# Pipeline Safety: Standards for Direct Assessment of Gas and Hazardous Liquid Pipelines

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- **citation:** PHMSA Guidance, Pipeline Safety: Standards for Direct Assessment of Gas and Hazardous Liquid Pipelines
- **title:** Pipeline Safety: Standards for Direct Assessment of Gas and Hazardous Liquid Pipelines
- **source type:** guidance
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** guidance
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- **summary:** Pipeline Safety: Standards for Direct Assessment of Gas and Hazardous Liquid Pipelines Document 05-21233.pdf (169.08 KB) 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 stand
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Pipeline Safety: Standards for Direct Assessment of Gas and Hazardous Liquid Pipelines

Document

 05-21233.pdf (169.08 KB)

        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.

          Effective Date: Tuesday, October 25, 2005

<<<PAGE 1>>>

Federal Register/ Vol. 70, No. 205/Tuesday, October 25, 2005/ Rules and Regulations
61571
area(s) which result from a CERCLA
administrative order, a CERCLA or RCRA
1552.229-70 [Removed and reserved]
*
consent decree or a court order.
1552.229-70.
• 11. Remove and reserve section
on pipelines made primarily of steel or
collection, indirect inspection, direct
iron. The process involves data
(Start) (Apr 2004)
Limitation of Future Contracting Alternate II
1552.237-73 [Removed and reserved]
examination, and evaluation. Operators
existing corrosion defects but also to
use direct assessment not only to find
• 12. Remove and reserve section
including any options, the Contractor agrees
(d) During the life of this contract,
1552.237-73.
prevent future corrosion problems.
[FR Doc. 05-21196 Filed 10-24-05; 8:45 am]
using direct assessment on U.S
Congress recognized the advantages of
that unless otherwise authorized by the
Contracting Officer:
BILLING CODE 6560-50-P
Department of Transportation (DOT)
services (e.g., Emergency and Rapid
(1) It will not provide to EPA cleanup
carbon dioxide pipeline facilities.
regulated gas, hazardous liquid, and
Response Services (ERRS) contracts) within
DEPARTMENT OF TRANSPORTATION
Improvement Act of 2002 (Pub. L. 107-
Section 14 of the Pipeline Safety
the Contractor's START assigned
geographical area(s), either as a prime
Safety Administration
Pipeline and Hazardous Materials
Contractor, subcontractor, or consultant.
355; Dec. 17, 2002) directs DOT to issue
has been prepared by a third party, it will not
(2) Unless an individual design for the site
pressure testing, and direct assessment
regulations on using internal inspection,
49 CFR Parts 192 and 195
subcontractor or consultant any remedial
provide to EPA as a prime contractor,
[Docket No. RSPA-04-16855; Amdt. 192-
facilities in high consequence areas. In
to manage the risks to gas pipeline
performed or plans to perform START work.
construction services at a site where it has
101 and 195-85]
addition, Section 23 directs DOT to
contractors from performing construction
This clause will not preclude START
RIN 2137—AD97
for inspecting pipeline facilities by
issue regulations prescribing standards
management services under other EPA
Assessment of Gas and Hazardous
Pipeline Safety: Standards for Direct
direct assessment.
directive, Section 14, DOT's Research
In response to the first statutory
type activities contracts for sites within its
(3) It will be ineligible for award of ERRS
Liquid Pipelines
respective START assigned geographical
Materials Safety Administration
AGENCY: Pipeline and Hazardous
(RSPA) 1 published regulations in 49
and Special Programs Administration
administrative order, a CERCLA or RCRA
area(s) which result from a CERCLA
(PHMSA), DOT.
operators to follow detailed programs to
CFR part 192, subpart O, that require
consent decree or a court order.
ACTION: Final rule.
manage the integrity of gas transmission
governing integrity management of gas
SUMMARY: Under current regulations
areas. Subpart O also requires an
line segments in high consequence
Limitation of Future Contracting Alternate
*
III (ESAT) (Apr 2004)
*
transmission lines, if an operator uses
operator electing to use direct
risks, it must carry out the direct
direct assessment to evaluate corrosion
program, to carry out the direct
assessment in its integrity management
IV (TES) (Apr 2004)
Limitation of Future Contracting Alternate
assessment according to PHMSA
192.927, and 192.929, as appropriate.2
assessment according to SS 192.925,
*
standards. In response to a statutory
directive, this Final Rule prescribes
192.929 cross-reference the American
Sections 192.925, 192.927, and
Limitation of Future Contracting Alternate V
when they use direct assessment on
similar standards operators must meet
(Headquarters Support) (Apr 2004)
(ASME), ASME B31.8S-2001,
Society of Mechanical Engineers'
certain other onshore gas, hazardous
contract, will be ineligible to enter into a
(c) The Contractor, during the life of this
PHMSA believes broader application of
liquid, and carbon dioxide pipelines.
Pipelines.
"Managing System Integrity of Gas
describes a comprehensive process to
" ASME B31 8S_2001|
work (e.g., Response Action Contract (RAC),
contract with EPA to perform response action
enhance public confidence in the use of
direct assessment standards will
assess and mitigate the likelihood and
(ERRS), Superfund Technical Assistance and
Emergency and Kapid Response Services
direct assessment to assure pipeline
addition, $ 192.925 cross-references a
consequences of gas pipeline risks. In
Support Services (ESS) contracts), unless
Removal Team (START), and Enforcement
otherwise authorized by the Contracting
DATES: This Final Rule takes effect
reference of NACE Standard RP0502-
November 25, 2005. Incorporation by
Programs Improvement Act (Pub. L. 108-426, 118;
1 The Norman Y. Mineta Research and Special
November 30, 2004) reorganized RSPA into two
2002 in this rule is approved by the
Hazardous Materials Safety Administration
new DOT administrations: the Pipeline and
VI (Site Specific) (Apr 2004)
Limitation of Future Contracting Alternate
November 25, 2005.
Director of the Federal Register as of
(PHMSA) and the Research and Innovative
*
*
Technology Administration. RSPA's regulatory
Furrow by phone at 202-366-4559, by
FOR FURTHER INFORMATION CONTACT: L.M.
safety was transferred to PHMSA.
authority over pipeline and hazardous materials
including any options, the Contractor agrees
(d) During the life of this contract,
Department of Transportation, 400
fax at 202-366-4566, by mail at U.S.
assessment $ 192.925) requires operators to
2 The standard on external corrosion direct
Contracting Officer:
that unless otherwise authorized by the
integrate data on physical characteristics and
Technical Assistance and Removal Team
(1) It will not provide any Superfund
Seventh Street, SW., Washington, DC
inspections, directly examine pipe surfaces, and
operating history, conduct indirect aboveground
buck.furrow@dot.gov.
20590, or by e-mail at
(START) type activities (e.g., START
Under the standard for direct assessment of internal
evaluate the effectiveness of the assessment process.
contractor, subcontractor, or consultant.
contracts) to EPA on the site either as a prime
SUPPLEMENTARY INFORMATION:
corrosion (§ 192.927), operators must predict
locations where electrolytes may accumulate in
*
I. Background
normally dry-gas pipelines, examine those
assessment, a process of managing the
This Final Rule concerns direct
standard for direct assessment of stress corrosion
locations, and validate the assessment process. The
1552.215-76 [Removed and reserved]
relevant to stress corrosion cracking, assessing the
cracking (§ 192.929) involves collecting data
1552.215-76.
• 10. Remove and reserve section
effects of external corrosion, internal
corrosion, or stress corrosion cracking
evaluating segments at risk.
risk of pipeline segments, and examining and

<<<PAGE 2>>>

61572 Federal Register / Vol. 70, No. 205 / Tuesday, October 25, 2005 / Rules and Regulations
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 § § 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
§ 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 § § 192.925, 192.927,
or 192.929, as appropriate. For regulated
hazardous liquid and carbon dioxide
pipelines, proposed § 195.588 would
require similar action, except
compliance with § 192.927 would not be
required, because § 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
State pipeline safety agency ................................................... Gas pipeline operators ............................................................ 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 (§ 195.452) to
allow use of direct assessment without
prior notice.
As a result of its deliberation, the
TPSSC voted unanimously that
proposed § 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:
Pennsylvania Public Utility Commission.
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).
American Public Gas Association (APGA), American Gas Association (AGA),
Interstate Natural Gas Association of America (INGAA), Northeast Gas Asso-
ciation (NGA).
Gas Piping Technology Committee (GPTC).
American Petroleum Institute (API), Association of Oil Pipe Lines (AOPL).
Cook Inlet Regional Citizens Advisory Council, Pipeline Safety Trust
Glen F. Armstrong.
Gas pipeline trade associations .............................................. Gas pipeline industry committee ........................................... Hazardous liquid pipeline trade associations ....................... Nonprofit organizations .......................................................... Consultant ................................................................................ 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 § 192.490 appropriate for
gas distribution lines? AGA, APGA,
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Federal Register / Vol. 70, No. 205 / Tuesday, October 25, 2005 / Rules and Regulations
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 § 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
(§ § 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
§ § 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 § 195.588
suitable for hazardous liquid and
carbon dioxide pipelines? In their
comments on proposed § 195.588, AOPL
and API opposed cross-referencing
§ § 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
§ 195.588. Instead, final § 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 (§ 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
(§ § 195.452(c)(1)(i)(C) and
195.452(j)(5)(iii)).
In contrast to § 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
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61574 Federal Register / Vol. 70, No. 205 / Tuesday, October 25, 2005 / Rules and Regulations
give advance notice before using direct
assessment.
In their comments on proposed
§ 195.588, AOPL and API suggested
direct assessment of external corrosion
should be listed directly in § 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 § 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 § 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 § 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 § 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
§ § 195.452(c)(1)(i)(C) and
195.452(j)(5)(iii) to allow use of direct
assessment in accordance with final
§ 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
§ 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 § 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 § 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
§ 192.929, final § 195.588 consists of the
text of § 192.925 without its cross-
references to ASME B31.8S–2001.
V. Editorial Changes
• Final § § 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 § 192.490 clarifies that ‘‘direct
assessment’’ means direct assessment as
defined in § 192.903.3 This definition
applies to ‘‘direct assessment’’ as it is
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.’’
used in subpart O of part 192, including
§ § 192.925, 192.927, and 192.929—the
bases of the proposed direct assessment
standards. Also, in final § 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.
• We added a similar definition of
‘‘direct assessment’’ to § 195.553, which
contains definitions applicable to
subpart H of part 195, including final
§ 195.588. This addition satisfies the
first THLPSSC recommendation. The
definition of ‘‘external corrosion direct
assessment,’’ which was proposed
through the cross-reference to § 192.925,
is also added to § 195.553.
• In final § 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 § 192.903—a segment of
transmission pipeline located in a high
consequence area—would
unintentionally constrain the scope of
final § 195.588. A footnote resolves a
similar problem in final § 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
(§ § 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 § 192.925,
the NPRM did not address extending
§ § 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 § 192.925
meant that operators who voluntarily
use external corrosion direct assessment
on pipelines outside subpart O would
also have to comply with § § 192.917(b)
and 192.917(e)(1). To ensure this
possible inference does not affect the
Final Rules, final § § 192.490 and
195.588 exclude pipelines outside
subpart O from the § 192.925(b)
requirement related to integrating
coating damage data. Nevertheless, for
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Federal Register / Vol. 70, No. 205 / Tuesday, October 25, 2005 / Rules and Regulations
61575
hazardous liquid and carbon dioxide
pipelines that are subject to the integrity
management regulations in § 195.452,
the detection of coating damage is an
important factor to consider in the
information analysis required by
§ 195.452(g) and the continual integrity
evaluation required by § 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.
s 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
s 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.
s 2. Add § 192.490 to read as follows:
§ 192.490 Direct assessment.
Each operator that uses direct
assessment as defined in § 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.
Threat External corrosion ................... Internal corrosion in pipelines
that transport dry gas.
Stress corrosion cracking ....... Standard 1
§ 192.925 2
§ 192.927
§ 192.929
1 For lines not subject to subpart O of this
part, the terms ‘‘covered segment’’ and ‘‘cov-
ered pipeline segment’’ in §§ 192.925,
192.927, and 192.929 refer to the pipeline
segment on which direct assessment is per-
formed.
2 In § 192.925(b), the provision regarding de-
tection of coating damage applies only to pipe-
lines subject to subpart O of this part.
PART 195—TRANSPORTATION OF
HAZARDOUS LIQUIDS BY PIPELINE
s 3. The authority citation for part 195
continues to read as follows:
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61576
Federal Register/ Vol. 70, No. 205/Tuesday, October 25, 2005/ Rules and Regulations
60108, 60109, 60118; and 49 CFR 1.53.
Authority: 49 U.S.C. 5103, 60102, 60104,
inspection, direct examination, and
post-assessment to evaluate the threat of
assessment tools;
(A) The known sensitivities of
• 4. In § 195.3(c), amend the table of
external corrosion to the integrity of a
tool; and
(B) The procedures for using each
referenced material by adding item G.(2)
to read as follows:
pipeline.
*
*
decreasing the physical spacing of
(C) The approach to be used for
whole or in part.
Matter incorporated by reference in
• 7. Add § 195.588 to read as follows:
§ 195.588 What standards apply to direct
indirect assessment tool readings when
(c)**
*
assessment?
the presence of a defect is suspected
during the indirect examination, criteria
(iii) For each indication identified
onshore pipeline to evaluate the effects
(a) If you use direct assessment on an
for-
G.
(2) NACE Standard RP0502-
Corrosion Direct Assess-
2002 "Pipeline External
§ 195.588
the requirements of this section for
of external corrosion, you must follow
excavation and direct examination of
(A) Defining the urgency of
assessment. This section does not apply
performing external corrosion direct
the indication; and
ment Methodology" (2002).
immediate, scheduled, or monitored;
(B) Defining the excavation urgency as
to methods associated with direct
• a. Redesignate paragraph (c)(1)(i)(C) as
• 5. Amend § 195.452 as follows:
assessment, such as close interval
examination of exposed pipelines, when
surveys, voltage gradient surveys, or
excavations of indications in each
(iv) Criteria for scheduling
(c)(1)(i)(D);
• b. Remove "or" from the end of
used separately from the direct
urgency level
paragraph (c)(1)(i)(B);
assessment process.
the requirements in Section 5 of NACE
(4) Direct examination. In addition to
(j)(5)(iv);
• c. Redesignate paragraph (j)(5)(iii) as
external corrosion direct assessment are
(b) The requirements for performing
for direct examination of indications
Standard RP0502-2002, the procedures
• d. Remove "or" from the end of
as follows:
paragraph (j)(5)(ii); and
requirements of NACE Standard
(1) General. You must follow the
from the indirect examination must
(j)(5)(iii) to read as follows:
• e. Add new paragraphs (c)(1)(i)(C) and
reference, see § 195.3). Also, you must
RP0502-2002 (incorporated by
restrictive criteria when conducting
(i) Provisions for applying more
high consequence areas.
§ 195.452 Pipeline integrity
- **truncated:** true
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