[Federal Register Volume 59, Number 123 (Tuesday, June 28, 1994)]
[Unknown Section]
[Page ]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 94-15510]
[Federal Register: June 28, 1994]
_______________________________________________________________________
Part VII
Department of Transportation
_______________________________________________________________________
Research and Special Programs Administration
_______________________________________________________________________
49 CFR Part 195
Regulatory Review: Hazardous Liquid and Carbon Dioxide Pipeline Safety
Standards; Final Rule
DEPARTMENT OF TRANSPORTATION
Research and Special Programs Administration
49 CFR Part 195
[Docket PS-127; Amdt. 195-52]
RIN 2137-AC27
Regulatory Review: Hazardous Liquid and Carbon Dioxide Pipeline
Safety Standards
AGENCY: Research and Special Programs Administration (RSPA), DOT.
ACTION: Final rule.
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SUMMARY: This rulemaking amends miscellaneous hazardous liquid and
carbon dioxide pipeline safety standards to provide clarity, eliminate
unnecessary or overly burdensome requirements, and foster economic
growth. The changes result from the regulatory review RSPA carried out
in response to the President's directive of January 28, 1992, on
reducing the burden of government regulation. The changes reduce costs
in the liquid pipeline industry without compromising safety.
EFFECTIVE DATE: This regulation is effective July 28, 1994. The
incorporation by reference of certain publications listed in the
regulations is approved by the Director of the Federal Register as of
July 28, 1994.
FOR FURTHER INFORMATION CONTACT: J. Willock, (202) 366-2392, regarding
the subject matter of this final rulemaking, or the Dockets Unit, (202)
366-5046, regarding copies of this final rulemaking or other material
that is referenced herein.
SUPPLEMENTARY INFORMATION:
Background
In a January 28, 1992, memorandum, the President wrote to
Department and agency heads about the need to reduce the burden imposed
by government regulation. The President was concerned that agencies
were not doing enough to review and revise existing regulations to
eliminate unnecessary and overly burdensome requirements. The President
recognized that regulations that do not keep pace with new technologies
and innovations impose needless costs and impede economic growth.
In response to the President's memorandum, DOT published a notice
requesting public comment on the Department's regulatory programs (57
FR 4745; Feb. 7, 1992). Commenters were asked to identify regulations
that substantially impede economic growth, may no longer be necessary,
are unnecessarily burdensome, impose needless costs or red tape, or
overlap or conflict with other DOT or federal regulations. The deadline
for submitting comments was March 2, 1992.
RSPA received comments from six organizations about the pipeline
safety regulations in part 195. Comments were from three regulated
pipeline companies, a pipeline trade association, a state pipeline
safety agency, and a federal agency. RSPA considered all comments in
its review of the regulations, and these comments are available in the
docket. Some comments will be considered in future rulemakings.
Additionally, RSPA has published a separate rulemaking ``Update of
Standards Incorporated by Reference'' (58 FR 14519; March 18, 1993)
which updates the editions of the industry standards that are
incorporated in part 195.
On November 27, 1992, RSPA published a Notice of Proposed
Rulemaking, NPRM, (57 FR 56304) proposing 18 changes to the regulations
based on the comments received from the public and asked for further
comments regarding the proposed changes. RSPA received comments from 21
organizations: 15 pipeline companies, 3 pipeline trade associations, 2
environmental organizations, and 1 county government. RSPA considered
all comments in preparation of the final rulemaking and the comments
are available in the Docket.
Advisory Committee
The Technical Hazardous Liquid Pipeline Safety Standards Committee
(THLPSSC), consisting of 15 members, was established by statute to
consider the feasibility, reasonableness, and practicability of
proposed pipeline regulations. RSPA implemented the committee balloting
process by mail. After initial balloting, the process allowed each
member to review the ballots, including comments, of all other members,
and to change his or her vote or initial comment if desired. Although
some THLPSSC members did not vote on every proposed change, a tally of
the second ballots showed that a large majority of THLPSSC members
found all the proposed changes technically feasible, reasonable, and
practicable. Nonetheless, in developing the final regulations, RSPA
considered all final THLPSSC votes and comments, including minority
positions. The following discussion explains how RSPA treated THLPSSC
positions and public comments on the proposed amendments in developing
the final rule.
Changes to Part 195 Safety Standards
The following discussion explains the changes to various standards
in part 195:
Section 195.1 Applicability.
Offshore production. Part 195 does not apply to pipelines used in
offshore production, whether on the Outer Continental Shelf or in state
offshore waters. However, this exception is clearly stated in part 195
only for production on the Outer Continental Shelf (Sec. 195.1(b)(5)).
To clarify that all offshore pipelines used in production are outside
part 195, RSPA proposed to delete from Sec. 195.1(b)(5) the phrase ``on
the Outer Continental Shelf''.
The 10 THLPSSC members who voted on the proposed amendment to
Sec. 195.1(b)(5) all approved the amendment.
In addition, RSPA received comments from three operators and two
pipeline-related associations in support of the amendment and no
adverse comments. Therefore, Sec. 195.1(b)(5) is amended as proposed in
the NPRM.
We also requested comments on whether there is a gap in the
regulation of production lines in state offshore waters. Only one
commenter responded. This commenter opined that existing state and
federal programs adequately regulate production lines in state waters.
In Louisiana, the Departments of Natural Resources and Environmental
Quality were said to have comprehensive regulations on facility
installation, operation, integrity, and removal, and sufficient
authority to address any ``gap'' that is identified. Since the other
states with production lines in state waters have similar regulations,
RSPA does not believe there is a gap in the regulation of production
lines in state waters.
In-plant piping. Part 195 does not apply to pipeline transportation
through onshore production, refining, or manufacturing facilities, or
storage or in-plant piping systems associated with such facilities
(Sec. 195.1(b)(6)). Because the physical distinction between a
regulated pipeline serving a plant and unregulated in-plant piping is
unclear, RSPA proposed to add a definition of ``in-plant piping
system'' to Sec. 195.2. The definition proposed was: ``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, not including any device
and associated piping that are necessary to control pressure in the
pipeline.'' The NPRM explained that we would consider in-plant piping
to extend to the plant boundary in the absence of a necessary pressure
control device on plant grounds.
All ten THLPSSC members who voted on this proposal supported it.
However, four members believed that because the NPRM primarily
concerned pipeline transportation rather than production, refining, or
manufacturing plants, it did not give plant owners adequate notice that
the proposed definition could affect plant piping. These members wanted
RSPA to publish a separate NPRM on the subject of in-plant piping.
RSPA does not agree that another NPRM is needed. The subject of in-
plant piping and the associated issues were clearly discussed in the
published NPRM. Also, all interested persons, including plant owners as
well as pipeline operators, were given an opportunity to comment on the
subject of in-plant piping.
RSPA received comments on the proposed definition from seven
operators, two pipeline-related associations, and one state agency. Two
operators and one association fully supported the proposal.
One operator and a pipeline-related association thought plant
owners were not adequately notified of the proposed rule, and that RSPA
should treat the subject in a separate NPRM. Our position on this issue
is given supra in response to a similar criticism by four THLPSSC
members.
Another operator was concerned that the proposed definition would
cause operator-owned components, such as pipe, meters, instruments, and
manifolds, that are located on plant grounds downstream from the
operator's pressure control device to fall outside part 195. The
operator was worried that other agencies would regulate these
components as non-transportation related facilities. We are not
persuaded, however, that the potential for such regulation is
sufficient reason to exclude the components from the definition of in-
plant piping system. The aim of the proposed definition was to
distinguish unregulated piping, not to limit the jurisdiction of other
government agencies.
In contrast, an operator of gathering and processing facilities was
concerned that part 195 would apply to plant piping that lies between
any necessary pressure control device and the connection to a pipeline.
This commenter apparently did not realize that such piping is subject
to part 195. RSPA has applied part 195 to such piping because it is
subject to pressure which is controlled by a device operators must have
to meet Sec. 195.406(b). However, this application has had little
effect on plant owners, because we hold the pipeline operator, not the
plant owner, responsible for compliance.
An operator commenting on the plant device exclusion in the
proposed definition advised us to change ``control pressure'' to
``prevent overpressure.'' This commenter said the change would avoid
making pipeline operators responsible under part 195 for nonessential
pressure control devices. We agree the suggested rewording would better
convey the intent of the proposal. But, in the final definition, we
have changed ``control pressure in the pipeline'' to ``control pressure
in the pipeline under Sec. 195.406(b)'' to convey the intent even more
precisely.
The state agency commented that if piping on plant grounds does not
include a device necessary to control pipeline pressure, the
jurisdiction of part 195 over the pipeline should not end at the plant
boundary. Instead, the state agency recommended ending jurisdiction at
a component inside the plant, such as a flange, where the pipeline can
be isolated for purposes of testing. Although operators may use such
components, part 195 does not require that they be on the pipeline.
Also, we believe the plant boundary is a more convenient demarcation of
in-plant piping than an unspecific inside-the-plant component. Thus,
the state agency's comment is not incorporated in the final definition.
The state agency, an operator, and a pipeline-related association
were concerned that because segments of transfer piping located off
plant grounds were not included in the proposed definition, a large
number of short pipelines would come under part 195. RSPA recognizes
that production, refining, or manufacturing plants often install
transfer piping off plant grounds. A plant may use this piping to
transfer hazardous liquids between its different facilities located on
the same grounds; between its different facilities located on separate
grounds (usually separated by a roadway, railway, waterway, or
industrial area); between its facilities and a transportation system,
such as a railroad or pipeline; or between its facilities and the
facilities of another plant or industrial consumer. The three
commenters thought the off-grounds segments should qualify as in-plant
piping if they connect facilities of the same plant. The association
also wanted to include under the definition off-grounds segments that
connect facilities of different plants. In addition, the operator and
association argued that the off-grounds segments pose minimum risk to
public safety and the environment, because the segments generally are
located in industrial areas, roadways, or railways. The association
further argued that a plant has the same operational control, including
response capability, over the off-grounds segments as it does over
piping on plant grounds.
In response to these comments, we note that Sec. 195.1(b)(6) echoes
section 201(3) of the Hazardous Liquid Pipeline Safety Act of 1979
(HLPSA), (49 U.S.C. app. 2001(3)), which excludes certain ``in-plant
piping systems'' from regulation under the HLPSA. Since neither the
HLPSA nor its legislative history explain ``in-plant piping,'' we adopt
an ordinary, reasonable understanding of the term. Therefore, we do not
accept the interpretation that the term includes piping that crosses
the property of others outside plant grounds. However, many plants are
separated by a public thoroughfare, and plant transfer piping crosses
the thoroughfare. A single public thoroughfare would include any road,
from a country lane to an interstate highway, but it does not include a
railroad. Because transfer piping that crosses such thoroughfares is
comparable in most respects to other in-plant piping, RSPA considers
the in-plant piping exception to include the thoroughfare crossings.
The thoroughfare exception does not apply to inter-facility lines or
delivery lines, because these lines are distinct from in-plant piping.
We did not intend the proposed definition of ``in-plant piping
systems'' to expand our present interpretation of the term. So the
final definition does not incorporate any of the comments concerning
piping located off plant grounds other than for thoroughfare crossings.
However, the proposed definition's first use of the term
``pipeline'' is changed to ``pipeline or other mode of
transportation.'' This change is needed to include, within the
definition, piping on plant grounds that transfer hazardous liquid or
carbon dioxide between plant facilities and modes of transportation
other than pipeline.
Terminal facilities. Part 195 does not apply to the transportation
of hazardous liquid or carbon dioxide by vessel, aircraft, tank truck,
tank car, or other vehicle, or by terminal facilities used exclusively
to transfer hazardous liquid or carbon dioxide between such modes of
transportation (Sec. 195.1(b)(7)). RSPA proposed to amend
Sec. 195.1(b)(7) to clarify that terminal facilities located off
terminal grounds are subject to part 195, and to distinguish
unregulated terminal facilities from a regulated pipeline entering or
leaving the terminal. As with the proposed in-plant piping definition,
any device and associated piping on terminal grounds necessary to
control pressure in a regulated pipeline would not be excepted from
part 195.
The THLPSSC voted to approve this proposal, but four members
believed the NPRM did not give terminal owners adequate notice that the
proposed amendment could affect their piping. These members wanted RSPA
to publish a separate NPRM on the subject. For the reasons stated supra
in response to a similar argument by these THLPSSC members concerning
in-plant piping, RSPA does not agree that another NPRM is needed.
Five operators and two pipeline-related associations commented on
the proposed amendment to Sec. 195.1(b)(7). Of these commenters, two
operators and one association agreed with the proposal.
A few commenters expressed the same concerns about the proposed
amendment to Sec. 195.1(b)(7) as they did about the proposed in-plant
piping definition. These concerns were that the NPRM did not adequately
notify plant (terminal) owners of the proposed rule, and that some
operator-owned components located on plant (terminal) grounds would
fall outside part 195. Our response to these concerns is the same as
stated supra regarding in-plant piping.
In regard to transfer lines located outside terminal grounds at
ports, an operator and a pipeline-related association pointed out that
the U.S. Coast Guard regulates transfers between terminal storage and
dock facilities. These commenters suggested that RSPA and Coast Guard
develop a memorandum of understanding to limit Coast Guard's
regulations to dock facilities.
We recognize that Coast Guard and RSPA jurisdictions overlap in
port areas, but the two agencies have different responsibilities. Also,
the overlap does not automatically result in regulatory conflicts, and
the commenters did not mention any. Nonetheless, though we have not
changed the final rule as a result of this comment, in enforcing part
195 at port areas, RSPA will act appropriately to resolve any
unnecessary regulatory burdens.
Carbon dioxide injection system. Section 195.1(b)(8) provides that
part 195 does not apply to ``[t]ransportation of carbon dioxide
downstream from a point in the vicinity of the well site at which
carbon dioxide is delivered to a production facility.'' RSPA proposed
to amend this section to clarify that the exception covers pipelines
used in the injection of carbon dioxide for oil recovery operations.
The THLPSSC approved the proposed amendment (10 voted in favor and
5 did not vote), and we received no adverse comments from the public.
The proposed amendment to Sec. 195.1(b)(8) is, therefore, adopted as
final.
Section 195.2 Definitions.
The proposed revision of the definition of ``Secretary'' is not
adopted in this rulemaking. Instead, it is being handled in an omnibus
rulemaking covering all regulations involving pipeline safety.
The definition of ``In-plant piping system'' is discussed above in
Sec. 195.1 Applicability.
Two commenters objected to the proposed definition for petroleum
products because of its use of the terms ``flammable'', ``toxic'', and
``corrosive'' which are not defined under part 195. The commenters
stated that absent specific definitions for these terms, their
applicability could be unclear.
RSPA agrees with the comments about the lack of clarity in the
proposed definition for petroleum products. So, the final rule for this
section includes new definitions for ``flammable'', ``toxic'', and
``corrosive'' that come from the definitions contained in 49 CFR part
173 for Transportation and Packaging of Hazardous Materials for the
terms ``flammable liquid'', ``poisonous material'', and ``corrosive
material'', respectively. RSPA has adopted the definition of
``poisonous material'' for ``toxic'' because it considers the terms
synonymous.
Sections 195.2, 195.106, 195.112, 195.212 and 195.413 (Nominal Outside
Diameter of the Pipe in Inches)
RSPA proposed to standardize the dimensioning of pipe size
throughout part 195 (Changes are made to Secs. 195.2, 195.106(b),
195.106(c), 195.112(c), 195.212(b)(3)(ii) and 195.413(a)). All 10
THLPSSC members who voted were in favor of the proposal and no
commenter objected thereto. Accordingly, the proposed amendment is
adopted as final.
Section 195.3 Matter incorporated by reference.
Section 195.3 sets out the general requirements for the
incorporation in the regulations of industry standards for the design,
construction and operation of hazardous liquid and carbon dioxide
pipelines. Paragraph 195.3(a) states that incorporation of a document
by reference has the same force as if the document were copied in the
regulations. Some operators have misinterpreted this section to mean
that they must comply with all of the terms contained in a referenced
document. Accordingly, RSPA hereby revises Sec. 195.3(a) to clarify
that an entire document is not incorporated when the document is
incorporated by reference; rather, only those portions specifically
referenced in the regulations are incorporated.
The rule is being revised to conform to a recent update of
references in another rulemaking (Update of Standards Incorporated by
Reference (58 FR 14519; March 18, 1993)). Also, references to ASME/ANSI
Codes B31.8 and B31.G are being added. The 10 THLPSSC members who voted
and 7 commenters favored the revision.
Section 195.5 Conversion to service subject to this part.
Section 195.5 regulates the conversion of steel pipelines to
hazardous liquid or carbon dioxide service that is subject to part 195.
Under Sec. 195.5(a)(4), a converted pipeline must be hydrostatically
tested to substantiate the maximum operating pressure (MOP) permitted
by Sec. 195.406.\1\
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\1\Section 195.5(a)(4) actually uses the term ``maximum
allowable operating pressure,'' but for consistency with
Sec. 195.406, this term is changed below to MOP by removing the word
``allowable.''
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To substantiate the MOP of a converted pipeline, an operator must
know the pipe design pressure (see current Sec. 195.406(a)(1)).
Consequently, if pipe design pressure is unknown, a steel pipeline may
not be converted under Sec. 195.5. Although the design pressure of
components is an MOP factor under Sec. 195.406(a)(2), pipeline
components are normally designed to be as strong or stronger than
attached pipe. Thus, pipe design is the critical factor in
substantiating MOP under Sec. 195.5(a)(4), and lack of knowledge of
component design pressure is not a significant safety concern.
RSPA proposed to amend Sec. 195.5 to permit conversion using an
approach found in section 845.214 and Appendix N of ASME B31.8 for gas
pipelines whose design pressure is unknown. Under this proposal,
operators would pressure test the pipeline under Appendix N until pipe
yield occurs. Instead of design pressure, this yield test pressure
would be used to compute MOP by applying certain reduction factors to
80 percent of the first pressure that produces pipe yield.
All THLPSSC members who voted on the proposed amendment to
Sec. 195.5 supported it in concept. However, two members thought the
wording of Appendix N should be copied directly into part 195 to avoid
referencing a gas pipeline code in liquid pipeline regulations. We
believe the principles of Appendix N apply equally to gas and liquid
pipelines. And since the B31.8 Code is widely used, operators of
hazardous liquid or carbon dioxide pipelines will not find it difficult
to obtain and apply Appendix N.
RSPA received five comments on the proposed amendment to
Sec. 195.5. Two operators and a pipeline-related association agreed
with the proposed amendment.
One operator suggested that if pipelines operating at less than 20
percent of specified minimum yield strength (SMYS) are subject to
Sec. 195.5, RSPA should allow operators up to 10 years to meet the
testing requirements. At present, none of the standards in part 195,
including Sec. 195.5, applies to pipelines operating at less than 20
percent of SMYS (see Sec. 195.1(b)(3)). However, this commenter may
have had in mind Sec. 206 of the Pipeline Safety Act of 1992 (Pub. L.
102-508), which provides that exceptions to regulations under the
Hazardous Liquid Pipeline Safety Act of 1979 (49 U.S.C. app. 2001 et
seq.), such as part 195, may not be based solely on low internal
stress. Because of this statutory mandate, RSPA has proposed to apply
part 195 to certain low-stress hazardous liquid pipelines (Docket PS-
117; 58 FR 12213; March 3, 1993). Still, that proposal would not
require any existing low-stress hazardous liquid pipeline to be tested
under Sec. 195.5, because such pipelines would not be converted
pipelines. Of course, if part 195 becomes applicable to low stress
pipelines, any pipeline converted to low stress hazardous liquid
service subject to part 195 would have to be tested under Sec. 195.5.
But, since testing is the backbone of the conversion process, RSPA does
not believe Sec. 195.5 should be amended to extend the time for testing
to 10 years.
A state agency was concerned that if test pressure must be measured
at the high elevation point of test segments, the test could stress the
low point of the segment beyond yield. However, the Appendix N test
method should not result in overstress at the low elevation, because
the method does not require increases in test pressure after the first
yield occurs in the test segment.
In a separate rulemaking proceeding (Docket No. PS-124; 57 FR
39572; August 31, 1992), RSPA proposed to allow the use of the Appendix
N method in converting pipelines to gas service under 49 CFR 192.14.
This gas pipeline conversion standard is similar to Sec. 195.5.
Comments to that notice argued that pressure testing to yield is
unnecessary to qualify certain pipelines that operate at low stress
(generally pipelines 12\3/4\ inches or less in nominal outside diameter
operating at pressures of 200 psig or less). RSPA believes these
comments are also relevant to hazardous liquid pipelines. All other
factors being equal, hazardous liquid pipelines operating at low
internal stress present less risk of failure from time-dependent
defects than higher stress hazardous liquid pipelines. Because of the
lower risk, RSPA has modified the final rule to provide that pipelines
12\3/4\ inches or less in nominal outside diameter to be operated at a
pressure of 200 psig or less may be converted without testing to yield.
The MOP of such pipelines may be determined under Sec. 195.406 by using
200 psig as pipe design pressure.
The proposed rule has been redrafted to improve clarity, to better
relate conversion to design pressure and MOP under Sec. 195.406, and to
include the changes discussed supra. In the final rule, the proposed
amendment to Sec. 195.5(a)(1) is revised and published as an amendment
to Sec. 195.406(a)(1). This latter section deals specifically with pipe
design pressure and MOP. As set forth infra, revised Sec. 195.406(a)(1)
provides that when pipe design pressure is unknown for steel pipelines
being converted, a reduced value of first yield hydrostatic test
pressure may be used as design pressure to compute MOP. If the pipeline
to be converted is 12\3/4\ inches or less in nominal outside diameter
and is not yield tested, 200 psig may be used as design pressure.
Section 195.8 Transportation of hazardous liquid or carbon dioxide in
pipelines constructed with other than steel pipe.
The proposal to replace the word ``he'' with ``the Secretary'' to
remove any implication of gender is not adopted in this rulemaking.
Instead, this proposal will be handled in an omnibus rulemaking to make
minor clarifications and error corrections covering all the pipeline
safety regulations.
Section 195.50 Reporting accidents and Sec. 195.52 Telephonic notice
of certain accidents.
Sections 195.50(f) and 195.52(a)(3) require operators to prepare
reports and give telephonic notice of accidents, respectively, when the
estimated property damage due to an accident exceeds $5,000. RSPA
discovered from its regulatory review and previous enforcement cases
that a significant amount of confusion exists among pipeline operators
as to which cost estimates must be included in calculating the
``estimated property damage to the property of the operator or others *
* *'' Frequently, when reporting accidents, pipeline operators fail to
include as ``property damage'' the fair market value of the product
released or those costs associated with clean-up and recovery efforts.
RSPA believes these costs should be included when reporting accidents.
Because the $5,000 reporting requirement requires the reporting of
minor accidents, RSPA proposed amending Secs. 195.50(f) and
195.52(a)(3) to increase the reporting threshold to $50,000, the same
level as required in 49 CFR part 192 and to include as property damage
the value of the product released and the costs associated with clean-
up and recovery efforts. The THLPSSC voted 10 to 0 in favor of the
change (5 members did not vote). Two of those favoring the proposed
changes recommended that RSPA modify the final rule to limit property
damage to fair market value of the lost product and initial clean-up
and product recovery costs. One member said that clean-up and recovery
costs should not be included in total property damage.
Three commenters disagreed with the proposed changes and
recommended that the rule be withdrawn. One complaint was that the
statistical base would be discontinuous because, in the future, RSPA
would not receive information on accidents costing between $5,000 and
$50,000. Another complaint was that the change could affect the
development of environmental protection requirements. RSPA understands
that a change in reporting levels will cause a slight skewing due to
truncation of the data, but believes requiring operators to report
accidents based solely on the $5,000 property damage criterion is
unnecessary and burdensome. Significant accidents will still be
reported because the other criteria (especially those that are
environmentally related) requiring reports will be unchanged: (1)
Explosion or fire, (2) loss of 50 barrels of liquid, (3) escape of five
barrels a day of highly volatile liquids, (4) a death, (5) bodily harm,
or (6) resulted in the pollution of any stream. Because these
requirements remain unchanged, those operators with more frequent small
releases will still be identified. As to a skewing of the data, those
organizations that keep track of such statistical data should be able
to make adjustments to account for such changes. Also, as explained in
the NPRM, this change will make the liquid safety reporting
requirements consistent with the gas safety reporting requirements
which will eliminate confusion. The rule change should have little, if
any, effect on the environment because the same spill volume reporting
criteria remain in effect. Only the dollar level of the reporting
criterion is being changed.
Two commenters supported the rule changes as they were written.
Five others favored the changes, but proposed modification of the rules
to explain more fully the meaning of ``estimated total damage'' in
order to spell out the items that must be covered. They said that
``estimated total damage'' is ambiguous and confusing and subject to
interpretation. One commenter stated that the costs of subsurface
restoration should be excluded from property damage because it is
nearly impossible to estimate the subsurface restoration costs within
the time allowed to report the accident.
RSPA agrees that early estimates of the costs to clean-up a liquid
spill may not be exact; however, the operator should, at a later date,
submit a revised report that provides more reliable cost figures for
the clean-up.
RSPA is clarifying the issue by amending Sec. 195.50(f) to read:
``(f) 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'' and Sec. 195.52(a)(3)
to read: ``(3) Caused 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.''
Section 195.106 Internal design pressure.
Section 195.106(a) prescribes the formula for calculating the
design pressure of steel pipe. In addition, Sec. 195.106(b) regulates
the pipe yield strength used in the design pressure formula. When the
specified minimum yield strength (SMYS) of pipe is unknown,
Sec. 195.106(b) requires that yield strength be derived from tensile
tests on random samples of pipe. Based on a comparable gas pipeline
safety standard (49 CFR 192.107(b)(2)), RSPA proposed to amend
Sec. 195.106(b) to allow operators to use 24,000 psi as yield strength
if pipe of unknown SMYS is not tensile tested. Editing changes to
Sec. 195.106(b) were also proposed.
The 10 THLPSSC members who voted on the proposed amendment of
Sec. 195.106(b) supported it (5 did not vote). In addition, RSPA
received comments from four operators and one pipeline-related
association. The association and three of the operators agreed with the
proposal. One of these operators suggested further editing, part of
which RSPA has included in the final rule.
One operator was concerned that the proposed rule could
unjustifiably reduce the MOP of its pipelines. The operator said its
pipelines are made of Grade B pipe (yield strength at least 35,000 psi)
or better. However, some pipelines may contain pipe for which
documentation of yield strength or tensile testing does not exist. For
such pipe, without new tensile testing, yield strength would have to be
assumed to be 24,000 psi. The operator suggested that RSPA allow
operators to use appropriate evidence besides tensile tests to
demonstrate the yield strength of pipe.
In response to this comment, we note, first, that the proposed
amendment to Sec. 195.106(b) would not affect the design pressure of
existing pipelines unless they are replaced, relocated, or otherwise
changed (see Sec. 195.100). Second, Sec. 195.106(b) currently requires
operators to use as yield strength either SMYS or a value based on
tensile testing. So the operator's apparent difficulty in verifying
yield strength is a problem of compliance with the current rule. Third,
the proposed rule would relax the burden of tensile testing only when
MOP does not exceed the level that corresponds to a yield strength of
24,000 psi. When a higher MOP is desired, operators must use the
tensile testing option. Finally, RSPA is not aware of any acceptable
evidence of the yield strength of pipe of unknown SMYS apart from
appropriate tensile testing. Thus, the amendments to Sec. 195.106(b),
as discussed above, are adopted.
Section 195.204 Inspection-general.
The THLPSSC voted 10 to 0 in favor of the proposed change to make
the language gender neutral and, except for a minor correction, no
objections were received from commenters. The proposed change is
adopted as corrected.
Section 195.228 Welds; standards of acceptability.
One of the comments we received on proposed amendments to
nondestructive testing requirements under Sec. 195.234(e) (discussed
infra) concerned the standards for acceptance of weld flaws
(Sec. 195.228(b)). A pipeline-related association asked us to
incorporate by reference the alternative acceptance standards for girth
welds that are in the Appendix to American Petroleum Institute (API)
Standard 1104 (17th edition). For weld acceptability, Sec. 195.228(b)
now references the standards in Section 6 of API Standard 1104.
In a notice of proposed rulemaking involving our review of the gas
pipeline safety standards in 49 CFR part 192 (Docket PS-124; 57 FR
39572; August 31, 1992), RSPA proposed to allow gas operators to apply
the API appendix in addition to section 6 criteria. Although that
proposal was based on a petition by API to incorporate the appendix by
reference in both parts 192 and 195, we overlooked the request to
include such a proposal in the present rulemaking.
In the part 192 rulemaking, RSPA's gas pipeline safety advisory
committee voted to support the proposed amendment. Also, all but one of
the public comments were in favor of allowing use of the Appendix of
API Standard 1104.
The dissenting commenter was concerned that industry inspection
personnel may not be qualified to apply the appendix. However, this
commenter may not have recognized that under Secs. 192.243(b) and (c),
operators must ensure that nondestructive testing is performed in
accordance with written procedures by persons who have been properly
trained and qualified. Sections 195.234(b) and (c) provide similar
requirements for nondestructive testing of welds on hazardous liquid
and carbon dioxide pipelines. RSPA believes these requirements are
adequate to assure proper application of the appendix.
The Appendix of API Standard 1104 applies equally to girth welds in
gas and liquid pipelines. This amendment is not mandatory, rather it
provides pipeline operators an optional operating procedure. In view of
the prior opportunity for public comment on use of the appendix for gas
pipelines, the favorable response by public commenters and RSPA's
advisory committee, and the fact that use of the appendix would not be
mandatory, we believe that a further opportunity for public comment is
unnecessary to allow use of the appendix under Sec. 195.228(b). We feel
this amendment is a logical outgrowth of the Notice and furthers our
efforts to make parts 192 and 195 consistent wherever possible. This
amendment will not have a substantial impact on the regulated
community.
Thus, in accordance with 5 U.S.C. 553(b)(3)(B), we are amending
Sec. 195.228(b) to reference the appendix without further rulemaking
notice. However, should any person be adversely affected by this
decision or wish to change the final rule, that person may submit a
petition for reconsideration under RSPA's rulemaking procedures in 49
CFR 106.35.
The final rule provides that the appendix may be used only for
girth welds to which the appendix applies. For example, as section A.1
of the appendix states, neither welds in pump stations nor welds used
to connect fittings and valves are covered by the appendix. Also, the
appendix applies only to girth welds between pipe of equal nominal wall
thickness.
Section 195.234 Welds: Nondestructive testing.
Section 195.234(e) requires that ``100 percent of each day's girth
welds installed in * * * [certain] locations must be nondestructively
tested 100 percent unless impracticable, in which case at least 90
percent must be tested.'' RSPA proposed to amend Sec. 195.234(e) to
clarify that ``90 percent'' pertains to the number of girth welds that
must be tested over their entire circumference.
In addition, Sec. 195.234(g) requires: ``At pipeline tie-ins 100
percent of the girth welds must be nondestructively tested.'' RSPA
proposed to clarify that this standard applies to tie-ins of
replacement sections of pipeline.
The THLPSSC supported the proposed amendments, although one member
thought part 195 should define the word ``impracticable.'' We did not
adopt this recommendation because the word is used in its ordinary
dictionary sense.
Three operators and two pipeline-related associations commented on
the proposed amendments. Three commenters agreed with the proposal, one
suggested editing changes, and one made a related proposal discussed
supra under the heading, ``Sec. 195.228(b) Welds; standards of
acceptability.'' Although we did not adopt all the editing suggestions,
these comments helped us provide clarity to the final rule.
In addition, one commenter thought the proposed amendment of
Sec. 195.234(g) was unnecessary because Sec. 195.200 already indicates
that Sec. 195.234(g) applies to replacement sections. Moreover, the
commenter thought adding the proposed phrase to Sec. 195.234(g) would
create confusion over whether Secs. 195.234(a) through (f) apply to
replacement sections. While these observations have theoretical merit,
in practice, some operators have failed to recognize that ``pipeline
tie-ins'' include tie-ins of replacement sections. The clarifying
phrase adds emphasis where it is apparently needed to assure compliance
with the full extent of the rule. Section 195.234(g) is, therefore,
adopted as proposed.
Sections 195.246 Installation of pipe in a ditch and 195.248 Cover
over buried pipeline.
Section 195.246(b) is inconsistent with Sec. 195.413(b)(3) for pipe
in the Gulf of Mexico and its inlets (See Sec. 195.2 Definitions) under
water less than 15 feet deep but at least 12 feet deep, because
Sec. 195.246(b) permits the pipe to be without cover or to be above the
seabed if properly protected. Such pipe is a ``hazard to navigation''
under the definition of that term in Sec. 195.2, and must have the
minimum cover required by Sec. 195.413(b)(3). In addition,
Secs. 195.248(a) and (b) are inconsistent with Sec. 195.413(b)(3) for
pipe in the Gulf of Mexico and its inlets under water less than 12 feet
deep. Section 195.248(a) allows pipe to be less than 12 inches below
the seabed (i.e., a hazard to navigation). In certain instances,
Sec. 195.248(b) allows pipe to be without cover or less than 12 inches
below the seabed. Neither condition is allowed under
Sec. 195.413(b)(3). In light of these inconsistences, RSPA proposed in
the NPRM to amend Secs. 195.246(b) and 195.248(a) and (b) to correct
the problem.
Ten THLPSSC members favored the proposed changes (5 members did not
vote). One of the members favoring the changes said it would make more
sense to retain the existing regulation which operators have adhered to
for years. In similar manner, two commenters and one pipeline-related
organization agreed with the proposal. One commenter and two pipeline-
related organizations disagreed and suggested that references to a
depth of 15 feet in the rule be eliminated. RSPA proposed changes to
Secs. 195.246(b), 195.248(a) and 195.248(b) so these sections would
conform with Public Law 101-599 (section 1, 104 Stat. 3038 (1990))
which requires burial of pipe where the subsurface is under 15 feet of
water as measured from mean low water. Therefore, Secs. 195.246(b),
195.248(a) and 195.248(b) are adopted as proposed in the NPRM.
Section 195.262 Pumping equipment.
Section 195.262(d) regulates the location of pumping equipment. The
rule prohibits the installation of pumping equipment on property not
under the operator's control. It also prohibits installation less than
50 feet from the pump station boundary. RSPA proposed to amend
Sec. 195.262(d) to clarify that these two restraints on location apply
conjunctively not alternatively.
The THLPSSC members who voted on the proposed amendment supported
it in concept, but 5 members recommended further editing of the rule
for clarity. Although three of the five persons who commented on the
proposal supported it as proposed, the other two commenters thought
further clarifying changes were needed. In view of these comments and
THLPSSC views, we have modified the final rule based on identical
wording suggested by five THLPSSC members and one commenter.
Section 195.304 Testing of components.
Section 195.304(b) excludes from hydrostatic testing under part 195
any component that is the only item being replaced or added to a
pipeline system if the component or a prototype was tested at the
factory. RSPA proposed to amend Sec. 195.304(b) to clarify that the
excluded components do not include pipe.
The THLPSSC fully supported the proposed amendment. Of the six
comments from the public on the proposal, a pipeline-related
association and two operators agreed with it, while three operators
suggested changes.
An operator suggested that instead of amending Sec. 195.304(b), we
should revise the definition of ``component'' to exclude pipe. We did
not adopt this suggestion because the revision would affect every rule
in part 195 that uses the term ``component.'' Editing suggested by
another operator was not adopted because it concerned matters not
addressed in the NPRM.
One operator felt pipe should be excluded from hydrostatic testing
under Sec. 195.304(b) to the same extent as other components. The
operator said that hydrostatically testing short sections of mill
tested pipe is duplicative, costly, and not needed for safety. Although
the NPRM did not propose to alter the existing requirement that
replacement sections of pipe of any length must be hydrostatically
tested to part 195 standards before operation, we do not agree with
this commenter's contention. Normal pipe mill tests are not duplicative
of part 195 tests, and are not a proven safe alternative to part 195
requirements. However, for short sections of replacement pipe, part 195
test requirements could be met anywhere, including, by prior
arrangement with the operator, in the pipe mill. So if an operator
wishes to avoid field testing of short replacement sections of pipe, it
only needs to assure that the mill tests of those sections were done in
accordance with part 195 test requirements.
Section 195.406 Maximum operating pressure.
The changes to Sec. 195.406 are discussed supra under Sec. 195.5.
Section 195.412 Inspection of rights-of-way and crossings under
navigable waters.
Section 195.412(a) requires an operator, at intervals not exceeding
3 weeks, but at least 26 times each calendar year, to inspect the
surface conditions on or adjacent to each pipeline right-of-way.
Because some surface condition activities that affect the safety and
operation of pipelines are more visible from aerial patrols than from
walking or driving the right-of-way, RSPA proposed that the section be
changed to clarify that aerial patrols are an optional method of
compliance. No comments were received regarding the change and the
THLPSSC voted 10 to 0 in favor of the change (5 members did not vote).
Accordingly, the change to Sec. 195.412(a) is adopted as proposed.
Section (b) requires operators, at intervals not exceeding 5 years,
to inspect each crossing under a navigable waterway (except offshore)
to determine the condition of the crossing. The purpose of the
inspection is to look for any damage, unanticipated loading, or loss of
protection that could threaten the safety of the pipeline. We stated in
the NPRM that bored crossings are usually so deep that there is little
likelihood the pipeline could be affected by waterway-related events,
such as scouring or anchor dragging. We proposed to add an exception to
Sec. 195.412(b) to cover bored crossings that are too deep to be
subject to waterway-related damage.
The THLPSSC voted 10 to 0 in favor of the rule (5 members did not
vote). However, a state pipeline agency suggested the existing
regulation be retained. The agency stated that a pipeline operator
cannot be 100 percent sure a bored crossing is so deep it cannot be
affected as stated. RSPA received four additional comments, three of
which expressed an opinion that the phrase ``too deep to anticipate
damage from waterway conditions or vessel traffic'' is vague and
inappropriate. The other commenter said the proposal is unduly
restrictive and should be refocused from bored crossings to a more
generic performance standard potentially including all crossings.
In view of the comments received, RSPA agrees with those who opined
that ``too deep to anticipate damage from waterway conditions or vessel
traffic'' is too vague. In the absence of a recognized standard on the
subject, it is too speculative to judge when bored crossings are buried
at a sufficient depth to be safe from damage by external forces.
Therefore, it is in the interest of public safety that the current rule
requiring inspection at intervals not exceeding 5 years be retained.
Accordingly, the proposed change to Sec. 195.412(b) is not adopted.
Section 195.416 External Corrosion Control.
Section 195.416(a) states that each operator shall, at intervals
not exceeding 15 months, but at least once each calendar year, conduct
tests on each underground facility that is under cathodic protection to
determine whether protection is adequate. RSPA is clarifying the rule
to reduce any misunderstanding regarding what is meant by
``underground.'' The word ``underground'' in this paragraph has meant
any facility that is buried or in contact with the ground. This rule
clarification will not change the burden on operators because RSPA
compliance inspectors have consistently required any facility in
contact with the ground to be cathodically protected.
RSPA received two comments regarding the change to Sec. 195.416(a).
One commenter recommended that offshore pipelines be excluded from
annual testing requirements. RSPA believes there is no acceptable
substitute for regular testing to determine if corrosion protection of
all lines, both onshore and offshore, is adequate. Accordingly, ``in
contact with the ground or submerged'' is added to the rule to assure
that all underwater pipelines, both onshore and offshore, are included
in the definition. The other commenter suggested requiring the testing
of ``carrier pipes'' in casings. ``Carrier pipes'' are normally buried
and subject to the rule. The THLPSSC voted 10 to 0 in favor of the
proposed change (5 members did not vote). The revision to
Sec. 195.416(a) is adopted as modified.
Section 195.416(f) requires that any pipe found to be generally
corroded so that the remaining wall thickness is less than the minimum
thickness required by the pipe specification tolerances must either be
replaced with coated pipe that meets the requirements of part 195 or,
if the area is small, must be repaired. However, the operator need not
replace generally corroded pipe if the operating pressure is reduced to
be commensurate with the limits on operating pressure specified in
Sec. 195.406, based on the actual remaining wall thickness.
Section 195.416(g) states that if localized corrosion pitting is
found to exist to a degree where leakage might result, the pipe 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.
RSPA recognizes that paragraphs (f) and (g) do not provide guidance
for an operator's use in determining the strength of the actual
remaining wall thickness of corroded steel pipe. To provide such
guidance, RSPA proposed amending Sec. 195.416(h) to adopt the ASME
Manual B31G procedure for determining the remaining strength of
corroded steel pipe in existing pipelines. Application of the procedure
was proposed to be in accordance with the limitations set out in the
B31G Manual. The rule would provide guidance as to whether a corroded
region (not penetrating the pipe wall) may be left in service; this
option might require a reduction in maximum allowable operating
pressure, but may be more economical than replacement or repair of the
corroded pipe.
Ten THLPSSC members voted for the proposal (5 members did not
vote).
Comments relative to Sec. 195.416(h) were received from five
commenters. One commenter said the proposal to change Sec. 195.416(h)
is inappropriate and should be redone to be consistent with
Sec. 192.485. Others stated that the proposal was unnecessarily
restrictive because it did not allow the use of other proven industry
developed methods for determining the remaining strength of corroded
pipelines. The most noteworthy method mentioned was ``A Modified
Criterion for Evaluating the Remaining Strength of Corroded Pipe (with
RSTRENG disk)'' developed by Battelle under the Pipeline Research
Committee of the American Gas Association (AGA). (Project PR 3-805,
December 1989, AGA catalog No. L51609). Project PR 3-805 was undertaken
to devise a modified criterion that, while still assuring pipeline
integrity, would eliminate as much as possible the excessive
specifications embodied in the ASME B31G manual. The AGA modified
criterion, using a complex analysis approach, can be carried out by
means of a PC-based program called RSTRENG. The modified criterion can
also be applied via tables or curves or a long-hand equation if a
simplified analysis is preferred.
The addition of the modified criterion to the rule does not
compromise safety because it merely accepts an established pipeline
industry guideline, and does not impose new requirements on the
operators. Accordingly, RSPA is amending Sec. 195.416(h) to include the
AGA/Battelle--A Modified Criterion for Evaluating the Remaining
Strength of Corroded Pipe (with the computer disk RSTRENG).
Rulemaking Analyses
Impact Assessment
This final rule is not considered a significant regulatory action
under section 3(f) of Executive Order 12866 and, therefore, was not
subject to review by the Office of Management and Budget. The rule is
not considered significant under the regulatory policies and procedures
of the Department of Transportation (44 FR 11034).
A Regulatory Evaluation has been prepared and is available in the
docket. RSPA estimates the proposed changes to existing rules would
result in an estimated savings of $1,534,000 per year for the hazardous
liquid pipeline industry at no cost to the industry, and with no
adverse effect on safety. As discussed above, these savings would come
largely from the use of new technology, greater flexibility in
constructing and operating pipelines, and the elimination of
unnecessary requirements.
Federalism Assessment
RSPA has analyzed the proposed rules under the criteria of
Executive Order 12612 (52 FR 41685; October 30, 1987). The regulations
have no substantial effects on the states, on the current federal-state
relationship, or on the current distribution of power and
responsibilities among the various levels of government. Thus,
preparation of a federalism assessment is not warranted.
Regulatory Flexibility Act
RSPA criteria for small companies or entities are those with less
than $1,000,000 in revenues and are independently owned and operated.
Few of the companies subject to this rulemaking meet these criteria.
Accordingly, based on the facts available concerning the impact of this
proposal, I certify under Section 605 of the Regulatory Flexibility Act
that this proposal would not have a significant economic impact on a
substantial number of small entities. This rule applies to intrastate
and interstate pipeline facilities used in the transportation of
hazardous liquids or carbon dioxide.
Paperwork Reduction Act
The documentation for the information collection requirements for
part 195 was submitted to the Office of Management and Budget (OMB)
during the original rulemaking processes. Currently, regulations in
part 195 are covered by OMB Control Numbers 2137-0047 (approved through
May 31, 1994), 2137-0578 (approved through October 31, 1994) and 2137-
0583 (approved through May 31, 1994). There are no new information
collection requirements in this final rule.
List of Subjects in 49 CFR Part 195
Ammonia, Carbon dioxide, Incorporation by reference, Petroleum,
Pipeline safety, Reporting and recordkeeping requirements.
In consideration of the foregoing, RSPA is amending 49 CFR part 195
as follows:
PART 195--[AMENDED]
1. The authority citation for part 195 continues to read as
follows:
Authority: 49 app. U.S.C. 2002 and 2015; and 49 CFR 1.53.
2. In Sec. 195.1, the introductory text of paragraph (b) is
republished, paragraph (b)(5) is revised, in paragraph (b)(6) a hyphen
is added between the words ``in'' and ``plant'', and paragraphs (b)(7)
and (b)(8) are revised to read as follows:
Sec. 195.1 Applicability.
* * * * *
(b) This part does not apply to--
* * * * *
(5) Transportation of hazardous liquid or carbon dioxide in
offshore pipelines which are located upstream from the outlet flange of
each facility where hydrocarbons or carbon dioxide are produced or
where produced hydrocarbons or carbon dioxide are first separated,
dehydrated, or otherwise processed, whichever facility is farther
downstream;
* * * * *
(7) 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 that 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, not including any device
and associated piping that are necessary to control pressure in the
pipeline under Sec. 195.406(b); and
(8) Transportation of carbon dioxide downstream from the following
point, as applicable:
(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 that transports carbon dioxide to injection wells or to headers
or manifolds from which pipelines branch to injection wells.
* * * * *
3. In Sec. 195.2, the introductory text is republished, definitions
for Corrosive product, Flammable product, In-plant piping system,
Petroleum, Petroleum product, and Toxic product are added in
alphabetical order to read as follows:
Sec. 195.2 Definitions.
As used in this part--
* * * * *
Corrosive product means ``corrosive material'' as defined by
Sec. 173.136 Class 8-Definitions of this chapter.
* * * * *
Flammable product means ``flammable liquid'' as defined by
Sec. 173.120 Class 3-Definitions of this chapter.
* * * * *
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).
* * * * *
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.
* * * * *
Toxic product means ``poisonous material'' as defined by
Sec. 173.132 Class 6, Division 6.1-Definitions of this chapter.
Secs. 195.2, 195.112, 195.212, 195.413 [Amended]
4. In the list below, for each section indicated in the left
column, the phrase indicated in the middle column is removed and the
phrase indicated in the right column is added:
----------------------------------------------------------------------------------------------------------------
Section Remove Add
----------------------------------------------------------------------------------------------------------------
195.2, Gathering line............... 8 inches or less in nominal diameter 219.1 mm (8\5/8\ in) or less nominal
outside diameter.
195.112(c).......................... An outside diameter of 4 inches or A nominal outside diameter of 114.3
more. mm (4\1/2\ in) or more.
195.212(b)(3)(ii)................... The pipe is 12 inches or less in The pipe is 323.8 mm (12\3/4\ in) or
outside diameter. less nominal outside diameter.
195.413(a).......................... Except for gathering lines of 4-inch Except for gathering lines of 114.3
nominal diameter or smaller. mm (4\1/2\ in) nominal outside
diameter or smaller.
----------------------------------------------------------------------------------------------------------------
5. In Sec. 195.3, paragraph (a) is revised to read as follows:
Sec. 195.3 Matter incorporated by reference.
(a) Any document or portion thereof incorporated by reference in
this part is included in this part as though it were printed in full.
When only a portion of a document is referenced, then this part
incorporates only that referenced portion of the document and the
remainder is not incorporated. Applicable editions are listed in
paragraph (c) of this section in parentheses following the title of the
referenced material. Earlier editions listed in previous editions of
this section may be used for components manufactured, designed, or
installed in accordance with those earlier editions at the time they
were listed. The user must refer to the appropriate previous edition of
49 CFR for a listing of the earlier editions.
* * * * *
6. In Sec. 195.3, paragraphs (b)(1) through (b)(5) are redesignated
as paragraphs (b)(2) through (b)(6) and paragraph (b)(1) is added to
read as follows:
Sec. 195.3 Matter incorporated by reference.
* * * * *
(b) * * *
(1) American Gas Association (AGA), 1515 Wilson Boulevard,
Arlington, VA 22209.
* * * * *
7. In Sec. 195.3, paragraphs (c)(2)(iii) and (c)(2)(iv) are
redesignated as paragraphs (c)(2)(v) and (c)(2)(vi) and paragraphs
(c)(2)(iii) and (c)(2)(iv) are added to read as follows:
Sec. 195.3 Matter incorporated by reference.
* * * * *
(c) * * *
(2) * * *
(iii) ASME/ANSI B31.8 ``Gas Transmission and Distribution Piping
Systems'' (1989 with ASME/ANSI B31.8a-1990, B31.8b-1990, B31.8c-1992
Addenda and Special Errata issued July 6, 1990 and Special Errata
(Second) issued February 28, 1991).
(iv) ASME/ANSI B31G, ``Manual for Determining the Remaining
Strength of Corroded Pipelines'' (1991).
* * * * *
8. In Sec. 195.3, paragraphs (c)(1) through (c)(4) are redesignated
as paragraphs (c)(2) through (c)(5) and paragraph (c)(1) is added to
read as follows:
Sec. 195.3 Matter incorporated by reference.
* * * * *
(c) * * *
(1) American Gas Association (AGA): AGA Pipeline Research
Committee, Project PR-3-805, ``A Modified Criterion for Evaluating the
Remaining Strength of Corroded Pipe'' (December 1989). The RSTRENG
program may be used for calculating remaining strength.
* * * * *
9. Section 195.5 is amended by revising paragraphs (a)(1) and
(a)(4) to read as follows:
Sec. 195.5 Conversion to service subject to this part.
(a) * * *
(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 B31.8, 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).
* * * * *
(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.
* * * * *
10. Section 195.50(f) is revised to read as follows:
Sec. 195.50 Reporting accidents.
* * * * *
(f) 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.
11. Section 195.52(a)(3) is revised to read as follows:
Sec. 195.52 Telephonic notice of certain accidents.
(a) * * *
(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;
* * * * *
12. Section 195.106(b) is revised to read as follows:
Sec. 195.106 Internal design pressure.
* * * * *
(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 API Specification 5L on randomly selected specimens
with the following number of tests:
------------------------------------------------------------------------
Pipe size No. of tests
------------------------------------------------------------------------
Less than 168.3 mm (6\5/8\ in) One test for each 200 lengths.
nominal outside diameter.
168.3 through 323.8 mm (6\5/8\ One test for each 100 lengths.
through 12\3/4\ in) nominal
outside diameter.
Larger than 323.8 mm (12\3/4\ in) One test for each 50 lengths.
nominal outside diameter.
------------------------------------------------------------------------
(ii) If the average yield-tensile ratio exceeds 0.85, the yield
strength shall be taken as 165,474 kPa (24,000 psi). 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 165,474 kPa
(24,000 psi).
* * * * *
13. In Sec. 195.106(c), the last sentence is revised to read as
follows:
Sec. 195.106 Internal design pressure.
* * * * *
(c) * * * However, the nominal wall thickness may not be more than
1.14 times the smallest measurement taken on pipe that is less than 508
mm (20 in) nominal outside diameter, nor more than 1.11 times the
smallest measurement taken on pipe that is 508 mm (20 in) or more in
nominal outside diameter.
* * * * *
14. In Sec. 195.204, the last sentence is revised to read as
follows:
Sec. 195.204 Inspection--general.
* * * No person may be used to perform inspections unless that
person has been trained and is qualified in the phase of construction
to be inspected.
15. Section 195.228(b) is revised to read as follows:
Sec. 195.228 Welds and welding inspection: Standards of acceptability.
* * * * *
(b) The acceptability of a weld is determined according to the
standards in section 6 of API Standard 1104. However, if a girth weld
is unacceptable under those standards for a reason other than a crack,
and if the Appendix to API Standard 1104 applies to the weld, the
acceptability of the weld may be determined under that appendix.
16. Section 195.234 is amended by revising the introductory text of
paragraph (e) and by revising paragraph (g) to read as follows:
Sec. 195.234 Welds: Nondestructive testing.
* * * * *
(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:
* * * * *
(g) At pipeline tie-ins, including tie-ins of replacement sections,
100 percent of the girth welds must be nondestructively tested.
17. Section 195.246 is amended by revising paragraph (b) to read as
follows:
Sec. 195.246 Installation of pipe in a ditch.
* * * * *
(b) Except for pipe in the Gulf of Mexico and its inlets, all
offshore pipe in water at least 3.7 m 12-ft-deep but not more than 61 m
(200 ft) deep, as measured from the mean low tide, 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.
18. Section 195.248 is amended by revising in the first column of
the table in paragraph (a) the language ``Other offshore areas under
water less than 12-ft-deep as measured from the mean low tide'' to read
``Gulf of Mexico and its inlets and other offshore areas under water
less than 12-ft-deep as measured from the mean low tide'' and by
revising the introductory text of paragraph (b) to read as follows:
Sec. 195.248 Cover over buried pipeline.
* * * * *
(b) Except for the Gulf of Mexico and its inlets, less cover than
the minimum required by paragraph (a) of this section and Sec. 195.210
may be used if--
* * * * *
19. Section 195.262(d) is revised to read as follows:
Sec. 195.262 Pumping equipment.
* * * * *
(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.
* * * * *
20. The introductory text of Sec. 195.304(b) is revised to read as
follows:
Sec. 195.304 Testing of components.
* * * * *
(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--
* * * * *
21. Section 195.406 is amended by republishing the introductory
text of paragraph (a) and revising paragraph (a)(1) to read as follows:
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 B31.8, reduced by the
appropriate factors in Secs. 195.106 (a) and (e); or
(ii) If the pipe is 323.8 mm (12\3/4\ in) or less outside diameter
and is not tested to yield under this paragraph, 1379 kPa (200 psig).
* * * * *
22. Section 195.412(a) is revised to read as follows:
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.
* * * * *
23. Section 195.416 is amended by revising paragraph (a),
redesignating paragraph (h) as paragraph (i) and adding a new paragraph
(h) to read as follows:
Sec. 195.416 External corrosion control.
(a) Each operator shall, at intervals not exceeding 15 months, but
at least once each calendar year, conduct tests on each buried, in
contact with the ground, or submerged pipeline facility in its pipeline
system that is under cathodic protection to determine whether the
protection is adequate.
* * * * *
(h) The strength of the pipe, based on actual remaining wall
thickness, for paragraphs (f) and (g) of this section may be determined
by the procedure in ASME B31G manual for Determining the Remaining
Strength of Corroded Pipelines or by the procedure developed by AGA/
Battelle--A Modified Criterion for Evaluating the Remaining Strength of
Corroded Pipe (with RSTRENG disk). Application of the procedure in the
ASME B31G manual or the AGA/Battelle Modified Criterion is applicable
to corroded regions (not penetrating the pipe wall) in existing steel
pipelines in accordance with limitations set out in the respective
procedures.
* * * * *
Issued in Washington, DC, on June 9, 1994.
Ana Sol Gutierrez,
Acting Administrator, Research and Special Programs Administration.
[FR Doc. 94-15510 Filed 6-27-94; 8:45 am]
BILLING CODE 4910-60-P