and stress corrosion cracking) to a pipeline 
segment's integrity. The process includes the gathering and integration 
of risk factor data, indirect examination or analysis to identify areas 
of suspected corrosion, direct examination of the pipeline in these 
areas, and post assessment evaluation.
    Electrical survey means a series of closely spaced pipe-to-soil 
readings over a pipeline that are subsequently analyzed to identify 
locations where a corrosive current is leaving the pipeline.
    External corrosion direct assessment (ECDA) means a four-step 
process that combines pre-assessment, indirect inspection, direct 
examination, and post-assessment to evaluate the threat of external 
corrosion to the integrity of a pipeline.
    Pipeline environment includes soil resistivity (high or low), soil 
moisture (wet or dry), soil contaminants that may promote corrosive 
activity, and other known conditions that could affect the probability 
of active corrosion.
    You means operator.

[Amdt. 195-73, 66 FR 67004, Dec. 27, 2001, as amended by Amdt. 195-85, 
70 FR 61576, Oct. 25, 2005]



Sec.  195.555  What are the qualifications for supervisors?

    You must require and verify that supervisors maintain a thorough 
knowledge of that portion of the corrosion control procedures 
established under Sec.  195.402(c)(3) for which they are responsible for 
insuring compliance.



Sec.  195.557  Which pipelines must have coating for external corrosion 
control?

    Except bottoms of aboveground breakout tanks, each buried or 
submerged pipeline must have an external coating for external corrosion 
control if the pipeline is--
    (a) Constructed, relocated, replaced, or otherwise changed after the 
applicable date in Sec.  195.401(c), not including the movement of pipe 
covered by Sec.  195.424; or
    (b) Converted under Sec.  195.5 and--
    (1) Has an external coating that substantially meets Sec.  195.559 
before the pipeline is placed in service; or
    (2) Is a segment that is relocated, replaced, or substantially 
altered.



Sec.  195.559  What coating material may I use for external corrosion 
control?

    Coating material for external corrosion control under Sec.  195.557 
must--
    (a) Be designed to mitigate corrosion of the buried or submerged 
pipeline;
    (b) Have sufficient adhesion to the metal surface to prevent under 
film migration of moisture;
    (c) Be sufficiently ductile to resist cracking;
    (d) Have enough strength to resist damage due to handling and soil 
stress;
    (e) Support any supplemental cathodic protection; and
    (f) If the coating is an insulating type, have low moisture 
absorption and provide high electrical resistance.



Sec.  195.561  When must I inspect pipe coating used for external corrosion 
control?

    (a) You must inspect all external pipe coating required by Sec.  
195.557 just prior to lowering the pipe into the ditch or submerging the 
pipe.
    (b) You must repair any coating damage discovered.

[[Page 701]]



Sec.  195.563  Which pipelines must have cathodic protection?

    (a) Each buried or submerged pipeline that is constructed, 
relocated, replaced, or otherwise changed after the applicable date in 
Sec.  195.401(c) must have cathodic protection. The cathodic protection 
must be in operation not later than 1 year after the pipeline is 
constructed, relocated, replaced, or otherwise changed, as applicable.
    (b) Each buried or submerged pipeline converted under Sec.  195.5 
must have cathodic protection if the pipeline--
    (1) Has cathodic protection that substantially meets Sec.  195.571 
before the pipeline is placed in service; or
    (2) Is a segment that is relocated, replaced, or substantially 
altered.
    (c) All other buried or submerged pipelines that have an effective 
external coating must have cathodic protection. \1\ Except as provided 
by paragraph (d) of this section, this requirement does not apply to 
breakout tanks and does not apply to buried piping in breakout tank 
areas and pumping stations until December 29, 2003.
---------------------------------------------------------------------------

    \1\ A pipeline does not have an effective external coating material 
if the current required to cathodically protect the pipeline is 
substantially the same as if the pipeline were bare.
---------------------------------------------------------------------------

    (d) Bare pipelines, breakout tank areas, and buried pumping station 
piping must have cathodic protection in places where regulations in 
effect before January 28, 2002 required cathodic protection as a result 
of electrical inspections. See previous editions of this part in 49 CFR, 
parts 186 to 199.
    (e) Unprotected pipe must have cathodic protection if required by 
Sec.  195.573(b).



Sec.  195.565  How do I install cathodic protection on breakout tanks?

    After October 2, 2000, when you install cathodic protection under 
Sec.  195.563(a) to protect the bottom of an aboveground breakout tank 
of more than 500 barrels 79.49m3 capacity built to API Spec 12F 
(incorporated by reference, see Sec.  195.3), API Std 620 (incorporated 
by reference, see Sec.  195.3), API Std 650 (incorporated by reference, 
see Sec.  195.3), or API Std 650's predecessor, Standard 12C, you must 
install the system in accordance with ANSI/API RP 651 (incorporated by 
reference, see Sec.  195.3). However, you don't need to comply with 
ANSI/API RP 651 when installing any tank for which you note in the 
corrosion control procedures established under Sec.  195.402(c)(3) why 
complying with all or certain provisions of ANSI/API RP 651 is not 
necessary for the safety of the tank.

[Amdt. 195-99, 80 FR 188, Jan. 5, 2015]



Sec.  195.567  Which pipelines must have test leads and what must I do to 
install and maintain the leads?

    (a) General. Except for offshore pipelines, each buried or submerged 
pipeline or segment of pipeline under cathodic protection required by 
this subpart must have electrical test leads for external corrosion 
control. However, this requirement does not apply until December 27, 
2004 to pipelines or pipeline segments on which test leads were not 
required by regulations in effect before January 28, 2002.
    (b) Installation. You must install test leads as follows:
    (1) Locate the leads at intervals frequent enough to obtain 
electrical measurements indicating the adequacy of cathodic protection.
    (2) Provide enough looping or slack so backfilling will not unduly 
stress or break the lead and the lead will otherwise remain mechanically 
secure and electrically conductive.
    (3) Prevent lead attachments from causing stress concentrations on 
pipe.
    (4) For leads installed in conduits, suitably insulate the lead from 
the conduit.
    (5) At the connection to the pipeline, coat each bared test lead 
wire and bared metallic area with an electrical insulating material 
compatible with the pipe coating and the insulation on the wire.
    (c) Maintenance. You must maintain the test lead wires in a 
condition that enables you to obtain electrical measurements to 
determine whether cathodic protection complies with Sec.  195.571.

[[Page 702]]



Sec.  195.569  Do I have to examine exposed portions of buried pipelines?

    Whenever you have knowledge that any portion of a buried pipeline is 
exposed, you must examine the exposed portion for evidence of external 
corrosion if the pipe is bare, or if the coating is deteriorated. If you 
find external corrosion requiring corrective action under Sec.  195.585, 
you must investigate circumferentially and longitudinally beyond the 
exposed portion (by visual examination, indirect method, or both) to 
determine whether additional corrosion requiring remedial action exists 
in the vicinity of the exposed portion.



Sec.  195.571  What criteria must I use to determine the adequacy of 
cathodic protection?

    Cathodic protection required by this subpart must comply with one or 
more of the applicable criteria and other considerations for cathodic 
protection contained paragraphs 6.2.2, 6.2.3, 6.2.4, 6.2.5 and 6.3 in 
NACE SP 0169 (incorporated by reference, see Sec.  195.3).

[Amdt. 195-100, 80 FR 12781, Mar. 11, 2015]



Sec.  195.573  What must I do to monitor external corrosion control?

    (a) Protected pipelines. You must do the following to determine 
whether cathodic protection required by this subpart complies with Sec.  
195.571:
    (1) Conduct tests on the protected pipeline at least once each 
calendar year, but with intervals not exceeding 15 months. However, if 
tests at those intervals are impractical for separately protected short 
sections of bare or ineffectively coated pipelines, testing may be done 
at least once every 3 calendar years, but with intervals not exceeding 
39 months.
    (2) Identify not more than 2 years after cathodic protection is 
installed, the circumstances in which a close-interval survey or 
comparable technology is practicable and necessary to accomplish the 
objectives of paragraph 10.1.1.3 of NACE SP 0169 (incorporated by 
reference, see Sec.  195.3).
    (b) Unprotected pipe. You must reevaluate your unprotected buried or 
submerged pipe and cathodically protect the pipe in areas in which 
active corrosion is found, as follows:
    (1) Determine the areas of active corrosion by electrical survey, or 
where an electrical survey is impractical, by other means that include 
review and analysis of leak repair and inspection records, corrosion 
monitoring records, exposed pipe inspection records, and the pipeline 
environment.
    (2) For the period in the first column, the second column prescribes 
the frequency of evaluation.

------------------------------------------------------------------------
                  Period                        Evaluation frequency
------------------------------------------------------------------------
Before December 29, 2003..................  At least once every 5
                                             calendar years, but with
                                             intervals not exceeding 63
                                             months.
Beginning December 29, 2003...............  At least once every 3
                                             calendar years, but with
                                             intervals not exceeding 39
                                             months.
------------------------------------------------------------------------

    (c) Rectifiers and other devices. You must electrically check for 
proper performance each device in the first column at the frequency 
stated in the second column.

------------------------------------------------------------------------
                  Device                           Check frequency
------------------------------------------------------------------------
Rectifier.................................  At least six times each
                                             calendar year, but with
                                             intervals not exceeding 2\1/
                                             2\ months.
Reverse current switch....................
Diode.....................................
Interference bond whose failure would
 jeopardize structural protection.
------------------------------------------------------------------------
Other interference bond...................  At least once each calendar
                                             year, but with intervals
                                             not exceeding 15 months.
------------------------------------------------------------------------

    (d) Breakout tanks. You must inspect each cathodic protection system 
used to control corrosion on the bottom of an aboveground breakout tank 
to ensure that operation and maintenance of the system are in accordance 
with API RP 651 (incorporated by reference, see Sec.  195.3). However, 
this inspection is not required if you note in the corrosion control 
procedures established under Sec.  195.402(c)(3) why complying with all 
or certain operation and maintenance provisions of API RP 651 is not 
necessary for the safety of the tank.
    (e) Corrective action. You must correct any identified deficiency in 
corrosion control as required by Sec.  195.401(b). However, if the 
deficiency involves a pipeline in an integrity management program under 
Sec.  195.452, you must correct

[[Page 703]]

the deficiency as required by Sec.  195.452(h).

[Amdt. 195-73, 66 FR 67004, Dec. 27, 2001; 67 FR 70118, Nov. 20, 2002, 
as amended by Amdt. 195-86, 71 FR 33411, June 9, 2006; Amdt. 195-94, 75 
FR 48607, Aug. 11, 2010; Amdt. 195-99, 80 FR 188, Jan. 5, 2015]



Sec.  195.575  Which facilities must I electrically isolate and what 
inspections, tests, and safeguards are required?

    (a) You must electrically isolate each buried or submerged pipeline 
from other metallic structures, unless you electrically interconnect and 
cathodically protect the pipeline and the other structures as a single 
unit.
    (b) You must install one or more insulating devices where electrical 
isolation of a portion of a pipeline is necessary to facilitate the 
application of corrosion control.
    (c) You must inspect and electrically test each electrical isolation 
to assure the isolation is adequate.
    (d) If you install an insulating device in an area where a 
combustible atmosphere is reasonable to foresee, you must take 
precautions to prevent arcing.
    (e) If a pipeline is in close proximity to electrical transmission 
tower footings, ground cables, or counterpoise, or in other areas where 
it is reasonable to foresee fault currents or an unusual risk of 
lightning, you must protect the pipeline against damage from fault 
currents or lightning and take protective measures at insulating 
devices.



Sec.  195.577  What must I do to alleviate interference currents?

    (a) For pipelines exposed to stray currents, you must have a program 
to identify, test for, and minimize the detrimental effects of such 
currents.
    (b) You must design and install each impressed current or galvanic 
anode system to minimize any adverse effects on existing adjacent 
metallic structures.



Sec.  195.579  What must I do to mitigate internal corrosion?

    (a) General. If you transport any hazardous liquid or carbon dioxide 
that would corrode the pipeline, you must investigate the corrosive 
effect of the hazardous liquid or carbon dioxide on the pipeline and 
take adequate steps to mitigate internal corrosion.
    (b) Inhibitors. If you use corrosion inhibitors to mitigate internal 
corrosion, you must--
    (1) Use inhibitors in sufficient quantity to protect the entire part 
of the pipeline system that the inhibitors are designed to protect;
    (2) Use coupons or other monitoring equipment to determine the 
effectiveness of the inhibitors in mitigating internal corrosion; and
    (3) Examine the coupons or other monitoring equipment at least twice 
each calendar year, but with intervals not exceeding 7\1/2\ months.
    (c) Removing pipe. Whenever you remove pipe from a pipeline, you 
must inspect the internal surface of the pipe for evidence of corrosion. 
If you find internal corrosion requiring corrective action under Sec.  
195.585, you must investigate circumferentially and longitudinally 
beyond the removed pipe (by visual examination, indirect method, or 
both) to determine whether additional corrosion requiring remedial 
action exists in the vicinity of the removed pipe.
    (d) Breakout tanks. After October 2, 2000, when you install a tank 
bottom lining in an aboveground breakout tank built to API Spec 12F 
(incorporated by reference, see Sec.  195.3), API Std 620 (incorporated 
by reference, see Sec.  195.3), API Std 650 (incorporated by reference, 
see Sec.  195.3), or API Std 650's predecessor, Standard 12C, you must 
install the lining in accordance with API RP 652 (incorporated by 
reference, see Sec.  195.3). However, you don't need to comply with API 
RP 652 when installing any tank for which you note in the corrosion 
control procedures established under Sec.  195.402(c)(3) why compliance 
with all or certain provisions of API RP 652 is not necessary for the 
safety of the tank.

[Amdt. 195-73, 66 FR 67004, Dec. 27, 2001, as amended by Amdt. 195-99, 
80 FR 188, Jan. 5, 2015]

[[Page 704]]



Sec.  195.581  Which pipelines must I protect against atmospheric corrosion 
and what coating material may I use?

    (a) You must clean and coat each pipeline or portion of pipeline 
that is exposed to the atmosphere, except pipelines under paragraph (c) 
of this section.
    (b) Coating material must be suitable for the prevention of 
atmospheric corrosion.
    (c) Except portions of pipelines in offshore splash zones or soil-
to-air interfaces, you need not protect against atmospheric corrosion 
any pipeline for which you demonstrate by test, investigation, or 
experience appropriate to the environment of the pipeline that corrosion 
will--
    (1) Only be a light surface oxide; or
    (2) Not affect the safe operation of the pipeline before the next 
scheduled inspection.



Sec.  195.583  What must I do to monitor atmospheric corrosion control?

    (a) You must inspect each pipeline or portion of pipeline that is 
exposed to the atmosphere for evidence of atmospheric corrosion, as 
follows:

------------------------------------------------------------------------
                                                Then the frequency of
        If the pipeline is located:                inspection is:
------------------------------------------------------------------------
Onshore...................................  At least once every 3
                                             calendar years, but with
                                             intervals not exceeding 39
                                             months.
Offshore..................................  At least once each calendar
                                             year, but with intervals
                                             not exceeding 15 months.
------------------------------------------------------------------------

    (b) During inspections you must give particular attention to pipe at 
soil-to-air interfaces, under thermal insulation, under disbonded 
coatings, at pipe supports, in splash zones, at deck penetrations, and 
in spans over water.
    (c) If you find atmospheric corrosion during an inspection, you must 
provide protection against the corrosion as required by Sec.  195.581.



Sec.  195.585  What must I do to correct corroded pipe?

    (a) General corrosion. If you find pipe so generally corroded that 
the remaining wall thickness is less than that required for the maximum 
operating pressure of the pipeline, you must replace the pipe. However, 
you need not replace the pipe if you--
    (1) Reduce the maximum operating pressure commensurate with the 
strength of the pipe needed for serviceability based on actual remaining 
wall thickness; or
    (2) Repair the pipe by a method that reliable engineering tests and 
analyses show can permanently restore the serviceability of the pipe.
    (b) Localized corrosion pitting. If you find pipe that has localized 
corrosion pitting to a degree that leakage might result, you must 
replace or repair the pipe, unless you reduce the maximum operating 
pressure commensurate with the strength of the pipe based on actual 
remaining wall thickness in the pits.



Sec.  195.587  What methods are available to determine the strength of 
corroded pipe?

    Under Sec.  195.585, you may use the procedure in ASME/ANSI B31G 
(incorporated by reference, see Sec.  195.3) or in PRCI PR-3-805 (R-
STRENG) (incorporated by reference, see Sec.  195.3) to determine the 
strength of corroded pipe based on actual remaining wall thickness. 
These procedures apply to corroded regions that do not penetrate the 
pipe wall, subject to the limitations set out in the respective 
procedures.

[Amdt. 195-99, 80 FR 188, Jan. 5, 2015]



Sec.  195.588  What standards apply to direct assessment?

    (a) If you use direct assessment on an onshore pipeline to evaluate 
the effects of external corrosion or stress corrosion cracking, you must 
follow the requirements of this section. This section does not apply to 
methods associated with direct assessment, such as close interval 
surveys, voltage gradient surveys, or examination of exposed pipelines, 
when used separately from the direct assessment process.
    (b) The requirements for performing external corrosion direct 
assessment are as follows:
    (1) General. You must follow the requirements of NACE SP0502 
(incorporated by reference, see Sec.  195.3). Also, you must develop and 
implement a External Corrosion Direct Assessment (ECDA) plan that 
includes procedures

[[Page 705]]

addressing pre-assessment, indirect examination, direct examination, and 
post-assessment.
    (2) Pre-assessment. In addition to the requirements in Section 3 of 
NACE SP0502 (incorporated by reference, see Sec.  195.3), the ECDA plan 
procedures for pre-assessment must include--
    (i) Provisions for applying more restrictive criteria when 
conducting ECDA for the first time on a pipeline segment;
    (ii) The basis on which you select at least two different, but 
complementary, indirect assessment tools to assess each ECDA region; and
    (iii) If you utilize an indirect inspection method not described in 
Appendix A of NACE SP0502 (incorporated by reference, see Sec.  195.3), 
you must demonstrate the applicability, validation basis, equipment 
used, application procedure, and utilization of data for the inspection 
method.
    (3) Indirect examination. In addition to the requirements in Section 
4 of NACE SP0502 (incorporated by reference, see Sec.  195.3), the 
procedures for indirect examination of the ECDA regions must include--
    (i) Provisions for applying more restrictive criteria when 
conducting ECDA for the first time on a pipeline segment;
    (ii) Criteria for identifying and documenting those indications that 
must be considered for excavation and direct examination, including at 
least the following:
    (A) The known sensitivities of assessment tools;
    (B) The procedures for using each tool; and
    (C) The approach to be used for decreasing the physical spacing of 
indirect assessment tool readings when the presence of a defect is 
suspected;
    (iii) For each indication identified during the indirect 
examination, criteria for--
    (A) Defining the urgency of excavation and direct examination of the 
indication; and
    (B) Defining the excavation urgency as immediate, scheduled, or 
monitored; and
    (iv) Criteria for scheduling excavations of indications in each 
urgency level.
    (4) Direct examination. In addition to the requirements in Section 5 
of NACE SP0502 (incorporated by reference, see Sec.  195.3), the 
procedures for direct examination of indications from the indirect 
examination must include--
    (i) Provisions for applying more restrictive criteria when 
conducting ECDA for the first time on a pipeline segment;
    (ii) Criteria for deciding what action should be taken if either:
    (A) Corrosion defects are discovered that exceed allowable limits 
(Section 5.5.2.2 of NACE SP0502 (incorporated by reference, see Sec.  
195.3) provides guidance for criteria); or
    (B) Root cause analysis reveals conditions for which ECDA is not 
suitable (Section 5.6.2 of NACE SP0502 (incorporated by reference, see 
Sec.  195.3) provides guidance for criteria);
    (iii) Criteria and notification procedures for any changes in the 
ECDA plan, including changes that affect the severity classification, 
the priority of direct examination, and the time frame for direct 
examination of indications; and
    (iv) Criteria that describe how and on what basis you will 
reclassify and re-prioritize any of the provisions specified in Section 
5.9 of NACE SP0502 (incorporated by reference, see Sec.  195.3).
    (5) Post assessment and continuing evaluation. In addition to the 
requirements in Section 6 of NACE SP 0502 (incorporated by reference, 
see Sec.  195.3), the procedures for post assessment of the 
effectiveness of the ECDA process must include--
    (i) Measures for evaluating the long-term effectiveness of ECDA in 
addressing external corrosion in pipeline segments; and
    (ii) Criteria for evaluating whether conditions discovered by direct 
examination of indications in each ECDA region indicate a need for 
reassessment of the pipeline segment at an interval less than that 
specified in Sections 6.2 and 6.3 of NACE SP0502 (see appendix D of NACE 
SP0502) (incorporated by reference, see Sec.  195.3).
    (c) If you use direct assessment on an onshore pipeline to evaluate 
the effects of stress corrosion cracking, you must develop and follow a 
Stress Corrosion Cracking Direct Assessment plan that

[[Page 706]]

meets all requirements and recommendations of NACE SP0204-2008 
(incorporated by reference, see Sec.  195.3) and that implements all 
four steps of the Stress Corrosion Cracking Direct Assessment process 
including pre-assessment, indirect inspection, detailed examination and 
post-assessment. As specified in NACE SP0204-2008, Section 1.1.7, Stress 
Corrosion Cracking Direct Assessment is complementary with other 
inspection methods such as in-line inspection or hydrostatic testing and 
is not necessarily an alternative or replacement for these methods in 
all instances. In addition, the plan must provide for--
    (1) Data gathering and integration. An operator's plan must provide 
for a systematic process to collect and evaluate data to identify 
whether the conditions for stress corrosion cracking are present and to 
prioritize the segments for assessment in accordance with NACE SP0204-
2008, Sections 3 and 4, and Table 1. This process must also include 
gathering and evaluating data related to SCC at all sites an operator 
excavates during the conduct of its pipeline operations (both within and 
outside covered segments) where the criteria in NACE SP0204-2008 
indicate the potential for Stress Corrosion Cracking Direct Assessment. 
This data gathering process must be conducted in accordance with NACE 
SP0204-2008, Section 5.3, and must include, at a minimum, all data 
listed in NACE SP0204-2008, Table 2. Further, an operator must analyze 
the following factors as part of this evaluation:
    (i) The effects of a carbonate-bicarbonate environment, including 
the implications of any factors that promote the production of a 
carbonate-bicarbonate environment such as soil temperature, moisture, 
factors that affect the rate of carbon dioxide generation, and/or 
cathodic protection.
    (ii) The effects of cyclic loading conditions on the susceptibility 
and propagation of SCC in both high-pH and near-neutral-pH environments.
    (iii) The effects of variations in applied cathodic protection such 
as overprotection, cathodic protection loss for extended periods, and 
high negative potentials.
    (iv) The effects of coatings that shield cathodic protection when 
disbonded from the pipe.
    (v) Other factors that affect the mechanistic properties associated 
with SCC including but not limited to operating pressures, high tensile 
residual stresses, and the presence of sulfides.
    (2) Indirect inspection. In addition to the requirements and 
recommendations of NACE SP0204-2008, Section 4, the plan's procedures 
for indirect inspection must include provisions for conducting at least 
two different, but complementary, indirect assessment electrical 
surveys, and the basis on the selections as the most appropriate for the 
pipeline segment based on the data gathering and integration step.
    (3) Direct examination. In addition to the requirements and 
recommendations of NACE SP0204-2008, Section 5, the plan's procedures 
for direct examination must provide for conducting a minimum of four 
direct examinations within the SCC segment at locations determined to be 
the most likely for SCC to occur.
    (4) Remediation and mitigation. If any indication of SCC is 
discovered in a segment, an operator must mitigate the threat in 
accordance with one of the following applicable methods:
    (i) Non-significant SCC, as defined by NACE SP0204-2008, may be 
mitigated by either hydrostatic testing in accordance with paragraph 
(b)(4)(ii) of this section, or by grinding out with verification by Non-
Destructive Examination (NDE) methods that the SCC defect is removed and 
repairing the pipe. If grinding is used for repair, the remaining 
strength of the pipe at the repair location must be determined using 
ASME/ANSI B31G or RSTRENG (incorporated by reference, see Sec.  195.3) 
and must be sufficient to meet the design requirements of subpart C of 
this part.
    (ii) Significant SCC must be mitigated using a hydrostatic testing 
program with a minimum test pressure between 100% up to 110% of the 
specified minimum yield strength for a 30-minute spike test immediately 
followed by a pressure test in accordance with subpart E of this part. 
The test pressure for the entire sequence must be continuously 
maintained for at least

[[Page 707]]

8 hours, in accordance with subpart E of this part. Any test failures 
due to SCC must be repaired by replacement of the pipe segment, and the 
segment retested until the pipe passes the complete test without 
leakage. Pipe segments that have SCC present, but that pass the pressure 
test, may be repaired by grinding in accordance with paragraph (c)(4)(i) 
of this section.
    (5) Post assessment. In addition to the requirements and 
recommendations of NACE SP0204-2008, sections 6.3, periodic 
reassessment, and 6.4, effectiveness of Stress Corrosion Cracking Direct 
Assessment, the plan's procedures for post assessment must include 
development of a reassessment plan based on the susceptibility of the 
operator's pipe to Stress Corrosion Cracking as well as on the behavior 
mechanism of identified cracking. Factors to be considered include, but 
are not limited to:
    (i) Evaluation of discovered crack clusters during the direct 
examination step in accordance with NACE SP0204-2008, sections 5.3.5.7, 
5.4, and 5.5;
    (ii) Conditions conducive to creation of the carbonate-bicarbonate 
environment;
    (iii) Conditions in the application (or loss) of cathodic protection 
that can create or exacerbate SCC;
    (iv) Operating temperature and pressure conditions;
    (v) Cyclic loading conditions;
    (vi) Conditions that influence crack initiation and growth rates;
    (vii) The effects of interacting crack clusters;
    (viii) The presence of sulfides; and
    (ix) Disbonded coatings that shield CP from the pipe.

[Amdt. 195-85, 70 FR 61576, Oct. 25, 2005, as amended by Amdt. 195-94, 
75 FR 48607, Aug. 11, 2010; Amdt. 195-101, 82 FR 8000, Jan. 23, 2017]



Sec.  195.589  What corrosion control information do I have to maintain?

    (a) You must maintain current records or maps to show the location 
of--
    (1) Cathodically protected pipelines;
    (2) Cathodic protection facilities, including galvanic anodes, 
installed after January 28, 2002; and
    (3) Neighboring structures bonded to cathodic protection systems.
    (b) Records or maps showing a stated number of anodes, installed in 
a stated manner or spacing, need not show specific distances to each 
buried anode.
    (c) You must maintain a record of each analysis, check, 
demonstration, examination, inspection, investigation, review, survey, 
and test required by this subpart in sufficient detail to demonstrate 
the adequacy of corrosion control measures or that corrosion requiring 
control measures does not exist. You must retain these records for at 
least 5 years, except that records related to Sec. Sec.  195.569, 
195.573(a) and (b), and 195.579(b)(3) and (c) must be retained for as 
long as the pipeline remains in service.



Sec.  195.591  In-Line inspection of pipelines.

    When conducting in-line inspection of pipelines required by this 
part, each operator must comply with the requirements and 
recommendations of API Std 1163, Inline Inspection Systems Qualification 
Standard; ANSI/ASNT ILI-PQ, Inline Inspection Personnel Qualification 
and Certification; and NACE SP0102-2010, Inline Inspection of Pipelines 
(incorporated by reference, see Sec.  195.3). An in-line inspection may 
also be conducted using tethered or remote control tools provided they 
generally comply with those sections of NACE SP0102-2010 that are 
applicable.

[Amdt. 195-101, 82 FR 8000, Jan. 23, 2017]





   Sec. Appendix A to Part 195--Delineation Between Federal and State 
       Jurisdiction--Statement of Agency Policy and Interpretation

    In 1979, Congress enacted comprehensive safety legislation governing 
the transportation of hazardous liquids by pipeline, the Hazardous 
Liquids Pipeline Safety Act of 1979, 49 U.S.C. 2001 et seq. (HLPSA). The 
HLPSA expanded the existing statutory authority for safety regulation, 
which was limited to transportation by common carriers in interstate and 
foreign commerce, to transportation through facilities used in or 
affecting interstate or foreign commerce. It also added civil penalty, 
compliance order, and injunctive enforcement authorities to the existing 
criminal sanctions. Modeled largely on the Natural Gas Pipeline Safety 
Act of 1968, 49 U.S.C. 1671 et seq. (NGPSA), the

[[Page 708]]

HLPSA provides for a national hazardous liquid pipeline safety program 
with nationally uniform minimal standards and with enforcement 
administered through a Federal-State partnership. The HLPSA leaves to 
exclusive Federal regulation and enforcement the ``interstate pipeline 
facilities,'' those used for the pipeline transportation of hazardous 
liquids in interstate or foreign commerce. For the remainder of the 
pipeline facilities, denominated ``intrastate pipeline facilities,'' the 
HLPSA provides that the same Federal regulation and enforcement will 
apply unless a State certifies that it will assume those 
responsibilities. A certified State must adopt the same minimal 
standards but may adopt additional more stringent standards so long as 
they are compatible. Therefore, in States which participate in the 
hazardous liquid pipeline safety program through certification, it is 
necessary to distinguish the interstate from the intrastate pipeline 
facilities.
    In deciding that an administratively practical approach was 
necessary in distinguishing between interstate and intrastate liquid 
pipeline facilities and in determining how best to accomplish this, DOT 
has logically examined the approach used in the NGPSA. The NGPSA defines 
the interstate gas pipeline facilities subject to exclusive Federal 
jurisdiction as those subject to the economic regulatory jurisdiction of 
the Federal Energy Regulatory Commission (FERC). Experience has proven 
this approach practical. Unlike the NGPSA however, the HLPSA has no 
specific reference to FERC jurisdiction, but instead defines interstate 
liquid pipeline facilities by the more commonly used means of specifying 
the end points of the transportation involved. For example, the economic 
regulatory jurisdiction of FERC over the transportation of both gas and 
liquids by pipeline is defined in much the same way. In implementing the 
HLPSA DOT has sought a practicable means of distinguishing between 
interstate and intrastate pipeline facilities that provide the requisite 
degree of certainty to Federal and State enforcement personnel and to 
the regulated entities. DOT intends that this statement of agency policy 
and interpretation provide that certainty.
    In 1981, DOT decided that the inventory of liquid pipeline 
facilities identified as subject to the jurisdiction of FERC 
approximates the HLPSA category of ``interstate pipeline facilities.'' 
Administrative use of the FERC inventory has the added benefit of 
avoiding the creation of a separate Federal scheme for determination of 
jurisdiction over the same regulated entities. DOT recognizes that the 
FERC inventory is only an approximation and may not be totally 
satisfactory without some modification. The difficulties stem from some 
significant differences in the economic regulation of liquid and of 
natural gas pipelines. There is an affirmative assertion of jurisdiction 
by FERC over natural gas pipelines through the issuance of certificates 
of public convenience and necessity prior to commencing operations. With 
liquid pipelines, there is only a rebuttable presumption of jurisdiction 
created by the filing by pipeline operators of tariffs (or concurrences) 
for movement of liquids through existing facilities. Although FERC does 
police the filings for such matters as compliance with the general 
duties of common carriers, the question of jurisdiction is normally only 
aired upon complaint. While any person, including State or Federal 
agencies, can avail themselves of the FERC forum by use of the complaint 
process, that process has only been rarely used to review jurisdictional 
matters (probably because of the infrequency of real disputes on the 
issue). Where the issue has arisen, the reviewing body has noted the 
need to examine various criteria primarily of an economic nature. DOT 
believes that, in most cases, the formal FERC forum can better receive 
and evaluate the type of information that is needed to make decisions of 
this nature than can DOT.
    In delineating which liquid pipeline facilities are interstate 
pipeline facilities within the meaning of the HLPSA, DOT will generally 
rely on the FERC filings; that is, if there is a tariff or concurrence 
filed with FERC governing the transportation of hazardous liquids over a 
pipeline facility or if there has been an exemption from the obligation 
to file tariffs obtained from FERC, then DOT will, as a general rule, 
consider the facility to be an interstate pipeline facility within the 
meaning of the HLPSA. The types of situations in which DOT will ignore 
the existence or non-existence of a filing with FERC will be limited to 
those cases in which it appears obvious that a complaint filed with FERC 
would be successful or in which blind reliance on a FERC filing would 
result in a situation clearly not intended by the HLPSA such as a 
pipeline facility not being subject to either State or Federal safety 
regulation. DOT anticipates that the situations in which there is any 
question about the validity of the FERC filings as a ready reference 
will be few and that the actual variations from reliance on those 
filings will be rare. The following examples indicate the types of 
facilities which DOT believes are interstate pipeline facilities subject 
to the HLPSA despite the lack of a filing with FERC and the types of 
facilities over which DOT will generally defer to the jurisdiction of a 
certifying state despite the existence of a filing with FERC.

    Example 1. Pipeline company P operates a pipeline from ``Point A'' 
located in State X to ``Point B'' (also in X). The physical facilities 
never cross a state line and do not connect with any other pipeline 
which does

[[Page 709]]

cross a state line. Pipeline company P also operates another pipeline 
between ``Point C'' in State X and ``Point D'' in an adjoining State Y. 
Pipeline company P files a tariff with FERC for transportation from 
``Point A'' to ``Point B'' as well as for transportation from ``Point 
C'' to ``Point D.'' DOT will ignore filing for the line from ``Point A'' 
to ``Point B'' and consider the line to be intrastate.
    Example 2. Same as in example 1 except that P does not file any 
tariffs with FERC. DOT will assume jurisdiction of the line between 
``Point C'' and ``Point D.''
    Example 3. Same as in example 1 except that P files its tariff for 
the line between ``Point C'' and ``Point D'' not only with FERC but also 
with State X. DOT will rely on the FERC filing as indication of 
interstate commerce.
    Example 4. Same as in example 1 except that the pipeline from 
``Point A'' to ``Point B'' (in State X) connects with a pipeline 
operated by another company transports liquid between ``Point B'' (in 
State X) and ``Point D'' (in State Y). DOT will rely on the FERC filing 
as indication of interstate commerce.
    Example 5. Same as in example 1 except that the line between ``Point 
C'' and ``Point D'' has a lateral line connected to it. The lateral is 
located entirely with State X. DOT will rely on the existence or non-
existence of a FERC filing covering transportation over that lateral as 
determinative of interstate commerce.
    Example 6. Same as in example 1 except that the certified agency in 
State X has brought an enforcement action (under the pipeline safety 
laws) against P because of its operation of the line between ``Point A'' 
and ``Point B''. P has successfully defended against the action on 
jurisdictional grounds. DOT will assume jurisdiction if necessary to 
avoid the anomaly of a pipeline subject to neither State or Federal 
safety enforcement. DOT's assertion of jurisdiction in such a case would 
be based on the gap in the state's enforcement authority rather than a 
DOT decision that the pipeline is an interstate pipeline facility.
    Example 7. Pipeline Company P operates a pipeline that originates on 
the Outer Continental Shelf. P does not file any tariff for that line 
with FERC. DOT will consider the pipeline to be an interstate pipeline 
facility.
    Example 8. Pipeline Company P is constructing a pipeline from 
``Point C'' (in State X) to ``Point D'' (in State Y). DOT will consider 
the pipeline to be an interstate pipeline facility.
    Example 9. Pipeline company P is constructing a pipeline from 
``Point C'' to ``Point E'' (both in State X) but intends to file tariffs 
with FERC in the transportation of hazardous liquid in interstate 
commerce. Assuming there is some connection to an interstate pipeline 
facility, DOT will consider this line to be an interstate pipeline 
facility.
    Example 10. Pipeline Company P has operated a pipeline subject to 
FERC economic regulation. Solely because of some statutory economic 
deregulation, that pipeline is no longer regulated by FERC. DOT will 
continue to consider that pipeline to be an interstate pipeline 
facility.

    As seen from the examples, the types of situations in which DOT will 
not defer to the FERC regulatory scheme are generally clear-cut cases. 
For the remainder of the situations where variation from the FERC scheme 
would require DOT to replicate the forum already provided by FERC and to 
consider economic factors better left to that agency, DOT will decline 
to vary its reliance on the FERC filings unless, of course, not doing so 
would result in situations clearly not intended by the HLPSA.

[Amdt. 195-33, 50 FR 15899, Apr. 23, 1985]



Sec. Appendix B to Part 195--Risk-Based Alternative to Pressure Testing 
           Older Hazardous Liquid and Carbon Dioxide Pipelines

                         Risk-Based Alternative

    This Appendix provides guidance on how a risk-based alternative to 
pressure testing older hazardous liquid and carbon dioxide pipelines 
rule allowed by Sec.  195.303 will work. This risk-based alternative 
establishes test priorities for older pipelines, not previously pressure 
tested, based on the inherent risk of a given pipeline segment. The 
first step is to determine the classification based on the type of pipe 
or on the pipeline segment's proximity to populated or environmentally 
sensitive area. Secondly, the classifications must be adjusted based on 
the pipeline failure history, product transported, and the release 
volume potential.
    Tables 2-6 give definitions of risk classification A, B, and C 
facilities. For the purposes of this rule, pipeline segments containing 
high risk electric resistance-welded pipe (ERW pipe) and lapwelded pipe 
manufactured prior to 1970 and considered a risk classification C or B 
facility shall be treated as the top priority for testing because of the 
higher risk associated with the susceptibility of this pipe to 
longitudinal seam failures.
    In all cases, operators shall annually, at intervals not to exceed 
15 months, review their facilities to reassess the classification and 
shall take appropriate action within two years or operate the pipeline 
system at a lower pressure. Pipeline failures, changes in the 
characteristics of the pipeline route, or changes in service should all 
trigger a reassessment of the originally classification.

[[Page 710]]

    Table 1 explains different levels of test requirements depending on 
the inherent risk of a given pipeline segment. The overall risk 
classification is determined based on the type of pipe involved, the 
facility's location, the product transported, the relative volume of 
flow and pipeline failure history as determined from Tables 2-6.

          Table 1. Test Requirements--Mainline Segments Outside of Terminals, Stations, and Tank Farms
----------------------------------------------------------------------------------------------------------------
         Pipeline segment           Risk classification           Test deadline \1\              Test medium
----------------------------------------------------------------------------------------------------------------
Pre-1970 Pipeline Segments         C or B                 12/7/2000 \3\...................  Water only.
 susceptible to longitudinal seam  A                      12/7/2002 \3\...................  Water only.
 failures \2\.
All Other Pipeline Segments......  C                      12/7/2002 \4\...................  Water only.
                                   B                      12/7/2004 \4\...................  Water/Liq. \5\
                                   A                      Additional pressure testing not
                                                           required.
----------------------------------------------------------------------------------------------------------------
\1\ If operational experience indicates a history of past failures for a particular pipeline segment, failure
  causes (time-dependent defects due to corrosion, construction, manufacture, or transmission problems, etc.)
  shall be reviewed in determining risk classification (See Table 6) and the timing of the pressure test should
  be accelerated.
\2\ All pre-1970 ERW pipeline segments may not require testing. In determining which ERW pipeline segments
  should be included in this category, an operator must consider the seam-related leak history of the pipe and
  pipe manufacturing information as available, which may include the pipe steel's mechanical properties,
  including fracture toughness; the manufacturing process and controls related to seam properties, including
  whether the ERW process was high-frequency or low-frequency, whether the weld seam was heat treated, whether
  the seam was inspected, the test pressure and duration during mill hydrotest; the quality control of the steel-
  making process; and other factors pertinent to seam properties and quality.
\3\ For those pipeline operators with extensive mileage of pre-1970 ERW pipe, any waiver requests for timing
  relief should be supported by an assessment of hazards in accordance with location, product, volume, and
  probability of failure considerations consistent with Tables 3, 4, 5, and 6.
\4\ A magnetic flux leakage or ultrasonic internal inspection survey may be utilized as an alternative to
  pressure testing where leak history and operating experience do not indicate leaks caused by longitudinal
  cracks or seam failures.
\5\ Pressure tests utilizing a hydrocarbon liquid may be conducted, but only with a liquid which does not
  vaporize rapidly.

    Using LOCATION, PRODUCT, VOLUME, and FAILURE HISTORY ``Indicators'' 
from Tables 3, 4, 5, and 6 respectively, the overall risk classification 
of a given pipeline or pipeline segment can be established from Table 2. 
The LOCATION Indicator is the primary factor which determines overall 
risk, with the PRODUCT, VOLUME, and PROBABILITY OF FAILURE Indicators 
used to adjust to a higher or lower overall risk classification per the 
following table.

                                          Table 2--Risk Classification
----------------------------------------------------------------------------------------------------------------
                                      Hazard location       Product/volume
       Risk classification               indicator             indicator        Probability of failure indicator
----------------------------------------------------------------------------------------------------------------
A................................  L or M..............  L/L.................  L.
B................................                          Not A or C Risk Classification
C................................  H...................  Any.................  Any.
----------------------------------------------------------------------------------------------------------------
H = High M = Moderate L = Low.
Note: For Location, Product, Volume, and Probability of Failure Indicators, see Tables 3, 4, 5, and 6.

    Table 3 is used to establish the LOCATION Indicator used in Table 2. 
Based on the population and environment characteristics associated with 
a pipeline facility's location, a LOCATION Indicator of H, M or L is 
selected.

                                 Table 3--Location Indicators--Pipeline Segments
----------------------------------------------------------------------------------------------------------------
               Indicator                                  Population \1\                      Environment \2\
----------------------------------------------------------------------------------------------------------------
H......................................  Non-rural areas................................  Environmentally
                                                                                           sensitive \2\ areas.
M                                        ...............................................  ......................
L......................................  Rural areas....................................  Not environmentally
                                                                                           sensitive \2\ areas.
----------------------------------------------------------------------------------------------------------------
\1\ The effects of potential vapor migration should be considered for pipeline segments transporting highly
  volatile or toxic products.
\2\ We expect operators to use their best judgment in applying this factor.

    Tables 4, 5 and 6 are used to establish the PRODUCT, VOLUME, and 
PROBABILITY OF FAILURE Indicators respectively, in Table 2. The PRODUCT 
Indicator is selected from Table 4 as H, M, or L based on the acute and 
chronic hazards associated with the product transported. The VOLUME 
Indicator is selected from Table 5 as H, M, or L based on the nominal 
diameter of the pipeline. The

[[Page 711]]

Probability of Failure Indicator is selected from Table 6.

                       Table 4--Product Indicators
------------------------------------------------------------------------
          Indicator              Considerations       Product examples
------------------------------------------------------------------------
H...........................  (Highly volatile and  (Propane, butane,
                               flammable).           Natural Gas Liquid
                                                     (NGL), ammonia)
                              Highly toxic........  (Benzene, high
                                                     Hydrogen Sulfide
                                                     content crude
                                                     oils).
M...........................  Flammable--flashpoin  (Gasoline, JP4, low
                               t <100F.              flashpoint crude
                                                     oils).
L...........................  Non-flammable--       (Diesel, fuel oil,
                               flashpoint 100 + F.   kerosene, JP5, most
                                                     crude oils).
                              Highly volatile and   Carbon Dioxide.
                               non-flammable/non-
                               toxic.
------------------------------------------------------------------------

    Considerations: The degree of acute and chronic toxicity to humans, 
wildlife, and aquatic life; reactivity; and, volatility, flammability, 
and water solubility determine the Product Indicator. Comprehensive 
Environmental Response, Compensation and Liability Act Reportable 
Quantity values can be used as an indication of chronic toxicity. 
National Fire Protection Association health factors can be used for 
rating acute hazards.

                       Table 5--Volume Indicators
------------------------------------------------------------------------
             Indicator                            Line size
------------------------------------------------------------------------
H.................................  =18.
M.................................  10-16 nominal
                                     diameters.
L.................................  <=8 nominal diameter.
------------------------------------------------------------------------
H = High M = Moderate L = Low.

    Table 6 is used to establish the PROBABILITY OF FAILURE Indicator 
used in Table 2. The ``Probability of Failure'' Indicator is selected 
from Table 6 as H or L.

               Table 6--Probability of Failure Indicators
                         [in each haz. location]
------------------------------------------------------------------------
                                       Failure history (time-dependent
             Indicator                          defects) \2\
------------------------------------------------------------------------
H \1\.............................  Three spills in last 10
                                     years.
L.................................  <=Three spills in last 10 years.
------------------------------------------------------------------------
H = High L = Low.
\1\ Pipeline segments with greater than three product spills in the last
  10 years should be reviewed for failure causes as described in subnote
  \2\. The pipeline operator should make an appropriate investigation
  and reach a decision based on sound engineering judgment, and be able
  to demonstrate the basis of the decision.
\2\ Time-Dependent Defects are defects that result in spills due to
  corrosion, gouges, or problems developed during manufacture,
  construction or operation, etc.


[Amdt. 195-65, 63 FR 59480, Nov. 4, 1998; 64 FR 6815, Feb. 11, 1999]



Sec. Appendix C to Part 195--Guidance for Implementation of an Integrity 
                           Management Program

    This Appendix gives guidance to help an operator implement the 
requirements of the integrity management program rule in Sec. Sec.  
195.450 and 195.452. Guidance is provided on:
    (1) Information an operator may use to identify a high consequence 
area and factors an operator can use to consider the potential impacts 
of a release on an area;
    (2) Risk factors an operator can use to determine an integrity 
assessment schedule;
    (3) Safety risk indicator tables for leak history, volume or line 
size, age of pipeline, and product transported, an operator may use to 
determine if a pipeline segment falls into a high, medium or low risk 
category;
    (4) Types of internal inspection tools an operator could use to find 
pipeline anomalies;
    (5) Measures an operator could use to measure an integrity 
management program's performance; and
    (6) Types of records an operator will have to maintain.
    (7) Types of conditions that an integrity assessment may identify 
that an operator should include in its required schedule for evaluation 
and remediation.
    I. Identifying a high consequence area and factors for considering a 
pipeline segment's potential impact on a high consequence area.
    A. The rule defines a High Consequence Area as a high population 
area, an other populated area, an unusually sensitive area, or a 
commercially navigable waterway. The Office of Pipeline Safety (OPS) 
will map these areas on the National Pipeline Mapping System (NPMS). An 
operator, member of the public or other government agency may view and 
download the data from the NPMS home page http://www.npms.phmsa.gov/. 
OPS will maintain the NPMS and update it periodically. However, it is an 
operator's responsibility to ensure that it has identified all high 
consequence areas that could be affected by a pipeline segment. An 
operator is also responsible for periodically evaluating its pipeline 
segments to look for population or environmental changes that may have 
occurred around the pipeline and to keep its program current with this 
information. (Refer to Sec.  195.452(d)(3).)

[[Page 712]]

    (1) Digital Data on populated areas available on U.S. Census Bureau 
maps.
    (2) Geographic Database on the commercial navigable waterways 
available on http://www.bts.gov/gis/ntatlas/networks.html.
    (3) The Bureau of Transportation Statistics database that includes 
commercially navigable waterways and non-commercially navigable 
waterways. The database can be downloaded from the BTS website at http:/
/www.bts.gov/gis/ntatlas/networks.html.
    B. The rule requires an operator to include a process in its program 
for identifying which pipeline segments could affect a high consequence 
area and to take measures to prevent and mitigate the consequences of a 
pipeline failure that could affect a high consequence area. (See 
Sec. Sec.  195.452 (f) and (i).) Thus, an operator will need to consider 
how each pipeline segment could affect a high consequence area. The 
primary source for the listed risk factors is a US DOT study on 
instrumented Internal Inspection devices (November 1992). Other sources 
include the National Transportation Safety Board, the Environmental 
Protection Agency and the Technical Hazardous Liquid Pipeline Safety 
Standards Committee. The following list provides guidance to an operator 
on both the mandatory and additional factors:
    (1) Terrain surrounding the pipeline. An operator should consider 
the contour of the land profile and if it could allow the liquid from a 
release to enter a high consequence area. An operator can get this 
information from topographical maps such as U.S. Geological Survey 
quadrangle maps.
    (2) Drainage systems such as small streams and other smaller 
waterways that could serve as a conduit to a high consequence area.
    (3) Crossing of farm tile fields. An operator should consider the 
possibility of a spillage in the field following the drain tile into a 
waterway.
    (4) Crossing of roadways with ditches along the side. The ditches 
could carry a spillage to a waterway.
    (5) The nature and characteristics of the product the pipeline is 
transporting (refined products, crude oils, highly volatile liquids, 
etc.) Highly volatile liquids becomes gaseous when exposed to the 
atmosphere. A spillage could create a vapor cloud that could settle into 
the lower elevation of the ground profile.
    (6) Physical support of the pipeline segment such as by a cable 
suspension bridge. An operator should look for stress indicators on the 
pipeline (strained supports, inadequate support at towers), atmospheric 
corrosion, vandalism, and other obvious signs of improper maintenance.
    (7) Operating conditions of the pipeline (pressure, flow rate, 
etc.). Exposure of the pipeline to an operating pressure exceeding the 
established maximum operating pressure.
    (8) The hydraulic gradient of the pipeline.
    (9) The diameter of the pipeline, the potential release volume, and 
the distance between the isolation points.
    (10) Potential physical pathways between the pipeline and the high 
consequence area.
    (11) Response capability (time to respond, nature of response).
    (12) Potential natural forces inherent in the area (flood zones, 
earthquakes, subsidence areas, etc.)
    II. Risk factors for establishing frequency of assessment.
    A. By assigning weights or values to the risk factors, and using the 
risk indicator tables, an operator can determine the priority for 
assessing pipeline segments, beginning with those segments that are of 
highest risk, that have not previously been assessed. This list provides 
some guidance on some of the risk factors to consider (see Sec.  
195.452(e)). An operator should also develop factors specific to each 
pipeline segment it is assessing, including:
    (1) Populated areas, unusually sensitive environmental areas, 
National Fish Hatcheries, commercially navigable waters, areas where 
people congregate.
    (2) Results from previous testing/inspection. (See Sec.  
195.452(h).)
    (3) Leak History. (See leak history risk table.)
    (4) Known corrosion or condition of pipeline. (See Sec.  
195.452(g).)
    (5) Cathodic protection history.
    (6) Type and quality of pipe coating (disbonded coating results in 
corrosion).
    (7) Age of pipe (older pipe shows more corrosion--may be uncoated or 
have an ineffective coating) and type of pipe seam. (See Age of Pipe 
risk table.)
    (8) Product transported (highly volatile, highly flammable and toxic 
liquids present a greater threat for both people and the environment) 
(see Product transported risk table.)
    (9) Pipe wall thickness (thicker walls give a better safety margin)
    (10) Size of pipe (higher volume release if the pipe ruptures).
    (11) Location related to potential ground movement (e.g., seismic 
faults, rock quarries, and coal mines); climatic (permafrost causes 
settlement--Alaska); geologic (landslides or subsidence).
    (12) Security of throughput (effects on customers if there is 
failure requiring shutdown).
    (13) Time since the last internal inspection/pressure testing.
    (14) With respect to previously discovered defects/anomalies, the 
type, growth rate, and size.
    (15) Operating stress levels in the pipeline.

[[Page 713]]

    (16) Location of the pipeline segment as it relates to the ability 
of the operator to detect and respond to a leak. (e.g., pipelines deep 
underground, or in locations that make leak detection difficult without 
specific sectional monitoring and/or significantly impede access for 
spill response or any other purpose).
    (17) Physical support of the segment such as by a cable suspension 
bridge.
    (18) Non-standard or other than recognized industry practice on 
pipeline installation (e.g., horizontal directional drilling).

    B. Example: This example illustrates a hypothetical model used to 
establish an integrity assessment schedule for a hypothetical pipeline 
segment. After we determine the risk factors applicable to the pipeline 
segment, we then assign values or numbers to each factor, such as, high 
(5), moderate (3), or low (1). We can determine an overall risk 
classification (A, B, C) for the segment using the risk tables and a 
sliding scale (values 5 to 1) for risk factors for which tables are not 
provided. We would classify a segment as C if it fell above \2/3\ of 
maximum value (highest overall risk value for any one segment when 
compared with other segments of a pipeline), a segment as B if it fell 
between \1/3\ to \2/3\ of maximum value, and the remaining segments as 
A.
    i. For the baseline assessment schedule, we would plan to assess 50% 
of all pipeline segments covered by the rule, beginning with the highest 
risk segments, within the first 3\1/2\ years and the remaining segments 
within the seven-year period. For the continuing integrity assessments, 
we would plan to assess the C segments within the first two (2) years of 
the schedule, the segments classified as moderate risk no later than 
year three or four and the remaining lowest risk segments no later than 
year five (5).
    ii. For our hypothetical pipeline segment, we have chosen the 
following risk factors and obtained risk factor values from the 
appropriate table. The values assigned to the risk factors are for 
illustration only.

Age of pipeline: assume 30 years old (refer to ``Age of Pipeline'' risk 
table)--
Risk Value = 5
Pressure tested: tested once during construction--
Risk Value = 5
Coated: (yes/no)--yes
Coating Condition: Recent excavation of suspected areas showed holidays 
in coating (potential corrosion risk)--
Risk Value = 5
Cathodically Protected: (yes/no)--yes--Risk Value = 1
Date cathodic protection installed: five years after pipeline was 
constructed (Cathodic protection installed within one year of the 
pipeline's construction is generally considered low risk.)--Risk Value = 
3
Close interval survey: (yes/no)--no--Risk Value = 5
Internal Inspection tool used: (yes/no)--yes. Date of pig run? In last 
five years--Risk Value = 1
Anomalies found: (yes/no)--yes, but do not pose an immediate safety risk 
or environmental hazard--Risk Value = 3
Leak History: yes, one spill in last 10 years. (refer to ``Leak 
History'' risk table)--Risk Value = 2
Product transported: Diesel fuel. Product low risk. (refer to 
``Product'' risk table)--Risk Value = 1
Pipe size: 16 inches. Size presents moderate risk (refer to ``Line 
Size'' risk table)--Risk Value = 3
    iii. Overall risk value for this hypothetical segment of pipe is 34. 
Assume we have two other pipeline segments for which we conduct similar 
risk rankings. The second pipeline segment has an overall risk value of 
20, and the third segment, 11. For the baseline assessment we would 
establish a schedule where we assess the first segment (highest risk 
segment) within two years, the second segment within five years and the 
third segment within seven years. Similarly, for the continuing 
integrity assessment, we could establish an assessment schedule where we 
assess the highest risk segment no later than the second year, the 
second segment no later than the third year, and the third segment no 
later than the fifth year.
    III. Safety risk indicator tables for leak history, volume or line 
size, age of pipeline, and product transported.

                              Leak History
------------------------------------------------------------------------
                                           Leak history (Time-dependent
          Safety risk indicator                    defects) \1\
------------------------------------------------------------------------
High....................................  3 Spills in last 10
                                           years
Low.....................................  <3 Spills in last 10 years
------------------------------------------------------------------------
\1\ Time-dependent defects are those that result in spills due to
  corrosion, gouges, or problems developed during manufacture,
  construction or operation, etc.


                     Line size or Volume transported
------------------------------------------------------------------------
          Safety risk indicator                      Line size
------------------------------------------------------------------------
High....................................  =18'
Moderate................................  10'--16' nominal diameters
Low.....................................  <=8' nominal diameter
------------------------------------------------------------------------


                             Age of Pipeline
------------------------------------------------------------------------
                                              Age Pipeline condition
          Safety risk indicator                   dependent) \1\
------------------------------------------------------------------------
High....................................  25 years
Low.....................................  <25 years
------------------------------------------------------------------------
\1\ Depends on pipeline's coating & corrosion condition, and steel
  quality, toughness, welding.


[[Page 714]]


                           Product Transported
------------------------------------------------------------------------
      Safety risk indicator       Considerations \1\   Product examples
------------------------------------------------------------------------
High............................  (Highly volatile    (Propane, butane,
                                   and flammable).     Natural Gas
                                                       Liquid (NGL),
                                                       ammonia).
                                  Highly toxic......  (Benzene, high
                                                       Hydrogen Sulfide
                                                       content crude
                                                       oils).
Medium..........................  Flammable--flashpo  (Gasoline, JP4,
                                   int <100F.          low flashpoint
                                                       crude oils).
Low.............................  Non-flammable--     (Diesel, fuel oil,
                                   flashpoint 100 +    kerosene, JP5,
                                   F.                  most crude oils).
------------------------------------------------------------------------
\1\ The degree of acute and chronic toxicity to humans, wildlife, and
  aquatic life; reactivity; and, volatility, flammability, and water
  solubility determine the Product Indicator. Comprehensive
  Environmental Response, Compensation and Liability Act Reportable
  Quantity values may be used as an indication of chronic toxicity.
  National Fire Protection Association health factors may be used for
  rating acute hazards.

    IV. Types of internal inspection tools to use.
    An operator should consider at least two types of internal 
inspection tools for the integrity assessment from the following list. 
The type of tool or tools an operator selects will depend on the results 
from previous internal inspection runs, information analysis and risk 
factors specific to the pipeline segment:
    (1) Geometry Internal inspection tools for detecting changes to 
ovality, e.g., bends, dents, buckles or wrinkles, due to construction 
flaws or soil movement, or other outside force damage;
    (2) Metal Loss Tools (Ultrasonic and Magnetic Flux Leakage) for 
determining pipe wall anomalies, e.g., wall loss due to corrosion.
    (3) Crack Detection Tools for detecting cracks and crack-like 
features, e.g., stress corrosion cracking (SCC), fatigue cracks, narrow 
axial corrosion, toe cracks, hook cracks, etc.
    V. Methods to measure performance.
    A. General. (1) This guidance is to help an operator establish 
measures to evaluate the effectiveness of its integrity management 
program. The performance measures required will depend on the details of 
each integrity management program and will be based on an understanding 
and analysis of the failure mechanisms or threats to integrity of each 
pipeline segment.
    (2) An operator should select a set of measurements to judge how 
well its program is performing. An operator's objectives for its program 
are to ensure public safety, prevent or minimize leaks and spills and 
prevent property and environmental damage. A typical integrity 
management program will be an ongoing program and it may contain many 
elements. Therefore, several performance measure are likely to be needed 
to measure the effectiveness of an ongoing program.
    B. Performance measures. These measures show how a program to 
control risk on pipeline segments that could affect a high consequence 
area is progressing under the integrity management requirements. 
Performance measures generally fall into three categories:
    (1) Selected Activity Measures--Measures that monitor the 
surveillance and preventive activities the operator has implemented. 
These measure indicate how well an operator is implementing the various 
elements of its integrity management program.
    (2) Deterioration Measures--Operation and maintenance trends that 
indicate when the integrity of the system is weakening despite 
preventive measures. This category of performance measure may indicate 
that the system condition is deteriorating despite well executed 
preventive activities.
    (3) Failure Measures--Leak History, incident response, product loss, 
etc. These measures will indicate progress towards fewer spills and less 
damage.
    C. Internal vs. External Comparisons. These comparisons show how a 
pipeline segment that could affect a high consequence area is 
progressing in comparison to the operator's other pipeline segments that 
are not covered by the integrity management requirements and how that 
pipeline segment compares to other operators' pipeline segments.
    (1) Internal--Comparing data from the pipeline segment that could 
affect the high consequence area with data from pipeline segments in 
other areas of the system may indicate the effects from the attention 
given to the high consequence area.
    (2) External--Comparing data external to the pipeline segment (e.g., 
OPS incident data) may provide measures on the frequency and size of 
leaks in relation to other companies.
    D. Examples. Some examples of performance measures an operator could 
use include--
    (1) A performance measurement goal to reduce the total volume from 
unintended releases by -% (percent to be determined by operator) with an 
ultimate goal of zero.
    (2) A performance measurement goal to reduce the total number of 
unintended releases (based on a threshold of 5 gallons) by ____-% 
(percent to be determined by operator) with an ultimate goal of zero.
    (3) A performance measurement goal to document the percentage of 
integrity management activities completed during the calendar year.
    (4) A performance measurement goal to track and evaluate the 
effectiveness of the operator's community outreach activities.
    (5) A narrative description of pipeline system integrity, including 
a summary of performance improvements, both qualitative

[[Page 715]]

and quantitative, to an operator's integrity management program prepared 
periodically.
    (6) A performance measure based on internal audits of the operator's 
pipeline system per 49 CFR Part 195.
    (7) A performance measure based on external audits of the operator's 
pipeline system per 49 CFR Part 195.
    (8) A performance measure based on operational events (for example: 
relief occurrences, unplanned valve closure, SCADA outages, etc.) that 
have the potential to adversely affect pipeline integrity.
    (9) A performance measure to demonstrate that the operator's 
integrity management program reduces risk over time with a focus on high 
risk items.
    (10) A performance measure to demonstrate that the operator's 
integrity management program for pipeline stations and terminals reduces 
risk over time with a focus on high risk items.
    VI. Examples of types of records an operator must maintain.
    The rule requires an operator to maintain certain records. (See 
Sec.  195.452(l)). This section provides examples of some records that 
an operator would have to maintain for inspection to comply with the 
requirement. This is not an exhaustive list.
    (1) a process for identifying which pipelines could affect a high 
consequence area and a document identifying all pipeline segments that 
could affect a high consequence area;
    (2) a plan for baseline assessment of the line pipe that includes 
each required plan element;
    (3) modifications to the baseline plan and reasons for the 
modification;
    (4) use of and support for an alternative practice;
    (5) a framework addressing each required element of the integrity 
management program, updates and changes to the initial framework and 
eventual program;
    (6) a process for identifying a new high consequence area and 
incorporating it into the baseline plan, particularly, a process for 
identifying population changes around a pipeline segment;
    (7) an explanation of methods selected to assess the integrity of 
line pipe;
    (8) a process for review of integrity assessment results and data 
analysis by a person qualified to evaluate the results and data;
    (9) the process and risk factors for determining the baseline 
assessment interval;
    (10) results of the baseline integrity assessment;
    (11) the process used for continual evaluation, and risk factors 
used for determining the frequency of evaluation;
    (12) process for integrating and analyzing information about the 
integrity of a pipeline, information and data used for the information 
analysis;
    (13) results of the information analyses and periodic evaluations;
    (14) the process and risk factors for establishing continual re-
assessment intervals;
    (15) justification to support any variance from the required re-
assessment intervals;
    (16) integrity assessment results and anomalies found, process for 
evaluating and remediating anomalies, criteria for remedial actions and 
actions taken to evaluate and remediate the anomalies;
    (17) other remedial actions planned or taken;
    (18) schedule for evaluation and remediation of anomalies, 
justification to support deviation from required remediation times;
    (19) risk analysis used to identify additional preventive or 
mitigative measures, records of preventive and mitigative actions 
planned or taken;
    (20) criteria for determining EFRD installation;
    (21) criteria for evaluating and modifying leak detection 
capability;
    (22) methods used to measure the program's effectiveness.
    VII. Conditions that may impair a pipeline's integrity.
    Section 195.452(h) requires an operator to evaluate and remediate 
all pipeline integrity issues raised by the integrity assessment or 
information analysis. An operator must develop a schedule that 
prioritizes conditions discovered on the pipeline for evaluation and 
remediation. The following are some examples of conditions that an 
operator should schedule for evaluation and remediation.
    A. Any change since the previous assessment.
    B. Mechanical damage that is located on the top side of the pipe.
    C. An anomaly abrupt in nature.
    D. An anomaly longitudinal in orientation.
    E. An anomaly over a large area.
    F. An anomaly located in or near a casing, a crossing of another 
pipeline, or an area with suspect cathodic protection.

[Amdt. 195-70, 65 FR 75409, Dec. 1, 2000, as amended by Amdt. 195-74, 67 
FR 1661, Jan. 14, 2002; Amdt. 195-94, 75 FR 48608, Aug. 11, 2010]



PART 196_PROTECTION OF UNDERGROUND PIPELINES FROM EXCAVATION ACTIVITY--Table   
                               of Contents



                            Subpart A_General

196.1 What is the purpose and scope of this part?
196.3 Definitions.

                Subpart B_Damage Prevention Requirements

196.101 What is the purpose and scope of this subpart?

[[Page 716]]

196.103 What must an excavator do to protect underground pipelines from 
          excavation-related damage?
196.105 [Reserved]
196.107 What must an excavator do if a pipeline is damaged by excavation 
          activity?
196.109 What must an excavator do if damage to a pipeline from 
          excavation activity causes a leak where product is released 
          from the pipeline?
196.111 What if a pipeline operator fails to respond to a locate request 
          or fails to accurately locate and mark its pipeline?

              Subpart C_Administrative Enforcement Process

196.201 What is the purpose and scope of this subpart?
196.203 What is the administrative process PHMSA will use to conduct 
          enforcement proceedings for alleged violations of excavation 
          damage prevention requirements?
196.205 Can PHMSA assess administrative civil penalties for violations?
196.207 What are the maximum administrative civil penalties for 
          violations?
196.209 May other civil enforcement actions be taken?
196.211 May criminal penalties be imposed?

    Authority: 49 U.S.C. 60101 et seq.; and 49 CFR 1.97.

    Source: 80 FR 43866, July 23, 2015, unless otherwise noted.



                            Subpart A_General



Sec.  196.1  What is the purpose and scope of this part?

    This part prescribes the minimum requirements that excavators must 
follow to protect underground pipelines from excavation-related damage. 
It also establishes an enforcement process for violations of these 
requirements.



Sec.  196.3  Definitions.

    Damage or excavation damage means any excavation activity that 
results in the need to repair or replace a pipeline due to a weakening, 
or the partial or complete destruction, of the pipeline, including, but 
not limited to, the pipe, appurtenances to the pipe, protective 
coatings, support, cathodic protection or the housing for the line 
device or facility.
    Excavation refers to excavation activities as defined in Sec.  
192.614, and covers all excavation activity involving both mechanized 
and non-mechanized equipment, including hand tools.
    Excavator means any person or legal entity, public or private, 
proposing to or engaging in excavation.
    One-call means a notification system through which a person can 
notify pipeline operators of planned excavation to facilitate the 
locating and marking of any pipelines in the excavation area.
    Pipeline means all parts of those physical facilities through which 
gas, carbon dioxide, or a hazardous liquid moves in transportation, 
including, but not limited to, pipe, valves, and other appurtenances 
attached or connected to pipe (including, but not limited to, tracer 
wire, radio frequency identification or other electronic marking system 
devices), pumping units, compressor units, metering stations, regulator 
stations, delivery stations, holders, fabricated assemblies, and 
breakout tanks.



                Subpart B_Damage Prevention Requirements



Sec.  196.101  What is the purpose and scope of this subpart?

    This subpart prescribes the minimum requirements that excavators 
must follow to protect pipelines subject to PHMSA or State pipeline 
safety regulations from excavation-related damage.



Sec.  196.103  What must an excavator do to protect underground pipelines  
from excavation-related damage?

    Prior to and during excavation activity, the excavator must:
    (a) Use an available one-call system before excavating to notify 
operators of underground pipeline facilities of the timing and location 
of the intended excavation;
    (b) If underground pipelines exist in the area, wait for the 
pipeline operator to arrive at the excavation site and establish and 
mark the location of its underground pipeline facilities before 
excavating;
    (c) Excavate with proper regard for the marked location of pipelines 
an operator has established by taking all practicable steps to prevent 
excavation damage to the pipeline;

[[Page 717]]

    (d) Make additional use of one-call as necessary to obtain locating 
and marking before excavating to ensure that underground pipelines are 
not damaged by excavation.



Sec.  196.105  [Reserved]



Sec.  196.107  What must an excavator do if a pipeline is damaged by  
excavation activity?

    If a pipeline is damaged in any way by excavation activity, the 
excavator must promptly report such damage to the pipeline operator, 
whether or not a leak occurs, at the earliest practicable moment 
following discovery of the damage.



Sec.  196.109  What must an excavator do if damage to a pipeline from 
excavation activity causes a leak where product is released from the 
pipeline?

    If damage to a pipeline from excavation activity causes the release 
of any PHMSA regulated natural and other gas or hazardous liquid as 
defined in part 192, 193, or 195 of this chapter from the pipeline, the 
excavator must promptly report the release to appropriate emergency 
response authorities by calling the 911 emergency telephone number.



Sec.  196.111  What if a pipeline operator fails to respond to a locate 
request or fails to accurately locate and mark its pipeline?

    PHMSA may enforce existing requirements applicable to pipeline 
operators, including those specified in 49 CFR 192.614 and 195.442 and 
49 U.S.C. 60114 if a pipeline operator fails to properly respond to a 
locate request or fails to accurately locate and mark its pipeline. The 
limitation in 49 U.S.C. 60114(f) does not apply to enforcement taken 
against pipeline operators and excavators working for pipeline 
operators.



              Subpart C_Administrative Enforcement Process



Sec.  196.201  What is the purpose and scope of this subpart?

    This subpart describes the enforcement authority and sanctions 
exercised by the Associate Administrator for Pipeline Safety for 
achieving and maintaining pipeline safety under this part. It also 
prescribes the procedures governing the exercise of that authority and 
the imposition of those sanctions.



Sec.  196.203  What is the administrative process PHMSA will use to conduct
enforcement proceedings for alleged violations of excavation damage prevention   
requirements?

    PHMSA will use the existing administrative adjudication process for 
alleged pipeline safety violations set forth in 49 CFR part 190, subpart 
B. This process provides for notification that a probable violation has 
been committed, a 30-day period to respond including the opportunity to 
request an administrative hearing, the issuance of a final order, and 
the opportunity to petition for reconsideration.



Sec.  196.205  Can PHMSA assess administrative civil penalties for 
violations?

    Yes. When the Associate Administrator for Pipeline Safety has reason 
to believe that a person has violated any provision of the 49 U.S.C. 
60101 et seq. or any regulation or order issued thereunder, including a 
violation of excavation damage prevention requirements under this part 
and 49 U.S.C. 60114(d) in a State with an excavation damage prevention 
law enforcement program PHMSA has deemed inadequate under 49 CFR part 
198, subpart D, PHMSA may conduct a proceeding to determine the nature 
and extent of the violation and to assess a civil penalty.



Sec.  196.207  What are the maximum administrative civil penalties for 
violations?

    The maximum administrative civil penalties that may be imposed are 
specified in 49 U.S.C. 60122.



Sec.  196.209  May other civil enforcement actions be taken?

    Whenever the Associate Administrator has reason to believe that a 
person has engaged, is engaged, or is about to engage in any act or 
practice constituting a violation of any provision of 49 U.S.C. 60101 et 
seq., or any regulations

[[Page 718]]

issued thereunder, PHMSA, or the person to whom the authority has been 
delegated, may request the Attorney General to bring an action in the 
appropriate U.S. District Court for such relief as is necessary or 
appropriate, including mandatory or prohibitive injunctive relief, 
interim equitable relief, civil penalties, and punitive damages as 
provided under 49 U.S.C. 60120.



Sec.  196.211  May criminal penalties be imposed?

    Yes. Criminal penalties may be imposed as specified in 49 U.S.C. 
60123.

                           PART 197 [RESERVED]



PART 198_REGULATIONS FOR GRANTS TO AID STATE PIPELINE SAFETY   
PROGRAMS--Table of Contents



                            Subpart A_General

Sec.
198.1 Scope.
198.3 Definitions.

                       Subpart B_Grant Allocation

198.11 Grant authority.
198.13 Grant allocation formula.

        Subpart C_Adoption of One-Call Damage Prevention Program

198.31 Scope.
198.33 [Reserved]
198.35 Grants conditioned on adoption of one-call damage prevention 
          program.
198.37 State one-call damage prevention program.
198.39 Qualifications for operation of one-call notification system.

         Subpart D_State Damage Prevention Enforcement Programs

198.51 What is the purpose and scope of this subpart?
198.53 When and how will PHMSA evaluate State damage prevention 
          enforcement programs?
198.55 What criteria will PHMSA use in evaluating the effectiveness of 
          State damage prevention enforcement programs?
198.57 What is the process PHMSA will use to notify a State that its 
          damage prevention enforcement program appears to be 
          inadequate?
198.59 How may a State respond to a notice of inadequacy?
198.61 How is a State notified of PHMSA's final decision?
198.63 How may a State with an inadequate damage prevention enforcement 
          program seek reconsideration by PHMSA?

    Authority: 49 U.S.C. 60101 et seq.; 49 CFR 1.97.

    Source: 55 FR 38691, Sept. 20, 1990, unless otherwise noted.



                            Subpart A_General



Sec.  198.1  Scope.

    This part prescribes regulations governing grants-in-aid for State 
pipeline safety compliance programs.



Sec.  198.3  Definitions.

    As used in this part:
    Administrator means the Administrator, Pipeline and Hazardous 
Materials Safety Administration or his or her delegate.
    Adopt means establish under State law by statute, regulation, 
license, certification, order, or any combination of these legal means.
    Excavation activity means an excavation activity defined in Sec.  
192.614(a) of this chapter, other than a specific activity the State 
determines would not be expected to cause physical damage to underground 
facilities.
    Excavator means any person intending to engage in an excavation 
activity.
    One-call notification system means a communication system that 
qualifies under this part and the one-call damage prevention program of 
the State concerned in which an operational center receives notices from 
excavators of intended excavation activities and transmits the notices 
to operators of underground pipeline facilities and other underground 
facilities that participate in the system.
    Person means any individual, firm, joint venture, partnership, 
corporation, association, state, municipality, cooperative association, 
or joint stock association, and including any trustee, receiver, 
assignee, or personal representative thereof.
    Underground pipeline facilities means buried pipeline facilities 
used in the transportation of gas or hazardous liquid subject to the 
pipeline safety laws (49 U.S.C. 60101 et seq.).

[[Page 719]]

    Secretary means the Secretary of Transportation or any person to 
whom the Secretary of Transportation has delegated authority in the 
matter concerned.
    Seeking to adopt means actively and effectively proceeding toward 
adoption.
    State means each of the several States, the District of Columbia, 
and the Commonwealth of Puerto Rico.

[55 FR 38691, Sept. 20, 1990, as amended by Amdt. 198-2, 61 FR 18518, 
Apr. 26, 1996; 68 FR 11750, Mar. 12, 2003; 70 FR 11140, Mar. 8, 2005]



                       Subpart B_Grant Allocation

    Source: Amdt. 198-1, 58 FR 10988, Feb. 23, 1993, unless otherwise 
noted.



Sec.  198.11  Grant authority.

    The pipeline safety laws (49 U.S.C. 60101 et seq.) authorize the 
Administrator to pay out funds appropriated or otherwise make available 
up to 80 percent of the cost of the personnel, equipment, and activities 
reasonably required for each state agency to carry out a safety program 
for intrastate pipeline facilities under a certification or agreement 
with the Administrator or to act as an agent of the Administrator with 
respect to interstate pipeline facilities.

[Amdt. 198-5, 74 FR 62506, Nov. 30, 2009]



Sec.  198.13  Grant allocation formula.

    (a) Beginning in calendar year 1993, the Administrator places 
increasing emphasis on program performance in allocating state agency 
funds under Sec.  198.11. The maximum percent of each state agency 
allocation that is based on performance follows: 1993--75 percent; 1994 
and subsequent years--100 percent.
    (b) A state's annual grant allocation is based on maximum of 100 
performance points derived as follows:
    (1) Fifty points based on information provided in the state's annual 
certification/agreement attachments which document its activities for 
the past year; and
    (2) Fifty points based on the annual state program evaluation.
    (c) The Administrator assigns weights to various performance factors 
reflecting program compliance, safety priorities, and national concerns 
identified by the Administrator and communicated to each State agency. 
At a minimum, the Administrator considers the following performance 
factors in allocating funds:
    (1) Adequacy of state operating practices;
    (2) Quality of state inspections, investigations, and enforcement/
compliance actions;
    (3) Adequacy of state recordkeeping;
    (4) Extent of state safety regulatory jurisdiction over pipeline 
facilities;
    (5) Qualifications of state inspectors;
    (6) Number of state inspection person-days;
    (7) State adoption of applicable federal pipeline safety standards; 
and
    (8) Any other factor the Administrator deems necessary to measure 
performance.
    (d) Notwithstanding these performance factors, the Administrator 
may, in 1993 and subsequent years, continue funding any state at the 
1991 level, provided its request is at the 1991 level or higher and 
appropriated funds are at the 1991 level or higher.
    (e) The Administrator notifies each state agency in writing of the 
specific performance factors to be used and the weights to be assigned 
to each factor at least 9 months prior to allocating funds. Prior to 
notification, PHMSA seeks state agency comments on any proposed changes 
to the allocation formula.
    (f) Grants are limited to the appropriated funds available. If total 
state agency requests for grants exceed the funds available, the 
Administrator prorates each state agency's allocation.

[Amdt. 198-1, 58 FR 10988, Feb. 23, 1993, as amended at 70 FR 11140, 
Mar. 8, 2005]



        Subpart C_Adoption of One-Call Damage Prevention Program



Sec.  198.31  Scope.

    This subpart implements parts of the pipeline safety laws (49 U.S.C. 
60101 et seq.), which direct the Secretary to require each State to 
adopt a one-call damage prevention program as a condition to receiving a 
full grant-in-aid for its pipeline safety compliance program.

[Amdt. 198-2, 61 FR 18518, Apr. 26, 1996]

[[Page 720]]



Sec.  198.33  [Reserved]



Sec.  198.35  Grants conditioned on adoption of one-call damage prevention 
program.

    In allocating grants to State agencies under the pipeline safety 
laws, (49 U.S.C. 60101 et seq.), the Secretary considers whether a State 
has adopted or is seeking to adopt a one-call damage prevention program 
in accordance with Sec.  198.37. If a State has not adopted or is not 
seeking to adopt such program, the State agency may not receive the full 
reimbursement to which it would otherwise be entitled.

[Amdt. 198-2, 61 FR 38403, July 24, 1996]



Sec.  198.37  State one-call damage prevention program.

    A State must adopt a one-call damage prevention program that 
requires each of the following at a minimum:
    (a) Each area of the State that contains underground pipeline 
facilities must be covered by a one-call notification system.
    (b) Each one-call notification system must be operated in accordance 
with Sec.  198.39.
    (c) Excavators must be required to notify the operational center of 
the one-call notification system that covers the area of each intended 
excavation activity and provide the following information:
    (1) Name of the person notifying the system.
    (2) Name, address and telephone number of the excavator.
    (3) Specific location, starting date, and description of the 
intended excavation activity.

However, an excavator must be allowed to begin an excavation activity in 
an emergency but, in doing so, required to notify the operational center 
at the earliest practicable moment.
    (d) The State must determine whether telephonic and other 
communications to the operational center of a one-call notification 
system under paragraph (c) of this section are to be toll free or not.
    (e) Except with respect to interstate transmission facilities as 
defined in the pipeline safety laws (49 U.S.C. 60101 et seq.), operators 
of underground pipeline facilities must be required to participate in 
the one-call notification systems that cover the areas of the State in 
which those pipeline facilities are located.
    (f) Operators of underground pipeline facilities participating in 
the one-call notification systems must be required to respond in the 
manner prescribed by Sec.  192.614 (c)(4) through (c)(6) of this chapter 
to notices of intended excavation activity received from the operational 
center of a one-call notification system.
    (g) Persons who operate one-call notification systems or operators 
of underground pipeline facilities participating or required to 
participate in the one-call notification systems must be required to 
notify the public and known excavators in the manner prescribed by Sec.  
192.614 (b)(1) and (b)(2) of this chapter of the availability and use of 
one-call notification systems to locate underground pipeline facilities. 
However, this paragraph does not apply to persons (including operator's 
master meters) whose primary activity does not include the production, 
transportation or marketing of gas or hazardous liquids.
    (h) Operators of underground pipeline facilities (other than 
operators of interstate transmission facilities as defined in the 
pipeline safety laws (49 U.S.C. 60101 et seq.), and interstate pipelines 
as defined in Sec.  195.2 of this chapter), excavators and persons who 
operate one-call notification systems who violate the applicable 
requirements of this subpart must be subject to civil penalties and 
injunctive relief that are substantially the same as are provided under 
the pipeline safety laws (49 U.S.C. 60101 et seq.).

[55 FR 38691, Sept. 20, 1990, as amended by Amdt. 198-2, 61 FR 18518, 
Apr. 26, 1996; Amdt. 198-6, 80 FR 188, Jan. 5, 2015]



Sec.  198.39  Qualifications for operation of one-call notification system.

    A one-call notification system qualifies to operate under this 
subpart if it complies with the following:
    (a) It is operated by one or more of the following:
    (1) A person who operates underground pipeline facilities or other 
underground facilities.
    (2) A private contractor.

[[Page 721]]

    (3) A State or local government agency.
    (4) A person who is otherwise eligible under State law to operate a 
one-call notification system.
    (b) It receives and records information from excavators about 
intended excavation activities.
    (c) It promptly transmits to the appropriate operators of 
underground pipeline facilities the information received from excavators 
about intended excavation activities.
    (d) It maintains a record of each notice of intent to engage in an 
excavation activity for the minimum time set by the State or, in the 
absence of such time, for the time specified in the applicable State 
statute of limitations on tort actions.
    (e) It tells persons giving notice of an intent to engage in an 
excavation activity the names of participating operators of underground 
pipeline facilities to whom the notice will be transmitted.



         Subpart D_State Damage Prevention Enforcement Programs

    Source: 80 FR 43868, July 23, 2015, unless otherwise noted.



Sec.  198.51  What is the purpose and scope of this subpart?

    This subpart establishes standards for effective State damage 
prevention enforcement programs and prescribes the administrative 
procedures available to a State that elects to contest a notice of 
inadequacy.



Sec.  198.53  When and how will PHMSA evaluate State damage prevention 
enforcement programs?

    PHMSA conducts annual program evaluations and certification reviews 
of State pipeline safety programs. PHMSA will also conduct annual 
reviews of State excavation damage prevention law enforcement programs. 
PHMSA will use the criteria described in Sec.  198.55 as the basis for 
the enforcement program reviews, utilizing information obtained from any 
State agency or office with a role in the State's excavation damage 
prevention law enforcement program. If PHMSA finds a State's enforcement 
program inadequate, PHMSA may take immediate enforcement against 
excavators in that State. The State will have five years from the date 
of the finding to make program improvements that meet PHMSA's criteria 
for minimum adequacy. A State that fails to establish an adequate 
enforcement program in accordance with Sec.  198.55 within five years of 
the finding of inadequacy may be subject to reduced grant funding 
established under 49 U.S.C. 60107. PHMSA will determine the amount of 
the reduction using the same process it uses to distribute the grant 
funding; PHMSA will factor the findings from the annual review of the 
excavation damage prevention enforcement program into the 49 U.S.C. 
60107 grant funding distribution to State pipeline safety programs. The 
amount of the reduction in 49 U.S.C. 60107 grant funding will not exceed 
four percent (4%) of prior year funding (not cumulative). If a State 
fails to implement an adequate enforcement program within five years of 
a finding of inadequacy, the Governor of that State may petition the 
Administrator of PHMSA, in writing, for a temporary waiver of the 
penalty, provided the petition includes a clear plan of action and 
timeline for achieving program adequacy.



Sec.  198.55  What criteria will PHMSA use in evaluating the effectiveness 
of State damage prevention enforcement programs?

    (a) PHMSA will use the following criteria to evaluate the 
effectiveness of a State excavation damage prevention enforcement 
program:
    (1) Does the State have the authority to enforce its State 
excavation damage prevention law using civil penalties and other 
appropriate sanctions for violations?
    (2) Has the State designated a State agency or other body as the 
authority responsible for enforcement of the State excavation damage 
prevention law?
    (3) Is the State assessing civil penalties and other appropriate 
sanctions for violations at levels sufficient to deter noncompliance and 
is the State making publicly available information that demonstrates the 
effectiveness of the State's enforcement program?

[[Page 722]]

    (4) Does the enforcement authority (if one exists) have a reliable 
mechanism (e.g., mandatory reporting, complaint-driven reporting) for 
learning about excavation damage to underground facilities?
    (5) Does the State employ excavation damage investigation practices 
that are adequate to determine the responsible party or parties when 
excavation damage to underground facilities occurs?
    (6) At a minimum, do the State's excavation damage prevention 
requirements include the following:
    (i) Excavators may not engage in excavation activity without first 
using an available one-call notification system to establish the 
location of underground facilities in the excavation area.
    (ii) Excavators may not engage in excavation activity in disregard 
of the marked location of a pipeline facility as established by a 
pipeline operator.
    (iii) An excavator who causes damage to a pipeline facility:
    (A) Must report the damage to the operator of the facility at the 
earliest practical moment following discovery of the damage; and
    (B) If the damage results in the escape of any PHMSA regulated 
natural and other gas or hazardous liquid, must promptly report to other 
appropriate authorities by calling the 911 emergency telephone number or 
another emergency telephone number.
    (7) Does the State limit exemptions for excavators from its 
excavation damage prevention law? A State must provide to PHMSA a 
written justification for any exemptions for excavators from State 
damage prevention requirements. PHMSA will make the written 
justifications available to the public.
    (b) PHMSA may consider individual enforcement actions taken by a 
State in evaluating the effectiveness of a State's damage prevention 
enforcement program.



Sec.  198.57  What is the process PHMSA will use to notify a State that 
its damage prevention enforcement program appears to be inadequate?

    PHMSA will issue a notice of inadequacy to the State in accordance 
with 49 CFR 190.5. The notice will state the basis for PHMSA's 
determination that the State's damage prevention enforcement program 
appears inadequate for purposes of this subpart and set forth the 
State's response options.



Sec.  198.59  How may a State respond to a notice of inadequacy?

    A State receiving a notice of inadequacy will have 30 days from 
receipt of the notice to submit a written response to the PHMSA official 
who issued the notice. In its response, the State may include 
information and explanations concerning the alleged inadequacy or 
contest the allegation of inadequacy and request the notice be 
withdrawn.



Sec.  198.61  How is a State notified of PHMSA's final decision?

    PHMSA will issue a final decision on whether the State's damage 
prevention enforcement program has been found inadequate in accordance 
with 49 CFR 190.5.



Sec.  198.63  How may a State with an inadequate damage prevention 
enforcement program seek reconsideration by PHMSA?

    At any time following a finding of inadequacy, the State may 
petition PHMSA to reconsider such finding based on changed circumstances 
including improvements in the State's enforcement program. Upon 
receiving a petition, PHMSA will reconsider its finding of inadequacy 
promptly and will notify the State of its decision on reconsideration 
promptly but no later than the time of the next annual certification 
review.



PART 199_DRUG AND ALCOHOL TESTING--Table of Contents



                            Subpart A_General

Sec.
199.1 Scope.
199.2 Applicability.
199.3 Definitions.
199.5 DOT procedures.
199.7 Stand-down waivers.
199.9 Preemption of State and local laws.

                         Subpart B_Drug Testing

199.100 Purpose.
199.101 Anti-drug plan.

[[Page 723]]

199.103 Use of persons who fail or refuse a drug test.
199.105 Drug tests required.
199.107 Drug testing laboratory.
199.109 Review of drug testing results.
199.111 [Reserved]
199.113 Employee assistance program.
199.115 Contractor employees.
199.117 Recordkeeping.
199.119 Reporting of anti-drug testing results.

               Subpart C_Alcohol Misuse Prevention Program

199.200 Purpose.
199.201 [Reserved]
199.202 Alcohol misuse plan.
199.203-199.205 [Reserved]
199.209 Other requirements imposed by operators.
199.211 Requirement for notice.
199.213 [Reserved]
199.215 Alcohol concentration.
199.217 On-duty use.
199.219 Pre-duty use.
199.221 Use following an accident.
199.223 Refusal to submit to a required alcohol test.
199.225 Alcohol tests required.
199.227 Retention of records.
199.229 Reporting of alcohol testing results.
199.231 Access to facilities and records.
199.233 Removal from covered function.
199.235 Required evaluation and testing.
199.237 Other alcohol-related conduct.
199.239 Operator obligation to promulgate a policy on the misuse of 
          alcohol.
199.241 Training for supervisors.
199.243 Referral, evaluation, and treatment.
199.245 Contractor employees.

    Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60117, and 60118; 49 
CFR 1.53.

    Source: 53 FR 47096, Nov. 21, 1988, unless otherwise noted.



                            Subpart A_General



Sec.  199.1  Scope.

    This part requires operators of pipeline facilities subject to part 
192, 193, or 195 of this chapter to test covered employees for the 
presence of prohibited drugs and alcohol.

[Amdt. 199-19, 66 FR 47117, Sept. 11, 2001]



Sec.  199.2  Applicability.

    (a) This part applies to pipeline operators only with respect to 
employees located within the territory of the United States, including 
those employees located within the limits of the ``Outer Continental 
Shelf `` as that term is defined in the Outer Continental Shelf Lands 
Act (43 U.S.C. 1331).
    (b) This part does not apply to any person for whom compliance with 
this part would violate the domestic laws or policies of another 
country.
    (c) This part does not apply to covered functions performed on--
    (1) Master meter systems, as defined in Sec.  191.3 of this chapter; 
or
    (2) Pipeline systems that transport only petroleum gas or petroleum 
gas/air mixtures.

[Amdt. 199-19, 66 FR 47117, Sept. 11, 2001]



Sec.  199.3  Definitions.

    As used in this part--
    Accident means an incident reportable under part 191 of this chapter 
involving gas pipeline facilities or LNG facilities, or an accident 
reportable under part 195 of this chapter involving hazardous liquid 
pipeline facilities.
    Administrator means the Administrator, Pipeline and Hazardous 
Materials Safety Administration or his or her delegate.
    Covered employee, employee, or individual to be tested means a 
person who performs a covered function, including persons employed by 
operators, contractors engaged by operators, and persons employed by 
such contractors.
    Covered function means an operations, maintenance, or emergency-
response function regulated by part 192, 193, or 195 of this chapter 
that is performed on a pipeline or on an LNG facility.
    DOT Procedures means the Procedures for Transportation Workplace 
Drug and Alcohol Testing Programs published by the Office of the 
Secretary of Transportation in part 40 of this title.
    Fail a drug test means that the confirmation test result shows 
positive evidence of the presence under DOT Procedures of a prohibited 
drug in an employee's system.
    Operator means a person who owns or operates pipeline facilities 
subject to part 192, 193, or 195 of this chapter.
    Pass a drug test means that initial testing or confirmation testing 
under DOT Procedures does not show evidence of the presence of a 
prohibited drug in a person's system.
    Performs a covered function includes actually performing, ready to 
perform,

[[Page 724]]

or immediately available to perform a covered function.
    Positive rate for random drug testing means the number of verified 
positive results for random drug tests conducted under this part plus 
the number of refusals of random drug tests required by this part, 
divided by the total number of random drug tests results (i.e., 
positives, negatives, and refusals) under this part.
    Prohibited drug means any of the substances specified in 49 CFR part 
40.
    Refuse to submit, refuse, or refuse to take means behavior 
consistent with DOT Procedures concerning refusal to take a drug test or 
refusal to take an alcohol test.
    State agency means an agency of any of the several states, the 
District of Columbia, or Puerto Rico that participates under the 
pipeline safety laws (49 U.S.C. 60101 et seq.)

[53 FR 47096, Nov. 21, 1988, as amended by Amdt. 199-2, 54 FR 51850, 
Dec. 18, 1989; 59 FR 62227, Dec. 2, 1994; Amdt. 199-13, 61 FR 18518, 
Apr. 26, 1996; Amdt. 199-15, 63 FR 13000, Mar. 17, 1998; Amdt. 199-19, 
66 FR 47117, Sept. 11, 2001; 68 FR 11750, Mar. 12, 2003; 68 FR 75465, 
Dec. 31, 2003; 70 FR 11140, Mar. 8, 2005; 84 FR 16775, Apr. 23, 2019]



Sec.  199.5  DOT procedures.

    The anti-drug and alcohol programs required by this part must be 
conducted according to the requirements of this part and DOT Procedures. 
Terms and concepts used in this part have the same meaning as in DOT 
Procedures. Violations of DOT Procedures with respect to anti-drug and 
alcohol programs required by this part are violations of this part.

[Amdt. 199-19, 66 FR 47118, Sept. 11, 2001]



Sec.  199.7  Stand-down waivers.

    (a) Each operator who seeks a waiver under Sec.  40.21 of this title 
from the stand-down restriction must submit an application for waiver in 
duplicate to the Associate Administrator for Pipeline Safety, Pipeline 
and Hazardous Materials Safety Administration, U.S. Department of 
Transportation, 1200 New Jersey Avenue, SE, Washington, DC 20590-0001.
    (b) Each application must--
    (1) Identify Sec.  40.21 of this title as the rule from which the 
waiver is sought;
    (2) Explain why the waiver is requested and describe the employees 
to be covered by the waiver;
    (3) Contain the information required by Sec.  40.21 of this title 
and any other information or arguments available to support the waiver 
requested; and
    (4) Unless good cause is shown in the application, be submitted at 
least 60 days before the proposed effective date of the waiver.
    (c) No public hearing or other proceeding is held directly on an 
application before its disposition under this section. If the Associate 
Administrator determines that the application contains adequate 
justification, he or she grants the waiver. If the Associate 
Administrator determines that the application does not justify granting 
the waiver, he or she denies the application. The Associate 
Administrator notifies each applicant of the decision to grant or deny 
an application.

[Amdt. 199-19, 66 FR 47118, Sept. 11, 2001, as amended at 70 FR 11140, 
Mar. 8, 2005; 74 FR 2894, Jan. 16, 2009]



Sec.  199.9  Preemption of State and local laws.

    (a) Except as provided in paragraph (b) of this section, this part 
preempts any State or local law, rule, regulation, or order to the 
extent that:
    (1) Compliance with both the State or local requirement and this 
part is not possible;
    (2) Compliance with the State or local requirement is an obstacle to 
the accomplishment and execution of any requirement in this part; or
    (3) The State or local requirement is a pipeline safety standard 
applicable to interstate pipeline facilities.
    (b) This part shall not be construed to preempt provisions of State 
criminal law that impose sanctions for reckless conduct leading to 
actual loss of life, injury, or damage to property, whether the 
provisions apply specifically to transportation employees or employers 
or to the general public.

[Amdt. 199-9, 59 FR 7430, Feb. 15, 1994. Redesignated and amended by 
Amdt. 199-19, 66 FR 47119, Sept. 11, 2001]

[[Page 725]]



                         Subpart B_Drug Testing



Sec.  199.100  Purpose.

    The purpose of this subpart is to establish programs designed to 
help prevent accidents and injuries resulting from the use of prohibited 
drugs by employees who perform covered functions for operators of 
certain pipeline facilities subject to part 192, 193, or 195 of this 
chapter.

[Amdt. 199-19, 66 FR 47118, Sept. 11, 2001]



Sec.  199.101  Anti-drug plan.

    (a) Each operator shall maintain and follow a written anti-drug plan 
that conforms to the requirements of this part and the DOT Procedures. 
The plan must contain--
    (1) Methods and procedures for compliance with all the requirements 
of this part, including the employee assistance program;
    (2) The name and address of each laboratory that analyzes the 
specimens collected for drug testing;
    (3) The name and address of the operator's Medical Review Officer, 
and Substance Abuse Professional; and
    (4) Procedures for notifying employees of the coverage and 
provisions of the plan.
    (b) The Associate Administrator or the State Agency that has 
submitted a current certification under the pipeline safety laws (49 
U.S.C. 60101 et seq.) with respect to the pipeline facility governed by 
an operator's plans and procedures may, after notice and opportunity for 
hearing as provided in 49 CFR 190.206 or the relevant State procedures, 
require the operator to amend its plans and procedures as necessary to 
provide a reasonable level of safety.

[53 FR 47096, Nov. 21, 1988, as amended by Amdt. 199-2, 54 FR 51850, 
Dec. 18, 1989; Amdt. 199-4, 56 FR 31091, July 9, 1991; 56 FR 41077, Aug. 
19, 1991; Amdt. 199-13, 61 FR 18518, Apr. 26, 1996; Amdt. 199-15, 63 FR 
36863, July 8, 1998. Redesignated by Amdt. 199-19, 66 FR 47118, Sept. 
11, 2001; Amdt. 199-25, 78 FR 58915, Sept. 25, 2013]



Sec.  199.103  Use of persons who fail or refuse a drug test.

    (a) An operator may not knowingly use as an employee any person 
who--
    (1) Fails a drug test required by this part and the medical review 
officer makes a determination under DOT Procedures; or
    (2) Refuses to take a drug test required by this part.
    (b) Paragraph (a)(1) of this section does not apply to a person who 
has--
    (1) Passed a drug test under DOT Procedures;
    (2) Been considered by the medical review officer in accordance with 
DOT Procedures and been determined by a substance abuse professional to 
have successfully completed required education or treatment; and
    (3) Not failed a drug test required by this part after returning to 
duty.

[53 FR 47096, Nov. 21, 1988, as amended by Amdt. 199-2, 54 FR 51850, 
Dec. 18, 1989. Redesignated and amended by Amdt. 199-19, 66 FR 47118, 
Sept. 11, 2001]



Sec.  199.105  Drug tests required.

    Each operator shall conduct the following drug tests for the 
presence of a prohibited drug:
    (a) Pre-employment testing. No operator may hire or contract for the 
use of any person as an employee unless that person passes a drug test 
or is covered by an anti-drug program that conforms to the requirements 
of this part.
    (b) Post-accident testing. (1) As soon as possible but no later than 
32 hours after an accident, an operator must drug test each surviving 
covered employee whose performance of a covered function either 
contributed to the accident or cannot be completely discounted as a 
contributing factor to the accident. An operator may decide not to test 
under this paragraph but such a decision must be based on specific 
information that the covered employee's performance had no role in the 
cause(s) or severity of the accident.
    (2) If a test required by this section is not administered within 
the 32 hours following the accident, the operator must prepare and 
maintain its decision stating the reasons why the test was not promptly 
administered. If a test required by paragraph (b)(1) of this section is 
not administered within 32 hours following the accident, the operator 
must cease attempts to administer a drug test and must state in the 
record the reasons for not administering the test.

[[Page 726]]

    (c) Random testing. (1) Except as provided in paragraphs (c)(2) 
through (4) of this section, the minimum annual percentage rate for 
random drug testing shall be 50 percent of covered employees.
    (2) The Administrator's decision to increase or decrease the minimum 
annual percentage rate for random drug testing is based on the reported 
positive rate for the entire industry. All information used for this 
determination is drawn from the drug MIS reports required by this 
subpart. In order to ensure reliability of the data, the Administrator 
considers the quality and completeness of the reported data, may obtain 
additional information or reports from operators, and may make 
appropriate modifications in calculating the industry positive rate. 
Each year, the Administrator will publish in the Federal Register the 
minimum annual percentage rate for random drug testing of covered 
employees. The new minimum annual percentage rate for random drug 
testing will be applicable starting January 1 of the calendar year 
following publication.
    (3) When the minimum annual percentage rate for random drug testing 
is 50 percent, the Administrator may lower this rate to 25 percent of 
all covered employees if the Administrator determines that the data 
received under the reporting requirements of Sec.  199.119 for two 
consecutive calendar years indicate that the reported positive rate is 
less than 1.0 percent.
    (4) When the minimum annual percentage rate for random drug testing 
is 25 percent, and the data received under the reporting requirements of 
Sec.  199.119 for any calendar year indicate that the reported positive 
rate is equal to or greater than 1.0 percent, the Administrator will 
increase the minimum annual percentage rate for random drug testing to 
50 percent of all covered employees.
    (5) The selection of employees for random drug testing shall be made 
by a scientifically valid method, such as a random number table or a 
computer-based random number generator that is matched with employees' 
Social Security numbers, payroll identification numbers, or other 
comparable identifying numbers. Under the selection process used, each 
covered employee shall have an equal chance of being tested each time 
selections are made.
    (6) The operator shall randomly select a sufficient number of 
covered employees for testing during each calendar year to equal an 
annual rate not less than the minimum annual percentage rate for random 
drug testing determined by the Administrator. If the operator conducts 
random drug testing through a consortium, the number of employees to be 
tested may be calculated for each individual operator or may be based on 
the total number of covered employees covered by the consortium who are 
subject to random drug testing at the same minimum annual percentage 
rate under this subpart or any DOT drug testing rule.
    (7) Each operator shall ensure that random drug tests conducted 
under this subpart are unannounced and that the dates for administering 
random tests are spread reasonably throughout the calendar year.
    (8) If a given covered employee is subject to random drug testing 
under the drug testing rules of more than one DOT agency for the same 
operator, the employee shall be subject to random drug testing at the 
percentage rate established for the calendar year by the DOT agency 
regulating more than 50 percent of the employee's function.
    (9) If an operator is required to conduct random drug testing under 
the drug testing rules of more than one DOT agency, the operator may--
    (i) Establish separate pools for random selection, with each pool 
containing the covered employees who are subject to testing at the same 
required rate; or
    (ii) Randomly select such employees for testing at the highest 
percentage rate established for the calendar year by any DOT agency to 
which the operator is subject.
    (d) Testing based on reasonable cause. Each operator shall drug test 
each employee when there is reasonable cause to believe the employee is 
using a prohibited drug. The decision to test must be based on a 
reasonable and articulable belief that the employee is using a 
prohibited drug on the basis of specific, contemporaneous physical, 
behavioral, or performance indicators of

[[Page 727]]

probable drug use. At least two of the employee's supervisors, one of 
whom is trained in detection of the possible symptoms of drug use, shall 
substantiate and concur in the decision to test an employee. The 
concurrence between the two supervisors may be by telephone. However, in 
the case of operators with 50 or fewer employees subject to testing 
under this part, only one supervisor of the employee trained in 
detecting possible drug use symptoms shall substantiate the decision to 
test.
    (e) Return-to-duty testing. A covered employee who refuses to take 
or has a positive drug test may not return to duty in the covered 
function until the covered employee has complied with applicable 
provisions of DOT Procedures concerning substance abuse professionals 
and the return-to-duty process.
    (f) Follow-up testing. A covered employee who refuses to take or has 
a positive drug test shall be subject to unannounced follow-up drug 
tests administered by the operator following the covered employee's 
return to duty. The number and frequency of such follow-up testing shall 
be determined by a substance abuse professional, but shall consist of at 
least six tests in the first 12 months following the covered employee's 
return to duty. In addition, follow-up testing may include testing for 
alcohol as directed by the substance abuse professional, to be performed 
in accordance with 49 CFR part 40. Follow-up testing shall not exceed 60 
months from the date of the covered employee's return to duty. The 
substance abuse professional may terminate the requirement for follow-up 
testing at any time after the first six tests have been administered, if 
the substance abuse professional determines that such testing is no 
longer necessary.

[53 FR 47096, Nov. 21, 1988, as amended by Amdt. 199-2, 54 FR 51850, 
Dec. 18, 1989; 59 FR 62227, Dec. 2, 1994; Amdt. 199-15, 63 FR 13000, 
Mar. 17, 1998; Amdt. 199-15, 63 FR 36863, July 8, 1998. Redesignated and 
amended by Amdt. 199-19, 66 FR 47118, Sept. 11, 2001; Amdt. 199-27, 82 
FR 8001, Jan. 23, 2017]



Sec.  199.107  Drug testing laboratory.

    (a) Each operator shall use for the drug testing required by this 
part only drug testing laboratories certified by the Department of 
Health and Human Services under the DOT Procedures.
    (b) The drug testing laboratory must permit--
    (1) Inspections by the operator before the laboratory is awarded a 
testing contract; and
    (2) Unannounced inspections, including examination of records, at 
any time, by the operator, the Administrator, and if the operator is 
subject to state agency jurisdiction, a representative of that state 
agency.

[53 FR 47096, Nov. 21, 1988. Redesignated by Amdt. 199-19, 66 FR 47118, 
Sept. 11, 2001]



Sec.  199.109  Review of drug testing results.

    (a) MRO appointment. Each operator shall designate or appoint a 
medical review officer (MRO). If an operator does not have a qualified 
individual on staff to serve as MRO, the operator may contract for the 
provision of MRO services as part of its anti-drug program.
    (b) MRO qualifications. Each MRO must be a licensed physician who 
has the qualifications required by DOT Procedures.
    (c) MRO duties. The MRO must perform functions for the operator as 
required by DOT Procedures.
    (d) MRO reports. The MRO must report all drug test results to the 
operator in accordance with DOT Procedures.
    (e) Evaluation and rehabilitation may be provided by the operator, 
by a substance abuse professional under contract with the operator, or 
by a substance abuse professional not affiliated with the operator. The 
choice of substance abuse professional and assignment of costs shall be 
made in accordance with the operator/employee agreements and operator/
employee policies.
    (f) The operator shall ensure that a substance abuse professional, 
who determines that a covered employee requires assistance in resolving 
problems with drug abuse, does not refer the covered employee to the 
substance abuse professional's private practice or to a person or 
organization from which the substance abuse professional receives 
remuneration or in which the substance abuse professional has a 
financial interest. This paragraph does not

[[Page 728]]

prohibit a substance abuse professional from referring a covered 
employee for assistance provided through:
    (1) A public agency, such as a State, county, or municipality;
    (2) The operator or a person under contract to provide treatment for 
drug problems on behalf of the operator;
    (3) The sole source of therapeutically appropriate treatment under 
the employee's health insurance program; or
    (4) The sole source of therapeutically appropriate treatment 
reasonably accessible to the employee.

[53 FR 47096, Nov. 21, 1988, as amended by Amdt. 199-2, 54 FR 51850, 
Dec. 18, 1989; Amdt. 199-15, 63 FR 13000, Mar. 17, 1998; Amdt. 199-15, 
63 FR 36863, July 8, 1998. Redesignated and amended by Amdt. 199-19, 66 
FR 47118, Sept. 11, 2001]



Sec.  199.111  [Reserved]



Sec.  199.113  Employee assistance program.

    (a) Each operator shall provide an employee assistance program (EAP) 
for its employees and supervisory personnel who will determine whether 
an employee must be drug tested based on reasonable cause. The operator 
may establish the EAP as a part of its internal personnel services or 
the operator may contract with an entity that provides EAP services. 
Each EAP must include education and training on drug use. At the 
discretion of the operator, the EAP may include an opportunity for 
employee rehabilitation.
    (b) Education under each EAP must include at least the following 
elements: display and distribution of informational material; display 
and distribution of a community service hot-line telephone number for 
employee assistance; and display and distribution of the employer's 
policy regarding the use of prohibited drugs.
    (c) Training under each EAP for supervisory personnel who will 
determine whether an employee must be drug tested based on reasonable 
cause must include one 60-minute period of training on the specific, 
contemporaneous physical, behavioral, and performance indicators of 
probable drug use.

[53 FR 47096, Nov. 21, 1988. Redesignated by Amdt. 199-19, 66 FR 47118, 
Sept. 11, 2001]



Sec.  199.115  Contractor employees.

    With respect to those employees who are contractors or employed by a 
contractor, an operator may provide by contract that the drug testing, 
education, and training required by this part be carried out by the 
contractor provided:
    (a) The operator remains responsible for ensuring that the 
requirements of this part are complied with; and
    (b) The contractor allows access to property and records by the 
operator, the Administrator, and if the operator is subject to the 
jurisdiction of a state agency, a representative of the state agency for 
the purpose of monitoring the operator's compliance with the 
requirements of this part.

[53 FR 47096, Nov. 21, 1988. Redesignated by Amdt. 199-19, 66 FR 47118, 
Sept. 11, 2001]



Sec.  199.117  Recordkeeping.

    (a) Each operator shall keep the following records for the periods 
specified and permit access to the records as provided by paragraph (b) 
of this section:
    (1) Records that demonstrate the collection process conforms to this 
part must be kept for at least 3 years.
    (2) Records of employee drug test that indicate a verified positive 
result, records that demonstrate compliance with the recommendations of 
a substance abuse professional, and MIS annual report data shall be 
maintained for a minimum of five years.
    (3) Records of employee drug test results that show employees passed 
a drug test must be kept for at least 1 year.
    (4) Records confirming that supervisors and employees have been 
trained as required by this part must be kept for at least 3 years.
    (5) Records of decisions not to administer post-accident employee 
drug tests must be kept for at least 3 years.
    (b) Information regarding an individual's drug testing results or 
rehabilitation must be released upon the written consent of the 
individual and as provided by DOT Procedures. Statistical data related 
to drug testing and rehabilitation that is not name-specific and

[[Page 729]]

training records must be made available to the Administrator or the 
representative of a state agency upon request.

[53 FR 47096, Nov. 21, 1988, as amended at 58 FR 68260, Dec. 23, 1993. 
Redesignated and amended by Amdt. 199-19, 66 FR 47119, Sept. 11, 2001; 
68 FR 75465, Dec. 31, 2003; Amdt. 199-27, 82 FR 8001, Jan. 23, 2017]



Sec.  199.119  Reporting of anti-drug testing results.

    (a) Each large operator (having more than 50 covered employees) must 
submit an annual Management Information System (MIS) report to PHMSA of 
its anti-drug testing using the MIS form and instructions as required by 
49 CFR part 40 (at Sec.  40.26 and appendix H to part 40), not later 
than March 15 of each year for the prior calendar year (January 1 
through December 31). The Administrator may require by notice in the 
PHMSA Portal (https://portal.phmsa.dot.gov/phmsaportallanding) that 
small operators (50 or fewer covered employees), not otherwise required 
to submit annual MIS reports, to prepare and submit such reports to 
PHMSA.
    (b) Each report required under this section must be submitted 
electronically at http://damis.dot.gov. An operator may obtain the user 
name and password needed for electronic reporting from the PHMSA Portal 
(https://portal.phmsa.dot.gov/phmsaportallanding). If electronic 
reporting imposes an undue burden and hardship, the operator may submit 
a written request for an alternative reporting method to the Information 
Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous 
Materials Safety Administration, 1200 New Jersey Avenue SE., Washington, 
DC 20590. The request must describe the undue burden and hardship. PHMSA 
will review the request and may authorize, in writing, an alternative 
reporting method. An authorization will state the period for which it is 
valid, which may be indefinite. An operator must contact PHMSA at 202-
366-8075, or electronically to [email protected] to 
make arrangements for submitting a report that is due after a request 
for alternative reporting is submitted but before an authorization or 
denial is received.
    (c) To calculate the total number of covered employees eligible for 
random testing throughout the year, as an operator, you must add the 
total number of covered employees eligible for testing during each 
random testing period for the year and divide that total by the number 
of random testing periods. Covered employees, and only covered 
employees, are to be in an employer's random testing pool, and all 
covered employees must be in the random pool. If you are an employer 
conducting random testing more often than once per month (e.g., you 
select daily, weekly, bi-weekly), you do not need to compute this total 
number of covered employees rate more than on a once per month basis.
    (d) As an employer, you may use a service agent (e.g., C/TPA) to 
perform random selections for you; and your covered employees may be 
part of a larger random testing pool of covered employees. However, you 
must ensure that the service agent you use is testing at the appropriate 
percentage established for your industry and that only covered employees 
are in the random testing pool.
    (e) Each operator that has a covered employee who performs multi-DOT 
agency functions (e.g., an employee performs pipeline maintenance duties 
and drives a commercial motor vehicle), count the employee only on the 
MIS report for the DOT agency under which he or she is randomly tested. 
Normally, this will be the DOT agency under which the employee performs 
more than 50% of his or her duties. Operators may have to explain the 
testing data for these employees in the event of a DOT agency inspection 
or audit.
    (f) A service agent (e.g., Consortia/Third Party Administrator as 
defined in 49 CFR part 40) may prepare the MIS report on behalf of an 
operator. However, each report shall be certified by the operator's 
anti-drug manager or designated representative for accuracy and 
completeness.

[68 FR 75465, Dec. 31, 2003, as amended by Amdt. 199-20, 69 FR 32898, 
June 14, 2004; 70 FR 11140, Mar. 8, 2005; 73 FR 16571, Mar. 28, 2008; 
Amdt. 199-27, 82 FR 8001, Jan. 23, 2017]

[[Page 730]]



               Subpart C_Alcohol Misuse Prevention Program

    Source: Amdt. 199-9, 59 FR 7430, Feb. 15, 1994, unless otherwise 
noted. Redesignated by Amdt. 199-19, 66 FR 47118, Sept. 11, 2001.



Sec.  199.200  Purpose.

    The purpose of this subpart is to establish programs designed to 
help prevent accidents and injuries resulting from the misuse of alcohol 
by employees who perform covered functions for operators of certain 
pipeline facilities subject to parts 192, 193, or 195 of this chapter.



Sec.  199.201  [Reserved]



Sec.  199.202  Alcohol misuse plan.

    Each operator must maintain and follow a written alcohol misuse plan 
that conforms to the requirements of this part and DOT Procedures 
concerning alcohol testing programs. The plan shall contain methods and 
procedures for compliance with all the requirements of this subpart, 
including required testing, recordkeeping, reporting, education and 
training elements.

[Amdt. 199-9, 59 FR 7430, Feb. 15, 1994, as amended by Amdt. 199-19, 66 
FR 47119, Sept. 11, 2001]



Sec. Sec.  199.203-199.205  [Reserved]



Sec.  199.209  Other requirements imposed by operators.

    (a) Except as expressly provided in this subpart, nothing in this 
subpart shall be construed to affect the authority of operators, or the 
rights of employees, with respect to the use or possession of alcohol, 
including authority and rights with respect to alcohol testing and 
rehabilitation.
    (b) Operators may, but are not required to, conduct pre-employment 
alcohol testing under this subpart. Each operator that conducts pre-
employment alcohol testing must--
    (1) Conduct a pre-employment alcohol test before the first 
performance of covered functions by every covered employee (whether a 
new employee or someone who has transferred to a position involving the 
performance of covered functions);
    (2) Treat all covered employees the same for the purpose of pre-
employment alcohol testing (i.e., you must not test some covered 
employees and not others);
    (3) Conduct the pre-employment tests after making a contingent offer 
of employment or transfer, subject to the employee passing the pre-
employment alcohol test;
    (4) Conduct all pre-employment alcohol tests using the alcohol 
testing procedures in DOT Procedures; and
    (5) Not allow any covered employee to begin performing covered 
functions unless the result of the employee's test indicates an alcohol 
concentration of less than 0.04.

[Amdt. 199-9, 59 FR 7430, Feb. 15, 1994, as amended by Amdt. 199-19, 66 
FR 47119, Sept. 11, 2001]



Sec.  199.211  Requirement for notice.

    Before performing an alcohol test under this subpart, each operator 
shall notify a covered employee that the alcohol test is required by 
this subpart. No operator shall falsely represent that a test is 
administered under this subpart.



Sec.  199.213  [Reserved]



Sec.  199.215  Alcohol concentration.

    Each operator shall prohibit a covered employee from reporting for 
duty or remaining on duty requiring the performance of covered functions 
while having an alcohol concentration of 0.04 or greater. No operator 
having actual knowledge that a covered employee has an alcohol 
concentration of 0.04 or greater shall permit the employee to perform or 
continue to perform covered functions.



Sec.  199.217  On-duty use.

    Each operator shall prohibit a covered employee from using alcohol 
while performing covered functions. No operator having actual knowledge 
that a covered employee is using alcohol while performing covered 
functions shall permit the employee to perform or continue to perform 
covered functions.

[[Page 731]]



Sec.  199.219  Pre-duty use.

    Each operator shall prohibit a covered employee from using alcohol 
within four hours prior to performing covered functions, or, if an 
employee is called to duty to respond to an emergency, within the time 
period after the employee has been notified to report for duty. No 
operator having actual knowledge that a covered employee has used 
alcohol within four hours prior to performing covered functions or 
within the time period after the employee has been notified to report 
for duty shall permit that covered employee to perform or continue to 
perform covered functions.



Sec.  199.221  Use following an accident.

    Each operator shall prohibit a covered employee who has actual 
knowledge of an accident in which his or her performance of covered 
functions has not been discounted by the operator as a contributing 
factor to the accident from using alcohol for eight hours following the 
accident, unless he or she has been given a post-accident test under 
Sec.  199.225(a), or the operator has determined that the employee's 
performance could not have contributed to the accident.



Sec.  199.223  Refusal to submit to a required alcohol test.

    Each operator shall require a covered employee to submit to a post-
accident alcohol test required under Sec.  199.225(a), a reasonable 
suspicion alcohol test required under Sec.  199.225(b), or a follow-up 
alcohol test required under Sec.  199.225(d). No operator shall permit 
an employee who refuses to submit to such a test to perform or continue 
to perform covered functions.



Sec.  199.225  Alcohol tests required.

    Each operator must conduct the following types of alcohol tests for 
the presence of alcohol:
    (a) Post-accident. (1) As soon as practicable following an accident, 
each operator must test each surviving covered employee for alcohol if 
that employee's performance of a covered function either contributed to 
the accident or cannot be completely discounted as a contributing factor 
to the accident. The decision not to administer a test under this 
section must be based on specific information that the covered 
employee's performance had no role in the cause(s) or severity of the 
accident.
    (2)(i) If a test required by this section is not administered within 
2 hours following the accident, the operator shall prepare and maintain 
on file a record stating the reasons the test was not promptly 
administered. If a test required by paragraph (a) is not administered 
within 8 hours following the accident, the operator shall cease attempts 
to administer an alcohol test and shall state in the record the reasons 
for not administering the test.
    (ii) [Reserved]
    (3) A covered employee who is subject to post-accident testing who 
fails to remain readily available for such testing, including notifying 
the operator or operator representative of his/her location if he/she 
leaves the scene of the accident prior to submission to such test, may 
be deemed by the operator to have refused to submit to testing. Nothing 
in this section shall be construed to require the delay of necessary 
medical attention for injured people following an accident or to 
prohibit a covered employee from leaving the scene of an accident for 
the period necessary to obtain assistance in responding to the accident 
or to obtain necessary emergency medical care.
    (b) Reasonable suspicion testing. (1) Each operator shall require a 
covered employee to submit to an alcohol test when the operator has 
reasonable suspicion to believe that the employee has violated the 
prohibitions in this subpart.
    (2) The operator's determination that reasonable suspicion exists to 
require the covered employee to undergo an alcohol test shall be based 
on specific, contemporaneous, articulable observations concerning the 
appearance, behavior, speech, or body odors of the employee. The 
required observations shall be made by a supervisor who is trained in 
detecting the symptoms of alcohol misuse. The supervisor who makes the 
determination that reasonable suspicion exists shall not conduct the 
breath alcohol test on that employee.

[[Page 732]]

    (3) Alcohol testing is authorized by this section only if the 
observations required by paragraph (b)(2) of this section are made 
during, just preceding, or just after the period of the work day that 
the employee is required to be in compliance with this subpart. A 
covered employee may be directed by the operator to undergo reasonable 
suspicion testing for alcohol only while the employee is performing 
covered functions; just before the employee is to perform covered 
functions; or just after the employee has ceased performing covered 
functions.
    (4)(i) If a test required by this section is not administered within 
2 hours following the determination under paragraph (b)(2) of this 
section, the operator shall prepare and maintain on file a record 
stating the reasons the test was not promptly administered. If a test 
required by this section is not administered within 8 hours following 
the determination under paragraph (b)(2) of this section, the operator 
shall cease attempts to administer an alcohol test and shall state in 
the record the reasons for not administering the test. Records shall be 
submitted to PHMSA upon request of the Administrator.
    (ii) [Reserved]
    (iii) Notwithstanding the absence of a reasonable suspicion alcohol 
test under this section, an operator shall not permit a covered employee 
to report for duty or remain on duty requiring the performance of 
covered functions while the employee is under the influence of or 
impaired by alcohol, as shown by the behavioral, speech, or performance 
indicators of alcohol misuse, nor shall an operator permit the covered 
employee to perform or continue to perform covered functions, until:
    (A) An alcohol test is administered and the employee's alcohol 
concentration measures less than 0.02; or
    (B) The start of the employee's next regularly scheduled duty 
period, but not less than 8 hours following the determination under 
paragraph (b)(2) of this section that there is reasonable suspicion to 
believe that the employee has violated the prohibitions in this subpart.
    (iv) Except as provided in paragraph (b)(4)(ii), no operator shall 
take any action under this subpart against a covered employee based 
solely on the employee's behavior and appearance in the absence of an 
alcohol test. This does not prohibit an operator with the authority 
independent of this subpart from taking any action otherwise consistent 
with law.
    (c) Return-to-duty testing. Each operator shall ensure that before a 
covered employee returns to duty requiring the performance of a covered 
function after engaging in conduct prohibited by Sec. Sec.  199.215 
through 199.223, the employee shall undergo a return-to-duty alcohol 
test with a result indicating an alcohol concentration of less than 
0.02.
    (d) Follow-up testing. (1) Following a determination under Sec.  
199.243(b) that a covered employee is in need of assistance in resolving 
problems associated with alcohol misuse, each operator shall ensure that 
the employee is subject to unannounced follow-up alcohol testing as 
directed by a substance abuse professional in accordance with the 
provisions of Sec.  199.243(c)(2)(ii).
    (2) Follow-up testing shall be conducted when the covered employee 
is performing covered functions; just before the employee is to perform 
covered functions; or just after the employee has ceased performing such 
functions.
    (e) Retesting of covered employees with an alcohol concentration of 
0.02 or greater but less than 0.04. Each operator shall retest a covered 
employee to ensure compliance with the provisions of Sec.  199.237, if 
an operator chooses to permit the employee to perform a covered function 
within 8 hours following the administration of an alcohol test 
indicating an alcohol concentration of 0.02 or greater but less than 
0.04.

[Amdt. 199-9, 59 FR 7430, Feb. 15, 1994, as amended at 59 FR 62239, 
62246, Dec. 2, 1994; Redesignated by Amdt. 199-19, 66 FR 47119, Sept. 
11, 2001; 70 FR 11140, March 8, 2005; Amdt. 199-27, 82 FR 8001, Jan. 23, 
2017]



Sec.  199.227  Retention of records.

    (a) General requirement. Each operator shall maintain records of its 
alcohol misuse prevention program as provided in this section. The 
records shall be maintained in a secure location with controlled access.

[[Page 733]]

    (b) Period of retention. Each operator shall maintain the records in 
accordance with the following schedule:
    (1) Five years. Records of employee alcohol test results with 
results indicating an alcohol concentration of 0.02 or greater, 
documentation of refusals to take required alcohol tests, calibration 
documentation, employee evaluation and referrals, and MIS annual report 
data shall be maintained for a minimum of five years.
    (2) Two years. Records related to the collection process (except 
calibration of evidential breath testing devices), and training shall be 
maintained for a minimum of two years.
    (3) One year. Records of all test results below 0.02 (as defined in 
49 CFR part 40) shall be maintained for a minimum of one year.
    (4) Three years. Records of decisions not to administer post-
accident employee alcohol tests must be kept for a minimum of three 
years.
    (c) Types of records. The following specific records shall be 
maintained:
    (1) Records related to the collection process:
    (i) Collection log books, if used.
    (ii) Calibration documentation for evidential breath testing 
devices.
    (iii) Documentation of breath alcohol technician training.
    (iv) Documents generated in connection with decisions to administer 
reasonable suspicion alcohol tests.
    (v) Documents generated in connection with decisions on post- 
accident tests.
    (vi) Documents verifying existence of a medical explanation of the 
inability of a covered employee to provide adequate breath for testing.
    (2) Records related to test results:
    (i) The operator's copy of the alcohol test form, including the 
results of the test.
    (ii) Documents related to the refusal of any covered employee to 
submit to an alcohol test required by this subpart.
    (iii) Documents presented by a covered employee to dispute the 
result of an alcohol test administered under this subpart.
    (3) Records related to other violations of this subpart.
    (4) Records related to evaluations:
    (i) Records pertaining to a determination by a substance abuse 
professional concerning a covered employee's need for assistance.
    (ii) Records concerning a covered employee's compliance with the 
recommendations of the substance abuse professional.
    (5) Record(s) related to the operator's MIS annual testing data.
    (6) Records related to education and training:
    (i) Materials on alcohol misuse awareness, including a copy of the 
operator's policy on alcohol misuse.
    (ii) Documentation of compliance with the requirements of Sec.  
199.231.
    (iii) Documentation of training provided to supervisors for the 
purpose of qualifying the supervisors to make a determination concerning 
the need for alcohol testing based on reasonable suspicion.
    (iv) Certification that any training conducted under this subpart 
complies with the requirements for such training.

[Amdt. 199-9, 59 FR 7430, Feb. 15, 1994, unless otherwise noted. 
Redesignated by Amdt. 199-19, 66 FR 47118, Sept. 11, 2001, as amended by 
Amdt. 199-27, 82 FR 8001, Jan. 23, 2017]



Sec.  199.229  Reporting of alcohol testing results.

    (a) Each large operator (having more than 50 covered employees) must 
submit an annual MIS report to PHMSA of its alcohol testing results 
using the MIS form and instructions as required by 49 CFR part 40 (at 
Sec.  40.26 and appendix H to part 40), not later than March 15 of each 
year for the prior calendar year (January 1 through December 31). The 
Administrator may require by notice in the PHMSA Portal (https://
portal.phmsa.dot.gov/phmsaportallanding) that small operators (50 or 
fewer covered employees), not otherwise required to submit annual MIS 
reports, to prepare and submit such reports to PHMSA.
    (b) Each operator that has a covered employee who performs multi-DOT 
agency functions (e.g., an employee performs pipeline maintenance duties 
and drives a commercial motor vehicle), count the employee only on the 
MIS report for the DOT agency under which he or she is tested. Normally,

[[Page 734]]

this will be the DOT agency under which the employee performs more than 
50% of his or her duties. Operators may have to explain the testing data 
for these employees in the event of a DOT agency inspection or audit.
    (c) Each report required under this section must be submitted 
electronically at http://damis.dot.gov. An operator may obtain the user 
name and password needed for electronic reporting from the PHMSA Portal 
(https://portal.phmsa.dot.gov/phmsaportallanding). If electronic 
reporting imposes an undue burden and hardship, the operator may submit 
a written request for an alternative reporting method to the Information 
Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous 
Materials Safety Administration, 1200 New Jersey Avenue SE., Washington, 
DC 20590. The request must describe the undue burden and hardship. PHMSA 
will review the request and may authorize, in writing, an alternative 
reporting method. An authorization will state the period for which it is 
valid, which may be indefinite. An operator must contact PHMSA at 202-
366-8075, or electronically to [email protected] to 
make arrangements for submitting a report that is due after a request 
for alternative reporting is submitted but before an authorization or 
denial is received.
    (d) A service agent (e.g., Consortia/Third Party Administrator as 
defined in part 40) may prepare the MIS report on behalf of an operator. 
However, each report shall be certified by the operator's anti-drug 
manager or designated representative for accuracy and completeness.

[68 FR 75466, Dec. 31, 2003, as amended by Amdt. 199-20, 69 FR 32898, 
June 14, 2004; 70 FR 11140, Mar. 8, 2005; 73 FR 16571, Mar. 28, 2008; 74 
FR 2895, Jan. 16, 2009; Amdt. 199-27, 82 FR 8001, Jan. 23, 2017]



Sec.  199.231  Access to facilities and records.

    (a) Except as required by law or expressly authorized or required in 
this subpart, no employer shall release covered employee information 
that is contained in records required to be maintained in Sec.  199.227.
    (b) A covered employee is entitled, upon written request, to obtain 
copies of any records pertaining to the employee's use of alcohol, 
including any records pertaining to his or her alcohol tests. The 
operator shall promptly provide the records requested by the employee. 
Access to an employee's records shall not be contingent upon payment for 
records other than those specifically requested.
    (c) Each operator shall permit access to all facilities utilized in 
complying with the requirements of this subpart to the Secretary of 
Transportation, any DOT agency, or a representative of a state agency 
with regulatory authority over the operator.
    (d) Each operator shall make available copies of all results for 
employer alcohol testing conducted under this subpart and any other 
information pertaining to the operator's alcohol misuse prevention 
program, when requested by the Secretary of Transportation, any DOT 
agency with regulatory authority over the operator, or a representative 
of a state agency with regulatory authority over the operator. The 
information shall include name-specific alcohol test results, records, 
and reports.
    (e) When requested by the National Transportation Safety Board as 
part of an accident investigation, an operator shall disclose 
information related to the operator's administration of any post- 
accident alcohol tests administered following the accident under 
investigation.
    (f) An operator shall make records available to a subsequent 
employer upon receipt of the written request from the covered employee. 
Disclosure by the subsequent employer is permitted only as expressly 
authorized by the terms of the employee's written request.
    (g) An operator may disclose information without employee consent as 
provided by DOT Procedures concerning certain legal proceedings.
    (h) An operator shall release information regarding a covered 
employee's records as directed by the specific, written consent of the 
employee authorizing release of the information to an identified person. 
Release of such information by the person receiving

[[Page 735]]

the information is permitted only in accordance with the terms of the 
employee's consent.

[Amdt. 199-9, 59 FR 7430, Feb. 15, 1994, as amended by Amdt. 199-19, 66 
FR 47119, Sept. 11, 2001]



Sec.  199.233  Removal from covered function.

    Except as provided in Sec. Sec.  199.239 through 199.243, no 
operator shall permit any covered employee to perform covered functions 
if the employee has engaged in conduct prohibited by Sec. Sec.  199.215 
through 199.223 or an alcohol misuse rule of another DOT agency.



Sec.  199.235  Required evaluation and testing.

    No operator shall permit a covered employee who has engaged in 
conduct prohibited by Sec. Sec.  199.215 through 199.223 to perform 
covered functions unless the employee has met the requirements of Sec.  
199.243.



Sec.  199.237  Other alcohol-related conduct.

    (a) No operator shall permit a covered employee tested under the 
provisions of Sec.  199.225, who is found to have an alcohol 
concentration of 0.02 or greater but less than 0.04, to perform or 
continue to perform covered functions, until:
    (1) The employee's alcohol concentration measures less than 0.02 in 
accordance with a test administered under Sec.  199.225(e); or
    (2) The start of the employee's next regularly scheduled duty 
period, but not less than eight hours following administration of the 
test.
    (b) Except as provided in paragraph (a) of this section, no operator 
shall take any action under this subpart against an employee based 
solely on test results showing an alcohol concentration less than 0.04. 
This does not prohibit an operator with authority independent of this 
subpart from taking any action otherwise consistent with law.



Sec.  199.239  Operator obligation to promulgate a policy on the misuse 
of alcohol.

    (a) General requirements. Each operator shall provide educational 
materials that explain these alcohol misuse requirements and the 
operator's policies and procedures with respect to meeting those 
requirements.
    (1) The operator shall ensure that a copy of these materials is 
distributed to each covered employee prior to start of alcohol testing 
under this subpart, and to each person subsequently hired for or 
transferred to a covered position.
    (2) Each operator shall provide written notice to representatives of 
employee organizations of the availability of this information.
    (b) Required content. The materials to be made available to covered 
employees shall include detailed discussion of at least the following:
    (1) The identity of the person designated by the operator to answer 
covered employee questions about the materials.
    (2) The categories of employees who are subject to the provisions of 
this subpart.
    (3) Sufficient information about the covered functions performed by 
those employees to make clear what period of the work day the covered 
employee is required to be in compliance with this subpart.
    (4) Specific information concerning covered employee conduct that is 
prohibited by this subpart.
    (5) The circumstances under which a covered employee will be tested 
for alcohol under this subpart.
    (6) The procedures that will be used to test for the presence of 
alcohol, protect the covered employee and the integrity of the breath 
testing process, safeguard the validity of the test results, and ensure 
that those results are attributed to the correct employee.
    (7) The requirement that a covered employee submit to alcohol tests 
administered in accordance with this subpart.
    (8) An explanation of what constitutes a refusal to submit to an 
alcohol test and the attendant consequences.
    (9) The consequences for covered employees found to have violated 
the prohibitions under this subpart, including the requirement that the 
employee be removed immediately from covered functions, and the 
procedures under Sec.  199.243.

[[Page 736]]

    (10) The consequences for covered employees found to have an alcohol 
concentration of 0.02 or greater but less than 0.04.
    (11) Information concerning the effects of alcohol misuse on an 
individual's health, work, and personal life; signs and symptoms of an 
alcohol problem (the employee's or a coworker's); and including 
intervening evaluating and resolving problems associated with the misuse 
of alcohol including intervening when an alcohol problem is suspected, 
confrontation, referral to any available EAP, and/or referral to 
management.
    (c) Optional provisions. The materials supplied to covered employees 
may also include information on additional operator policies with 
respect to the use or possession of alcohol, including any consequences 
for an employee found to have a specified alcohol level, that are based 
on the operator's authority independent of this subpart. Any such 
additional policies or consequences shall be clearly described as being 
based on independent authority.



Sec.  199.241  Training for supervisors.

    Each operator shall ensure that persons designated to determine 
whether reasonable suspicion exists to require a covered employee to 
undergo alcohol testing under Sec.  199.225(b) receive at least 60 
minutes of training on the physical, behavioral, speech, and performance 
indicators of probable alcohol misuse.



Sec.  199.243  Referral, evaluation, and treatment.

    (a) Each covered employee who has engaged in conduct prohibited by 
Sec. Sec.  199.215 through 199.223 of this subpart shall be advised of 
the resources available to the covered employee in evaluating and 
resolving problems associated with the misuse of alcohol, including the 
names, addresses, and telephone numbers of substance abuse professionals 
and counseling and treatment programs.
    (b) Each covered employee who engages in conduct prohibited under 
Sec. Sec.  199.215 through 199.223 shall be evaluated by a substance 
abuse professional who shall determine what assistance, if any, the 
employee needs in resolving problems associated with alcohol misuse.
    (c)(1) Before a covered employee returns to duty requiring the 
performance of a covered function after engaging in conduct prohibited 
by Sec. Sec.  199.215 through 199.223 of this subpart, the employee 
shall undergo a return-to-duty alcohol test with a result indicating an 
alcohol concentration of less than 0.02.
    (2) In addition, each covered employee identified as needing 
assistance in resolving problems associated with alcohol misuse--
    (i) Shall be evaluated by a substance abuse professional to 
determine that the employee has properly followed any rehabilitation 
program prescribed under paragraph (b) of this section, and
    (ii) Shall be subject to unannounced follow-up alcohol tests 
administered by the operator following the employee's return to duty. 
The number and frequency of such follow-up testing shall be determined 
by a substance abuse professional, but shall consist of at least six 
tests in the first 12 months following the employee's return to duty. In 
addition, follow-up testing may include testing for drugs, as directed 
by the substance abuse professional, to be performed in accordance with 
49 CFR part 40. Follow-up testing shall not exceed 60 months from the 
date of the employee's return to duty. The substance abuse professional 
may terminate the requirement for follow-up testing at any time after 
the first six tests have been administered, if the substance abuse 
professional determines that such testing is no longer necessary.
    (d) Evaluation and rehabilitation may be provided by the operator, 
by a substance abuse professional under contract with the operator, or 
by a substance abuse professional not affiliated with the operator. The 
choice of substance abuse professional and assignment of costs shall be 
made in accordance with the operator/employee agreements and operator/
employee policies.
    (e) The operator shall ensure that a substance abuse professional 
who determines that a covered employee requires assistance in resolving 
problems with alcohol misuse does not refer the

[[Page 737]]

employee to the substance abuse professional's private practice or to a 
person or organization from which the substance abuse professional 
receives remuneration or in which the substance abuse professional has a 
financial interest. This paragraph does not prohibit a substance abuse 
professional from referring an employee for assistance provided 
through--
    (1) A public agency, such as a State, county, or municipality;
    (2) The operator or a person under contract to provide treatment for 
alcohol problems on behalf of the operator;
    (3) The sole source of therapeutically appropriate treatment under 
the employee's health insurance program; or
    (4) The sole source of therapeutically appropriate treatment 
reasonably accessible to the employee.



Sec.  199.245  Contractor employees.

    (a) With respect to those covered employees who are contractors or 
employed by a contractor, an operator may provide by contract that the 
alcohol testing, training and education required by this subpart be 
carried out by the contractor provided:
    (b) The operator remains responsible for ensuring that the 
requirements of this subpart and part 40 of this title are complied 
with; and
    (c) The contractor allows access to property and records by the 
operator, the Administrator, any DOT agency with regulatory authority 
over the operator or covered employee, and, if the operator is subject 
to the jurisdiction of a state agency, a representative of the state 
agency for the purposes of monitoring the operator's compliance with the 
requirements of this subpart and part 40 of this title.

[[Page 739]]



                              FINDING AIDS




  --------------------------------------------------------------------

  A list of CFR titles, subtitles, chapters, subchapters and parts and 
an alphabetical list of agencies publishing in the CFR are included in 
the CFR Index and Finding Aids volume to the Code of Federal Regulations 
which is published separately and revised annually.

  Table of CFR Titles and Chapters
  Alphabetical List of Agencies Appearing in the CFR
  List of CFR Sections Affected

[[Page 741]]



                    Table of CFR Titles and Chapters




                     (Revised as of October 1, 2023)

                      Title 1--General Provisions

         I  Administrative Committee of the Federal Register 
                (Parts 1--49)
        II  Office of the Federal Register (Parts 50--299)
       III  Administrative Conference of the United States (Parts 
                300--399)
        IV  Miscellaneous Agencies (Parts 400--599)
        VI  National Capital Planning Commission (Parts 600--699)

                    Title 2--Grants and Agreements

            Subtitle A--Office of Management and Budget Guidance 
                for Grants and Agreements
         I  Office of Management and Budget Governmentwide 
                Guidance for Grants and Agreements (Parts 2--199)
        II  Office of Management and Budget Guidance (Parts 200--
                299)
            Subtitle B--Federal Agency Regulations for Grants and 
                Agreements
       III  Department of Health and Human Services (Parts 300--
                399)
        IV  Department of Agriculture (Parts 400--499)
        VI  Department of State (Parts 600--699)
       VII  Agency for International Development (Parts 700--799)
      VIII  Department of Veterans Affairs (Parts 800--899)
        IX  Department of Energy (Parts 900--999)
         X  Department of the Treasury (Parts 1000--1099)
        XI  Department of Defense (Parts 1100--1199)
       XII  Department of Transportation (Parts 1200--1299)
      XIII  Department of Commerce (Parts 1300--1399)
       XIV  Department of the Interior (Parts 1400--1499)
        XV  Environmental Protection Agency (Parts 1500--1599)
     XVIII  National Aeronautics and Space Administration (Parts 
                1800--1899)
        XX  United States Nuclear Regulatory Commission (Parts 
                2000--2099)
      XXII  Corporation for National and Community Service (Parts 
                2200--2299)
     XXIII  Social Security Administration (Parts 2300--2399)
      XXIV  Department of Housing and Urban Development (Parts 
                2400--2499)
       XXV  National Science Foundation (Parts 2500--2599)
      XXVI  National Archives and Records Administration (Parts 
                2600--2699)

[[Page 742]]

     XXVII  Small Business Administration (Parts 2700--2799)
    XXVIII  Department of Justice (Parts 2800--2899)
      XXIX  Department of Labor (Parts 2900--2999)
       XXX  Department of Homeland Security (Parts 3000--3099)
      XXXI  Institute of Museum and Library Services (Parts 3100--
                3199)
     XXXII  National Endowment for the Arts (Parts 3200--3299)
    XXXIII  National Endowment for the Humanities (Parts 3300--
                3399)
     XXXIV  Department of Education (Parts 3400--3499)
      XXXV  Export-Import Bank of the United States (Parts 3500--
                3599)
     XXXVI  Office of National Drug Control Policy, Executive 
                Office of the President (Parts 3600--3699)
    XXXVII  Peace Corps (Parts 3700--3799)
     LVIII  Election Assistance Commission (Parts 5800--5899)
       LIX  Gulf Coast Ecosystem Restoration Council (Parts 5900--
                5999)
        LX  Federal Communications Commission (Parts 6000--6099)

                        Title 3--The President

         I  Executive Office of the President (Parts 100--199)

                           Title 4--Accounts

         I  Government Accountability Office (Parts 1--199)

                   Title 5--Administrative Personnel

         I  Office of Personnel Management (Parts 1--1199)
        II  Merit Systems Protection Board (Parts 1200--1299)
       III  Office of Management and Budget (Parts 1300--1399)
        IV  Office of Personnel Management and Office of the 
                Director of National Intelligence (Parts 1400--
                1499)
         V  The International Organizations Employees Loyalty 
                Board (Parts 1500--1599)
        VI  Federal Retirement Thrift Investment Board (Parts 
                1600--1699)
      VIII  Office of Special Counsel (Parts 1800--1899)
        IX  Appalachian Regional Commission (Parts 1900--1999)
        XI  Armed Forces Retirement Home (Parts 2100--2199)
       XIV  Federal Labor Relations Authority, General Counsel of 
                the Federal Labor Relations Authority and Federal 
                Service Impasses Panel (Parts 2400--2499)
       XVI  Office of Government Ethics (Parts 2600--2699)
       XXI  Department of the Treasury (Parts 3100--3199)
      XXII  Federal Deposit Insurance Corporation (Parts 3200--
                3299)
     XXIII  Department of Energy (Parts 3300--3399)
      XXIV  Federal Energy Regulatory Commission (Parts 3400--
                3499)
       XXV  Department of the Interior (Parts 3500--3599)

[[Page 743]]

      XXVI  Department of Defense (Parts 3600--3699)
    XXVIII  Department of Justice (Parts 3800--3899)
      XXIX  Federal Communications Commission (Parts 3900--3999)
       XXX  Farm Credit System Insurance Corporation (Parts 4000--
                4099)
      XXXI  Farm Credit Administration (Parts 4100--4199)
    XXXIII  U.S. International Development Finance Corporation 
                (Parts 4300--4399)
     XXXIV  Securities and Exchange Commission (Parts 4400--4499)
      XXXV  Office of Personnel Management (Parts 4500--4599)
     XXXVI  Department of Homeland Security (Parts 4600--4699)
    XXXVII  Federal Election Commission (Parts 4700--4799)
        XL  Interstate Commerce Commission (Parts 5000--5099)
       XLI  Commodity Futures Trading Commission (Parts 5100--
                5199)
      XLII  Department of Labor (Parts 5200--5299)
     XLIII  National Science Foundation (Parts 5300--5399)
       XLV  Department of Health and Human Services (Parts 5500--
                5599)
      XLVI  Postal Rate Commission (Parts 5600--5699)
     XLVII  Federal Trade Commission (Parts 5700--5799)
    XLVIII  Nuclear Regulatory Commission (Parts 5800--5899)
      XLIX  Federal Labor Relations Authority (Parts 5900--5999)
         L  Department of Transportation (Parts 6000--6099)
       LII  Export-Import Bank of the United States (Parts 6200--
                6299)
      LIII  Department of Education (Parts 6300--6399)
       LIV  Environmental Protection Agency (Parts 6400--6499)
        LV  National Endowment for the Arts (Parts 6500--6599)
       LVI  National Endowment for the Humanities (Parts 6600--
                6699)
      LVII  General Services Administration (Parts 6700--6799)
     LVIII  Board of Governors of the Federal Reserve System 
                (Parts 6800--6899)
       LIX  National Aeronautics and Space Administration (Parts 
                6900--6999)
        LX  United States Postal Service (Parts 7000--7099)
       LXI  National Labor Relations Board (Parts 7100--7199)
      LXII  Equal Employment Opportunity Commission (Parts 7200--
                7299)
     LXIII  Inter-American Foundation (Parts 7300--7399)
      LXIV  Merit Systems Protection Board (Parts 7400--7499)
       LXV  Department of Housing and Urban Development (Parts 
                7500--7599)
      LXVI  National Archives and Records Administration (Parts 
                7600--7699)
     LXVII  Institute of Museum and Library Services (Parts 7700--
                7799)
    LXVIII  Commission on Civil Rights (Parts 7800--7899)
      LXIX  Tennessee Valley Authority (Parts 7900--7999)
       LXX  Court Services and Offender Supervision Agency for the 
                District of Columbia (Parts 8000--8099)
      LXXI  Consumer Product Safety Commission (Parts 8100--8199)

[[Page 744]]

    LXXIII  Department of Agriculture (Parts 8300--8399)
     LXXIV  Federal Mine Safety and Health Review Commission 
                (Parts 8400--8499)
     LXXVI  Federal Retirement Thrift Investment Board (Parts 
                8600--8699)
    LXXVII  Office of Management and Budget (Parts 8700--8799)
      LXXX  Federal Housing Finance Agency (Parts 9000--9099)
   LXXXIII  Special Inspector General for Afghanistan 
                Reconstruction (Parts 9300--9399)
    LXXXIV  Bureau of Consumer Financial Protection (Parts 9400--
                9499)
    LXXXVI  National Credit Union Administration (Parts 9600--
                9699)
     XCVII  Department of Homeland Security Human Resources 
                Management System (Department of Homeland 
                Security--Office of Personnel Management) (Parts 
                9700--9799)
    XCVIII  Council of the Inspectors General on Integrity and 
                Efficiency (Parts 9800--9899)
      XCIX  Military Compensation and Retirement Modernization 
                Commission (Parts 9900--9999)
         C  National Council on Disability (Parts 10000--10049)
        CI  National Mediation Board (Parts 10100--10199)
       CII  U.S. Office of Special Counsel (Parts 10200--10299)
       CIV  Office of the Intellectual Property Enforcement 
                Coordinator (Part 10400--10499)

                      Title 6--Domestic Security

         I  Department of Homeland Security, Office of the 
                Secretary (Parts 1--199)
         X  Privacy and Civil Liberties Oversight Board (Parts 
                1000--1099)

                         Title 7--Agriculture

            Subtitle A--Office of the Secretary of Agriculture 
                (Parts 0--26)
            Subtitle B--Regulations of the Department of 
                Agriculture
         I  Agricultural Marketing Service (Standards, 
                Inspections, Marketing Practices), Department of 
                Agriculture (Parts 27--209)
        II  Food and Nutrition Service, Department of Agriculture 
                (Parts 210--299)
       III  Animal and Plant Health Inspection Service, Department 
                of Agriculture (Parts 300--399)
        IV  Federal Crop Insurance Corporation, Department of 
                Agriculture (Parts 400--499)
         V  Agricultural Research Service, Department of 
                Agriculture (Parts 500--599)
        VI  Natural Resources Conservation Service, Department of 
                Agriculture (Parts 600--699)
       VII  Farm Service Agency, Department of Agriculture (Parts 
                700--799)

[[Page 745]]

      VIII  Agricultural Marketing Service (Federal Grain 
                Inspection Service, Fair Trade Practices Program), 
                Department of Agriculture (Parts 800--899)
        IX  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Fruits, Vegetables, Nuts), Department 
                of Agriculture (Parts 900--999)
         X  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Milk), Department of Agriculture 
                (Parts 1000--1199)
        XI  Agricultural Marketing Service (Marketing Agreements 
                and Orders; Miscellaneous Commodities), Department 
                of Agriculture (Parts 1200--1299)
       XIV  Commodity Credit Corporation, Department of 
                Agriculture (Parts 1400--1499)
        XV  Foreign Agricultural Service, Department of 
                Agriculture (Parts 1500--1599)
       XVI  [Reserved]
      XVII  Rural Utilities Service, Department of Agriculture 
                (Parts 1700--1799)
     XVIII  Rural Housing Service, Rural Business-Cooperative 
                Service, Rural Utilities Service, and Farm Service 
                Agency, Department of Agriculture (Parts 1800--
                2099)
        XX  [Reserved]
       XXV  Office of Advocacy and Outreach, Department of 
                Agriculture (Parts 2500--2599)
      XXVI  Office of Inspector General, Department of Agriculture 
                (Parts 2600--2699)
     XXVII  Office of Information Resources Management, Department 
                of Agriculture (Parts 2700--2799)
    XXVIII  Office of Operations, Department of Agriculture (Parts 
                2800--2899)
      XXIX  Office of Energy Policy and New Uses, Department of 
                Agriculture (Parts 2900--2999)
       XXX  Office of the Chief Financial Officer, Department of 
                Agriculture (Parts 3000--3099)
      XXXI  Office of Environmental Quality, Department of 
                Agriculture (Parts 3100--3199)
     XXXII  Office of Procurement and Property Management, 
                Department of Agriculture (Parts 3200--3299)
    XXXIII  Office of Transportation, Department of Agriculture 
                (Parts 3300--3399)
     XXXIV  National Institute of Food and Agriculture (Parts 
                3400--3499)
      XXXV  Rural Housing Service, Department of Agriculture 
                (Parts 3500--3599)
     XXXVI  National Agricultural Statistics Service, Department 
                of Agriculture (Parts 3600--3699)
    XXXVII  Economic Research Service, Department of Agriculture 
                (Parts 3700--3799)
   XXXVIII  World Agricultural Outlook Board, Department of 
                Agriculture (Parts 3800--3899)
       XLI  [Reserved]

[[Page 746]]

      XLII  Rural Business-Cooperative Service and Rural Utilities 
                Service, Department of Agriculture (Parts 4200--
                4299)
         L  Rural Business-Cooperative Service, and Rural 
                Utilities Service, Department of Agriculture 
                (Parts 5000--5099)

                    Title 8--Aliens and Nationality

         I  Department of Homeland Security (Parts 1--499)
         V  Executive Office for Immigration Review, Department of 
                Justice (Parts 1000--1399)

                 Title 9--Animals and Animal Products

         I  Animal and Plant Health Inspection Service, Department 
                of Agriculture (Parts 1--199)
        II  Agricultural Marketing Service (Fair Trade Practices 
                Program), Department of Agriculture (Parts 200--
                299)
       III  Food Safety and Inspection Service, Department of 
                Agriculture (Parts 300--599)

                           Title 10--Energy

         I  Nuclear Regulatory Commission (Parts 0--199)
        II  Department of Energy (Parts 200--699)
       III  Department of Energy (Parts 700--999)
         X  Department of Energy (General Provisions) (Parts 
                1000--1099)
      XIII  Nuclear Waste Technical Review Board (Parts 1300--
                1399)
      XVII  Defense Nuclear Facilities Safety Board (Parts 1700--
                1799)
     XVIII  Northeast Interstate Low-Level Radioactive Waste 
                Commission (Parts 1800--1899)

                      Title 11--Federal Elections

         I  Federal Election Commission (Parts 1--9099)
        II  Election Assistance Commission (Parts 9400--9499)

                      Title 12--Banks and Banking

         I  Comptroller of the Currency, Department of the 
                Treasury (Parts 1--199)
        II  Federal Reserve System (Parts 200--299)
       III  Federal Deposit Insurance Corporation (Parts 300--399)
        IV  Export-Import Bank of the United States (Parts 400--
                499)
         V  [Reserved]
        VI  Farm Credit Administration (Parts 600--699)
       VII  National Credit Union Administration (Parts 700--799)
      VIII  Federal Financing Bank (Parts 800--899)
        IX  (Parts 900--999) [Reserved]

[[Page 747]]

         X  Consumer Financial Protection Bureau (Parts 1000--
                1099)
        XI  Federal Financial Institutions Examination Council 
                (Parts 1100--1199)
       XII  Federal Housing Finance Agency (Parts 1200--1299)
      XIII  Financial Stability Oversight Council (Parts 1300--
                1399)
       XIV  Farm Credit System Insurance Corporation (Parts 1400--
                1499)
        XV  Department of the Treasury (Parts 1500--1599)
       XVI  Office of Financial Research, Department of the 
                Treasury (Parts 1600--1699)
      XVII  Office of Federal Housing Enterprise Oversight, 
                Department of Housing and Urban Development (Parts 
                1700--1799)
     XVIII  Community Development Financial Institutions Fund, 
                Department of the Treasury (Parts 1800--1899)

               Title 13--Business Credit and Assistance

         I  Small Business Administration (Parts 1--199)
       III  Economic Development Administration, Department of 
                Commerce (Parts 300--399)
        IV  Emergency Steel Guarantee Loan Board (Parts 400--499)
         V  Emergency Oil and Gas Guaranteed Loan Board (Parts 
                500--599)

                    Title 14--Aeronautics and Space

         I  Federal Aviation Administration, Department of 
                Transportation (Parts 1--199)
        II  Office of the Secretary, Department of Transportation 
                (Aviation Proceedings) (Parts 200--399)
       III  Commercial Space Transportation, Federal Aviation 
                Administration, Department of Transportation 
                (Parts 400--1199)
         V  National Aeronautics and Space Administration (Parts 
                1200--1299)
        VI  Air Transportation System Stabilization (Parts 1300--
                1399)

                 Title 15--Commerce and Foreign Trade

            Subtitle A--Office of the Secretary of Commerce (Parts 
                0--29)
            Subtitle B--Regulations Relating to Commerce and 
                Foreign Trade
         I  Bureau of the Census, Department of Commerce (Parts 
                30--199)
        II  National Institute of Standards and Technology, 
                Department of Commerce (Parts 200--299)
       III  International Trade Administration, Department of 
                Commerce (Parts 300--399)
        IV  Foreign-Trade Zones Board, Department of Commerce 
                (Parts 400--499)
       VII  Bureau of Industry and Security, Department of 
                Commerce (Parts 700--799)

[[Page 748]]

      VIII  Bureau of Economic Analysis, Department of Commerce 
                (Parts 800--899)
        IX  National Oceanic and Atmospheric Administration, 
                Department of Commerce (Parts 900--999)
        XI  National Technical Information Service, Department of 
                Commerce (Parts 1100--1199)
      XIII  East-West Foreign Trade Board (Parts 1300--1399)
       XIV  Minority Business Development Agency (Parts 1400--
                1499)
        XV  Office of the Under-Secretary for Economic Affairs, 
                Department of Commerce (Parts 1500--1599)
            Subtitle C--Regulations Relating to Foreign Trade 
                Agreements
        XX  Office of the United States Trade Representative 
                (Parts 2000--2099)
            Subtitle D--Regulations Relating to Telecommunications 
                and Information
     XXIII  National Telecommunications and Information 
                Administration, Department of Commerce (Parts 
                2300--2399) [Reserved]

                    Title 16--Commercial Practices

         I  Federal Trade Commission (Parts 0--999)
        II  Consumer Product Safety Commission (Parts 1000--1799)

             Title 17--Commodity and Securities Exchanges

         I  Commodity Futures Trading Commission (Parts 1--199)
        II  Securities and Exchange Commission (Parts 200--399)
        IV  Department of the Treasury (Parts 400--499)

          Title 18--Conservation of Power and Water Resources

         I  Federal Energy Regulatory Commission, Department of 
                Energy (Parts 1--399)
       III  Delaware River Basin Commission (Parts 400--499)
        VI  Water Resources Council (Parts 700--799)
      VIII  Susquehanna River Basin Commission (Parts 800--899)
      XIII  Tennessee Valley Authority (Parts 1300--1399)

                       Title 19--Customs Duties

         I  U.S. Customs and Border Protection, Department of 
                Homeland Security; Department of the Treasury 
                (Parts 0--199)
        II  United States International Trade Commission (Parts 
                200--299)
       III  International Trade Administration, Department of 
                Commerce (Parts 300--399)
        IV  U.S. Immigration and Customs Enforcement, Department 
                of Homeland Security (Parts 400--599) [Reserved]

[[Page 749]]

                     Title 20--Employees' Benefits

         I  Office of Workers' Compensation Programs, Department 
                of Labor (Parts 1--199)
        II  Railroad Retirement Board (Parts 200--399)
       III  Social Security Administration (Parts 400--499)
        IV  Employees' Compensation Appeals Board, Department of 
                Labor (Parts 500--599)
         V  Employment and Training Administration, Department of 
                Labor (Parts 600--699)
        VI  Office of Workers' Compensation Programs, Department 
                of Labor (Parts 700--799)
       VII  Benefits Review Board, Department of Labor (Parts 
                800--899)
      VIII  Joint Board for the Enrollment of Actuaries (Parts 
                900--999)
        IX  Office of the Assistant Secretary for Veterans' 
                Employment and Training Service, Department of 
                Labor (Parts 1000--1099)

                       Title 21--Food and Drugs

         I  Food and Drug Administration, Department of Health and 
                Human Services (Parts 1--1299)
        II  Drug Enforcement Administration, Department of Justice 
                (Parts 1300--1399)
       III  Office of National Drug Control Policy (Parts 1400--
                1499)

                      Title 22--Foreign Relations

         I  Department of State (Parts 1--199)
        II  Agency for International Development (Parts 200--299)
       III  Peace Corps (Parts 300--399)
        IV  International Joint Commission, United States and 
                Canada (Parts 400--499)
         V  United States Agency for Global Media (Parts 500--599)
       VII  U.S. International Development Finance Corporation 
                (Parts 700--799)
        IX  Foreign Service Grievance Board (Parts 900--999)
         X  Inter-American Foundation (Parts 1000--1099)
        XI  International Boundary and Water Commission, United 
                States and Mexico, United States Section (Parts 
                1100--1199)
       XII  United States International Development Cooperation 
                Agency (Parts 1200--1299)
      XIII  Millennium Challenge Corporation (Parts 1300--1399)
       XIV  Foreign Service Labor Relations Board; Federal Labor 
                Relations Authority; General Counsel of the 
                Federal Labor Relations Authority; and the Foreign 
                Service Impasse Disputes Panel (Parts 1400--1499)
        XV  African Development Foundation (Parts 1500--1599)
       XVI  Japan-United States Friendship Commission (Parts 
                1600--1699)
      XVII  United States Institute of Peace (Parts 1700--1799)

[[Page 750]]

                          Title 23--Highways

         I  Federal Highway Administration, Department of 
                Transportation (Parts 1--999)
        II  National Highway Traffic Safety Administration and 
                Federal Highway Administration, Department of 
                Transportation (Parts 1200--1299)
       III  National Highway Traffic Safety Administration, 
                Department of Transportation (Parts 1300--1399)

                Title 24--Housing and Urban Development

            Subtitle A--Office of the Secretary, Department of 
                Housing and Urban Development (Parts 0--99)
            Subtitle B--Regulations Relating to Housing and Urban 
                Development
         I  Office of Assistant Secretary for Equal Opportunity, 
                Department of Housing and Urban Development (Parts 
                100--199)
        II  Office of Assistant Secretary for Housing-Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Parts 200--299)
       III  Government National Mortgage Association, Department 
                of Housing and Urban Development (Parts 300--399)
        IV  Office of Housing and Office of Multifamily Housing 
                Assistance Restructuring, Department of Housing 
                and Urban Development (Parts 400--499)
         V  Office of Assistant Secretary for Community Planning 
                and Development, Department of Housing and Urban 
                Development (Parts 500--599)
        VI  Office of Assistant Secretary for Community Planning 
                and Development, Department of Housing and Urban 
                Development (Parts 600--699) [Reserved]
       VII  Office of the Secretary, Department of Housing and 
                Urban Development (Housing Assistance Programs and 
                Public and Indian Housing Programs) (Parts 700--
                799)
      VIII  Office of the Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Section 8 Housing Assistance 
                Programs, Section 202 Direct Loan Program, Section 
                202 Supportive Housing for the Elderly Program and 
                Section 811 Supportive Housing for Persons With 
                Disabilities Program) (Parts 800--899)
        IX  Office of Assistant Secretary for Public and Indian 
                Housing, Department of Housing and Urban 
                Development (Parts 900--1699)
         X  Office of Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Interstate Land Sales 
                Registration Program) (Parts 1700--1799) 
                [Reserved]
       XII  Office of Inspector General, Department of Housing and 
                Urban Development (Parts 2000--2099)
        XV  Emergency Mortgage Insurance and Loan Programs, 
                Department of Housing and Urban Development (Parts 
                2700--2799) [Reserved]

[[Page 751]]

        XX  Office of Assistant Secretary for Housing--Federal 
                Housing Commissioner, Department of Housing and 
                Urban Development (Parts 3200--3899)
      XXIV  Board of Directors of the HOPE for Homeowners Program 
                (Parts 4000--4099) [Reserved]
       XXV  Neighborhood Reinvestment Corporation (Parts 4100--
                4199)

                           Title 25--Indians

         I  Bureau of Indian Affairs, Department of the Interior 
                (Parts 1--299)
        II  Indian Arts and Crafts Board, Department of the 
                Interior (Parts 300--399)
       III  National Indian Gaming Commission, Department of the 
                Interior (Parts 500--599)
        IV  Office of Navajo and Hopi Indian Relocation (Parts 
                700--899)
         V  Bureau of Indian Affairs, Department of the Interior, 
                and Indian Health Service, Department of Health 
                and Human Services (Part 900--999)
        VI  Office of the Assistant Secretary, Indian Affairs, 
                Department of the Interior (Parts 1000--1199)
       VII  Office of the Special Trustee for American Indians, 
                Department of the Interior (Parts 1200--1299)

                      Title 26--Internal Revenue

         I  Internal Revenue Service, Department of the Treasury 
                (Parts 1--End)

           Title 27--Alcohol, Tobacco Products and Firearms

         I  Alcohol and Tobacco Tax and Trade Bureau, Department 
                of the Treasury (Parts 1--399)
        II  Bureau of Alcohol, Tobacco, Firearms, and Explosives, 
                Department of Justice (Parts 400--799)

                   Title 28--Judicial Administration

         I  Department of Justice (Parts 0--299)
       III  Federal Prison Industries, Inc., Department of Justice 
                (Parts 300--399)
         V  Bureau of Prisons, Department of Justice (Parts 500--
                599)
        VI  Offices of Independent Counsel, Department of Justice 
                (Parts 600--699)
       VII  Office of Independent Counsel (Parts 700--799)
      VIII  Court Services and Offender Supervision Agency for the 
                District of Columbia (Parts 800--899)
        IX  National Crime Prevention and Privacy Compact Council 
                (Parts 900--999)

[[Page 752]]

        XI  Department of Justice and Department of State (Parts 
                1100--1199)

                            Title 29--Labor

            Subtitle A--Office of the Secretary of Labor (Parts 
                0--99)
            Subtitle B--Regulations Relating to Labor
         I  National Labor Relations Board (Parts 100--199)
        II  Office of Labor-Management Standards, Department of 
                Labor (Parts 200--299)
       III  National Railroad Adjustment Board (Parts 300--399)
        IV  Office of Labor-Management Standards, Department of 
                Labor (Parts 400--499)
         V  Wage and Hour Division, Department of Labor (Parts 
                500--899)
        IX  Construction Industry Collective Bargaining Commission 
                (Parts 900--999)
         X  National Mediation Board (Parts 1200--1299)
       XII  Federal Mediation and Conciliation Service (Parts 
                1400--1499)
       XIV  Equal Employment Opportunity Commission (Parts 1600--
                1699)
      XVII  Occupational Safety and Health Administration, 
                Department of Labor (Parts 1900--1999)
        XX  Occupational Safety and Health Review Commission 
                (Parts 2200--2499)
       XXV  Employee Benefits Security Administration, Department 
                of Labor (Parts 2500--2599)
     XXVII  Federal Mine Safety and Health Review Commission 
                (Parts 2700--2799)
        XL  Pension Benefit Guaranty Corporation (Parts 4000--
                4999)

                      Title 30--Mineral Resources

         I  Mine Safety and Health Administration, Department of 
                Labor (Parts 1--199)
        II  Bureau of Safety and Environmental Enforcement, 
                Department of the Interior (Parts 200--299)
        IV  Geological Survey, Department of the Interior (Parts 
                400--499)
         V  Bureau of Ocean Energy Management, Department of the 
                Interior (Parts 500--599)
       VII  Office of Surface Mining Reclamation and Enforcement, 
                Department of the Interior (Parts 700--999)
       XII  Office of Natural Resources Revenue, Department of the 
                Interior (Parts 1200--1299)

                 Title 31--Money and Finance: Treasury

            Subtitle A--Office of the Secretary of the Treasury 
                (Parts 0--50)
            Subtitle B--Regulations Relating to Money and Finance

[[Page 753]]

         I  Monetary Offices, Department of the Treasury (Parts 
                51--199)
        II  Fiscal Service, Department of the Treasury (Parts 
                200--399)
        IV  Secret Service, Department of the Treasury (Parts 
                400--499)
         V  Office of Foreign Assets Control, Department of the 
                Treasury (Parts 500--599)
        VI  Bureau of Engraving and Printing, Department of the 
                Treasury (Parts 600--699)
       VII  Federal Law Enforcement Training Center, Department of 
                the Treasury (Parts 700--799)
      VIII  Office of Investment Security, Department of the 
                Treasury (Parts 800--899)
        IX  Federal Claims Collection Standards (Department of the 
                Treasury--Department of Justice) (Parts 900--999)
         X  Financial Crimes Enforcement Network, Department of 
                the Treasury (Parts 1000--1099)

                      Title 32--National Defense

            Subtitle A--Department of Defense
         I  Office of the Secretary of Defense (Parts 1--399)
         V  Department of the Army (Parts 400--699)
        VI  Department of the Navy (Parts 700--799)
       VII  Department of the Air Force (Parts 800--1099)
            Subtitle B--Other Regulations Relating to National 
                Defense
       XII  Department of Defense, Defense Logistics Agency (Parts 
                1200--1299)
       XVI  Selective Service System (Parts 1600--1699)
      XVII  Office of the Director of National Intelligence (Parts 
                1700--1799)
     XVIII  National Counterintelligence Center (Parts 1800--1899)
       XIX  Central Intelligence Agency (Parts 1900--1999)
        XX  Information Security Oversight Office, National 
                Archives and Records Administration (Parts 2000--
                2099)
       XXI  National Security Council (Parts 2100--2199)
      XXIV  Office of Science and Technology Policy (Parts 2400--
                2499)
     XXVII  Office for Micronesian Status Negotiations (Parts 
                2700--2799)
    XXVIII  Office of the Vice President of the United States 
                (Parts 2800--2899)

               Title 33--Navigation and Navigable Waters

         I  Coast Guard, Department of Homeland Security (Parts 
                1--199)
        II  Corps of Engineers, Department of the Army, Department 
                of Defense (Parts 200--399)
        IV  Great Lakes St. Lawrence Seaway Development 
                Corporation, Department of Transportation (Parts 
                400--499)

[[Page 754]]

                          Title 34--Education

            Subtitle A--Office of the Secretary, Department of 
                Education (Parts 1--99)
            Subtitle B--Regulations of the Offices of the 
                Department of Education
         I  Office for Civil Rights, Department of Education 
                (Parts 100--199)
        II  Office of Elementary and Secondary Education, 
                Department of Education (Parts 200--299)
       III  Office of Special Education and Rehabilitative 
                Services, Department of Education (Parts 300--399)
        IV  Office of Career, Technical, and Adult Education, 
                Department of Education (Parts 400--499)
         V  Office of Bilingual Education and Minority Languages 
                Affairs, Department of Education (Parts 500--599) 
                [Reserved]
        VI  Office of Postsecondary Education, Department of 
                Education (Parts 600--699)
       VII  Office of Educational Research and Improvement, 
                Department of Education (Parts 700--799) 
                [Reserved]
            Subtitle C--Regulations Relating to Education
        XI  [Reserved]
       XII  National Council on Disability (Parts 1200--1299)

                          Title 35 [Reserved]

             Title 36--Parks, Forests, and Public Property

         I  National Park Service, Department of the Interior 
                (Parts 1--199)
        II  Forest Service, Department of Agriculture (Parts 200--
                299)
       III  Corps of Engineers, Department of the Army (Parts 
                300--399)
        IV  American Battle Monuments Commission (Parts 400--499)
         V  Smithsonian Institution (Parts 500--599)
        VI  [Reserved]
       VII  Library of Congress (Parts 700--799)
      VIII  Advisory Council on Historic Preservation (Parts 800--
                899)
        IX  Pennsylvania Avenue Development Corporation (Parts 
                900--999)
         X  Presidio Trust (Parts 1000--1099)
        XI  Architectural and Transportation Barriers Compliance 
                Board (Parts 1100--1199)
       XII  National Archives and Records Administration (Parts 
                1200--1299)
        XV  Oklahoma City National Memorial Trust (Parts 1500--
                1599)
       XVI  Morris K. Udall Scholarship and Excellence in National 
                Environmental Policy Foundation (Parts 1600--1699)

             Title 37--Patents, Trademarks, and Copyrights

         I  United States Patent and Trademark Office, Department 
                of Commerce (Parts 1--199)
        II  U.S. Copyright Office, Library of Congress (Parts 
                200--299)

[[Page 755]]

       III  Copyright Royalty Board, Library of Congress (Parts 
                300--399)
        IV  National Institute of Standards and Technology, 
                Department of Commerce (Parts 400--599)

           Title 38--Pensions, Bonuses, and Veterans' Relief

         I  Department of Veterans Affairs (Parts 0--199)
        II  Armed Forces Retirement Home (Parts 200--299)

                       Title 39--Postal Service

         I  United States Postal Service (Parts 1--999)
       III  Postal Regulatory Commission (Parts 3000--3099)

                  Title 40--Protection of Environment

         I  Environmental Protection Agency (Parts 1--1099)
        IV  Environmental Protection Agency and Department of 
                Justice (Parts 1400--1499)
         V  Council on Environmental Quality (Parts 1500--1599)
        VI  Chemical Safety and Hazard Investigation Board (Parts 
                1600--1699)
       VII  Environmental Protection Agency and Department of 
                Defense; Uniform National Discharge Standards for 
                Vessels of the Armed Forces (Parts 1700--1799)
      VIII  Gulf Coast Ecosystem Restoration Council (Parts 1800--
                1899)
        IX  Federal Permitting Improvement Steering Council (Part 
                1900)

          Title 41--Public Contracts and Property Management

            Subtitle A--Federal Procurement Regulations System 
                [Note]
            Subtitle B--Other Provisions Relating to Public 
                Contracts
        50  Public Contracts, Department of Labor (Parts 50-1--50-
                999)
        51  Committee for Purchase From People Who Are Blind or 
                Severely Disabled (Parts 51-1--51-99)
        60  Office of Federal Contract Compliance Programs, Equal 
                Employment Opportunity, Department of Labor (Parts 
                60-1--60-999)
        61  Office of the Assistant Secretary for Veterans' 
                Employment and Training Service, Department of 
                Labor (Parts 61-1--61-999)
   62--100  [Reserved]
            Subtitle C--Federal Property Management Regulations 
                System
       101  Federal Property Management Regulations (Parts 101-1--
                101-99)
       102  Federal Management Regulation (Parts 102-1--102-299)
  103--104  (Parts 103-001--104-099) [Reserved]
       105  General Services Administration (Parts 105-1--105-999)

[[Page 756]]

       109  Department of Energy Property Management Regulations 
                (Parts 109-1--109-99)
       114  Department of the Interior (Parts 114-1--114-99)
       115  Environmental Protection Agency (Parts 115-1--115-99)
       128  Department of Justice (Parts 128-1--128-99)
  129--200  [Reserved]
            Subtitle D--Federal Acquisition Supply Chain Security
       201  Federal Acquisition Security Council (Parts 201-1--
                201-99)
            Subtitle E [Reserved]
            Subtitle F--Federal Travel Regulation System
       300  General (Parts 300-1--300-99)
       301  Temporary Duty (TDY) Travel Allowances (Parts 301-1--
                301-99)
       302  Relocation Allowances (Parts 302-1--302-99)
       303  Payment of Expenses Connected with the Death of 
                Certain Employees (Part 303-1--303-99)
       304  Payment of Travel Expenses from a Non-Federal Source 
                (Parts 304-1--304-99)

                        Title 42--Public Health

         I  Public Health Service, Department of Health and Human 
                Services (Parts 1--199)
   II--III  [Reserved]
        IV  Centers for Medicare & Medicaid Services, Department 
                of Health and Human Services (Parts 400--699)
         V  Office of Inspector General-Health Care, Department of 
                Health and Human Services (Parts 1000--1099)

                   Title 43--Public Lands: Interior

            Subtitle A--Office of the Secretary of the Interior 
                (Parts 1--199)
            Subtitle B--Regulations Relating to Public Lands
         I  Bureau of Reclamation, Department of the Interior 
                (Parts 400--999)
        II  Bureau of Land Management, Department of the Interior 
                (Parts 1000--9999)
       III  Utah Reclamation Mitigation and Conservation 
                Commission (Parts 10000--10099)

             Title 44--Emergency Management and Assistance

         I  Federal Emergency Management Agency, Department of 
                Homeland Security (Parts 0--399)
        IV  Department of Commerce and Department of 
                Transportation (Parts 400--499)

[[Page 757]]

                       Title 45--Public Welfare

            Subtitle A--Department of Health and Human Services 
                (Parts 1--199)
            Subtitle B--Regulations Relating to Public Welfare
        II  Office of Family Assistance (Assistance Programs), 
                Administration for Children and Families, 
                Department of Health and Human Services (Parts 
                200--299)
       III  Office of Child Support Enforcement (Child Support 
                Enforcement Program), Administration for Children 
                and Families, Department of Health and Human 
                Services (Parts 300--399)
        IV  Office of Refugee Resettlement, Administration for 
                Children and Families, Department of Health and 
                Human Services (Parts 400--499)
         V  Foreign Claims Settlement Commission of the United 
                States, Department of Justice (Parts 500--599)
        VI  National Science Foundation (Parts 600--699)
       VII  Commission on Civil Rights (Parts 700--799)
      VIII  Office of Personnel Management (Parts 800--899)
        IX  Denali Commission (Parts 900--999)
         X  Office of Community Services, Administration for 
                Children and Families, Department of Health and 
                Human Services (Parts 1000--1099)
        XI  National Foundation on the Arts and the Humanities 
                (Parts 1100--1199)
       XII  Corporation for National and Community Service (Parts 
                1200--1299)
      XIII  Administration for Children and Families, Department 
                of Health and Human Services (Parts 1300--1399)
       XVI  Legal Services Corporation (Parts 1600--1699)
      XVII  National Commission on Libraries and Information 
                Science (Parts 1700--1799)
     XVIII  Harry S. Truman Scholarship Foundation (Parts 1800--
                1899)
       XXI  Commission of Fine Arts (Parts 2100--2199)
     XXIII  Arctic Research Commission (Parts 2300--2399)
      XXIV  James Madison Memorial Fellowship Foundation (Parts 
                2400--2499)
       XXV  Corporation for National and Community Service (Parts 
                2500--2599)

                          Title 46--Shipping

         I  Coast Guard, Department of Homeland Security (Parts 
                1--199)
        II  Maritime Administration, Department of Transportation 
                (Parts 200--399)
       III  Coast Guard (Great Lakes Pilotage), Department of 
                Homeland Security (Parts 400--499)
        IV  Federal Maritime Commission (Parts 500--599)

[[Page 758]]

                      Title 47--Telecommunication

         I  Federal Communications Commission (Parts 0--199)
        II  Office of Science and Technology Policy and National 
                Security Council (Parts 200--299)
       III  National Telecommunications and Information 
                Administration, Department of Commerce (Parts 
                300--399)
        IV  National Telecommunications and Information 
                Administration, Department of Commerce, and 
                National Highway Traffic Safety Administration, 
                Department of Transportation (Parts 400--499)
         V  The First Responder Network Authority (Parts 500--599)

           Title 48--Federal Acquisition Regulations System

         1  Federal Acquisition Regulation (Parts 1--99)
         2  Defense Acquisition Regulations System, Department of 
                Defense (Parts 200--299)
         3  Department of Health and Human Services (Parts 300--
                399)
         4  Department of Agriculture (Parts 400--499)
         5  General Services Administration (Parts 500--599)
         6  Department of State (Parts 600--699)
         7  Agency for International Development (Parts 700--799)
         8  Department of Veterans Affairs (Parts 800--899)
         9  Department of Energy (Parts 900--999)
        10  Department of the Treasury (Parts 1000--1099)
        12  Department of Transportation (Parts 1200--1299)
        13  Department of Commerce (Parts 1300--1399)
        14  Department of the Interior (Parts 1400--1499)
        15  Environmental Protection Agency (Parts 1500--1599)
        16  Office of Personnel Management, Federal Employees 
                Health Benefits Acquisition Regulation (Parts 
                1600--1699)
        17  Office of Personnel Management (Parts 1700--1799)
        18  National Aeronautics and Space Administration (Parts 
                1800--1899)
        19  Broadcasting Board of Governors (Parts 1900--1999)
        20  Nuclear Regulatory Commission (Parts 2000--2099)
        21  Office of Personnel Management, Federal Employees 
                Group Life Insurance Federal Acquisition 
                Regulation (Parts 2100--2199)
        23  Social Security Administration (Parts 2300--2399)
        24  Department of Housing and Urban Development (Parts 
                2400--2499)
        25  National Science Foundation (Parts 2500--2599)
        28  Department of Justice (Parts 2800--2899)
        29  Department of Labor (Parts 2900--2999)
        30  Department of Homeland Security, Homeland Security 
                Acquisition Regulation (HSAR) (Parts 3000--3099)
        34  Department of Education Acquisition Regulation (Parts 
                3400--3499)

[[Page 759]]

        51  Department of the Army Acquisition Regulations (Parts 
                5100--5199) [Reserved]
        52  Department of the Navy Acquisition Regulations (Parts 
                5200--5299)
        53  Department of the Air Force Federal Acquisition 
                Regulation Supplement (Parts 5300--5399) 
                [Reserved]
        54  Defense Logistics Agency, Department of Defense (Parts 
                5400--5499)
        57  African Development Foundation (Parts 5700--5799)
        61  Civilian Board of Contract Appeals, General Services 
                Administration (Parts 6100--6199)
        99  Cost Accounting Standards Board, Office of Federal 
                Procurement Policy, Office of Management and 
                Budget (Parts 9900--9999)

                       Title 49--Transportation

            Subtitle A--Office of the Secretary of Transportation 
                (Parts 1--99)
            Subtitle B--Other Regulations Relating to 
                Transportation
         I  Pipeline and Hazardous Materials Safety 
                Administration, Department of Transportation 
                (Parts 100--199)
        II  Federal Railroad Administration, Department of 
                Transportation (Parts 200--299)
       III  Federal Motor Carrier Safety Administration, 
                Department of Transportation (Parts 300--399)
        IV  Coast Guard, Department of Homeland Security (Parts 
                400--499)
         V  National Highway Traffic Safety Administration, 
                Department of Transportation (Parts 500--599)
        VI  Federal Transit Administration, Department of 
                Transportation (Parts 600--699)
       VII  National Railroad Passenger Corporation (AMTRAK) 
                (Parts 700--799)
      VIII  National Transportation Safety Board (Parts 800--999)
         X  Surface Transportation Board (Parts 1000--1399)
        XI  Research and Innovative Technology Administration, 
                Department of Transportation (Parts 1400--1499) 
                [Reserved]
       XII  Transportation Security Administration, Department of 
                Homeland Security (Parts 1500--1699)

                   Title 50--Wildlife and Fisheries

         I  United States Fish and Wildlife Service, Department of 
                the Interior (Parts 1--199)
        II  National Marine Fisheries Service, National Oceanic 
                and Atmospheric Administration, Department of 
                Commerce (Parts 200--299)
       III  International Fishing and Related Activities (Parts 
                300--399)

[[Page 760]]

        IV  Joint Regulations (United States Fish and Wildlife 
                Service, Department of the Interior and National 
                Marine Fisheries Service, National Oceanic and 
                Atmospheric Administration, Department of 
                Commerce); Endangered Species Committee 
                Regulations (Parts 400--499)
         V  Marine Mammal Commission (Parts 500--599)
        VI  Fishery Conservation and Management, National Oceanic 
                and Atmospheric Administration, Department of 
                Commerce (Parts 600--699)

[[Page 761]]





           Alphabetical List of Agencies Appearing in the CFR




                     (Revised as of October 1, 2023)

                                                  CFR Title, Subtitle or 
                     Agency                               Chapter

Administrative Conference of the United States    1, III
Advisory Council on Historic Preservation         36, VIII
Advocacy and Outreach, Office of                  7, XXV
Afghanistan Reconstruction, Special Inspector     5, LXXXIII
     General for
African Development Foundation                    22, XV
  Federal Acquisition Regulation                  48, 57
Agency for International Development              2, VII; 22, II
  Federal Acquisition Regulation                  48, 7
Agricultural Marketing Service                    7, I, VIII, IX, X, XI; 9, 
                                                  II
Agricultural Research Service                     7, V
Agriculture, Department of                        2, IV; 5, LXXIII
  Advocacy and Outreach, Office of                7, XXV
  Agricultural Marketing Service                  7, I, VIII, IX, X, XI; 9, 
                                                  II
  Agricultural Research Service                   7, V
  Animal and Plant Health Inspection Service      7, III; 9, I
  Chief Financial Officer, Office of              7, XXX
  Commodity Credit Corporation                    7, XIV
  Economic Research Service                       7, XXXVII
  Energy Policy and New Uses, Office of           2, IX; 7, XXIX
  Environmental Quality, Office of                7, XXXI
  Farm Service Agency                             7, VII, XVIII
  Federal Acquisition Regulation                  48, 4
  Federal Crop Insurance Corporation              7, IV
  Food and Nutrition Service                      7, II
  Food Safety and Inspection Service              9, III
  Foreign Agricultural Service                    7, XV
  Forest Service                                  36, II
  Information Resources Management, Office of     7, XXVII
  Inspector General, Office of                    7, XXVI
  National Agricultural Library                   7, XLI
  National Agricultural Statistics Service        7, XXXVI
  National Institute of Food and Agriculture      7, XXXIV
  Natural Resources Conservation Service          7, VI
  Operations, Office of                           7, XXVIII
  Procurement and Property Management, Office of  7, XXXII
  Rural Business-Cooperative Service              7, XVIII, XLII
  Rural Development Administration                7, XLII
  Rural Housing Service                           7, XVIII, XXXV
  Rural Utilities Service                         7, XVII, XVIII, XLII
  Secretary of Agriculture, Office of             7, Subtitle A
  Transportation, Office of                       7, XXXIII
  World Agricultural Outlook Board                7, XXXVIII
Air Force, Department of                          32, VII
  Federal Acquisition Regulation Supplement       48, 53
Air Transportation Stabilization Board            14, VI
Alcohol and Tobacco Tax and Trade Bureau          27, I
Alcohol, Tobacco, Firearms, and Explosives,       27, II
     Bureau of
AMTRAK                                            49, VII
American Battle Monuments Commission              36, IV
American Indians, Office of the Special Trustee   25, VII
Animal and Plant Health Inspection Service        7, III; 9, I
Appalachian Regional Commission                   5, IX
Architectural and Transportation Barriers         36, XI
   Compliance Board
[[Page 762]]

Arctic Research Commission                        45, XXIII
Armed Forces Retirement Home                      5, XI; 38, II
Army, Department of                               32, V
  Engineers, Corps of                             33, II; 36, III
  Federal Acquisition Regulation                  48, 51
Benefits Review Board                             20, VII
Bilingual Education and Minority Languages        34, V
     Affairs, Office of
Blind or Severely Disabled, Committee for         41, 51
     Purchase from People Who Are
  Federal Acquisition Regulation                  48, 19
Career, Technical, and Adult Education, Office    34, IV
     of
Census Bureau                                     15, I
Centers for Medicare & Medicaid Services          42, IV
Central Intelligence Agency                       32, XIX
Chemical Safety and Hazard Investigation Board    40, VI
Chief Financial Officer, Office of                7, XXX
Child Support Enforcement, Office of              45, III
Children and Families, Administration for         45, II, III, IV, X, XIII
Civil Rights, Commission on                       5, LXVIII; 45, VII
Civil Rights, Office for                          34, I
Coast Guard                                       33, I; 46, I; 49, IV
Coast Guard (Great Lakes Pilotage)                46, III
Commerce, Department of                           2, XIII; 44, IV; 50, VI
  Census Bureau                                   15, I
  Economic Affairs, Office of the Under-          15, XV
       Secretary for
  Economic Analysis, Bureau of                    15, VIII
  Economic Development Administration             13, III
  Emergency Management and Assistance             44, IV
  Federal Acquisition Regulation                  48, 13
  Foreign-Trade Zones Board                       15, IV
  Industry and Security, Bureau of                15, VII
  International Trade Administration              15, III; 19, III
  National Institute of Standards and Technology  15, II; 37, IV
  National Marine Fisheries Service               50, II, IV
  National Oceanic and Atmospheric                15, IX; 50, II, III, IV, 
       Administration                             VI
  National Technical Information Service          15, XI
  National Telecommunications and Information     15, XXIII; 47, III, IV
       Administration
  National Weather Service                        15, IX
  Patent and Trademark Office, United States      37, I
  Secretary of Commerce, Office of                15, Subtitle A
Commercial Space Transportation                   14, III
Commodity Credit Corporation                      7, XIV
Commodity Futures Trading Commission              5, XLI; 17, I
Community Planning and Development, Office of     24, V, VI
     Assistant Secretary for
Community Services, Office of                     45, X
Comptroller of the Currency                       12, I
Construction Industry Collective Bargaining       29, IX
     Commission
Consumer Financial Protection Bureau              5, LXXXIV; 12, X
Consumer Product Safety Commission                5, LXXI; 16, II
Copyright Royalty Board                           37, III
Corporation for National and Community Service    2, XXII; 45, XII, XXV
Cost Accounting Standards Board                   48, 99
Council on Environmental Quality                  40, V
Council of the Inspectors General on Integrity    5, XCVIII
     and Efficiency
Court Services and Offender Supervision Agency    5, LXX; 28, VIII
     for the District of Columbia
Customs and Border Protection                     19, I
Defense, Department of                            2, XI; 5, XXVI; 32, 
                                                  Subtitle A; 40, VII
  Advanced Research Projects Agency               32, I
  Air Force Department                            32, VII
  Army Department                                 32, V; 33, II; 36, III; 
                                                  48, 51
  Defense Acquisition Regulations System          48, 2
  Defense Intelligence Agency                     32, I

[[Page 763]]

  Defense Logistics Agency                        32, I, XII; 48, 54
  Engineers, Corps of                             33, II; 36, III
  National Imagery and Mapping Agency             32, I
  Navy, Department of                             32, VI; 48, 52
  Secretary of Defense, Office of                 2, XI; 32, I
Defense Contract Audit Agency                     32, I
Defense Intelligence Agency                       32, I
Defense Logistics Agency                          32, XII; 48, 54
Defense Nuclear Facilities Safety Board           10, XVII
Delaware River Basin Commission                   18, III
Denali Commission                                 45, IX
Disability, National Council on                   5, C; 34, XII
District of Columbia, Court Services and          5, LXX; 28, VIII
     Offender Supervision Agency for the
Drug Enforcement Administration                   21, II
East-West Foreign Trade Board                     15, XIII
Economic Affairs, Office of the Under-Secretary   15, XV
     for
Economic Analysis, Bureau of                      15, VIII
Economic Development Administration               13, III
Economic Research Service                         7, XXXVII
Education, Department of                          2, XXXIV; 5, LIII
  Bilingual Education and Minority Languages      34, V
       Affairs, Office of
  Career, Technical, and Adult Education, Office  34, IV
       of
  Civil Rights, Office for                        34, I
  Educational Research and Improvement, Office    34, VII
       of
  Elementary and Secondary Education, Office of   34, II
  Federal Acquisition Regulation                  48, 34
  Postsecondary Education, Office of              34, VI
  Secretary of Education, Office of               34, Subtitle A
  Special Education and Rehabilitative Services,  34, III
       Office of
Educational Research and Improvement, Office of   34, VII
Election Assistance Commission                    2, LVIII; 11, II
Elementary and Secondary Education, Office of     34, II
Emergency Oil and Gas Guaranteed Loan Board       13, V
Emergency Steel Guarantee Loan Board              13, IV
Employee Benefits Security Administration         29, XXV
Employees' Compensation Appeals Board             20, IV
Employees Loyalty Board                           5, V
Employment and Training Administration            20, V
Employment Policy, National Commission for        1, IV
Employment Standards Administration               20, VI
Endangered Species Committee                      50, IV
Energy, Department of                             2, IX; 5, XXIII; 10, II, 
                                                  III, X
  Federal Acquisition Regulation                  48, 9
  Federal Energy Regulatory Commission            5, XXIV; 18, I
  Property Management Regulations                 41, 109
Energy, Office of                                 7, XXIX
Engineers, Corps of                               33, II; 36, III
Engraving and Printing, Bureau of                 31, VI
Environmental Protection Agency                   2, XV; 5, LIV; 40, I, IV, 
                                                  VII
  Federal Acquisition Regulation                  48, 15
  Property Management Regulations                 41, 115
Environmental Quality, Office of                  7, XXXI
Equal Employment Opportunity Commission           5, LXII; 29, XIV
Equal Opportunity, Office of Assistant Secretary  24, I
     for
Executive Office of the President                 3, I
  Environmental Quality, Council on               40, V
  Management and Budget, Office of                2, Subtitle A; 5, III, 
                                                  LXXVII; 14, VI; 48, 99
  National Drug Control Policy, Office of         2, XXXVI; 21, III
  National Security Council                       32, XXI; 47, II
  Presidential Documents                          3
  Science and Technology Policy, Office of        32, XXIV; 47, II
  Trade Representative, Office of the United      15, XX
     States
[[Page 764]]

Export-Import Bank of the United States           2, XXXV; 5, LII; 12, IV
Family Assistance, Office of                      45, II
Farm Credit Administration                        5, XXXI; 12, VI
Farm Credit System Insurance Corporation          5, XXX; 12, XIV
Farm Service Agency                               7, VII, XVIII
Federal Acquisition Regulation                    48, 1
Federal Acquisition Security Council              41, 201
Federal Aviation Administration                   14, I
  Commercial Space Transportation                 14, III
Federal Claims Collection Standards               31, IX
Federal Communications Commission                 2, LX; 5, XXIX; 47, I
Federal Contract Compliance Programs, Office of   41, 60
Federal Crop Insurance Corporation                7, IV
Federal Deposit Insurance Corporation             5, XXII; 12, III
Federal Election Commission                       5, XXXVII; 11, I
Federal Emergency Management Agency               44, I
Federal Employees Group Life Insurance Federal    48, 21
     Acquisition Regulation
Federal Employees Health Benefits Acquisition     48, 16
     Regulation
Federal Energy Regulatory Commission              5, XXIV; 18, I
Federal Financial Institutions Examination        12, XI
     Council
Federal Financing Bank                            12, VIII
Federal Highway Administration                    23, I, II
Federal Home Loan Mortgage Corporation            1, IV
Federal Housing Enterprise Oversight Office       12, XVII
Federal Housing Finance Agency                    5, LXXX; 12, XII
Federal Labor Relations Authority                 5, XIV, XLIX; 22, XIV
Federal Law Enforcement Training Center           31, VII
Federal Management Regulation                     41, 102
Federal Maritime Commission                       46, IV
Federal Mediation and Conciliation Service        29, XII
Federal Mine Safety and Health Review Commission  5, LXXIV; 29, XXVII
Federal Motor Carrier Safety Administration       49, III
Federal Permitting Improvement Steering Council   40, IX
Federal Prison Industries, Inc.                   28, III
Federal Procurement Policy Office                 48, 99
Federal Property Management Regulations           41, 101
Federal Railroad Administration                   49, II
Federal Register, Administrative Committee of     1, I
Federal Register, Office of                       1, II
Federal Reserve System                            12, II
  Board of Governors                              5, LVIII
Federal Retirement Thrift Investment Board        5, VI, LXXVI
Federal Service Impasses Panel                    5, XIV
Federal Trade Commission                          5, XLVII; 16, I
Federal Transit Administration                    49, VI
Federal Travel Regulation System                  41, Subtitle F
Financial Crimes Enforcement Network              31, X
Financial Research Office                         12, XVI
Financial Stability Oversight Council             12, XIII
Fine Arts, Commission of                          45, XXI
Fiscal Service                                    31, II
Fish and Wildlife Service, United States          50, I, IV
Food and Drug Administration                      21, I
Food and Nutrition Service                        7, II
Food Safety and Inspection Service                9, III
Foreign Agricultural Service                      7, XV
Foreign Assets Control, Office of                 31, V
Foreign Claims Settlement Commission of the       45, V
     United States
Foreign Service Grievance Board                   22, IX
Foreign Service Impasse Disputes Panel            22, XIV
Foreign Service Labor Relations Board             22, XIV
Foreign-Trade Zones Board                         15, IV
Forest Service                                    36, II
General Services Administration                   5, LVII; 41, 105
  Contract Appeals, Board of                      48, 61
  Federal Acquisition Regulation                  48, 5

[[Page 765]]

  Federal Management Regulation                   41, 102
  Federal Property Management Regulations         41, 101
  Federal Travel Regulation System                41, Subtitle F
  General                                         41, 300
  Payment From a Non-Federal Source for Travel    41, 304
       Expenses
  Payment of Expenses Connected With the Death    41, 303
       of Certain Employees
  Relocation Allowances                           41, 302
  Temporary Duty (TDY) Travel Allowances          41, 301
Geological Survey                                 30, IV
Government Accountability Office                  4, I
Government Ethics, Office of                      5, XVI
Government National Mortgage Association          24, III
Grain Inspection, Packers and Stockyards          7, VIII; 9, II
     Administration
Great Lakes St. Lawrence Seaway Development       33, IV
     Corporation
Gulf Coast Ecosystem Restoration Council          2, LIX; 40, VIII
Harry S. Truman Scholarship Foundation            45, XVIII
Health and Human Services, Department of          2, III; 5, XLV; 45, 
                                                  Subtitle A
  Centers for Medicare & Medicaid Services        42, IV
  Child Support Enforcement, Office of            45, III
  Children and Families, Administration for       45, II, III, IV, X, XIII
  Community Services, Office of                   45, X
  Family Assistance, Office of                    45, II
  Federal Acquisition Regulation                  48, 3
  Food and Drug Administration                    21, I
  Indian Health Service                           25, V
  Inspector General (Health Care), Office of      42, V
  Public Health Service                           42, I
  Refugee Resettlement, Office of                 45, IV
Homeland Security, Department of                  2, XXX; 5, XXXVI; 6, I; 8, 
                                                  I
  Coast Guard                                     33, I; 46, I; 49, IV
  Coast Guard (Great Lakes Pilotage)              46, III
  Customs and Border Protection                   19, I
  Federal Emergency Management Agency             44, I
  Human Resources Management and Labor Relations  5, XCVII
       Systems
  Immigration and Customs Enforcement Bureau      19, IV
  Transportation Security Administration          49, XII
HOPE for Homeowners Program, Board of Directors   24, XXIV
     of
Housing and Urban Development, Department of      2, XXIV; 5, LXV; 24, 
                                                  Subtitle B
  Community Planning and Development, Office of   24, V, VI
       Assistant Secretary for
  Equal Opportunity, Office of Assistant          24, I
       Secretary for
  Federal Acquisition Regulation                  48, 24
  Federal Housing Enterprise Oversight, Office    12, XVII
       of
  Government National Mortgage Association        24, III
  Housing--Federal Housing Commissioner, Office   24, II, VIII, X, XX
       of Assistant Secretary for
  Housing, Office of, and Multifamily Housing     24, IV
       Assistance Restructuring, Office of
  Inspector General, Office of                    24, XII
  Public and Indian Housing, Office of Assistant  24, IX
       Secretary for
  Secretary, Office of                            24, Subtitle A, VII
Housing--Federal Housing Commissioner, Office of  24, II, VIII, X, XX
     Assistant Secretary for
Housing, Office of, and Multifamily Housing       24, IV
     Assistance Restructuring, Office of
Immigration and Customs Enforcement Bureau        19, IV
Immigration Review, Executive Office for          8, V
Independent Counsel, Office of                    28, VII
Independent Counsel, Offices of                   28, VI
Indian Affairs, Bureau of                         25, I, V
Indian Affairs, Office of the Assistant           25, VI
     Secretary
Indian Arts and Crafts Board                      25, II

[[Page 766]]

Indian Health Service                             25, V
Industry and Security, Bureau of                  15, VII
Information Resources Management, Office of       7, XXVII
Information Security Oversight Office, National   32, XX
     Archives and Records Administration
Inspector General
  Agriculture Department                          7, XXVI
  Health and Human Services Department            42, V
  Housing and Urban Development Department        24, XII, XV
Institute of Peace, United States                 22, XVII
Intellectual Property Enforcement Coordinator,    5, CIV
     Office of
Inter-American Foundation                         5, LXIII; 22, X
Interior, Department of                           2, XIV
  American Indians, Office of the Special         25, VII
       Trustee
  Endangered Species Committee                    50, IV
  Federal Acquisition Regulation                  48, 14
  Federal Property Management Regulations System  41, 114
  Fish and Wildlife Service, United States        50, I, IV
  Geological Survey                               30, IV
  Indian Affairs, Bureau of                       25, I, V
  Indian Affairs, Office of the Assistant         25, VI
       Secretary
  Indian Arts and Crafts Board                    25, II
  Land Management, Bureau of                      43, II
  National Indian Gaming Commission               25, III
  National Park Service                           36, I
  Natural Resource Revenue, Office of             30, XII
  Ocean Energy Management, Bureau of              30, V
  Reclamation, Bureau of                          43, I
  Safety and Environmental Enforcement, Bureau    30, II
       of
  Secretary of the Interior, Office of            2, XIV; 43, Subtitle A
  Surface Mining Reclamation and Enforcement,     30, VII
       Office of
Internal Revenue Service                          26, I
International Boundary and Water Commission,      22, XI
     United States and Mexico, United States 
     Section
International Development, United States Agency   22, II
     for
  Federal Acquisition Regulation                  48, 7
International Development Cooperation Agency,     22, XII
     United States
International Development Finance Corporation,    5, XXXIII; 22, VII
     U.S.
International Joint Commission, United States     22, IV
     and Canada
International Organizations Employees Loyalty     5, V
     Board
International Trade Administration                15, III; 19, III
International Trade Commission, United States     19, II
Interstate Commerce Commission                    5, XL
Investment Security, Office of                    31, VIII
James Madison Memorial Fellowship Foundation      45, XXIV
Japan-United States Friendship Commission         22, XVI
Joint Board for the Enrollment of Actuaries       20, VIII
Justice, Department of                            2, XXVIII; 5, XXVIII; 28, 
                                                  I, XI; 40, IV
  Alcohol, Tobacco, Firearms, and Explosives,     27, II
       Bureau of
  Drug Enforcement Administration                 21, II
  Federal Acquisition Regulation                  48, 28
  Federal Claims Collection Standards             31, IX
  Federal Prison Industries, Inc.                 28, III
  Foreign Claims Settlement Commission of the     45, V
       United States
  Immigration Review, Executive Office for        8, V
  Independent Counsel, Offices of                 28, VI
  Prisons, Bureau of                              28, V
  Property Management Regulations                 41, 128
Labor, Department of                              2, XXIX; 5, XLII
  Benefits Review Board                           20, VII
  Employee Benefits Security Administration       29, XXV
  Employees' Compensation Appeals Board           20, IV
  Employment and Training Administration          20, V
  Federal Acquisition Regulation                  48, 29

[[Page 767]]

  Federal Contract Compliance Programs, Office    41, 60
       of
  Federal Procurement Regulations System          41, 50
  Labor-Management Standards, Office of           29, II, IV
  Mine Safety and Health Administration           30, I
  Occupational Safety and Health Administration   29, XVII
  Public Contracts                                41, 50
  Secretary of Labor, Office of                   29, Subtitle A
  Veterans' Employment and Training Service,      41, 61; 20, IX
       Office of the Assistant Secretary for
  Wage and Hour Division                          29, V
  Workers' Compensation Programs, Office of       20, I, VI
Labor-Management Standards, Office of             29, II, IV
Land Management, Bureau of                        43, II
Legal Services Corporation                        45, XVI
Libraries and Information Science, National       45, XVII
     Commission on
Library of Congress                               36, VII
  Copyright Royalty Board                         37, III
  U.S. Copyright Office                           37, II
Management and Budget, Office of                  5, III, LXXVII; 14, VI; 
                                                  48, 99
Marine Mammal Commission                          50, V
Maritime Administration                           46, II
Merit Systems Protection Board                    5, II, LXIV
Micronesian Status Negotiations, Office for       32, XXVII
Military Compensation and Retirement              5, XCIX
     Modernization Commission
Millennium Challenge Corporation                  22, XIII
Mine Safety and Health Administration             30, I
Minority Business Development Agency              15, XIV
Miscellaneous Agencies                            1, IV
Monetary Offices                                  31, I
Morris K. Udall Scholarship and Excellence in     36, XVI
     National Environmental Policy Foundation
Museum and Library Services, Institute of         2, XXXI
National Aeronautics and Space Administration     2, XVIII; 5, LIX; 14, V
  Federal Acquisition Regulation                  48, 18
National Agricultural Library                     7, XLI
National Agricultural Statistics Service          7, XXXVI
National and Community Service, Corporation for   2, XXII; 45, XII, XXV
National Archives and Records Administration      2, XXVI; 5, LXVI; 36, XII
  Information Security Oversight Office           32, XX
National Capital Planning Commission              1, IV, VI
National Counterintelligence Center               32, XVIII
National Credit Union Administration              5, LXXXVI; 12, VII
National Crime Prevention and Privacy Compact     28, IX
     Council
National Drug Control Policy, Office of           2, XXXVI; 21, III
National Endowment for the Arts                   2, XXXII
National Endowment for the Humanities             2, XXXIII
National Foundation on the Arts and the           45, XI
     Humanities
National Geospatial-Intelligence Agency           32, I
National Highway Traffic Safety Administration    23, II, III; 47, VI; 49, V
National Imagery and Mapping Agency               32, I
National Indian Gaming Commission                 25, III
National Institute of Food and Agriculture        7, XXXIV
National Institute of Standards and Technology    15, II; 37, IV
National Intelligence, Office of Director of      5, IV; 32, XVII
National Labor Relations Board                    5, LXI; 29, I
National Marine Fisheries Service                 50, II, IV
National Mediation Board                          5, CI; 29, X
National Oceanic and Atmospheric Administration   15, IX; 50, II, III, IV, 
                                                  VI
National Park Service                             36, I
National Railroad Adjustment Board                29, III
National Railroad Passenger Corporation (AMTRAK)  49, VII
National Science Foundation                       2, XXV; 5, XLIII; 45, VI
  Federal Acquisition Regulation                  48, 25
National Security Council                         32, XXI; 47, II

[[Page 768]]

National Technical Information Service            15, XI
National Telecommunications and Information       15, XXIII; 47, III, IV, V
     Administration
National Transportation Safety Board              49, VIII
Natural Resource Revenue, Office of               30, XII
Natural Resources Conservation Service            7, VI
Navajo and Hopi Indian Relocation, Office of      25, IV
Navy, Department of                               32, VI
  Federal Acquisition Regulation                  48, 52
Neighborhood Reinvestment Corporation             24, XXV
Northeast Interstate Low-Level Radioactive Waste  10, XVIII
     Commission
Nuclear Regulatory Commission                     2, XX; 5, XLVIII; 10, I
  Federal Acquisition Regulation                  48, 20
Occupational Safety and Health Administration     29, XVII
Occupational Safety and Health Review Commission  29, XX
Ocean Energy Management, Bureau of                30, V
Oklahoma City National Memorial Trust             36, XV
Operations Office                                 7, XXVIII
Patent and Trademark Office, United States        37, I
Payment From a Non-Federal Source for Travel      41, 304
     Expenses
Payment of Expenses Connected With the Death of   41, 303
     Certain Employees
Peace Corps                                       2, XXXVII; 22, III
Pennsylvania Avenue Development Corporation       36, IX
Pension Benefit Guaranty Corporation              29, XL
Personnel Management, Office of                   5, I, IV, XXXV; 45, VIII
  Federal Acquisition Regulation                  48, 17
  Federal Employees Group Life Insurance Federal  48, 21
       Acquisition Regulation
  Federal Employees Health Benefits Acquisition   48, 16
       Regulation
  Human Resources Management and Labor Relations  5, XCVII
       Systems, Department of Homeland Security
Pipeline and Hazardous Materials Safety           49, I
     Administration
Postal Regulatory Commission                      5, XLVI; 39, III
Postal Service, United States                     5, LX; 39, I
Postsecondary Education, Office of                34, VI
President's Commission on White House             1, IV
     Fellowships
Presidential Documents                            3
Presidio Trust                                    36, X
Prisons, Bureau of                                28, V
Privacy and Civil Liberties Oversight Board       6, X
Procurement and Property Management, Office of    7, XXXII
Public and Indian Housing, Office of Assistant    24, IX
     Secretary for
Public Contracts, Department of Labor             41, 50
Public Health Service                             42, I
Railroad Retirement Board                         20, II
Reclamation, Bureau of                            43, I
Refugee Resettlement, Office of                   45, IV
Relocation Allowances                             41, 302
Research and Innovative Technology                49, XI
     Administration
Rural Business-Cooperative Service                7, XVIII, XLII, L
Rural Development Administration                  7, XLII
Rural Housing Service                             7, XVIII, XXXV, L
Rural Utilities Service                           7, XVII, XVIII, XLII, L
Safety and Environmental Enforcement, Bureau of   30, II
Science and Technology Policy, Office of          32, XXIV; 47, II
Secret Service                                    31, IV
Securities and Exchange Commission                5, XXXIV; 17, II
Selective Service System                          32, XVI
Small Business Administration                     2, XXVII; 13, I
Smithsonian Institution                           36, V
Social Security Administration                    2, XXIII; 20, III; 48, 23
Soldiers' and Airmen's Home, United States        5, XI
Special Counsel, Office of                        5, VIII
Special Education and Rehabilitative Services,    34, III
     Office of
State, Department of                              2, VI; 22, I; 28, XI

[[Page 769]]

  Federal Acquisition Regulation                  48, 6
Surface Mining Reclamation and Enforcement,       30, VII
     Office of
Surface Transportation Board                      49, X
Susquehanna River Basin Commission                18, VIII
Tennessee Valley Authority                        5, LXIX; 18, XIII
Trade Representative, United States, Office of    15, XX
Transportation, Department of                     2, XII; 5, L
  Commercial Space Transportation                 14, III
  Emergency Management and Assistance             44, IV
  Federal Acquisition Regulation                  48, 12
  Federal Aviation Administration                 14, I
  Federal Highway Administration                  23, I, II
  Federal Motor Carrier Safety Administration     49, III
  Federal Railroad Administration                 49, II
  Federal Transit Administration                  49, VI
  Great Lakes St. Lawrence Seaway Development     33, IV
       Corporation
  Maritime Administration                         46, II
  National Highway Traffic Safety Administration  23, II, III; 47, IV; 49, V
  Pipeline and Hazardous Materials Safety         49, I
       Administration
  Secretary of Transportation, Office of          14, II; 49, Subtitle A
  Transportation Statistics Bureau                49, XI
Transportation, Office of                         7, XXXIII
Transportation Security Administration            49, XII
Transportation Statistics Bureau                  49, XI
Travel Allowances, Temporary Duty (TDY)           41, 301
Treasury, Department of the                       2, X; 5, XXI; 12, XV; 17, 
                                                  IV; 31, IX
  Alcohol and Tobacco Tax and Trade Bureau        27, I
  Community Development Financial Institutions    12, XVIII
       Fund
  Comptroller of the Currency                     12, I
  Customs and Border Protection                   19, I
  Engraving and Printing, Bureau of               31, VI
  Federal Acquisition Regulation                  48, 10
  Federal Claims Collection Standards             31, IX
  Federal Law Enforcement Training Center         31, VII
  Financial Crimes Enforcement Network            31, X
  Fiscal Service                                  31, II
  Foreign Assets Control, Office of               31, V
  Internal Revenue Service                        26, I
  Investment Security, Office of                  31, VIII
  Monetary Offices                                31, I
  Secret Service                                  31, IV
  Secretary of the Treasury, Office of            31, Subtitle A
Truman, Harry S. Scholarship Foundation           45, XVIII
United States Agency for Global Media             22, V
United States and Canada, International Joint     22, IV
     Commission
United States and Mexico, International Boundary  22, XI
     and Water Commission, United States Section
U.S. Copyright Office                             37, II
U.S. Office of Special Counsel                    5, CII
Utah Reclamation Mitigation and Conservation      43, III
     Commission
Veterans Affairs, Department of                   2, VIII; 38, I
  Federal Acquisition Regulation                  48, 8
Veterans' Employment and Training Service,        41, 61; 20, IX
     Office of the Assistant Secretary for
Vice President of the United States, Office of    32, XXVIII
Wage and Hour Division                            29, V
Water Resources Council                           18, VI
Workers' Compensation Programs, Office of         20, I, VII
World Agricultural Outlook Board                  7, XXXVIII

[[Page 771]]



List of CFR Sections Affected



All changes in this volume of the Code of Federal Regulations (CFR) that 
were made by documents published in the Federal Register since January 
1, 2018 are enumerated in the following list. Entries indicate the 
nature of the changes effected. Page numbers refer to Federal Register 
pages. The user should consult the entries for chapters, parts and 
subparts as well as sections for revisions.
For changes to this volume of the CFR prior to this listing, consult the 
annual edition of the monthly List of CFR Sections Affected (LSA). The 
LSA is available at www.govinfo.gov. For changes to this volume of the 
CFR prior to 2001, see the ``List of CFR Sections Affected, 1949-1963, 
1964-1972, 1973-1985, and 1986-2000'' published in 11 separate volumes. 
The ``List of CFR Sections Affected 1986-2000'' is available at 
www.govinfo.gov.

                                  2018

49 CFR
                                                                   83 FR
                                                                    Page
Subtitle B
178.35 (f)(7) added................................................55810
178.337-9 (b)(8) revised...........................................55810
178.516 (b)(7) revised.............................................55810
178.703 (b)(6) revised.............................................55810
179.102-10 Removed.................................................48401
179.202-12 (g) removed.............................................48401
179.202-13 (i) removed.............................................48401
180 Authority citation revised.....................................28168
180.407 (c) table, notes, and (g)(1)(ii) revised...................28168
    (g)(1)(iv) revised.............................................55810
180.605 (l) revised................................................55811
190.223 (a) through (d) revised....................................60744
192 Authority citation revised.....................................58715
192.3 Amended......................................................58715
192.7 (c)(3) through (9) redesignated as (c)(4) through (10); new 
        (c)(3), (d)(16) through (24), and (j)(2) added; (d)(11) 
        through (15) and (j)(1) revised............................58715
192.9 (d) revised..................................................58716
192.59 (a)(1), (2), and (b)(3) revised; (a)(3) added...............58716
192.63 (a) revised; (e) added......................................58716
192.67 Added.......................................................58716
192.121 Revised....................................................58716
192.123 Removed....................................................58717
192.143 (c) added..................................................58717
192.145 (f) added..................................................58717
192.149 (c) added..................................................58718
192.191 Removed....................................................58718
192.204 Added......................................................58718
192.281 (b)(2), (3), and (c) revised; (e)(3) and (4) added.........58718
192.283 Revised....................................................58718
192.285 (b)(2)(i) revised..........................................58718
192.313 (d) added..................................................58718
192.321 (a), (d), (f), and (h)(3) revised; (i) added...............58718
192.329 Added......................................................58719
192.367 (b)(1) and (2) revised; (b)(3) added.......................58719
192.375 (a)(2) revised.............................................58719
192.376 Added......................................................58719
192.455 (a) introductory text revised; (g) added...................58719
192.513 (c) revised................................................58719
192.720 Added......................................................58719
192.756 Added......................................................58719
192 Appendix B amended.............................................58719

                                  2019

49 CFR
                                                                   84 FR
                                                                    Page
Subtitle B
190 Authority citation revised.....................................37071
190.3 Amended; eff. 12-2-19........................................52026
190.5 (a) revised; eff. 12-2-19....................................52026
190.223 (a) through (d) revised....................................37071
190.236 Revised; eff. 12-2-19......................................52027
190.237 Revised; eff. 12-2-19......................................52027
191 Authority citation revised; eff. 7-1-20........................52242

[[Page 772]]

191.23 (a)(6) and (b)(4) revised; (a)(10) added; eff. 7-1-20.......52242
191.25 Revised; eff. 7-1-20........................................52242
192 Authority citation revised; eff. 7-1-20........................52243
192 Policy statement...............................................11253
192.3 Amended; eff. 7-1-20.........................................52243
192.5 (d) added; eff. 7-1-20.......................................52243
192.7 (d) through (j) redesignated as (e) through (k); (a)(1)(ii), 
        (c)(2), (4), and new (j)(1) revised; (b)(12), new (d), and 
        new (h)(2) added; eff. 7-1-20..............................52243
192.9 (b), (c), (d)(1), (2), and (6) revised; eff. 7-1-20..........52244
192.18 Added; eff. 7-1-20..........................................52244
192.67 Redesignated as 192.69; new section added; eff. 7-1-20......52244
192.69 Redesignated from 192.67; eff. 7-1-20.......................52244
192.127 Added; eff. 7-1-20.........................................52244
192.150 (a) revised; eff. 7-1-20...................................52244
192.205 Added; eff. 7-1-20.........................................52245
192.227 (c) added; eff. 7-1-20.....................................52245
192.285 (e) added; eff. 7-1-20.....................................52245
192.493 Added; eff. 7-1-20.........................................52245
192.506 Added; eff. 7-1-20.........................................52245
192.517 (a) introductory text revised; eff. 7-1-20.................52245
192.607 Added; eff. 7-1-20.........................................52245
192.619 (a) introductory text, (2), and (4) revised; (e) and (f) 
        added; eff. 7-1-20.........................................52247
192.624 Added; eff. 7-1-20.........................................52247
192.632 Added; eff. 7-1-20.........................................52249
192.710 Added; eff. 7-1-20.........................................52250
192.712 Added; eff. 7-1-20.........................................52251
192.750 Added; eff. 7-1-20.........................................52252
192.805 (i) revised; eff. 7-1-20...................................52252
192.909 (b) revised; eff. 7-1-20...................................52253
192.917 (a)(3), (e)(2), (3), and (4) revised; (e)(6) added; eff. 
        7-1-20.....................................................52253
192.921 (a) revised; (i) added; eff. 7-1-20........................52253
192.933 (a)(1) and (2) revised; eff. 7-1-20........................52254
192.935 (b)(2) revised; eff. 7-1-20................................52254
192.937 (c) revised; (d) added; eff. 7-1-20........................52254
192.939 (a) introductory text, (b) introductory text, and (1) 
        revised; eff. 7-1-20.......................................52255
192.949 Removed; eff. 7-1-20.......................................52255
192 Appendix F added; eff. 7-1-20..................................52255
195 Authority citation revised; eff. 7-1-20........................52294
195.1 (a)(5) added; (b)(2) and (4) revised; eff. 7-1-20............52294
195.2 Amended; eff. 7-1-20.........................................52294
195.3 (g)(3) amended; eff. 7-1-20..................................52294
195.13 Added; eff. 7-1-20..........................................52294
195.15 Added; eff. 7-1-20..........................................52294
195.65 Added; eff. 7-1-20..........................................52294
195.120 Revised; eff. 7-1-20.......................................52294
195.134 Revised; eff. 7-1-20.......................................52295
195.401 (b)(3) added; eff. 7-1-20..................................52295
195.414 Added; eff. 7-1-20.........................................52295
195.416 Added; eff. 7-1-20.........................................52295
195.444 Revised; eff. 7-1-20.......................................52296
195.452 (a)(3), (b)(1), (c)(1)(i) introductory text, (A), (d), 
        (e)(1)(vii), (g), (h)(1) introductory text, (2), and 
        (j)(2) revised; (i)(2)(viii) amended; (i)(2)(ix), (n), and 
        (o) added; eff. 7-1-20.....................................52296
195.454 Added; eff. 7-1-20.........................................52298
199.3 Amended......................................................16775

                                  2020

49 CFR
                                                                   85 FR
                                                                    Page
Subtitle B
178.35 (b)(2) and (c) revised......................................75716
178.35 (f)(8) added................................................85420
178.36 (i) revised.................................................85420
178.37 (i) revised.................................................85420
178.38 (i) revised.................................................85420
178.39 (i) revised.................................................85420
178.42 (f) revised.................................................85421
178.44 (i) revised.................................................85421
178.45 (g) revised.................................................85421
178.46 (g) revised.................................................85421
178.47 (j) revised.................................................85421
178.50 Revised.....................................................85422
178.51 Revised.....................................................85424
178.53 (h) revised.................................................85426
178.55 (i) revised.................................................85426
178.56 (i) revised.................................................85427
178.57 (i) revised.................................................85427
178.58 (i) revised.................................................85427
178.59 (h) revised.................................................85427
178.60 (j) revised.................................................85428
178.61 Revised.....................................................85428
178.65 (f) revised.................................................85430
178.68 (b), (e), (h), (j) introductory text, (j)(1), and (k) 
        through (m) revised; (n) redesignated as (o); new (n) 
        added......................................................85431
178.70 (d) revised.................................................85432

[[Page 773]]

178.75 (e)(3)(i), (ii), and (f)(1) revised.........................85432
178.338-10 (c)(2) revised..........................................83402
178.345-8 (b)(1) Amended...........................................83402
178.521 (b)(4) revised.............................................75716
179.22 (e) revised.................................................75716
179.201-6 Revised..................................................83403
179.202-13 (h)(1) introductory text revised........................83403
180.203 Amended....................................................85432
180.205 (c) introductory text, (d), (g), (h)(3), (i)(1)(viii), 
        (2), and (3) revised; (f)(5), (6), (i)(1)(ix) through 
        (xi), and (j) added........................................85433
180.207 (a)(3), (b)(2), (c) introductory text, (d) introductory 
        text, and (1) revised......................................85434
180.209 (a) Table 1 and (e) revised................................68797
180.209 (b)(1)(iii) removed; (c), (e), (g), (j), and (l)(1) 
        revised....................................................85434
180.209 (l)(2) revised.............................................75716
180.212 (a)(3) added...............................................85435
180.213 (d)(2) revised.............................................75717
180.213 (c) and (d)(2) revised; (f)(10), (11), and (g) added.......85435
180.215 (a)(6), (b), and (c)(2)(vii) revised; (c)(3) added.........85436
180.407 (b)(1), (d)(5), (e)(3), and (g)(1)(iv) revised.............83403
180.417 (a)(3) heading revised.....................................75717

                                  2021

49 CFR
                                                                   86 FR
                                                                    Page
178 Technical correction............................................2564
179 Technical correction............................................2564
180 Technical correction............................................2564
190.223 (a), (c), and (d) revised............................1756, 23252
191 Notification....................................................3839
191 Heading revised................................................63294
191.1 (a), (b)(2), and (3) revised; (b)(4) removed; (c) added......63294
191.3 Amended................................................2237, 63295
191.3 Regulation at 86 FR 2237 eff. date delayed to 3-21-21........12834
191.11 (b) revised..................................................2237
191.11 Regulation at 86 FR 2237 eff. date delayed to 3-21-21.......12834
191.12 Removed......................................................2237
191.12 Regulation at 86 FR 2237 eff. date delayed to 3-21-21.......12834
191.15 (a) revised.................................................63295
191.17 (a) revised.................................................63295
191.23 (b)(1) revised..............................................63295
191.29 (c) added...................................................63295
191 Appendix A added................................................2237
191 Regulation at 86 FR 2237 eff. date delayed to 3-21-21..........12834
192 Notification....................................................3839
192.3 Amended......................................................63295
192.7 (a), (b) introductory text, (9), (e) introductory text, 
        (11), and (20) revised; (c)(7) removed......................2237
192.7 Regulation at 86 FR 2237 eff. date delayed to 3-21-21........12834
192.8 (b) redesignated as (c); heading and new (c) revised; (a)(5) 
        and new (b) added..........................................63295
192.9 (e) redesignated as (g); heading, new (g)(2), and new (3) 
        revised; new (e), (f), (g)(4), (5), and (h) added..........63296
192.13 (a) and (b) revised.........................................63298
192.18 (c) revised.................................................63298
192.121 (a), (c)(2) introductory text, and (e) introductory text 
        amended; (c)(2)(iii), (iv), and (e)(4) revised..............2238
192.121 Regulation at 86 FR 2238 eff. date delayed to 3-21-21......12834
192.150 (b)(7)(ii) amended; (b)(8) redesignated as (b)(9); new 
        (b)(8) added...............................................63298
192.153 (b) and (e) revised.........................................2239
192.153 Regulation at 86 FR 2239 eff. date delayed to 3-21-21......12834
192.229 (b) revised.................................................2240
192.229 Regulation at 86 FR 2240 eff. date delayed to 3-21-21......12834
192.281 (c) revised.................................................2240
192.281 Regulation at 86 FR 2240 eff. date delayed to 3-21-21......12834
192.281 Correction: instruction amended............................12836
192.283 (a)(3) revised..............................................2240
192.283 Regulation at 86 FR 2240 eff. date delayed to 3-21-21......12834
192.285 (b) revised.................................................2240
192.285 Regulation at 86 FR 2240 eff. date delayed to 3-21-21......12834
192.452 Heading and (b) introductory text revised; (c) and (d) 
        added......................................................63298
192.465 (b) revised.................................................2240
192.465 Regulation at 86 FR 2240 eff. date delayed to 3-21-21......12834
192.481 (a) revised; (d) added......................................2240
192.481 Regulation at 86 FR 2240 eff. date delayed to 3-21-21......12834
192.491 (c) revised.................................................2241

[[Page 774]]

192.491 Regulation at 86 FR 2241 eff. date delayed to 3-21-21......12834
192 Regulation at 86 FR 2242 eff. date delayed to 3-21-21..........12834
192 Correction: Appendix B amended.................................12836
192.505 (c) revised.................................................2241
192.505 Regulation at 86 FR 2241 eff. date delayed to 3-21-21......12834
192.507 (d) added...................................................2241
192.507 Regulation at 86 FR 2241 eff. date delayed to 3-21-21......12834
192.507 Correction: (d) amended....................................12836
192.619 (a)(2)(ii) Table 1 revised..................................2241
192.619 Regulation at 86 FR 2241 eff. date delayed to 3-21-21......12834
192.619 (a)(3) and (c) revised.....................................63299
192.740 (a) revised.................................................2241
192.740 Regulation at 86 FR 2241 eff. date delayed to 3-21-21......12834
192.1003 Revised....................................................2241
192.1003 Regulation at 86 FR 2241 eff. date delayed to 3-21-21.....12834
192.1005 Heading revised............................................2241
192.1005 Regulation at 86 FR 2241 eff. date delayed to 3-21-21.....12834
192.1007 (b) revised................................................2241
192.1007 Regulation at 86 FR 2241 eff. date delayed to 3-21-21.....12834
192.1009 Removed....................................................2242
192.1009 Regulation at 86 FR 2242 eff. date delayed to 3-21-21.....12834
192.1015 Revised....................................................2242
192.1015 Regulation at 86 FR 2242 eff. date delayed to 3-21-21.....12834
192 Appendix B amended..............................................2242
192 Regulation at 84 FR 11283 withdrawn............................12834

                                  2022

49 CFR
                                                                   87 FR
                                                                    Page
Subtitle B
Chapter I
178.3 (a)(4) revised...............................................44999
178.50 (a) revised.................................................79784
178.71 (d)(2) and (o)(1) revised; (l)(1)(iv) added.................44999
178.75 (d)(3) introductory text revised; (d)(3)(vi) through (ix) 
        added......................................................44999
178.275 (i)(2)(i)(A) revised.......................................44999
178.337-1 (f) amended..............................................79784
178.338-10 (c)(2) revised..........................................79784
178.505 (b)(6) and (7) redesignated as (b)(7) and (8); new (b)(6) 
        added......................................................45000
178.506 (b)(6) and (7) redesignated as (b)(7) and (8); new (b)(6) 
        added......................................................45000
178.601 (g)(2)(vi) revised.........................................79784
178.609 (g) revised................................................45000
178.703 (b)(6) introductory text and (7)(iv) revised...............45000
178.705 (c)(1)(iv) introductory text and (A) revised...............45000
180.207 (d)(3) revised; (d)(7) added...............................45000
180.507 (b) revised................................................79785
180.605 Heading and (b)(5) revised.................................79785
190.223 (a), (c), and (d) revised..................................15866
190.293 Revised....................................................28781
191.15 (a)(1) revised..............................................35677
191.17 (a)(1) revised..............................................35677
191.23 (b)(1) revised..............................................26299
192.3 Amended; eff. 10-5-22........................................20982
192.3 Amended; eff. 5-24-23........................................52267
192.3 Correction: (2)(i) revised...................................64384
192.7 (h)(1) and (2) redesignated as (h)(4) and new (1); (a), 
        (c)(6), and new (h)(4) revised; new (h)(2) and (3) added; 
        eff. 5-24-23...............................................52267
192.8 (c)(4) added.................................................26299
192.9 (d)(1) and (e)(1)(i) revised; eff. 10-5-22...................20982
192.9 (b), (c), (d)(1), (2), (e)(1)(i), and (ii) revised; eff. 5-
        24-23......................................................52268
192.13 (d) added; eff. 5-24-23.....................................52268
192.18 (c) revised; eff. 10-5-22...................................20982
192.18 (c) revised; eff. 5-24-23...................................52268
192.179 (e) through (h) added; eff. 10-5-22........................20982
192.319 (d) through (g) added; eff. 5-24-23........................52268
192.461 (a)(4) revised; (f) through (i) added; eff. 5-24-23........52269
192.465 Heading and (d) revised; (f) added; eff. 5-24-23...........52269
192.473 (c) added; eff. 5-24-23....................................52269
192.478 Added; eff. 5-24-23........................................52270
192.485 (c) revised; eff. 5-24-23..................................52270
192.610 added; eff. 10-5-22........................................20983
192.613 (c) added; eff. 5-24-23....................................52270
192.615 (a)(2), (6), (8), and (11) revised; (a)(12) added; (c) 
        introductory text revised; eff. 10-5-22....................20983
192.617 Revised; eff. 10-5-22......................................20983
192.634 Added; eff. 10-5-22........................................20984

[[Page 775]]

192.635 Added; eff. 10-5-22........................................20985
192.636 Added; eff. 10-5-22........................................20985
192.710 (f) revised; eff. 5-24-23..................................52270
192.711 (b)(1) revised; eff. 5-24-23...............................52270
192.712 Heading and (b) revised; (c) and (h) added; eff. 5-24-23 
                                                                   52270
192.714 Added; eff. 5-24-23........................................52271
192.745 (c) through (f) added; eff. 10-5-22........................20986
192.911 (k) revised; eff. 5-24-23..................................52273
192.917 (a) through (d) revised; eff. 5-24-23......................52273
192.923 (b)(2) and (3) revised; eff. 5-24-23.......................52274
192.927 (b) and (c) revised; eff. 5-24-23..........................52275
192.929 Revised; eff. 5-24-23......................................52276
192.933 (a) introductory text, (1), (b), and (d) revised; (e) 
        added; eff. 5-24-23........................................52277
192.935 (c) revised; (f) added; eff. 10-5-22.......................20986
192.935 (a) and (d)(3) revised; eff. 5-24-23.......................52279
192.941 (b)(1) and (2) introductory text revised; eff. 5-24-23.....52279
195.2 Amended; eff. 10-5-22........................................20987
195.11 (b)(2) revised; eff. 10-5-22................................20987
195.18 Added; eff. 10-5-22.........................................20987
195.258 (c) through (e) added; eff. 10-5-22........................20987
195.260 Revised; eff. 10-5-22......................................20987
195.402 (c)(4), (5), (12), (e)(1), (4), (7), and (10) revised; 
        eff. 10-5-22...............................................20989
195.417 Added; eff. 10-5-22........................................20989
195.418 Added; eff. 10-5-22........................................20989
195.419 Added; eff. 10-5-22........................................20990
195.420 (b) revised; (d) through (g) added; eff. 10-5-22...........20991
195.452 (i)(4) revised; eff. 10-5-22...............................20992

                                  2023

  (Regulations published from January 1, 2023, through October 1, 2023)

49 CFR
                                                                   88 FR
                                                                    Page
Subtitle A
178 Technical correction............................................4756
180 Technical correction............................................4756
190.223 (a), (c), and (d) revised...................................1125
192.3 Amended......................................................50060
192.9 (b), (c), and (e)(1)(iv) revised.............................50060
192.179 (e) and (f) revised........................................50061
192.319 Correction: (f) revised....................................24711
192.473 Correction: (c)(3) revised.................................24711
192.610 (b) introductory text revised..............................50061
192.634 (b)(3) revised; (c) removed................................50061
192.636 (h) added..................................................50062
192.714 Correction: (b), (d)(1) introductory text, and (3)(i) 
        revised....................................................24712
192.933 Correction: (a) introductory text revised..................24712
195.2 Amended......................................................50062
195.11 (b)(2) revised..............................................50062
195.258 (e) revised; (f) added.....................................50062
195.260 (i) added..................................................50062
195.402 (c)(5)(ii) introductory text revised; (g) added............50062
195.417 (a) introductory text and (3) revised; (c) added...........50062
195.418 (b)(3) revised; (d) added..................................50063
195.419 (h) added..................................................50063
195.420 (b) revised; (h) added.....................................50063
195.452 (i)(4) introductory text revised; (i)(4)(iv) added.........50063


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