[Federal Register: October 25, 2005 (Volume 70, Number 205)]
[Rules and Regulations]
[Page 61571-61577]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr25oc05-9]
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DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
49 CFR Parts 192 and 195
[Docket No. RSPA-04-16855; Amdt. 192-101 and 195-85]
RIN 2137--AD97
Pipeline Safety: Standards for Direct Assessment of Gas and
Hazardous Liquid Pipelines
AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
DOT.
ACTION: Final rule.
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SUMMARY: Under current regulations governing integrity management of
gas transmission lines, if an operator uses direct assessment to
evaluate corrosion risks, it must carry out the direct assessment
according to PHMSA standards. In response to a statutory directive,
this Final Rule prescribes similar standards operators must meet when
they use direct assessment on certain other onshore gas, hazardous
liquid, and carbon dioxide pipelines. PHMSA believes broader
application of direct assessment standards will enhance public
confidence in the use of direct assessment to assure pipeline safety.
DATES: This Final Rule takes effect November 25, 2005. Incorporation by
reference of NACE Standard RP0502-2002 in this rule is approved by the
Director of the Federal Register as of November 25, 2005.
FOR FURTHER INFORMATION CONTACT: L.M. Furrow by phone at 202-366-4559,
by fax at 202-366-4566, by mail at U.S. Department of Transportation,
400 Seventh Street, SW., Washington, DC 20590, or by e-mail at
buck.furrow@dot.gov.
SUPPLEMENTARY INFORMATION:
I. Background
This Final Rule concerns direct assessment, a process of managing
the effects of external corrosion, internal corrosion, or stress
corrosion cracking on pipelines made primarily of steel or iron. The
process involves data collection, indirect inspection, direct
examination, and evaluation. Operators use direct assessment not only
to find existing corrosion defects but also to prevent future corrosion
problems.
Congress recognized the advantages of using direct assessment on
U.S. Department of Transportation (DOT) regulated gas, hazardous
liquid, and carbon dioxide pipeline facilities. Section 14 of the
Pipeline Safety Improvement Act of 2002 (Pub. L. 107-355; Dec. 17,
2002) directs DOT to issue regulations on using internal inspection,
pressure testing, and direct assessment to manage the risks to gas
pipeline facilities in high consequence areas. In addition, Section 23
directs DOT to issue regulations prescribing standards for inspecting
pipeline facilities by direct assessment.
In response to the first statutory directive, Section 14, DOT's
Research and Special Programs Administration (RSPA) \1\ published
regulations in 49 CFR part 192, subpart O, that require operators to
follow detailed programs to manage the integrity of gas transmission
line segments in high consequence areas. Subpart O also requires an
operator electing to use direct assessment in its integrity management
program, to carry out the direct assessment according to Sec. Sec.
192.925, 192.927, and 192.929, as appropriate.\2\
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\1\ The Norman Y. Mineta Research and Special Programs
Improvement Act (Pub. L. 108-426, 118; November 30, 2004)
reorganized RSPA into two new DOT administrations: the Pipeline and
Hazardous Materials Safety Administration (PHMSA) and the Research
and Innovative Technology Administration. RSPA's regulatory
authority over pipeline and hazardous materials safety was
transferred to PHMSA.
\2\ The standard on external corrosion direct assessment Sec.
192.925) requires operators to integrate data on physical
characteristics and operating history, conduct indirect aboveground
inspections, directly examine pipe surfaces, and evaluate the
effectiveness of the assessment process. Under the standard for
direct assessment of internal corrosion (Sec. 192.927), operators
must predict locations where electrolytes may accumulate in normally
dry-gas pipelines, examine those locations, and validate the
assessment process. The standard for direct assessment of stress
corrosion cracking (Sec. 192.929) involves collecting data relevant
to stress corrosion cracking, assessing the risk of pipeline
segments, and examining and evaluating segments at risk.
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Sections 192.925, 192.927, and 192.929 cross-reference the American
Society of Mechanical Engineers' (ASME), ASME B31.8S-2001, ``Managing
System Integrity of Gas Pipelines.'' ASME B31.8S-2001 describes a
comprehensive process to assess and mitigate the likelihood and
consequences of gas pipeline risks. In addition, Sec. 192.925 cross-
references a
[[Page 61572]]
NACE International (NACE) standard, NACE Standard RP0502-2002,
``Pipeline External Corrosion Direct Assessment Methodology.'' NACE
Standard RP0502-2002 describes a step-by-step process for identifying
and addressing external corrosion activity, repairing defects, and
taking remedial action. Other parts of Sec. Sec. 192.925, 192.927,
and 192.929 ensure operators use appropriate criteria in making direct
assessment decisions.
II. Proposed Rules
In response to the second statutory directive, Section 23, PHMSA
published a notice of proposed rulemaking (NPRM) (69 FR 61771; Oct. 21,
2004). The NPRM proposed standards for using direct assessment on any
onshore gas pipeline made primarily of steel or iron and regulated by
49 CFR part 192 or onshore steel hazardous liquid or carbon dioxide
pipeline regulated by 49 CFR part 195. Under proposed Sec. 192.490, if
an operator chooses to use direct assessment to evaluate the threat of
external corrosion, internal corrosion, or stress corrosion cracking on
a regulated onshore gas pipeline, the direct assessment would have to
be done according to Sec. Sec. 192.925, 192.927, or 192.929, as
appropriate. For regulated hazardous liquid and carbon dioxide
pipelines, proposed Sec. 195.588 would require similar action, except
compliance with Sec. 192.927 would not be required, because Sec.
192.927 requirements are only suitable for dry gas pipelines.
III. Advisory Committee Recommendations
The Technical Pipeline Safety Standards Committee (TPSSC) and the
Technical Hazardous Liquid Pipeline Safety Standards Committee
(THLPSSC) considered the NPRM at meetings in Washington, DC, on
December 14 and 15, 2004. The TPSSC, a statutorily mandated advisory
committee, advises PHMSA on proposed safety standards and other
policies concerning gas pipelines. The THLPSSC is a similar committee
that provides advice about hazardous liquid and carbon dioxide
pipelines. Each committee has an authorized membership of 15 persons
with membership evenly divided between government, industry, and the
public. Each member is qualified to consider the technical feasibility,
reasonableness, cost-effectiveness, and practicability of proposed
pipeline safety standards. A transcript of each committee's meeting is
available in Docket No. PHMSA-98-4470.
After careful consideration of the NPRM, the THLPSSC voted
unanimously to recommend the following: (1) Adopt a single definition
of direct assessment for use by hazardous liquid pipeline operators
inside and outside high consequence areas; (2) state direct assessment
standards directly in part 195, rather than by cross-referencing part
192 standards; (3) consider adopting the consensus standard under
development by NACE for direct assessment of stress corrosion cracking;
and (4) amend the integrity management rule (Sec. 195.452) to allow
use of direct assessment without prior notice.
As a result of its deliberation, the TPSSC voted unanimously that
proposed Sec. 192.490 should not be applied to gas distribution lines.
It also voted unanimously that the Final Rule should distinguish direct
assessment from similar methods of assessing corrosion. Such a
distinction would identify situations where similar methods of
addressing corrosion are appropriate but are not regulated under the
proposed direct assessment standard.
IV. Disposition of Comments and Advisory Committee Recommendations on
Proposed Rules
We received written comments on the proposed rules from 19 sources.
These sources are categorized as follows:
State pipeline safety agency........... Pennsylvania Public Utility
Commission.
Gas pipeline operators................. Duke Energy Gas Transmission
(Duke), El Paso Corporation
(El Paso), Nicor Gas (Nicor),
NiSource Corporate Services
Company (Nisource), Pacific
Gas & Electric Company (PG&E),
Paiute Pipeline Company
(Paiute), Puget Sound Energy
(Puget), Southwest Gas
Corporation (SWGas).
Gas pipeline trade associations........ American Public Gas Association
(APGA), American Gas
Association (AGA), Interstate
Natural Gas Association of
America (INGAA), Northeast Gas
Association (NGA).
Gas pipeline industry committee........ Gas Piping Technology Committee
(GPTC).
Hazardous liquid pipeline trade American Petroleum Institute
associations. (API), Association of Oil Pipe
Lines (AOPL).
Nonprofit organizations................ Cook Inlet Regional Citizens
Advisory Council, Pipeline
Safety Trust
Consultant............................. Glen F. Armstrong.
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Only one commenter, the Cook Inlet Regional Citizens Advisory
Council (Council), created by the Oil Pollution Act of 1990, supported
the proposed rules without change. The Council welcomed the additional
Federal standards because of the need to control pipeline corrosion.
The remaining commenters' issues are stated below along with our
disposition of those issues and the advisory committee's
recommendations.
Is this rulemaking necessary? AGA, Duke, El Paso, GPTC, INGAA,
NiSource, and Puget claimed the integrity management regulations for
gas transmission lines (subpart O of part 192) satisfy the statutory
directive to prescribe direct assessment standards. Taking a similar
position, AOPL and API contended that Congress did not intend direct
assessment standards to apply outside integrity management regulations.
To support this position, these commenters stated that Congress did not
require operators to use direct assessment on pipelines outside
integrity management regulations. They also pointed out that direct
assessment was developed for use in integrity management programs.
Because the legislative history does not support the commenter's
argument that direct assessment standards should apply only to
pipelines subject to integrity management rules, PHMSA believes this
rulemaking is necessary. It is reasonable to conclude Congress did not
intend to restrict direct assessment standards to pipelines covered by
integrity management regulations. Unlike the first statutory directive
concerning direct assessment, which applies only to pipeline facilities
in high consequence areas, the second directive applies to pipeline
facilities regardless of location. Also, the first and second
directives appear in separate sections of the statute (Sections 14 and
23 of Pub. L. 107-355), with no apparent connection. Had Congress
wanted to restrict direct assessment standards to pipelines covered by
integrity management regulations, it could have expressly linked the
second directive to the first or included the second directive in the
same section as the first.
Is proposed Sec. 192.490 appropriate for gas distribution lines?
AGA, APGA,
[[Page 61573]]
Duke, El Paso, GPTC, INGAA, NGA, Nicor, NiSource, Paiute, and PG&E
argued direct assessment was developed for gas transmission integrity
management and has not been shown to be appropriate for gas
distribution lines. They said the relevant technical data and
experience do not show direct assessment would be effective on gas
distribution lines. In addition, some of these commenters thought
because gas distribution lines differ from gas transmission lines in
design, operation, configuration, and location, direct assessment may
be impractical on gas distribution lines. The many aboveground and
belowground utility facilities--both in-service and abandoned--were
thought to pose significant technical hurdles. The Pennsylvania Public
Utility Commission and the Pipeline Safety Trust also questioned the
suitability of direct assessment for gas distribution lines.
These comments came as a surprise to PHMSA because the two
documents that are the mainstays of the proposed direct assessment
standards, ASME B31.8S-2001 and NACE Standard RP0502-2002, can be
interpreted to cover gas distribution lines. Each document states that
it applies to onshore pipelines. Although neither document defines
``pipeline,'' ASME's B31.8 Code, to which ASME B31.8S-2001 is a
supplement, defines ``pipeline'' as ``all parts of physical facilities
through which gas moves in transportation.'' And ``transportation of
gas'' is defined as the ``gathering, transmission, or distribution of
gas.''
No matter how ASME B31.8S-2001 and NACE Standard RP0502-2002 are
interpreted, the comments persuaded us that direct assessment, as
depicted by these two documents, is not appropriate for gas
distribution lines. Both ASME B31.8S-2001 and NACE Standard RP0502-
2002, were developed during the rulemaking proceeding on gas
transmission integrity management and in furtherance of that
proceeding. Consequently, neither document was developed with a focus
on gas distribution lines. Furthermore, although both documents apply
to pipelines, they do not take full account of gas distribution line
features as comments suggest they should to treat gas distribution
lines appropriately.
Given these considerations and the TPSSC's unanimous recommendation
that we not apply the proposed direct assessment standards to gas
distribution lines, we decided to exclude distribution lines from final
Sec. 192.490. Removing ``pipeline'' from the proposed wording and
adding ``transmission line'' in its place accomplishes this change.
Would the proposed standards discourage the voluntary use of
corrosion control methods? AGA, Armstrong, Duke, El Paso, GPTC, INGAA,
NGA, Nicor, NiSource, Paiute, PG&E, Puget, and SWGas were concerned the
proposed standards (Sec. Sec. 192.490 and 195.588) would discourage
operators from voluntarily using corrosion control methods related to
direct assessment on pipelines not subject to the integrity management
regulations. Their concern stemmed from the difficulty of recognizing
when direct assessment is being used. They said performance of any one
of the four steps that constitute direct assessment could imply use of
direct assessment and lead to disagreements with government inspectors
over whether direct assessment is being used. For example, some
commenters said performing a close interval electrical survey resembled
the indirect examination step of direct assessment. Others thought
examining buried pipe for corrosion could be considered the direct
examination step. El Paso, INGAA, Nicor, and Armstrong suggested the
Final Rule clarify that operators may use corrosion control methods
related to direct assessment without having to meet the proposed direct
assessment standards.
We recognize disagreements could arise over whether the use of a
corrosion control method is part of the direct assessment process.
However, we do not think such disagreements are likely to be serious
enough to discourage operators from continuing to use such methods
separately from direct assessment. To minimize potential disagreements,
operators may explain in their corrosion control procedures the
situations in which they use methods related to direct assessment
separately from direct assessment.
In view of the commenters' concern, PHMSA has added provisions to
final Sec. Sec. 192.490 and 195.588 to clarify application of the
direct assessment standards. The statement provides that the direct
assessment standards do not apply to methods related to direct
assessment, such as close interval surveys, voltage gradient surveys,
or examination of exposed pipelines, when used separately from the
direct assessment process. This change is consistent with the TPSSC's
second recommendation.
Are the gas pipeline standards cross-referenced in proposed Sec.
195.588 suitable for hazardous liquid and carbon dioxide pipelines? In
their comments on proposed Sec. 195.588, AOPL and API opposed cross-
referencing Sec. Sec. 192.925 and 192.929 primarily because these
standards refer to ASME B31.8S-2001. They argued ASME B31.8S-2001 was
developed for natural gas transmission lines and without the
involvement of hazardous liquid pipeline operators. They were also
concerned that cross-referencing part 192 gas pipeline standards could
lead to misunderstandings by hazardous liquid pipeline operators. The
THLPSSC similarly opposed cross-referencing part 192 standards.
In developing the NPRM, we assumed the cross-referenced part 192
standards and their cross-references to ASME B31.8S-2001 would be
suitable for hazardous liquid and carbon dioxide pipelines. However,
the AOPL and API comments and the THLPSSC's recommendation have caused
us to doubt that assumption. In addition, we are concerned that
application of the part 192 direct assessment standards to hazardous
liquid and carbon dioxide pipelines could present compliance problems.
Contributing to this concern is the comment that ASME B31.8S-2001 was
not developed with an eye to hazardous liquid pipelines. In fact,
paragraph 1.1 of ASME B31.8S-2001 specifically states that the scope of
ASME B31.8S-2001 is limited to ``onshore pipeline systems * * * that
transport gas.''
Therefore, we decided not to include cross-references to part 192
standards or to ASME B31.8S-2001 in final Sec. 195.588. Instead, final
Sec. 195.588 includes a complete statement of direct assessment
standards, with cross-references only to NACE Standard RP0502-2002.
Should the integrity management regulations for hazardous liquid
and carbon dioxide pipelines allow use of direct assessment without
advance notice? The integrity management regulations for hazardous
liquid and carbon dioxide pipelines (Sec. 195.452) prescribe three
ways to assess pipeline integrity: internal inspection via a smart pig,
pressure testing, and any other technology the operator demonstrates
can provide an equivalent understanding of pipe conditions. However,
before another technology, such as direct assessment may be used, the
operator must notify PHMSA at least 90 days in advance (Sec. Sec.
195.452(c)(1)(i)(C) and 195.452(j)(5)(iii)).
In contrast to Sec. 195.452, the proposed direct assessment
standards do not include a requirement to give 90 days' advance notice
as a precondition to using direct assessment. We see no need to propose
such a requirement since the current Part 192 direct assessment
standards do not require operators to
[[Page 61574]]
give advance notice before using direct assessment.
In their comments on proposed Sec. 195.588, AOPL and API suggested
direct assessment of external corrosion should be listed directly in
Sec. 195.452 as a permissible method of integrity assessment. They
believe that when external corrosion direct assessment is performed
according to NACE Standard RP0502-2002, it is an acceptable use of
``other technology'' for which 90 days advance notice is no longer
necessary. As discussed above under Advisory Committee Recommendations,
the THLPSSC also favored listing direct assessment directly in Sec.
195.452 as a recognized assessment method that would bypass the 90-day
advance notice requirement.
The purpose of the 90 days advance notice requirement in Sec.
195.452 is to provide time for PHMSA and State pipeline safety agencies
to review technology other than pigging and pressure testing to learn
what information the technology provides about pipe conditions.
According to information on a PHMSA Web site (http://primis.phmsa.dot.gov/iim/notifications.imd
), several operators have
submitted notices of their intent to use direct assessment on hazardous
liquid or carbon dioxide pipelines. In a majority of cases, there were
no PHMSA or State government objections to the use of direct
assessment. Objections were raised where the notification lacked
information explaining how the direct assessment was to be performed.
When applied to direct assessment, we believe the 90-day advance
notice requirement of Sec. 195.452 is no longer useful and is
inconsistent with the proposed rules. Direct assessment is now being
used under the part 192 integrity management regulations without
advance notice. As a result, government inspectors are fully aware of
the direct assessment technology and the situations for which it is
suited, making advance case-by-case review under Sec. 195.452
unnecessary. In addition, requiring operators to follow prescribed
standards when using direct assessment will remove the primary
objection previously raised about operators' advance notices--
insufficient information to explain the method of assessment.
Therefore, we are changing Sec. Sec. 195.452(c)(1)(i)(C) and
195.452(j)(5)(iii) to allow use of direct assessment in accordance with
final Sec. 195.588 without 90 days advance notice.
What standard should apply to direct assessment of stress corrosion
cracking on hazardous liquid and carbon dioxide pipelines? The NPRM
proposed that Sec. 192.929 be the standard for direct assessment of
stress corrosion cracking on hazardous liquid and carbon dioxide
pipelines. This standard relies largely on cross-references to ASME
B31.8S-2001.
Besides their objections to cross-referencing part 192 standards
and particularly ASME B31.8S-2001, AOPL and API suggested that we not
adopt any standard for the direct assessment of stress corrosion
cracking on hazardous liquid pipelines. They said because methods of
detecting stress corrosion cracking are developing rapidly, direct
assessment may not be the optimum technology for hazardous liquid
pipelines. The THLPSSC recommended we consider adopting the consensus
standard that NACE International was developing for direct assessment
of stress corrosion cracking.
As explained above, we decided not to cross-reference directly or
indirectly ASME B31.8S-2001 in final Sec. 195.588, because the
document is closely identified with gas pipelines. Consequently, since
provisions of ASME B31.8S-2001 are an important part of the proposed
stress corrosion standard, we have not included a direct assessment
standard for stress corrosion cracking in final Sec. 195.588. As the
THLPSSC recommended, we will consider the recently published NACE
Standard RP0204-2004, Stress Corrosion Cracking (SCC) Direct Assessment
Methodology, for possible future rulemaking action. By removing the
proposed cross-reference to Sec. 192.929, final Sec. 195.588 consists
of the text of Sec. 192.925 without its cross-references to ASME
B31.8S-2001.
V. Editorial Changes
Final Sec. Sec. 192.490 and 195.588 do not include the
proposed phrase ``or to meet any requirement of this Subpart regarding
that threat.'' The phrase was used in the proposed rules to draw
attention to situations in which operators might choose to use direct
assessment. However, the phrase appears to be unnecessary and,
according to comments, possibly confusing.
Final Sec. 192.490 clarifies that ``direct assessment''
means direct assessment as defined in Sec. 192.903.\3\ This definition
applies to ``direct assessment'' as it is used in subpart O of part
192, including Sec. Sec. 192.925, 192.927, and 192.929--the bases of
the proposed direct assessment standards. Also, in final Sec. 192.490,
instead of using the proposed term ``ferrous'' to limit pipelines to
which the direct assessment standards apply, we used ``made primarily
of steel or iron.'' This change removes the possibility of confusion
over the meaning of ferrous.
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\3\ Section 192.903 defines ``direct assessment'' as ``an
integrity assessment method that utilizes a process to evaluate
certain threats (i.e., external corrosion, internal corrosion and
stress corrosion cracking) to a covered pipeline segment's
intergrity. The process includes the gathering and integration of
risk factor data, indirect examination or analysis to identify areas
of suspected corrosion, direct examination of the pipeline in these
areas, and post assessment evaluation.''
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We added a similar definition of ``direct assessment'' to
Sec. 195.553, which contains definitions applicable to subpart H of
part 195, including final Sec. 195.588. This addition satisfies the
first THLPSSC recommendation. The definition of ``external corrosion
direct assessment,'' which was proposed through the cross-reference to
Sec. 192.925, is also added to Sec. 195.553.
In final Sec. 195.588, we substituted ``pipeline
segment'' for the terms ``covered segment'' and ``covered pipeline
segment'' to avoid the possibility that the definition of these terms
in Sec. 192.903--a segment of transmission pipeline located in a high
consequence area--would unintentionally constrain the scope of final
Sec. 195.588. A footnote resolves a similar problem in final Sec.
192.490.
Section 192.925(b) provides that if coating damage is
detected by external corrosion direct assessment, the operator must
integrate that information with data gathered and integrated under
certain other requirements (Sec. Sec. 192.917(b) and 192.917(e)(1)).
These other requirements, which involve evaluating and addressing risks
besides corrosion, including third-party damage, apply only to gas
transmission lines subject to the integrity management regulations in
subpart O of part 192. Although the proposed direct assessment
standards for other pipelines included cross-references to Sec.
192.925, the NPRM did not address extending Sec. Sec. 192.917(b) and
192.917(e)(1) to pipelines outside subpart O by virtue of the cross-
references. The focus of the NPRM was strictly on using direct
assessment to evaluate and address corrosion risks. Using direct
assessment data to evaluate non-corrosion risks to pipeline integrity
was not discussed. So it would be inappropriate to infer that the
proposed references to Sec. 192.925 meant that operators who
voluntarily use external corrosion direct assessment on pipelines
outside subpart O would also have to comply with Sec. Sec. 192.917(b)
and 192.917(e)(1). To ensure this possible inference does not affect
the Final Rules, final Sec. Sec. 192.490 and 195.588 exclude
pipelines outside subpart O from the Sec. 192.925(b) requirement
related to integrating coating damage data. Nevertheless, for
[[Page 61575]]
hazardous liquid and carbon dioxide pipelines that are subject to the
integrity management regulations in Sec. 195.452, the detection of
coating damage is an important factor to consider in the information
analysis required by Sec. 195.452(g) and the continual integrity
evaluation required by Sec. 195.452(j)(2).
VI. Regulatory Analyses and Notices
Executive Order 12866 and DOT Policies and Procedures. PHMSA does
not consider this rulemaking to be a significant regulatory action
under Section 3(f) of Executive Order 12866 (58 FR 51735; Oct. 4,
1993). Therefore, the Office of Management and Budget (OMB) has not
received a copy of the Final Rule to review. PHMSA also does not
consider this rulemaking to be significant under DOT regulatory
policies and procedures (44 FR 11034: February 26, 1979).
PHMSA has evaluated the costs and benefits of this Final Rule and a
copy of the evaluation is in the docket. The evaluation concludes
operators will incur only minimal costs to comply with the Final Rule.
Regulatory Flexibility Act. Under the Regulatory Flexibility Act (5
U.S.C. 601 et seq.), PHMSA must consider whether rulemaking actions
have a significant economic impact on a substantial number of small
entities. Based on the facts available about the anticipated impacts of
this rulemaking, I certify that this rulemaking will not have a
significant impact on a substantial number of small entities.
Executive Order 13175. PHMSA has analyzed this rulemaking according
to the principles and criteria contained in Executive Order 13175,
``Consultation and Coordination with Indian Tribal Governments.''
Because the Final Rule will not significantly or uniquely affect the
communities of the Indian Tribal Governments nor impose substantial
direct compliance costs, the funding and consultation requirements of
Executive Order 13175 do not apply.
Paperwork Reduction Act. Operators have just recently begun to use
direct assessment to assess the effects of corrosion on onshore gas
transmission lines subject to the integrity management regulations in
subpart O of part 192. The use of direct assessment on other pipelines
regulated by part 192 or part 195 is voluntary. This Final Rule does
not change this voluntary use status. It merely sets standards for
performing direct assessment if operators choose to use it.
Pipeline operators covered by the Final Rule who choose to use
direct assessment would have to prepare appropriate plans and
procedures and keep records as required by Section 7 of NACE Standard
RP0502-2002. To help estimate the paperwork burden these operators
would face, the NPRM invited comments on how many operators plan to use
direct assessment voluntarily and what the burden hours and cost would
be.
None of the commenters foresaw any voluntary use of direct
assessment or commented on the potential paperwork burden. This result
was not a surprise, for direct assessment is a new process and so far
its use is mostly limited to gas transmission lines subject to subpart
O of part 192. Under these circumstances, it is reasonable to expect
that few, if any, operators will be affected by the Final Rule. So no
net increase in paperwork burdens is likely from this Final Rule. For
this reason, we believe that submitting an analysis of the burdens to
OMB under the Paperwork Reduction Act is unnecessary.
Unfunded Mandates Reform Act of 1995. This Final Rule does not
impose unfunded mandates under the Unfunded Mandates Reform Act of
1995. It does not result in costs of $100 million or more to either
State, local, or tribal governments, in the aggregate, or to the
private sector, and is the least burdensome alternative that achieves
the objective of the rulemaking.
National Environmental Policy Act. PHMSA has analyzed the Final
Rule for purposes of the National Environmental Policy Act (42 U.S.C.
4321 et seq.). Because the Final Rule affects only those operators that
voluntarily use direct assessment and because it largely involves
processes of data collection and evaluation, we have determined that it
is unlikely to significantly affect the quality of the human
environment. An Environmental Assessment is available for review in the
docket.
Executive Order 13132. PHMSA has analyzed the Final Rule according
to the principles and criteria contained in Executive Order 13132,
``Federalism.'' No part of the rule (1) has substantial direct effects
on the States, the relationship between the national government and the
States, or the distribution of power and responsibilities among the
various levels of government; (2) imposes substantial direct compliance
costs on State and local governments; or (3) preempts State law.
Therefore, the consultation and funding requirements of Executive Order
13132 do not apply.
Executive Order 13211. This Final Rule is not a ``Significant
Energy Action'' under Executive Order 13211. It is not a significant
regulatory action under Executive Order 12866 and is not likely to have
a significant adverse effect on the supply, distribution, or use of
energy. Further, this rulemaking has not been designated by the
Administrator of the Office of Information and Regulatory Affairs as a
significant energy action.
List of Subjects
49 CFR Part 192
Natural gas, Pipeline safety, Reporting and recordkeeping
requirements.
49 CFR Part 195
Ammonia, Carbon dioxide, Incorporation by reference, Petroleum,
Pipeline safety, Reporting and recordkeeping requirements.
0
In consideration of the foregoing, PHMSA amends 49 CFR parts 192 and
195 as follows:
PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE:
MINIMUM FEDERAL SAFETY STANDARDS
0
1. The authority citation for part 192 continues to read as follows:
Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110,
60113, and 60118; and 49 CFR 1.53.
0
2. Add Sec. 192.490 to read as follows:
Sec. 192.490 Direct assessment.
Each operator that uses direct assessment as defined in Sec.
192.903 on an onshore transmission line made primarily of steel or iron
to evaluate the effects of a threat in the first column must carry out
the direct assessment according to the standard listed in the second
column. These standards do not apply to methods associated with direct
assessment, such as close interval surveys, voltage gradient surveys,
or examination of exposed pipelines, when used separately from the
direct assessment process.
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Threat Standard \1\
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External corrosion....................... Sec. 192.925 \2\
Internal corrosion in pipelines that Sec. 192.927
transport dry gas.
Stress corrosion cracking................ Sec. 192.929
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\1\ For lines not subject to subpart O of this part, the terms ``covered
segment'' and ``covered pipeline segment'' in Sec. Sec. 192.925,
192.927, and 192.929 refer to the pipeline segment on which direct
assessment is performed.
\2\ In Sec. 192.925(b), the provision regarding detection of coating
damage applies only to pipelines subject to subpart O of this part.
PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE
0
3. The authority citation for part 195 continues to read as follows:
[[Page 61576]]
Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60118;
and 49 CFR 1.53.
0
4. In Sec. 195.3(c), amend the table of referenced material by adding
item G.(2) to read as follows:
Sec. 195.3 Matter incorporated by reference in whole or in part.
* * * * *
(c) * * *
------------------------------------------------------------------------
------------------------------------------------------------------------
G. * * *.................................. * * *
(2) NACE Standard RP0502-2002 ``Pipeline Sec. 195.588
External Corrosion Direct Assessment
Methodology'' (2002).
------------------------------------------------------------------------
0
5. Amend Sec. 195.452 as follows:
0
a. Redesignate paragraph (c)(1)(i)(C) as (c)(1)(i)(D);
0
b. Remove ``or'' from the end of paragraph (c)(1)(i)(B);
0
c. Redesignate paragraph (j)(5)(iii) as (j)(5)(iv);
0
d. Remove ``or'' from the end of paragraph (j)(5)(ii); and
0
e. Add new paragraphs (c)(1)(i)(C) and (j)(5)(iii) to read as follows:
Sec. 195.452 Pipeline integrity management in high consequence areas.
* * * * *
(c) * * *
(1) * * *
(i) * * *
(C) External corrosion direct assessment in accordance with Sec.
195.588; or
* * * * *
(j) * * *
(5) * * *
(iii) External corrosion direct assessment in accordance with Sec.
195.588; or
* * * * *
0
6. In Sec. 195.553, add definitions for ``direct assessment'' and
``external corrosion direct assessment (ECDA)'' as follows:
Sec. 195.553 What special definitions apply to this Subpart?
* * * * *
Direct assessment means an integrity assessment method that
utilizes a process to evaluate certain threats (i.e., external
corrosion, internal corrosion and stress corrosion cracking) to a
pipeline segment's integrity. The process includes the gathering and
integration of risk factor data, indirect examination or analysis to
identify areas of suspected corrosion, direct examination of the
pipeline in these areas, and post assessment evaluation.
* * * * *
External corrosion direct assessment (ECDA) means a four-step
process that combines pre-assessment, indirect inspection, direct
examination, and post-assessment to evaluate the threat of external
corrosion to the integrity of a pipeline.
* * * * *
0
7. Add Sec. 195.588 to read as follows:
Sec. 195.588 What standards apply to direct assessment?
(a) If you use direct assessment on an onshore pipeline to evaluate
the effects of external corrosion, you must follow the requirements of
this section for performing external corrosion direct assessment. This
section does not apply to methods associated with direct assessment,
such as close interval surveys, voltage gradient surveys, or
examination of exposed pipelines, when used separately from the direct
assessment process.
(b) The requirements for performing external corrosion direct
assessment are as follows:
(1) General. You must follow the requirements of NACE Standard
RP0502-2002 (incorporated by reference, see Sec. 195.3). Also, you
must develop and implement an ECDA plan that includes procedures
addressing pre-assessment, indirect examination, direct examination,
and post-assessment.
(2) Pre-assessment. In addition to the requirements in Section 3 of
NACE Standard RP0502-2002, the ECDA plan procedures for pre-assessment
must include--
(i) Provisions for applying more restrictive criteria when
conducting ECDA for the first time on a pipeline segment;
(ii) The basis on which you select at least two different, but
complementary, indirect assessment tools to assess each ECDA region;
and
(iii) If you utilize an indirect inspection method not described in
Appendix A of NACE Standard RP0502-2002, you must demonstrate the
applicability, validation basis, equipment used, application procedure,
and utilization of data for the inspection method.
(3) Indirect examination. In addition to the requirements in
Section 4 of NACE Standard RP0502-2002, the procedures for indirect
examination of the ECDA regions must include--
(i) Provisions for applying more restrictive criteria when
conducting ECDA for the first time on a pipeline segment;
(ii) Criteria for identifying and documenting those indications
that must be considered for excavation and direct examination,
including at least the following:
(A) The known sensitivities of assessment tools;
(B) The procedures for using each tool; and
(C) The approach to be used for decreasing the physical spacing of
indirect assessment tool readings when the presence of a defect is
suspected;
(iii) For each indication identified during the indirect
examination, criteria for--
(A) Defining the urgency of excavation and direct examination of
the indication; and
(B) Defining the excavation urgency as immediate, scheduled, or
monitored; and
(iv) Criteria for scheduling excavations of indications in each
urgency level.
(4) Direct examination. In addition to the requirements in Section
5 of NACE Standard RP0502-2002, the procedures for direct examination
of indications from the indirect examination must include--
(i) Provisions for applying more restrictive criteria when
conducting ECDA for the first time on a pipeline segment;
(ii) Criteria for deciding what action should be taken if either:
(A) Corrosion defects are discovered that exceed allowable limits
(Section 5.5.2.2 of NACE Standard RP0502-2002 provides guidance for
criteria); or
(B) Root cause analysis reveals conditions for which ECDA is not
suitable (Section 5.6.2 of NACE Standard RP0502-2002 provides guidance
for criteria);
(iii) Criteria and notification procedures for any changes in the
ECDA plan, including changes that affect the severity classification,
the priority of direct examination, and the time frame for direct
examination of indications; and
(iv) Criteria that describe how and on what basis you will
reclassify and re-prioritize any of the provisions specified in Section
5.9 of NACE Standard RP0502-2002.
(5) Post assessment and continuing evaluation. In addition to the
requirements in Section 6 of NACE Standard UP 0502-2002, the procedures
for post assessment of the effectiveness of the ECDA process must
include--
(i) Measures for evaluating the long-term effectiveness of ECDA in
addressing external corrosion in pipeline segments; and
(ii) Criteria for evaluating whether conditions discovered by
direct examination of indications in each ECDA region indicate a need
for reassessment of the pipeline segment at an interval less than that
specified in
[[Page 61577]]
Sections 6.2 and 6.3 of NACE Standard RP0502-2002 (see Appendix D of
NACE Standard RP0502-2002).
Issued in Washington, DC, on October 19, 2005.
Brigham A. McCown,
Acting Administrator, PHMSA.
[FR Doc. 05-21233 Filed 10-24-05; 8:45 am]
BILLING CODE 4910-60-P