[Federal Register Volume 72, Number 75 (Thursday, April 19, 2007)]
[Notices]
[Pages 19757-19761]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E7-7414]


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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

[Docket No. PHMSA--2006--25803]


Pipeline Safety: Grant of Waiver; Kinder Morgan Louisiana 
Pipeline, LLC

AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA); 
DOT.

ACTION: Notice; Grant of Waiver.

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SUMMARY: The Pipeline and Hazardous Materials Safety Administration 
(PHMSA) is granting Kinder Morgan Louisiana Pipeline, LLC (KMLP) a 
waiver of compliance from the Federal pipeline safety regulations for a 
new natural gas transmission pipeline. The regulations establish the 
maximum stress level and overpressure protection limits for natural gas 
pipelines.

FOR FURTHER INFORMATION CONTACT: Alan Mayberry at (202) 366-5124, or by 
e-mail at [email protected] or Wayne Lemoi at (404) 832-1160, or by 
e-mail at [email protected].

SUPPLEMENTARY INFORMATION:

Waiver Request

    Pipeline Operator: Kinder Morgan Louisiana Pipeline, LLC (KMLP) 
petitioned PHMSA on August 2, 2006 for a waiver of compliance with the 
Federal pipeline safety regulations limiting the operating stress 
levels for Class 1 locations along the Leg 1 segment of the KMLP 
pipeline in Louisiana. This waiver would allow KMLP to operate a new 
natural gas transmission pipeline at a maximum allowable operating 
pressure (MAOP) corresponding to a pipe stress level up to 80 percent 
of the steel pipe's specified minimum yield strength (SMYS) in rural 
areas along the pipeline route. SMYS is defined as the level of stress 
where steel transitions from elastic to plastic deformation. The 
current maximum SMYS level allowed on pipelines in Class 1 locations is 
72 percent according to 49 CFR 192.111. Because the proposed operating 
stress level of 80 percent is higher than the upper limit of the 
required overpressure protection under existing regulations (i.e., 10 
percent over MAOP or 75 percent SMYS), KMLP proposes increasing the 
overpressure protection limit to 104 percent of the pipeline MAOP or 83 
percent SMYS. The pipeline MAOP will be 1,440 psig.

Public Notice

    On November 22, 2006 PHMSA published notice of this waiver request 
in the Federal Register (71 FR 67704) inviting interested persons to 
comment on the request. We did not receive any comments for or against 
this waiver request as a result of this notice. We also requested and 
received supplemental information from KMLP. The waiver request, 
Federal Register notice, supplemental information from KMLP, and all 
other pertinent documents are

[[Page 19758]]

available for review in the DOT's Document Management System (DMS), 
Docket Number PHMSA-2006-25803.

Waiver Analysis

Background

    On January 6, 2006 PHMSA issued a meeting notice and a call for 
papers in the Federal Register (71 FR 977) to seek public input on 
raising the MAOP on certain natural gas transmission pipelines. On 
March 21, 2006 PHMSA conducted a public meeting where subject matter 
experts from across the U.S. and other countries presented papers 
describing technical issues and experiences with operating pipelines 
above 72 percent SMYS. After receiving favorable public responses and 
comments from the meeting, PHMSA began developing criteria for the 
design and operation of pipelines above 72 percent SMYS.
    PHMSA previously issued three waivers allowing operators to operate 
natural gas transmission pipelines above 72 percent SMYS. The waivers 
were granted with conditions that require operators to meet certain 
specified safety criteria. The safety criteria were developed from 
information received from the public meeting, industry best practices 
and internal research. KMLP used information gathered from these prior 
waiver grants along with internal procedures to develop its waiver 
petition.

Waiver Findings

    PHMSA concludes that granting a waiver to KMLP is not inconsistent 
with pipeline safety and achieves a level of safety equal to or better 
than a similar pipeline designed and operated under existing 
regulations. The analysis concluded the following:
    (1) KMLP's waiver application describes actions for the proposed 
pipeline life cycle addressing pipe and material quality, construction 
quality control, pre-in service strength testing, the Supervisory 
Control and Data Acquisition (SCADA) System, operations and maintenance 
and integrity management. The aggregate affect of these actions 
provides for more inspections and oversight than would occur on a 
pipeline installed under existing regulations.
    (2) The actions proposed in KMLP's waiver application are 
consistent with prior waiver grants.
    (3) The safety criteria contained in this waiver grant requires 
KMLP to more closely inspect and monitor this pipeline than a similar 
pipeline installed without a waiver.

Waiver Grant

    PHMSA grants a waiver of compliance with Sec. Sec.  192.111 and 
192.201(a)(2)(i) to Kinder Morgan Louisiana Pipeline, LLC for Class 1 
locations along the Leg 1 segment of the KMLP pipeline. The Leg 1 
segment is a 137-mile, 42-inch pipeline, originating at the Sabine Pass 
Liquefied Natural Gas (LNG) terminal and extending to Evangeline 
Parish, Louisiana. Approximately 92 percent of the Leg 1 segment is 
located in Class 1 locations. For the purpose of this waiver, the 
waiver area is defined as the pipeline right-of-way for the Class 1 
locations along the entire 137-mile Leg 1 segment of the KMLP pipeline.

Waiver Conditions

    This waiver is granted with the following conditions:
    (1) Steel Properties: The skelp/plate must be micro alloyed, fine 
grain, fully killed steel with calcium treatment and continuous 
casting.
    (2) Manufacturing Standards: The pipe must be manufactured 
according to American Petroleum Institute Specification 5L (API 5L), 
product specification level 2 (PSL 2), supplementary requirements (SR) 
for maximum operating pressures and minimum operating temperatures. 
Pipe carbon equivalents must be at or below 0.25 percent based on the 
material chemistry parameter (Pcm) formula.
    (3) Fracture Control: API 5L, the American Society of Mechanical 
Engineers B31.8 Standard (ASME B31.8) and other specifications and 
standards address the steel pipe toughness properties needed to resist 
crack initiation, crack propagation and to ensure crack arrest during a 
pipeline failure caused by a fracture. KMLP must institute an overall 
fracture control plan addressing steel pipe properties necessary to 
resist crack initiation and crack propagation and to arrest a fracture 
within eight pipe joints with a 99 percent occurrence probability or 
within five pipe joints with a 90 percent occurrence probability. The 
plan must include acceptable Charpy Impact and Drop Weight Tear Test 
values, which are measures of a steel pipeline's toughness and 
resistance to fracture. The fracture control plan, which must be 
submitted to PHMSA Headquarters, must be in accordance with API 5L, 
Appendix F and must include the following tests:
    (a) SR 5A-Fracture Toughness Testing for Shear Area: Test results 
must indicate at least 85 percent minimum average shear area for all X-
70 heats and 80 percent minimum shear area for all X-80 heats with a 
minimum result of 80 percent shear area for any single test and must 
ensure ductile fracture and arrest;
    (b) SR 5B-Fracture Toughness Testing for Absorbed Energy; and
    (c) SR 6-Fracture Toughness Testing by Drop Weight Tear Test: Test 
results must be at least 80 percent of the average shear area for all 
heats with a minimum result of 60 percent of the shear area for any 
single test and must ensure a ductile fracture.
    The above fracture initiation, propagation and arrest plan must 
account for the entire range of pipeline operating temperatures, 
pressures and gas compositions planned for the pipeline diameter, grade 
and operating stress levels, including maximum pressures and minimum 
temperatures for shut-in conditions associated with the waiver area. 
Where the use of stress factors, pipe grade, operating temperatures and 
gas composition make fracture toughness calculations non-conservative, 
correction factors must be used. If the fracture control plan of the 
pipe in the waiver area does not meet these specifications, KMLP must 
submit to PHMSA Headquarters an alternative plan providing an 
acceptable method to resist crack initiation, crack propagation and to 
arrest ductile fractures in the waiver area.
    (4) Steel Plate Quality Control: The steel mill and/or pipe rolling 
mill must incorporate a comprehensive plate/coil mill and pipe mill 
inspection program to check for defects and inclusions that could 
affect the pipe quality. This program must include a plate (body and 
all ends) ultrasonic testing (UT) inspection program to check for 
imperfections such as laminations. An inspection protocol for 
centerline segregation evaluation using a test method referred to as 
slab macro-etching must be employed to check for inclusions that may 
form as the steel plate cools after it has been cast. A minimum of one 
macro-etch test must be performed from the first heat (manufacturing 
run) of each sequence (approximately 4 heats) and graded on the 
Mannesmann scale or equivalent. Test results with a Mannesmann scale 
rating of one or two out of a possible five are acceptable.
    (5) Pipe Seam Quality Control: A quality assurance program must be 
instituted for pipe weld seams. The pipe weld seam tests must meet the 
minimum requirements for tensile strength in API 5L for the appropriate 
pipe grade properties. A pipe weld seam hardness test using the Vickers 
hardness testing of a cross-section from the weld seam must be 
performed on one length

[[Page 19759]]

of pipe from each heat. The weld seam and heat affected zone hardness 
must be a maximum of 280 Vickers hardness. The hardness tests must 
include a minimum of three readings for each heat affected zone, three 
readings in the weld metal and two readings in each section of pipe 
base metal for a total of 13 readings. The pipe weld seam must be 100 
percent UT inspected after expansion and hydrostatic testing per APL 
5L.
    (6) Puncture Resistance: Steel pipe must be puncture resistant to 
65 tons. Puncture resistance will be calculated based on industry 
established calculations such as the Pipeline Research Council 
International's ``Reliability Based Prevention of Mechanical Damage to 
Pipelines'' calculation method.
    (7) Mill Hydrostatic Test: The pipe must be subjected to a mill 
hydrostatic test pressure of 95 percent SMYS or greater for 10 seconds.
    (8) Pipe Coating: The application of a corrosion resistant coating 
to the steel pipe must be subject to a coating application quality 
control program. The program must address pipe surface cleanliness 
standards, blast cleaning, application temperature control, adhesion, 
cathodic disbondment, moisture permeation, bending, minimum coating 
thickness, coating imperfections and coating repair.
    (9) Field Coating: A field girth weld joint coating application 
specification and quality standards to ensure pipe surface cleanliness, 
application temperature control, adhesion quality, cathodic 
disbondment, moisture permeation, bending, minimum coating thickness, 
holiday detection and repair quality must be implemented in field 
conditions. Field joint coatings must be non-shielding to cathodic 
protection (CP). Field coating applicators must use valid coating 
procedures and be trained to use these procedures.
    (10) Coatings for Trenchless Installation: Coatings used for 
directional bore, slick bore and other trenchless installation methods 
must resist abrasions and other damages that may occur due to rocks and 
other obstructions encountered in this installation technique.
    (11) Bends Quality: Certification records of factory induction 
bends and/or factory weld bends must be obtained and retained. All 
bends, flanges and fittings must have carbon equivalents (CE) below 
0.42 or a pre-heat procedure prior to welding for CE above 0.42.
    (12) Fittings: All pressure rated fittings and components 
(including flanges, valves, gaskets, pressure vessels and compressors) 
must be rated for a pressure rating commensurate with the MAOP and 
class location of the pipeline. Designed fittings (including tees, 
elbows and caps) must have the same design factors as the adjacent pipe 
class location.
    (13) Design Factor--Stations: Compressor and meter stations must be 
designed using a design factor of 0.50 in accordance with Sec.  
192.111.
    (14) Temperature Control: The compressor station discharge 
temperature must not exceed 120[deg] Fahrenheit or a temperature below 
the maximum long-term operating temperature for the pipe coating.
    (15) Overpressure Protection Control: Mainline pipeline 
overpressure protection must not exceed 104 percent MAOP.
    (16) Welding Procedures: The appropriate PHMSA regional office must 
be notified within 14 days of the beginning of welding procedure 
qualification activities. Automated or manual welding procedure 
documentation must be submitted to the same PHMSA regional office.
    (17) Depth of Cover: The soil cover must be a minimum of 36 inches 
in all areas. In areas where threats from chisel plowing or other 
activities are threats to the pipeline, the top of the pipeline must be 
installed at least one foot below the deepest penetration above the 
pipeline. If a routine patrol or other observed conditions indicate the 
possible loss of cover over the pipeline, KMLP must perform a depth of 
cover study and replace cover as necessary to meet the minimum depth of 
cover requirements specified herein.
    (18) Construction Quality: A construction quality assurance plan to 
ensure quality standards and controls must be maintained throughout the 
construction phase for inspection, pipe hauling and stringing, field 
bending, welding, non-destructive examination (NDE) of girth welds, 
field joint coating, pipeline coating integrity tests, lowering of the 
pipeline in the ditch, padding materials to protect the pipeline, 
backfilling, alternating current (AC) interference mitigation and CP 
systems. All girth welds must be non-destructively examined (NDE) by 
radiography or alternative means. The NDE examiner must have all 
required certifications which must be current.
    (19) Interference Currents Control: Control of induced AC from 
parallel electric transmission lines and other interference issues that 
may affect the pipeline must be incorporated into the design of the 
pipeline and addressed during the construction phase. Issues identified 
and not originally addressed in the design phase must be brought to 
PHMSA Headquarters' attention. An induced AC program to protect the 
pipeline from corrosion caused by stray currents must be in place 
within six months after placing the pipeline in service.
    (20) Test Level: The pre-in service hydrostatic test pressure on 
0.8 designed Class 1 location pipe must be equal to or greater than 125 
percent of the MAOP and produce a hoop stress of at least 100 percent 
SMYS.
    (21) Assessment of Test Failures: Any pipe failure occurring during 
the pre-in service hydrostatic test must undergo a root cause failure 
analysis to include a metallurgical examination of the failed pipe. The 
results of this examination must preclude a systemic pipeline material 
issue and the results must be reported to PHMSA Headquarters and the 
appropriate PHMSA regional office.
    (22) SCADA System Capabilities: A SCADA system to provide remote 
monitoring and control of the entire pipeline system must be employed.
    (23) SCADA Procedures: A detailed procedure for establishing and 
maintaining accurate SCADA set points must be established to ensure the 
pipeline operates within acceptable design limits at all times.
    (24) Mainline Valve Control: Mainline valves located on either side 
of a pipeline segment containing a High Consequence Area (HCA) where 
personnel response time to the valve exceeds one hour must be remotely 
controlled by the SCADA system. The SCADA system must be capable of 
opening and closing the valve and monitoring the valve position, 
upstream pressure and downstream pressure. As an alternative, a leak 
detection system for mainline valve control is acceptable.
    (25) Leak Reporting: KMLP must notify the appropriate PHMSA 
regional office within 24 hours of any non-reportable leaks occurring 
on the pipeline.
    (26) Annual Reporting: Following approval of the waiver, KMLP must 
annually report the following:
    (a) The results of any in-line inspection (ILI) and the results of 
any direct assessment performed within the waiver area during the 
previous year;
    (b) Any new integrity threats identified within the waiver area 
during the previous year;
    (c) Any encroachment in the waiver area, including the number of 
new residences or public gathering areas;
    (d) Any class or HCA changes in the waiver area during the previous 
year;
    (e) Any reportable incidents associated with the waiver area that 
occurred during the previous year;

[[Page 19760]]

    (f) Any leaks on the pipeline in the waiver area that occurred 
during the previous year;
    (g) A list of all repairs on the pipeline in the waiver area made 
during the previous year;
    (h) On-going damage prevention initiatives on the pipeline in the 
waiver area and a discussion of their success or failure;
    (i) Any changes in procedures used to assess and/or monitor the 
pipeline operating under this waiver; and
    (j) Any company mergers, acquisitions, transfers of assets, or 
other events affecting the regulatory responsibility of the company 
operating the pipeline to which this waiver applies.
    (27) Pipeline Inspection: The pipeline must be capable of passing 
ILI tools. All headers and other segments covered under this waiver 
that do not allow the passage of an ILI device must have a corrosion 
mitigation plan.
    (28) Gas Quality Monitoring: Gas quality monitoring equipment must 
be installed to permit the operator to manage and limit the 
introduction of contaminants and free liquids into the pipeline. An 
acceptable gas quality monitoring and mitigation program must be 
instituted to not exceed the following limits:
    (a) H2S (0.25 grains per 100 standard cubic feet or 4 
parts per million, maximum);
    (b) CO2 (3 percent maximum);
    (c) H2O (less than or equal to 7 pounds per million 
standard cubic feet and no free water); and
    (d) Other deleterious constituents that may impact the integrity of 
the pipeline must be instituted.
    (29) Gas Quality Control: Filters/separators must be installed at 
locations where gas is received into the pipeline where the incoming 
gas stream quality includes potentially deleterious constituents to 
minimize the entry of contaminants and to protect the integrity of 
downstream pipeline segments.
    (30) Cathodic Protection: The initial CP system must be operational 
within 12 months of placing the pipeline in service.
    (31) Interference Current Surveys: Interference surveys must be 
performed within six months of placing the pipeline in service to 
ensure compliance with applicable NACE International Standard 
Recommended Practices 0169 and 0177 (NACE RP 0169 and NACE RP 0177) for 
interference current levels. If interference currents are found, KMLP 
will determine if there have been any adverse effects to the pipeline 
and mitigate the effects as necessary. KMLP will report to PHMSA the 
results of any negative finding and the associated mitigative efforts.
    (32) Corrosion Surveys: Corrosion surveys of the affected pipeline 
must be completed within six months of placing the respective CP 
system(s) in operation to ensure adequate external corrosion protection 
per NACE RP 0169. The survey must also address the proper number and 
location of CP test stations as well as AC interference mitigation and 
AC grounding programs per NACE RP 0177.
    (33) Verification of Cathodic Protection: An interrupted close 
interval survey (CIS) must be performed in concert with ILI for all HCA 
pipeline mileage in accordance with 49 CFR 192 Subpart O reassessment 
intervals. At least one CP test station must be located within each HCA 
with a maximum spacing between test stations of one-half mile within an 
HCA. If any annual test station reading fails to meet 49 CFR 192 
Subpart I requirements, remedial actions must occur within six months. 
Remedial actions must include a CIS on each side of the affected test 
station and all modifications to the CP system necessary to ensure 
adequate external corrosion control.
    (34) Pipeline Markers: KMLP must employ line-of-sight markings on 
the pipeline in the waiver area except in agricultural areas or large 
water crossings such as lakes where line of sight signage is not 
practical. The marking of pipelines is also subject to Federal Energy 
Regulatory Commission orders or environmental permits and local 
restrictions.
    (35) Pipeline Patrolling: Pipeline patrolling must be conducted at 
least monthly to inspect for excavation activities, ground movement, 
wash-outs, leakage or other activities and conditions affecting the 
safe operation of the pipeline.
    (36) Monitoring of Ground Movement: An effective monitoring/
mitigation plan must be in place to monitor for and mitigate issues of 
unstable soil and ground movement.
    (37) Review of Risk Assessment Calculations: A copy of the C-FER 
PIRAMID risk analysis report regarding the pipe subject to this waiver 
must be submitted to PHMSA Headquarters.
    (38) Initial ILI: KMLP must perform a baseline ILI in association 
with the construction of the pipeline using a high-resolution Magnetic 
Flux Leakage (MFL) tool to be completed within three years of placing 
the pipeline in service. KMLP must also run a geometry tool after the 
backfill of the pipeline and after the dewatering from the hydrostatic 
strength test but not later than six months after placing the pipeline 
in service.
    (39) Future ILI: A second high-resolution MFL inspection must be 
performed and completed on the pipe subject to this waiver within the 
first reassessment interval required by 49 CFR Subpart O, regardless of 
HCA classification. Future ILI must be performed on a frequency 
consistent with Subpart O for the entire pipeline covered by this 
waiver.
    (40) Direct Assessment Plan: Headers, mainline valve bypasses and 
other sections covered by this waiver that cannot accommodate ILI tools 
must be part of a Direct Assessment (DA) plan or other acceptable 
integrity monitoring method.
    (41) Initial CIS: A CIS must be performed on the pipeline within 
two years of the pipeline in-service date. The CIS results must be 
integrated with the baseline ILI to determine whether further action is 
needed.
    (42) Damage Prevention Program: The Common Ground Alliance's damage 
prevention best practices must be incorporated into the KMLP damage 
prevention program.
    (43) Class 2 and 3 Pipe: Pipe installed in Class 2 and Class 3 
locations must use stress factors of 0.60 and 0.50 as required in Sec.  
192.111. Pipe in road and railroad crossings must meet the requirements 
of Sec.  192.111. Future class changes must meet the requirements of 
Sec. Sec.  192.609 and 192.611.
    (44) Anomaly Evaluation and Repair: Anomaly evaluations and repairs 
must be performed based upon the following:
(a) Anomaly Response Time
    --Any waiver area anomaly with a failure pressure ratio (FPR) equal 
to or less than 1.1 must be treated as an ``immediate repair 
condition'' per 49 CFR 192, Subpart O.
    --Any waiver area anomaly with a FPR equal to or less than 1.25 
must be repaired within 12 months.
(b) Anomaly Repair Criteria
    --All other pipe segments with anomalies not repaired must be 
reassessed according to Subpart O and ASME B31.8S requirements and 
class location factor. Each anomaly not repaired, as an immediate 
repair, must have a corrosion growth rate and ILI tool tolerance 
assigned to it per the Gas Integrity Management Program (IMP) to 
determine the maximum re-inspection interval.
    --KMLP must confirm the remaining strength (R-STRENG) effective 
area method, R-STRENG-0.85dL, and ASME B31G assessment methods are 
valid for the pipe diameter, wall thickness, grade, operating

[[Page 19761]]

pressure, operating stress level and operating temperature. KMLP must 
also use the most conservative method until confirmation of the proper 
method is made to PHMSA Headquarters.
    --Dents in the pipe in the waiver area must be evaluated and 
repaired per 49 CFR 192.309(b) for initial ILI and per 49 CFR 
192.933(d) for future ILI.
    (45) Preliminary Report: A preliminary report describing the 
results, completion dates and status of the waiver conditions must be 
completed for the pipeline and submitted to PHMSA Headquarters and the 
appropriate PHMSA regional office prior to commencing construction of 
the pipeline.
    (46) Completion Report: A completion report describing the results, 
completion dates and status of the outstanding waiver conditions must 
be submitted to PHMSA Headquarters and the appropriate regional office 
within 180 days after completion of the pipeline.
    (47) ILI Reports: A report must be submitted for the pipeline after 
the baseline ILI (MFL and Geometry) run has been performed with 
assessment and integration of the results. A report must also be 
submitted upon completion of the second ILI run. These reports must be 
submitted to PHMSA Headquarters and the appropriate PHMSA regional 
office.
    (48) Potential Impact Radius Calculation Updates: If the pipeline 
operating pressures and gas quality are determined to be outside the 
parameters of the C-FER Study, a revised study with the updated 
parameters must be incorporated into the IMP.

Waiver Limitations

    Should KMLP fail to comply with any conditions of the wavier, or 
should PHMSA determine this waiver is no longer appropriate or that the 
waiver is inconsistent with pipeline safety, PHMSA may revoke this 
waiver and require KMLP to comply with regulatory requirements of 
Sec. Sec.  192.111 and 192.201(a)(2)(i).

    Authority: 49 U.S.C. 60118(c)(1) and 49 CFR 1.53.

    Issued in Washington, DC on April 13, 2007.
Jeffrey D. Wiese,
Acting Associate Administrator for Pipeline Safety.
[FR Doc. E7-7414 Filed 4-18-07; 8:45 am]
BILLING CODE 4910-60-P