[Federal Register: December 15, 2003 (Volume 68, Number 240)]
[Rules and Regulations]
[Page 69777-69837]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr15de03-19]
[[Page 69777]]
-----------------------------------------------------------------------
Part II
Department of Transportation
-----------------------------------------------------------------------
Research and Special Programs Administration
-----------------------------------------------------------------------
49 CFR Part 192
Pipeline Safety: Pipeline Integrity Management in High Consequence
Areas (Gas Transmission Pipelines); Final Rule
[[Page 69778]]
-----------------------------------------------------------------------
DEPARTMENT OF TRANSPORTATION
Research and Special Programs Administration
49 CFR Part 192
[Docket No. RSPA-00-7666; Amendment 192-95]
RIN 2137-AD54
Pipeline Safety: Pipeline Integrity Management in High
Consequence Areas (Gas Transmission Pipelines)
AGENCY: Office of Pipeline Safety (OPS), Research and Special Programs
Administration (RSPA), DOT.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: This final rule requires operators to develop integrity
management programs for gas transmission pipelines located where a leak
or rupture could do the most harm, i.e., could impact high consequence
areas (HCAs). The rule requires gas transmission pipeline operators to
perform ongoing assessments of pipeline integrity, to improve data
collection, integration, and analysis, to repair and remediate the
pipeline as necessary, and to implement preventive and mitigative
actions. RSPA/OPS has also modified the definition of HCAs in response
to a petition for reconsideration from industry associations. This
final rule comprehensively addresses statutory mandates, safety
recommendations, and conclusions from accident analyses, all of which
indicate that coordinated risk control measures are needed to improve
pipeline safety.
DATES: This final rule takes effect January 14, 2004. The incorporation
by reference of certain publications in this rule is approved by the
Director of the Federal Register as of January 14, 2004.
Privacy Act Information: You may review DOT's complete Privacy Act
Statement in the Federal Register published on April 11, 2000 (Volume
65, Number 70; Pages 19477-78) or you may visit the Dockets Management
System (DMS) Web site at http://dms.dot.gov. You may search the
electronic form of all comments received into any of our dockets by the
name of the individual submitting the comment (or signing the comment,
if submitted on behalf of an association, business, labor union, etc.).
General Information: You may contact the Dockets Facility by phone
at (202) 366-9329 for copies of this final rule or other material in
the docket. All materials in this docket may be accessed electronically
at http://dms.dot.gov/search. Once you access this address, type in the
last four digits of the docket number shown at the beginning of this
notice (7666), and click on search. You will then be able to read and
download comments and other documents related to this final rule.
FOR FURTHER INFORMATION CONTACT: Mike Israni by phone at (202) 366-
4571, by fax at (202) 366-4566, or by e-mail at mike.israni@rspa.dot.gov, regarding the subject matter of this final
rule. General information about the RSPA/OPS programs may be obtained
by accessing RSPA's Internet page at http://RSPA.dot.gov.
SUPPLEMENTARY INFORMATION: RSPA/OPS believes it can ensure the
integrity of gas transmission pipelines by requiring each operator to:
(a) Develop and implement a comprehensive integrity management program
for pipeline segments where a failure would have the greatest impact on
the public or property; (b) identify and characterize applicable
threats to pipeline segments that could impact a high consequence area;
(c) conduct a baseline assessment and periodic reassessments of these
pipeline segments; (d) mitigate significant defects discovered from the
assessment; and (e) continually monitor the effectiveness of its
integrity program and modify the program as needed to improve its
effectiveness. This final rule does not apply to gas gathering or to
gas distribution pipelines.
This final rule satisfies Congressional mandates that require RSPA/
OPS to prescribe standards that establish criteria for identifying each
gas pipeline facility located in a high-density population area and to
prescribe standards requiring the periodic inspection of pipelines
located in these areas, including the circumstances under which an
inspection can be conducted using an instrumented internal inspection
device (smart pig) or an equally effective alternative inspection
method. The final rule also incorporates the required elements for gas
integrity management programs mandated in the Pipeline Safety
Improvement Act of 2002, which was signed into law on December 17,
2002, and codified at 49 U.S.C. 60109.
Background
Notice of Proposed Rulemaking
On January 28, 2003, RSPA/OPS published a Notice of Proposed
Rulemaking (68 FR 4278) that proposed pipeline integrity management
requirements for gas transmission pipelines. In the preamble to that
Notice, RSPA/OPS explained in great detail the history of the proposed
rule and how the proposal addressed statutory mandates, National
Transportation Safety Board (NTSB) recommendations, and safety
conclusions drawn from accident analyses. RSPA/OPS had finalized the
definition of HCAs for gas transmission pipelines in a prior rulemaking
on August 6, 2002 (67 FR 50824).
The American Gas Association (AGA), the American Public Gas
Association (APGA), the Interstate Natural Gas Association of America
(INGAA), and the New York Gas Group (NYGAS) filed a petition for
reconsideration of the HCA final rule. Issues raised in the petition
are discussed in the section titled, Petition for Reconsideration of
the final rule on the definition of High Consequence Areas. RSPA/OPS
addressed certain aspects of the petition in the published notice of
proposed rulemaking on gas transmission pipeline integrity management
program requirements (68 FR 4278; January 28, 2003). The remaining
issues were addressed in two notices published on July 17, 2003--
Response to Petition for Reconsideration (68 FR 42456) and Issuance of
Advisory Bulletin (68 FR 42458).
Pipeline Safety Improvement Act of 2002
On November 15, 2002, Congress passed the Pipeline Safety
Improvement Act of 2002, which was signed into law on December 17,
2002, and codified at 49 U.S.C. 60109. This law requires RSPA/OPS to
``issue regulations prescribing standards to direct an operator's
conduct of a risk analysis and adoption and implementation of an
integrity management program'' no later than 12 months after December
17, 2002. The statute sets forth minimum requirements for integrity
management programs for gas pipelines located in HCAs. These
requirements have been incorporated into this final rule. Statutory
requirements for an integrity program include conducting baseline and
reassessment testing of each covered transmission pipeline segment at
specified intervals, conducting an integrated data analysis on a
continuing basis, taking actions to address integrity concerns,
addressing issues raised by RSPA/OPS and by state and local authorities
under an interstate agent agreement, conducting testing in an
environmentally appropriate manner, providing notification of changes
to a program, and permitting a State interstate agent access to the
risk analysis and integrity management program.
[[Page 69779]]
Petition for Reconsideration of the Final Rule on the Definition of
High Consequence Areas
RSPA/OPS issued a final rule defining HCAs for gas transmission
pipelines on August 6, 2002 (67 FR 50824). On September 5, 2002, the
American Gas Association (AGA), the American Public Gas Association
(APGA), the Interstate Natural Gas Association of America (INGAA), and
the New York Gas Group (NYGAS) filed a petition for the reconsideration
of the final rule defining HCAs for gas transmission pipelines. This
petition is in the docket. The petition raised the following issues:
(1) The splitting of the gas integrity rule into two rulemakings--
the definition and the integrity requirements--causes confusion,
particularly, since the Potential Impact Zone concept was not included
in the definition.
(2) The high consequence area definition should clarify that it
applies to gas transmission pipelines that have the potential to impact
high population density areas and does not apply to distribution
pipelines.
(3) The ``identified site'' component of the definition (buildings
and outside areas) is overly broad. The definition should instead use
the current language in Sec. 192.5 for Class 3 outside areas.
When this petition was received, RSPA/OPS was in the final stages
of developing the NPRM on pipeline integrity management for gas
transmission pipelines in HCAs. In addition to the proposed substantive
requirements, the NPRM proposed an expanded definition of HCAs and
proposed to include a definition of a Potential Impact Zone, the area
likely to be affected by a failure. In the NPRM, RSPA/OPS discussed the
issues raised in the petition for reconsideration and its belief that
the proposal, and the final rule to follow, would address the more
significant of the issues (68 FR 4278, 4295-4296; January 28, 2003).
RSPA/OPS requested comments on several aspects of the final definition,
particularly with respect to the ``identified sites'' component. In two
notices published on July 17, 2003--Response to Petition for
Reconsideration (68 FR 42458) and Issuance of Advisory Bulletin (68 FR
42456)--RSPA/OPS addressed the remainder of issues raised by the
petitioners, and provided guidance to operators of gas transmission
pipelines on how to identify HCAs.
Comments received in response to the NPRM on integrity management
programs, comments at the public meetings following issuance of the
NPRM, and advice from the Technical Pipeline Safety Standards Committee
(TPSSC or Committee), the statutory gas pipeline advisory committee,
indicated the need for greater clarification of how operators are to
implement the ``identified sites'' aspect of the HCA definition. The
advisory bulletin published on July 17, 2003 (68 FR 42456) provides
guidance to gas transmission operators on the steps RSPA/OPS expects
them to take to determine ``identified sites'' along their pipelines.
``Identified sites'' include buildings housing people who are confined
and of limited mobility who would be difficult to evacuate, and outside
areas and buildings where people gather. The guidance allows operators
to identify these sites for purposes of planning integrity management
programs. RSPA has agreed that the intent of the regulation will be
satisfied if an operator follows the guidance. The guidance has been
incorporated into this final rule.
Public Meetings Following the NPRM
On January 28, 2003 (68 FR 4278), RSPA/OPS proposed integrity
management program requirements for gas transmission pipelines in HCAs.
The comment period for this proposal was scheduled to close on March
31, 2003, but RSPA/OPS extended this comment period to April 30, 2003.
Because the proposal was complex, a series of public meetings were held
to educate the industry and public about the proposed requirements and
to listen to comments and concerns.
On February 20-21, 2003, RSPA/OPS participated in a public workshop
sponsored by the INGAA and AGA in Houston, and on February 26, 2003, in
an audio conference jointly sponsored by AGA, APGA, and other pipeline
trade associations, to give an overview of the proposed rule and
clarify certain proposed requirements. On March 19, 2003, RSPA/OPS held
a public meeting in Washington, DC, to address issues raised at the
INGAA/AGA workshop and to better explain the proposed rule.
Participants included representatives from the National Association of
Pipeline Safety Representatives (NAPSR), INGAA, AGA, APGA, and other
Federal government agencies. Summaries of these meetings are in the
docket.
On March 25, 2003, RSPA/OPS briefed the TPSSC members about issues
raised in the public meetings and heard additional briefings on
integrity management issues, including the HCA definition. On May 28-
29, 2003, the TPSSC met to vote on the proposed gas integrity
management rule and the recommend changes.
On April 25, 2003, RSPA/OPS held another public meeting to discuss
possible courses of action on issues that had been raised during the
previous meetings. Participants included State pipeline safety
representatives, industry representatives, and the general public.
The comments at the public meetings closely tracked the comments
received to the docket and the discussions by the TPSSC at its May 2003
meeting. These issues and the advisory committee's recommendations are
discussed in the section titled, Gas Advisory Committee Considerations.
The 12 issues addressed in the comments to the docket are discussed
below in Comments to NPRM.
Gas Advisory Committee Considerations
The Technical Pipeline Safety Standards Committee is the Federal
advisory committee charged with responsibility for advising on the
technical feasibility, reasonableness, cost-effectiveness, and
practicability of proposed gas pipeline safety standards. The 15-member
Committee is comprised of individuals from industry, government, and
the general public.
On May 28-30, 2003, the TPSSC met to review the proposed gas
pipeline integrity management rule and the associated cost-benefit
analysis. The Committee voted unanimously to accept the proposed
integrity management rule as technically reasonable, feasible, and
practicable, subject to the recommended changes identified during
committee discussion. The Committee decided that before it could vote
to accept the cost-benefit analysis, RSPA/OPS must revise it in
compliance with the recommendations at the May 28-30 meeting. RSPA/OPS
sent a revised cost-benefit analysis to the committee. On July 31,
2003, the Committee voted to accept the revised cost-benefit analysis.
The transcripts from both meetings are in the docket.
Discussion on the HCA Definition and Proposed Rule
The TPSSC made the following recommendations during the May 28-30
meeting with respect to the HCA definition and the language in the
proposed integrity management program rule. RSPA/OPS discusses how it
addressed each recommendation in the final rule.
The Committee discussed how to best identify those segments of a
pipeline that present the greatest potential hazard to people so that
operators could focus integrity management efforts on those segments.
The Committee considered the bifurcated approach
[[Page 69780]]
INGAA had presented in its comments. The Committee discussed whether
rural buildings, such as rural churches, should be designated as
Moderate Risk Areas. Much of the meeting was spent on the industry's
petition for reconsideration. The Committee held an extensive
discussion on the ``identified sites'' component of the HCA definition,
focusing on places where people congregate and on buildings containing
persons of limited mobility. The TPSSC made the following
recommendations with respect to the definition of and identification of
HCAs:
Allow a bifurcated option for building count as part of the
definition of HCAs.
RSPA adopted this recommendation into the final rule and modified
Sec. 192.903 to allow two methods of identifying HCAs. This is
discussed below in section 3 of Comments to NPRM.
Address rural buildings in the same manner as any HCA.
RSPA has adopted this recommendation by modifying the ``identified
sites'' component of the HCA definition as it relates to outside areas
where people gather. The definition now differentiates between outside
areas, open structures, and rural buildings, which provide more
protection. This is discussed below in Comments to NPRM.
In the HCA definition, substitute ``public safety officials,
emergency response officials, or local emergency planning committees''
for ``local officials.''
RSPA accepted this recommendation and modified the ``identified
sites'' component of the high consequence area definition to
incorporate this change.
Define an identified site as any of the following within a
Potential Impact Circle:
1. A facility housing persons of limited mobility that is known to
public safety officials, emergency response officials, or local
emergency planning committee, and which meets one of the following
three criteria: (a) Is visibly marked, (b) is licensed or registered by
a Federal, state, or local agency, or (c) is listed on a map maintained
by or available from a Federal, State, or local agency, or
2. An outdoor area where people congregate that is known to public
safety officials, emergency response officials or local emergency
planning committee and which is occupied by 20 or more people on at
least 50 days per year, or
3. A building occupied by 20 or more people 5 days per week, 10
weeks in any 12-month period (the days and weeks need not be
consecutive).
RSPA accepted this recommendation and modified the ``identified
site'' component of the HCA area definition. This revision is
consistent with the Class 3 definition of outside area in Sec. 192.5.
The Committee discussed whether the criterion for determining the
population density component of a high consequence area should be 10 or
20 buildings intended for human occupancy within the impact circle. The
Committee recommended that RSPA/OPS:
Use 20 buildings intended for human occupancy occurring within a
Potential Impact Circle as a criterion for determining high consequence
areas.
RSPA adopted this recommendation and modified the definition of
HCA.
The TPSSC discussed whether an additional safety margin should be
applied to the Potential Impact Circle radius calculated using the C-
FER model and recommended that:
To define an HCA use the C-FER radius without additional safety
margin to define the Potential Impact Circle, and extend by one
additional radius on either side of the segment that could potentially
impact an HCA.
RSPA adopted this recommendation and modified the definition of HCA
to incorporate this additional length of pipeline.
The TPSSC discussed whether the rule should allow an operator to
use data regarding the number of buildings within 660 feet of the
pipeline (available now to operators because of the existing definition
of Class Locations at Sec. 192.5) to extrapolate the building density
in Potential Impact Circles larger than 660 feet, and what the interim
period should be for operator to collect the additional data on
buildings beyond 660 feet. The Committee voted that the rule should:
Allow a three-year period for operators to use existing house count
data out to 660 feet to infer the number of houses in impact circles
exceeding 660 feet in radius.
RSPA accepted this recommendation and intends to allow operators
three years to collect actual data and to revise the HCA to reflect
this data.
The Committee discussed what assessment requirements should be
applicable to plastic transmission pipelines and recommended that the
rule should:
Allow operators to conduct a reliability analysis as a baseline
assessment for plastic pipeline, and require appropriate preventive and
mitigative measures.
RSPA revised the final rule to require additional preventive and
mitigative measures for plastic transmission pipelines.
The Committee discussed the assessment methods and intervals that
should be required for low-stress pipelines and then voted for RSPA/OPS
to:
Use the approach suggested by AGA as described on pages 6 and 7 of
its April 30, 2003 letter, ``Amendment to Low-Stress Pipeline
Requirements.''
RSPA adopted this recommendation and created a new section in the
gas rule (Sec. 192.941) on low-stress reassessment for pipelines
operating below 30% of specified minimum yield strength (SMYS). This
recommendation provides for additional analysis focused on third-party
damage and increases the frequency of leak surveys as an alternative
form of reassessment. This is discussed below in section 7 of Comments
to NPRM.
The TPSSC discussed whether a requirement to pressure test a
pipeline to verify its integrity against material and construction
defects be limited to pipeline segments for which information suggests
a potential vulnerability. The Committee recommended that RSPA/OPS:
Incorporate into the rule the concepts of B31.8S pertaining to
material and construction defects and increased operating pressure.
RSPA has incorporated ASME/ANSI B31.8S-2001, Managing System
Integrity of Gas Pipelines, into the regulation.
The TPSSC discussed the proposed direct assessment requirements and
ways to ensure that the method provides an understanding of pipeline
integrity comparable to that provided by other assessment methods. In
particular the discussion focused on whether it should be allowed as a
primary assessment method only to address certain threats, and whether
the assessment intervals should be the same as those allowed for the
other assessment methods. The TPSSC recommended that the rule:
Allow direct assessment as a primary assessment method contingent
only on applicability to the threats and have assessment intervals the
same as those for other methods, subject to clarification on how
confirmatory direct assessment fits into the process and relates to the
NACE Recommended Practice.
RSPA/OPS has accepted this recommendation and revised the final
rule to allow direct assessment as a primary assessment method for
certain threats and to have the same assessment intervals as the other
assessment
[[Page 69781]]
methods. This is discussed below in section 4 of Comments to NPRM.
The Committee discussed some of the proposed requirements for
remediation of anomalies found during an assessment, including whether
repair criteria for dents located on the bottom of the pipeline should
be different from those for top dents and whether the presence of
stress risers or metal loss should affect this decision. The Committee
voted that RSPA/OPS:
Modify the proposal to require remediation of dents without stress
risers in one year to allow treating bottom-side dents as monitored
conditions if the operator runs the necessary tools to perform strain
calculations, meets B31.8 strain criteria, and [ensures] that the dent
involves no corrosion or stress riser.
RSPA accepted this recommendation and revised Sec. 192.933 to
address remediation requirements.
A member of the Committee noted that the proposed waiver language
did not exactly track the language in the statue. The Committee
recommended that RSPA/OPS:
Revise the proposed waiver language to be consistent with the
language in the statute.
RSPA/OPS revised the waiver language in Sec. 192.943 to track the
language in the statute. This is discussed below in section 5 of
Comments to NPRM.
The TPSSC discussed how to cost-effectively protect against delayed
failures from third-party damage and whether additional third-party
damage prevention methods should be used instead of assessments for
third-party damage. The Committee recommended that RSPA/OPS:
Use the language proposed by INGAA, in its April 17, 2003, letter
(as modified by Committee comments) as the basis for requiring
additional preventive and mitigative measures to address third-party
damage.
RSPA accepted this recommendation and revised the third-party
damage requirements.
The Committee discussed how to clarify the requirements for an
operator to look beyond the HCA segment to address segments outside the
HCA that are likely to have similar integrity concerns. After
discussion the Committee voted that the rule should:
Require that operators use the risk assessment process as described
in ASME B31.8S as the basis for deciding when actions need to be taken
for pipeline segments not in HCAs.
RSPA incorporated this recommendation into the final rule.
The TPSSC discussed at what frequency and by what means operators
should report performance measures. The recommendation was to:
Require operators to submit performance measures electronically
(instead of merely maintaining the information) on a semi-annual
frequency.
RSPA revised Sec. 192.945 to incorporate this recommendation.
The Committee discussed the proposed rule's treatment of earlier
integrity assessments to allow only assessments conducted after
December 17, 1997, to be used as a baseline assessment. The TPSSC
recommend that the rule:
Allow, without a time limit, an assessment conducted prior to the
rule as a baseline assessment as long as the prior assessment
substantially meets the requirements of the rule, and provide that the
reassessment for such a segment not be required until December 17, 2009
to the extent allowed by law.
For the reasons discussed below in section 4 of Program
Requirements, RSPA/OPS is allowing as a baseline assessment any prior
assessment conducted in accordance with the requirements of the subpart
on integrity management. RSPA/OPS has further revised the rule to
specify that the reassessment on a covered segment for which a prior
assessment is credited as a baseline be completed by December 17, 2009.
Discussion on Cost-Benefit Analysis
The TPSSC met via conference telephone call on July 31, 2003, to
discuss the draft cost-benefit analysis prepared in support of the
final rule. RSPA/OPS presented a summary of the benefits and costs of
the rule. Because of the integrity requirements in the Pipeline Safety
Improvement Act of 2002 (49 U.S.C. 60109), this rule does not impose
integrity management requirements from a baseline condition in which no
such requirements exist. The law required pipeline companies to develop
and follow integrity management programs. This rule takes advantage of
the implementation flexibility allowed in the law to focus integrity
management efforts on the highest risk areas.
RSPA/OPS estimates that implementing the requirements in the law,
without any additional flexibility, would cost approximately $11
billion over 20 years. Using the same basic assumptions, implementing
the provisions of this rule is estimated to cost $4.7 billion over 20
years, which is $6.2 billion less than implementation of the law
without a regulation. The $6.2 billion savings represents a benefit of
the rule, since the requirements of the law would have to be
implemented in the absence of regulatory action. RSPA/OPS informed the
Committee that:
[sbull] Changes in the definition of HCAs focuses pipeline operator
resources on areas of high consequence. Class 3 areas that are sparsely
populated have been deleted.
[sbull] Confirmatory direct assessment (CDA) is allowed to perform
assessments at the seven-year intervals specified in the Act. This
method is not among those listed in the law.
[sbull] The rule explicitly recognizes the scientific conclusion
that low-pressure pipelines are more likely to leak than to rupture.
Outside force damage is therefore a relatively more important threat
for low-pressure pipelines. The rule provides for assessments and
actions that emphasize damage protection, leak surveys, and electrical
surveys to better address the relevant integrity threats.
The direct safety benefits of the rule will be realized in reduced
consequences of accidents, including deaths, serious injuries, and
property damage. RSPA/OPS has estimated the value of this benefit at
$800 million over 20 years. There are a number of other potential
benefits of the rule as described to the TPSSC:
[sbull] Improved ability to site new pipelines in certain high-
volume markets because of the improvements in public confidence. RSPA/
OPS informed the Committee that this benefit is difficult to quantify,
and would be qualitatively described in the final regulatory analysis.
[sbull] Averting accidents with larger consequences than any
experienced to date. The quantitative estimate of this safety benefit
is based on the historical accident record. Population growth along
some transmission pipelines puts more people at risk and exposes the
pipelines to increased chances of third-party damage. Therefore, it is
possible that accidents larger than any in the historical record could
occur. This rule will act to significantly reduce the likelihood of
such accidents, because it is focused on precisely the high population
areas in which they could occur. RSPA/OPS informed the Committee that
this benefit would be analyzed further and quantified in the final
regulatory analysis.
[sbull] The final rule exceeds the requirements of the law in ways
that will avert accidents. This includes the requirement that consensus
standards be used, and that a threat-by-threat analysis be performed to
ascertain needed protections.
[[Page 69782]]
[sbull] Avoiding the economic impact of unexpected supply
interruptions. The Federal Energy Regulatory Commission (FERC) has
estimated the impact of the 2000 Carlsbad, New Mexico accident on
California spot gas prices. RSPA/OPS has used this estimate to
calculate that the increase in gas prices resulted in an economic
impact to California of approximately $17.25 million per day.
[sbull] The rule will provide a better technical justification for
increasing operating pressure in pipelines to alleviate future supply
crises.
[sbull] The rule will provide a better technical justification to
support waivers from existing requirements that mandate replacement of
pipeline when population increases cause a change in class location.
Experience may lead to future changes in the existing requirements. For
now, estimation of the value of this benefit will be based on the use
of waivers to eliminate pipe replacement after a class location change
where there is adequate safety justification.
The TPSSC suggested that a reduction in the time required to return
pipelines to service after accidents or regulatory shutdowns is another
benefit of the rule. The premise is that implementation of the rule
will provide better information about the pipeline. When pipelines are
ordered shutdown, much of the time is used to gather additional
information about the pipeline's integrity to support a return to
service. Implementation of this rule will make more information readily
available and will lead to less shutdown time. We expect shutdown times
to be reduced by 50%.
The TPSSC agreed that the cost estimates presented by RSPA/OPS were
reasonable. The committee commented that it is reasonable to assume
that the benefits from implementing the law and the final rule would be
similar, but that they are also very uncertain.
The TPSSC commented that the Pipeline Safety Improvement Act of
2002 imposes restrictions on what can be done within this rule. The
Committee concluded that RSPA/OPS had reasonably exercised the
authority it was afforded under the Act. The Committee also recommended
that provisions in the Act that impose the most hardships--requirements
to perform assessments at seven-year intervals and to perform
reassessments before baseline assessments--be revisited in discussions
with Congress.
The TPSSC unanimously approved the draft cost-benefit analysis,
subject to the comments noted above.
Comments to NPRM
We received over 700 comments from 90 different sources in response
to the NPRM. Some commenters submitted several comments, each comment
addressing a different topic in the proposed rule. The commenters were
as follows:
Seven (7) Trade associations with members affected by this
rulemaking: American Gas Association (AGA), American Public Gas
Association (APGA), Association of Texas Intrastate Natural Gas
Pipelines, Energy Association of Pennsylvania, Interstate Natural Gas
Association of America (INGAA), Inline Inspection Association (IIA),
and Northeast Gas Association (NEGA).
50 U.S. pipeline operators: AGL Resources, Air Products and
Chemicals, Inc., Arkansas Oklahoma Gas Corporation, Atmos Energy Corp.,
Baltimore Gas and Electric Company, ChevronTexaco, CMS Panhandle
Eastern Pipe Line Company, CMS Sea Robin Pipeline Company, CMS
Trunkline Gas Company, Consolidated Edison Company of New York,
Consumers Energy, Dominion Delivery, Duke Energy Gas Transmission
Corporation, El Paso Pipeline Group, Enbridge Energy Company, Enron
Transportation Services, Equitable Gas Company and Equitrans LP,
Houston Pipe Line Company, Intermountain Gas Company, Kansas Gas
Service, Kern River Gas Transmission Company, Laclede Gas Company,
Metropolitan Utilities District, MidAmerican Energy Company, National
Fuel Gas Supply Corporation, New Jersey Natural Gas Company, Nicor Gas,
NiSource Corporate Services, North Shore Gas Company, Northern Natural
Gas Company, Oklahoma Natural Gas, ONEOK, Paiute Pipeline Company, PECO
Energy, Peoples Gas Light and Coke Company, PG&E Corporation, Piedmont
Natural Gas, PSNC Energy, Public Service Electric and Gas Company,
Puget Sound Energy, Questar Regulated Services, Sempra Energy
Utilities, South Carolina Pipeline Corporation, Southwest Gas
Corporation, TXU Gas Company, Vectren Utility Holdings, Inc. Williams
Gas Pipeline, Williston Basin Interstate Pipeline Company, and Xcel
Energy.
One (1) Canadian pipeline operator: TransCanada Pipelines Limited.
Five (5) state agencies: Florida Department of Environmental
Protection, Iowa Utilities Board New York State Department of Public
Service, State of Connecticut Department of Public Utility Control,
Washington Utilities and Transportation Commission.
Three (3) advocacy groups: Citizens for Safe Pipelines, Cook Inlet
Keeper, and Washington State Citizens Advisory Committee on Pipeline
Safety.
Three (3) consensus standards organizations: Gas Piping Technology
Committee (GPTC), NACE International, and Standards-Developing
Organizations Coordinating Council (SDOCC).
One (1) Federal agency: National Transportation Safety Board
(NTSB).
One (1 ) city/county: Washington City and County Pipeline Safety
Consortium.
Two (2) consultant/contractors: Accufacts, and Oleska & Associates.
Three (3) businesses: Advanced Technology Corporation,
Controlotron, and Kaempen Pipe Corporation.
One (1) private citizen: Carol M. Parker.
General Comments
Most commenters supported the need for integrity management program
requirements, and provided comments to the proposed rule that focused
on specific details and language. Most commenters asserted that the
proposed rule was too complicated and, to ensure safety and ease of
compliance, should be simplified and clarified.
Some of the broader comments included one from a private citizen,
Carol Parker, who asserted that the new pipeline safety law was written
to ensure ``adequate protection against risks to life and property
posed by pipeline transportation'' and that RSPA should use this new
law as a guide to ensure adequate protection. Similarly, the Washington
State Advisory Committee commented that the new rule should not
sacrifice rule credibility and enforceability for timeliness, and
recommended that RSPA slow down the process to ensure proper rule
development. The NTSB stated that it generally supported the elements
of the proposed rule including the baseline assessments, threat risk
assessments, determination of assessment methods, and remediation and
reassessment provisions. More specific comments are discussed under the
applicable topic.
We have organized the comments into the following twelve groups,
and will summarize both the comments and our responses on an individual
basis.
1. Need for Clarity and Specificity
2. Applicability (Coverage) of the Rule
3. High Consequence Areas
4. Program Requirements and Implementation, including Integrity
Assessment Time Frames, Assessment Methods and Criteria
5. Review, Notification and Enforcement Processes
[[Page 69783]]
6. Consensus Standard on Pipeline Integrity
7. Low-Stress Pipelines
8. Remedial Actions
9. Additional Preventive and Mitigative Measures, including, Leak
Detection Devices and Automatic Shut-off and Remote Control Valves
10. Methods to Measure Program Effectiveness
11. Information for Local Officials and the Public
12. Cost-Benefit Analysis
1. Need for Clarity and Specificity
Several commenters, including the Public Service Electric and Gas
Company (PSE&G), maintained that the formatting of the proposed rule
makes it difficult to follow, which could lead to a lower level of
understanding and less compliance. PSE&G suggested that the final rule
be simplified and reformatted, with clearly numbered sections and an
index. Piedmont Natural Gas recommended the use of several sections to
present the regulations because the proposed cross-references and
formatting make the proposed rule difficult to read and understand.
Some commenters, including Peoples Energy, suggested that we better
define terms that are subjective and possibly vague. Some of those
terms included: state-of-the-art, comprehensive additional preventive
measures, expected future corrosion conditions, critical stage, and
additional extensive inspection and maintenance programs.
Numerous other commenters, including Northeast Gas Association,
Puget Sound Energy, and the Iowa Utilities Board, suggested rewriting
the rule as a separate subpart of part 192 in a clearer, more
simplified form.
Response: RSPA/OPS agrees that the proposed rule was complicated
and often difficult to follow. There are a large number of interrelated
requirements. Including all of those requirements under a single
section of part 192, as was done in the proposed rule, required use of
many sub-paragraphs and divisions. RSPA/OPS has adopted the suggestion
that the final rule be rewritten as a separate subpart of part 192.
The final rule has been recast as new Subpart O, Pipeline Integrity
Management, of part 192, in which we have consolidated all of the
requirements applicable to gas transmission pipeline integrity
management programs. The definition of HCAs, previously Sec. 192.761,
has been relocated to the new subpart (with changes as described
below). This revised structure allows each of the major elements of the
rule to be described in a separate, numbered section. The use of
subparagraphs and divisions in the final rule is very limited. RSPA/OPS
believes that the structure of the final rule makes it much easier to
follow and understand, and will better support compliance by operators.
The rule has also been revised to improve its clarity and
specificity. For example, we deleted terms such as ``state-of-the-
art.'' And we specify which ``comprehensive additional preventive
measures'' an operator must implement. We eliminated the section
containing the phrase ``expected future corrosion conditions'' in favor
of referencing an applicable consensus standard. At the time we
proposed the rule, relevant industry consensus standards were under
development. These standards have since been finalized and we have
incorporated them into the rule.
This rule uses, as did the corresponding rule for hazardous liquid
pipelines, a mix of performance-based and prescriptive requirements. As
described in the final rule on integrity management programs for
hazardous liquid pipelines (65 FR 73832), RSPA/OPS believes that
performance-based regulation will result in effective integrity
management programs that are sufficiently flexible to reflect pipeline-
specific conditions and risks. Pipeline conditions vary. It is
impractical to specify requirements that will address all
circumstances. In some cases, they would impose unnecessary burdens. In
others, they might not achieve the desired level of safety. Including
performance-based requirements is the best means to ensure that each
pipeline develops and implements effective integrity management
programs that address the risks of each pipeline segment.
2. Applicability (Coverage) of the Rule--Sec. 192.901 (Formerly Sec.
192.763(a)(b))
The proposed integrity management program requirements were
intended to apply to all gas transmission pipelines. Other gas
pipelines were not included in the scope of the proposed rule.
NTSB commented that gathering pipelines in populated areas should
be included. The New York State Department of Public Service maintained
that only those gathering pipelines in HCAs and operating above 20% of
SMYS should be included.
At the public meetings and advisory committee meeting, participants
noted that the NPRM and pipeline safety statute did not address plastic
gas transmission pipelines. At the advisory committee meeting, a
representative of APGA prepared a handout on plastic transmission
pipelines. The handout included recommendations from Southwest Gas that
RSPA/OPS should exclude plastic pipelines from the integrity management
regulation or, as an alternative, exclude these pipelines from the
assessment requirements because the assessment methods are not
applicable to plastic. In addition, the handout noted that the proposed
additional preventive and mitigative measures for corrosion are not
applicable to plastic pipe because it is not subject to corrosion. The
handout suggested that third-party excavation damage is the primary
threat to plastic pipe.
Both Cook Inlet Keeper and the Washington Utilities and
Transportation Commission (WUTC) commended OPS's goal to promote safety
throughout pipeline systems. They recommended that the proposed rule
require that lessons learned from assessments on pipeline segments in
HCAs be applied to all segments of pipeline and all operators. Although
INGAA agreed with the concept of applying lessons learned to pipeline
segments outside the scope of the proposal, it recommended modifying
the requirement to clarify how data and information developed from
covered segments will be applied to non-covered segments. INGAA
suggested an approach for applying this concept using the framework of
standard ASME/ANSI B31.8S. Several industry commenters agreed with
INGAA, but numerous commenters asserted that expanding the requirements
of the rule to entire pipelines is inappropriate. NiSource contended
that an expansion conflicts with the intent of Congress to focus
resources on high risk areas. NiSource also suggested that the final
rule should incorporate ASME/ANSI B31.8S as it relates to collection,
review, and integration of data to update risk assessments.
Response: The final rule prescribes minimum requirements for
integrity management programs on any gas transmission pipeline subject
to Part 192. The requirements do not apply to gas gathering or
distribution pipelines. Although some requirements are of broad
applicability, they apply mainly to segments of gas transmission
pipelines in HCAs. RSPA/OPS agrees with Cook Inlet Keeper and WUTC that
lessons learned in developing and applying the integrity management
program in HCAs should be applied to other portions of the pipeline. It
would not be prudent to fail to address known problems that could
challenge the integrity of a pipeline simply because they did not occur
in HCA pipeline segments. The rule requires that all operators evaluate
and remediate non-
[[Page 69784]]
covered segments of their pipelines that have similar characteristics
to covered sections on which corrosion is found (Sec. 192.917(e)(5)
and Sec. 192.927(c)(3)(iii)). The rule further requires that operators
who qualify for the performance-based option have a procedure for
applying lessons learned from assessment of covered pipe segments to
pipe segments not covered. (Sec. 192.913(b)(1)(iv).)
The rule does not require integrity assessment, but it does require
evaluation of risk associated with non-covered segments and appropriate
actions to address those risks. Such a requirement would divert
resources away from pipeline segments that pose the most risk (i.e.,
those located in HCAs) to those which pose lesser risks. ASME/ANSI
B31.8S, the consensus standard on Managing System Integrity of Gas
Pipelines, provides a method by which operators can perform these
evaluations.
Although it is necessary to apply lessons learned on covered
segments to non-covered segments of pipeline, it is equally appropriate
that knowledge gained in segments of pipeline that cannot affect HCAs
be used in the evaluation of covered segments. The rule requires this
as part of an operator's data gathering and integration activities
(Sec. 192.917(b)). The operators must, at a minimum, evaluate the set
of data specified in ASME/ANSI B31.8S.
When RSPA/OPS proposed the integrity management program
requirements for gas transmission pipelines, it had not considered
plastic transmission pipelines. The statute does not allow an exemption
for such pipelines. However, based on the information developed after
issuance of the NPRM, we recognize that these pipelines typically
operate at very low pressures and are not subject to corrosion.
Internal inspection tools are not useful for evaluating the condition
of these pipelines. Corrosion protection measures are not required
because plastic does not corrode. Therefore, in the final rule we have
recognized that these pipelines cannot be assessed by the methods
allowed for metallic transmission pipelines. An operator of a plastic
transmission pipeline will have to conduct, on a continual basis, a
threat analysis to evaluate the threats unique to the integrity of
plastic pipe. If the analysis shows that the pipeline is susceptible to
failure from a cause other than third-party damage, the operator must
conduct a baseline assessment by a method demonstrated to characterize
the risks, and must apply additional preventive and mitigative measures
as necessary.
A government/industry Plastic Pipe Database Committee (PPDC) has
been formed to develop and maintain a voluntary plastic pipe data
collection process to support the analysis of the frequency and causes
of in-service plastic pipe material failures. The PPDC monitors failure
experience to characterize any failure trends in older plastic pipe
materials. Thorough analysis of data on plastic pipelines having
similar fabrication, construction, and operational characteristics will
alert operators of these pipelines to integrity threats other than
third-party damage.
3. High Consequence Areas--Sec. 192.903 (Formerly Sec. 192.761)
The definition of HCAs for gas transmission pipelines was set forth
in a final rule on August 6, 2002. The definition included Class 3 and
4 locations, and ``identified sites'', i.e., buildings housing people
who have limited mobility or are difficult to evacuate and outside
areas where there is sufficient evidence of people congregating. The
rule listed ways for an operator to identify these sites, including
visible marking, licensure or registration by a Federal, State, or
local agency, knowledge of public safety officials, or a list or map
maintained by or available from a Federal, State, or local agency.
The definition generated numerous comments. And, as discussed
elsewhere in this document, industry trade associations filed a
petition for reconsideration of the definition. At the public meetings
following the issuance of the integrity management NPRM, meeting
participants commented in great detail about problems with the
definition. At the TPSSC meeting, members discussed the definition and
issues raised in the petition for reconsideration.
Comments on the proposed definition of HCAs for gas transmission
pipelines addressed the complexity of the definition and difficulty in
identifying HCAs; additional areas to be included; the role of public
officials in ``identified sites;'' numbers of people congregating in
outside areas and in ``identified site'' buildings; C-FER model;
Threshold Radius; system considerations; and calculation of Moderate
Risk Areas, Potential Impact Circle (PIC), Potential Impact Radius
(PIR), and Potential Impact Zone (PIZ). The comments on each of these
topics are discussed below.
The Definition's Complexity and Difficulty in Identifying HCAs
The high consequence area definition included Class 3 and 4 areas
because these areas are currently defined in the gas pipeline safety
regulations. The definition also included ``identified sites'' and a
list of methods for identifying them. These sites included facilities
with people who are confined, of limited mobility or would be difficult
to evacuate, and outside areas and buildings where there is evidence
that at least 20 or more people congregate on at least 50 days in any
12-month period.
In the NPRM for integrity management program, RSPA/OPS proposed to
add another area to the definition--a circle of Threshold Radius 1,000
feet or larger that has a cluster of 20 or more buildings intended for
human occupancy.
In their petition for reconsideration of the HCA definition, the
petitioners argued that RSPA should clarify the definition,
particularly with regard to ``identified sites,'' because the
definition is so broad and vague as to make compliance impractical.
Comments at the post-NPRM public meetings also suggested that the
definition needed to be clarified.
Many commenters noted the complexity of the proposed expanded
definition and asked that it be simplified. Baltimore Gas and Electric
(BG&E) asserted that the number of variables and data requirements
related to the definition make it unworkable. BG&E explained that
distribution system operators maintain data on population and buildings
near their pipelines, but would have difficulty identifying facilities
with persons who are confined or of limited mobility and areas where
people congregate. The company recommended that the definition only
reference verifiable criteria in determining areas to be covered under
the integrity management requirements. Northeast Gas Association
requested clarification on whether the proposed expanded definition
only applied to large diameter, high pressure pipe.
Dominion supported the use of current Class designations to define
HCAs because it believes smaller pipeline companies do not have access
to sophisticated geographic information systems (GIS). The State of New
York also supported the use of the current Class designations,
supplemented by the use of the C-FER model to identify HCAs outside of
Class 3 and 4 areas.
INGAA argued that the proposed addition to the HCA definition added
complexity and additional practices that would not improve pipeline
safety. INGAA proposed a bifurcated option, which would allow the
operator some flexibility in determining its cumulative HCA sites.
Under this proposal, an
[[Page 69785]]
operator could choose from two approaches to determine HCAs. Both
approaches would require that an operator identify potential HCAs for
certain ``identified sites'' located within a Potential Impact Circle.
In addition to the ``identified sites,'' the operator would either
identify the remaining HCAs by selecting all Class 3 and 4 areas or by
determining all Potential Impact Circles containing 20 or more
buildings intended for human occupancy. Potential Impact Circles would
be based on the C-FER model. When the size of the pipeline requires
that the radius is greater than 660 feet, INGAA's proposal would allow
prorating the number of buildings in the circle based on an increased
circle size. INGAA's proposed proration scheme would allow operators
additional time to collect the expanded population data--until as late
as 2007.
AGA supported this approach because it is simpler, allows operators
to use existing data from house count surveys, and provides safety
benefits to unsheltered areas. At least 30 other commenters endorsed
this alternative approach.
Response: RSPA/OPS has adopted a bifurcated definition, as
suggested by INGAA. It gives an operator two options to define HCAs. In
both options ``identified sites'' are treated the same. However, an
operator will now be allowed to identify the HCAs associated with high
population density either by including all Class 3 and 4 areas or by
counting the residences within a potential impact circle to determine
whether the threshold number is present. Changes made to the
``identified sites'' definition are described further below. We agree
that this approach is less complex, allows flexibility to operators
(particularly local distribution companies who may wish to designate
all Class 3 and 4 areas), and better focuses on areas where people
could be most affected by pipeline ruptures, fires, and explosions.
RSPA/OPS has decided to allow operators to prorate the number of
buildings in Potential Impact Circles larger than 660 feet in radius
for a period of three years. We believe that the recommended five-year
period for proration is too long, but acknowledge that collecting all
of the additional data in one year would be an unreasonable resource
burden. Operators now have data on the number of buildings located
within 660 feet from their pipelines because they have needed this
information for identifying Class Location areas pursuant to Sec.
192.5. The three-year period is adequate for operators to gather
additional information for the large-diameter, high-pressure pipelines
for which Potential Impact Circle(s) will exceed 660 feet.
RSPA/OPS expects that many, perhaps most, operators will follow the
Potential Impact Circle option for defining HCAs. Under this approach,
an operator would calculate the heat affected zones along its pipeline
that would result from a pipeline rupture. An operator would determine
the radius of the Potential Impact Circle for the pipeline, identify
segments of pipeline within a Potential Impact Radius of ``identified
sites,'' and identify segments of pipeline having 20 or more residences
within a Potential Impact Circle. Such segments would be HCAs, and the
length of pipeline included in the HCA would be the pipe within the HCA
plus the length of pipe extending one Potential Impact Radius in both
directions beyond the HCA.
For transmission pipelines operating at low pressures, like much of
the pipeline operated by distribution companies, the radius of the
Potential Impact Circle calculated with the C-FER model will be small.
For example, the radius for a 6-inch diameter pipeline operating at 150
psi would be 50 feet. It is unlikely that 20 buildings intended for
human occupancy could be found in circles of such small radius. It is
also less likely that ``identified sites'' will be found within the
circles as the radius decreases. As a result, using the Potential
Impact Circle option will tend to exclude much low-pressure pipeline
from the assessment requirements of this rule. Because accidents along
these pipelines in developed areas can affect people and property, the
rule requires an operator of a low-stress pipeline in these developed
area to take additional preventive and mitigative actions.
Additional Areas
Several commenters suggested adding other sites as HCAs. The
Florida State Clearinghouse, the Washington City and County Safety
Consortium, and the New York State Department of Public Service all
asserted that certain critical infrastructure facilities be included as
HCAs. These included, but were not limited to, interstate interchanges,
bridges, tunnels, certain railway facilities, electric transmission
substations, drinking water plants, and sewer facilities. They asserted
that impacts to these types of facilities could detrimentally impact a
wide range of people. The Washington City and County Safety Consortium
further contended that environmentally sensitive areas, particularly
those critical to endangered species, should be included as well.
Response: RSPA/OPS has not included these additional areas in the
final rule. We addressed comments such as this in the rulemaking on
high consequences areas. Other than the issues that had been raised in
the petition for reconsideration, and the areas in the NPRM for
integrity management program requirements we proposed to add, or
requested comment, we did not open the final definition up for changes.
When we issued the final rule defining these areas, we agreed that
impacts to critical infrastructure could have detrimental impact but
that such impacts would not likely include death or serious injury. A
major purpose of the integrity management rule is to focus the highest
level of operator attention on those portions of its pipeline that can
have the most severe safety consequences, i.e., can cause death and
injury.
However, to protect vital infrastructure, the rule provides for
applying lessons learned through integrity management to areas outside
HCAs. The ASME/ANSI B31.8S process provides that operators use their
risk assessments to guide them in applying these lessons. Proper risk
assessments will identify portions of pipeline that have a higher
likelihood of failure.
Similarly, as we explained when we finalized the definition of HCAs
(67 FR 50824), we did not include environmentally sensitive areas in
the definition. The impact of gas pipeline accidents on such areas is
expected to be significantly less than a similar accident involving a
hazardous liquid pipeline because of the different nature of gas and
hazardous liquids.
Public Officials and Identified Sites
For the ``identified sites'' component of the high consequence area
definition, the definition listed various means by which an operator
could identify these areas. The list included a site being visibly
marked, being licensed or registered by a Federal, State, or local
agency, being known to public safety officials or being on a list or
map maintained by or available from a Federal, State, or local agency.
In the preamble to the NPRM, RSPA/OPS invited comment on whether we
should use the term public safety officials and/or emergency response
officials instead of public officials (68 FR 4278, 4295).
In the petition for reconsideration of the high consequence area
definition, petitioners objected to relying on public safety officials
for identifying these sites because these officials might not be able
to convey accurate information.
PECO, PG&E, and Peoples Energy all concurred that the phrase
``public safety
[[Page 69786]]
officials and/or emergency response officials'' was preferable to
``public officials.'' PG&E maintained the term ``public officials'' was
too broad and provided too much variance for interpretation.
Both the Washington State Advisory Committee on Pipeline Safety and
the Washington City and County Pipeline Safety Consortium suggested
that operators work with local cities or municipalities to identify
additional HCAs within their territories. They asserted that the cities
and municipalities have the best information on facilities and on
growth trends in their areas and would be in the best position to
identify HCAs.
The Association of Texas Intrastate Natural Gas Pipelines and
several other commenters asserted that the requirement to identify a
site under the HCA definition by reference to commercially available
databases is not reasonable. Kern River suggested that the rule needs
to be expanded to define the exact process to follow to identify
locations of people with limited mobility. Kansas Gas Service commented
that the methods to identify these sites are unduly burdensome and
impractical.
Several commenters sought more specificity in the procedure to
identify outdoor areas and buildings requiring consideration as
``identified sites,'' and recommended that local public safety
officials be relied upon in making these identifications.
Discussion at the public meetings and the May 2003 meeting of the
advisory committee further highlighted industry concerns about locating
buildings housing populations of limited mobility and areas where
people congregate. The TPSSC recommended that local emergency planning
committees (LEPC) be considered in addition to public safety and
emergency response officials and that local public safety and emergency
response officials or LEPCs be relied on as a principal source of
information in identifying buildings containing populations of limited
mobility. The TPSSC recommended that the focus for such buildings be
those known to these local safety officials and meeting one of the
tests: Be visibly marked, be licensed or registered, or be listed on a
government map.
Response: RSPA/OPS agrees that specifying public safety officials,
emergency response officials, or local emergency planning committees is
clearer than the term ``public officials'' for purposes of this rule.
These are the officials and agencies charged with protecting the health
and safety of the community, and they are most likely to have
information relevant to identifying and protecting areas where people
could be affected by pipeline accidents. Other employees of local
governments, who might be considered ``public officials,'' would be
less likely to know the relevant information. The final rule has been
revised to use this more focused terminology, and to make these
officials a principal source of information regarding places where
people congregate and buildings housing populations of limited
mobility. RSPA/OPS is working to inform local emergency responders
about the need to be knowledgeable about the ``identified sites.'' This
change is consistent with the advisory bulletin RSPA/OPS issued on July
17, 2003.
The ``identified sites'' component of the definition included a
list of methods operators could use to identify facilities with persons
of limited mobility. However, the definition caused consternation
because many operators saw it as an exclusive list. To address this
concern, in the advisory bulletin issued on July 17, 2003 (68 FR 42458)
we explained that it was never intended that operators perform an
exhaustive search of every possible source of information. Rather,
operators who consult public safety or emergency response or planning
officials who indicate that they have knowledge of the ``identified
sites'' need not do more (68 FR 42458, 42460).
In the final definition, we have clarified that local safety
officials are the principal source of information on places where
people congregate and buildings housing populations of limited
mobility. This change is consistent with the guidance in the advisory
bulletin issued on July 17, 2003. If these officials do not have the
information to identify these sites, then an operator must use at least
one of the other methods, such as visible marking or registration lists
to identify the sites. These methods are explained in the new Sec.
192.905 on how an operator is to identify a high consequence area.
Rather than include these methods in the high consequence area
definition in Sec. 192.903, we moved them to the new section that
explains the methods for identifying these sites. For outdoor areas,
the final rule also relies on the knowledge of local safety officials
to identify these areas.
People in Outside Areas and in Identified Site Buildings--Sec. 192.903
(Formerly Sec. 192.763(i))
In the petition for reconsideration of the high consequence area
definition, petitioners argued that RSPA should clarify the definition,
particularly with regard to ``identified sites,'' because the
definition is so broad and vague as to make compliance impractical.
Petitioners noted that the definition references two standards for
identifying places as HCAs because people congregate at those places.
Petitioners requested that for consistency the same standard be used as
the one used in the Class 3 definition, i.e., 20 or more persons on at
least 5 days a week for 10 weeks in any 12-month period.
We had included rural churches in the example of outside areas
under the HCA definition. In the petition for reconsideration,
petitioners contended that the definition would pick up isolated and
infrequently occupied buildings. In the Preamble to the NPRM on
integrity management program requirements, RSPA/OPS acknowledged it did
not know how many rural buildings would be covered and requested
comment on whether to include these buildings, instead, as Moderate
Risk Areas. The definition did not require a minimum number of confined
or mobility-impaired people needed to occupy a facility. The definition
did require that for outside gathering areas, there be 20 or more
persons on at least 50 days in any 12-month period. The NPRM did not
propose a new threshold for the number of persons needed to occupy an
identified site. Nonetheless, we received a variety of comments on the
number that had been included in the final definition.
Citizens for Safe Pipelines was adamant that Congress intended to
protect sites similar to the Carlsbad accident site and, as support,
referenced statements made by members of Congress. Citizens for Safe
Pipelines contended that the definition is under-inclusive of places
where pipelines should be inspected. Cook Inlet Keeper, along with the
Washington City and County Pipeline Safety Consortium commented that
the threshold for persons in outside areas of congregation should be 10
instead of 20. Accufacts supported having the outside area threshold as
10 instead of 20, but keeping the building threshold at 20. Most of
industry sided with INGAA which supported 20 or more persons in outside
areas of congregation with a much stricter frequency of 5 days a week,
10 weeks a year.
INGAA also proposed that we change the ``identified sites''
component to differentiate between rural buildings and outside areas,
and to use different occupancy rates. The definition had grouped rural
buildings and outside areas together, subject to a minimum use by 20
persons on at least 50 days in
[[Page 69787]]
any 12-month period. INGAA proposed changing the HCA definition to
define an identified site as a building occupied by 50 or more persons
at least 5 days a week, 10 weeks a year with the days and weeks not
necessarily consecutive, and as an outside area that is small, well-
defined and occupied by 20 or more persons at least 5 days a week, 10
weeks a year with the days and weeks not necessarily consecutive.
Industry generally shared INGAA's position that the building should
be occupied by 50 or more persons at least 5 days a week 10 weeks a
year and the buildings would not be limited to those containing persons
of limited mobility. Both Accufacts and Cook Inlet Keeper said the
threshold number of persons should be no less than what was specified
in the HCA definition.
Response: When RSPA/OPS defined the number of people needed to
gather in an outside area, we intended that areas, like the camping
area in Carlsbad, would be covered. The number of people and the
frequency of use was intended to pick up areas used for recreation on
weekends. We did not open for discussion the threshold number of people
needed to occupy a building with persons of limited mobility or to
gather in an outside rural gathering area or building. The definition
did not specify an occupancy rate for buildings with persons who would
be hard to evacuate, and specified 20 persons for a rural building or
outside area. Nor did we open for comment the specified frequency in an
outside area (50 days in any 12-month period). We have not changed the
occupancy threshold in these outside gathering areas.
However, we reopened the issue of how to treat rural buildings. In
the final rule, we have modified the definition of outside gathering
areas to address the rural building issue. The identified site
definition in the final rule includes an outside area or open structure
that is occupied by twenty (20) or more persons on at least 50 days in
any twelve (12)-month period. The days need not be consecutive.
Examples of these areas would be beaches, playgrounds, recreational
facilities, camping grounds, outdoor theaters, stadiums, recreational
areas near a body of water, or areas outside a rural building such as a
religious facility where 20 or more people congregate regularly for
bazaars or civic activities at least 50 days a year.
We did not change the occupancy threshold for these outside areas
and open structures. A threshold of 10, as recommended by several
commenters, is too low to be practical and would lose the focus on
higher consequence areas. Current regulations for protecting outdoor
areas in which people congregate (i.e., by designating them as Class 3
areas) use a threshold of 20 persons, and this threshold is consistent
with that practice. The high consequence area definition differs from
current practice in using a criterion of 50 days per year, which need
not be consecutive, rather than 5 days per week and 10 weeks per year.
This recognizes the patterns by which people congregate, including
weekend use of outdoor areas. This frequency is intended to pick up
areas similar to the camping area where the Carlsbad accident occurred,
where local officials know that people gather regularly.
To further address the rural building issue, the identified site
definition in the final rule has been revised to differentiate between
outside open structures and rural buildings. The definition in the
final rule includes buildings housing 50 or more people 5 days per week
and 10 weeks per year (the days and weeks need not be consecutive).
This modification is intended to pick up buildings outside populated
areas where people gather during the week, or on weekends for
recreational activities. Because buildings provide some protection from
the effects of a pipeline accident, RSPA/OPS finds it appropriate that
the threshold be based on a higher number of people and occupancy
criteria consistent with current class location regulations. This will
allow operators to make maximum use of the data they already have
regarding buildings containing concentrations of people, and further
reduce the burden of implementing this rule.
The identified site component also included buildings housing
people who would be difficult to evacuate or are of limited mobility.
The definition did not include an occupancy threshold for those
buildings. We have not modified that component of the definition,
rather we are relying on the knowledge of local emergency officials.
C-FER Model, Potential Impact Circle (PIC), Potential Impact Radius
(PIR), and Potential Impact Zone (PIZ) Calculations, and Threshold
Radius
Many comments related to the proposed use of the C-FER model and
the various other calculation methods referenced in the NPRM. The high
consequence area definition had been based on the heat affected zone
from a rupture calculated using the C-FER model, with an added margin
of safety--thresholds of 300 feet for small-diameter, low-pressure
pipelines, and 1,000 feet for higher-pressure, larger-diameter
pipelines. The NPRM further proposed to add populated areas at
distances greater than 660 feet from large-diameter, high-pressure
pipelines. The C-FER model used a heat flux of 5,000 Btu/hr/
ft2. RSPA/OPS has questioned whether a more conservative
heat flux rate of 4,000 Btu/hr/ft2, the heat flux rate used
in the liquefied natural gas regulations (Part 193), should be used
instead.
The proposed regulations also included calculations for determining
the Potential Impact Radius of a covered segment, for determining the
Threshold Radius associated with the Potential Impact Radius, and for
identifying the Potential Impact Circle(s) and Potential Impact Zone(s)
for the pipeline.
A number of commenters, such as Consolidated Edison and the Iowa
Utilities Board, suggested that calculations should be based on the
maximum operating pressure and not on the Maximum Allowable Operating
Pressure (MAOP).
Several commenters noted that the term, ``diameter,'' should be
clarified as inside diameter, outside diameter, or nominal diameter and
pressure should be clarified as gage or absolute. Consolidated Edison
suggested that the PIR formula for natural gas should be simplified to
r = 0.69d[radic]p. Air Products suggested operators be allowed to
rederive the C-FER model considering product, size of pipeline, and
operation of emergency flow restricting devices (EFRDs).
Several commenters supported the use of the C-FER model. Williston
Basin asserted the model was reliable and should be used over the full
spectrum of pipeline conditions.
Northeast Gas Association, Gas Piping Technology Committee, Peoples
Energy and several other commenters contended that there was no
justifiable reason to impose an additional safety margin on top of the
C-FER calculation. In contrast, NTSB argued that an adequate and
uniform safety margin should be applied for all pipelines and noted
that the farthest building burned from the Edison, NJ rupture would be
within the 1,000 foot threshold. NTSB further suggested that RSPA/OPS
consider the effects of horizontal jetting along the pipeline as
demonstrated at the Carlsbad, New Mexico rupture site.
Panhandle Eastern, Williams, and other commenters contended that
utilizing 5,000 BTUs in the equation was appropriate and there was no
technical basis for utilizing 4,000 BTUs. The State of New York alleged
that 5,000 BTUs is too high and the value should be an appropriate
value to
[[Page 69788]]
eliminate the possibility of fatality and ignition of protective wooden
structures.
A large number of commenters were opposed to the use of a Threshold
Radius, and asserted that its use is unjustified and with no technical
basis. Northeast Gas Association commented that the wording is
confusing and asked for clarification as to whether the Threshold
Radius becomes 1,000 feet when the PIR exceeds 660 feet and when the
diameter is also 36 inches and the pressure is 1,000 psig or greater.
The Iowa Utilities Board concurred that the PIC and Threshold Radius
should be based on the distance of the actual hazard and not on
arbitrary distances that include areas outside of the Potential Impact
Radius. The Iowa Utilities Board further contended that burdens on
small pipelines and operators should be minimized. PECO asked for
additional clarification as to whether the radius of all Class 3 and 4
locations is effectively 1,000 feet.
AGA and several operators, including Baltimore Gas and Electric,
suggested that operators of pipelines operating below 30% SMYS should
not be required to go beyond the actual impact zone calculations in
their identification of HCA areas. Laclede Gas stated that there should
be no margin above the C-FER calculation, especially for pipelines
operating below 30% SMYS.
Response: The appropriateness of the C-FER model was the subject of
considerable discussion at the public meetings held during the comment
period on the proposed rule. As a result of these discussions and
comments to the docket, RSPA/OPS has concluded that the C-FER model is
sufficiently conservative for use in the screening process to identify
HCAs. RSPA/OPS believes the model adequately reflects the distance,
lateral to the pipeline, at which significant effects of accidents will
occur. In the final rule, we have adopted the model as the basis for
calculating Potential Impact Circles under the bifurcated option for
defining HCAs (discussed in prior section) with the addition of the one
radius at either end (discussed below).
Discussion at the public meetings and with the advisory committee,
and analysis of recent pipeline accidents, also identified that
pipeline accidents have sometimes affected an elliptical area, with the
long axis of the ellipse along the pipeline. The NTSB noted that this
likely results from horizontal jetting in the direction of the
pipeline. The elliptical nature of the burn pattern means that the C-
FER radius is not always conservative in identifying the maximum
distance from a potential pipe rupture, measured along the pipeline, at
which the effects from the rupture will be felt. Following careful
analysis of the burn patterns near pipeline ruptures, RSPA/OPS
determined that it is appropriate to add an additional length of
pipeline equal to the C-FER radius on either side of a high consequence
area, i.e., increase its extent along the pipeline, rather than
increase the lateral distance. INGAA concurred with this approach. We
have incorporated this this approach into the final rule. Where
Potential Impact Circle(s) are used to define HCAs, the pipeline
segment in the high consequence area extends from the outermost edge of
the first circle to the outermost edge of the last contiguous circle.
This is illustrated in Appendix, Figure E.I.A to the final rule. Under
the proposed rule, the segment would have been limited to the pipe
between the centers of these circles.
The concept of Threshold Radius has been eliminated from the final
rule. This concept was intended to apply some margin to C-FER
calculations and to simplify the identification of HCAs. As described
above, RSPA/OPS is convinced that the C-FER model is conservative
enough for this purpose. We are also convinced by the comments that the
use of Threshold Radius complicated, rather than simplified, the
identification of HCAs. With the elimination of this approach, pipeline
segments are included or not included on the basis of the calculated
distance of the actual hazard, as recommended by many commenters.
RSPA/OPS has not adopted the suggestion that maximum operating
pressure, instead of MAOP, be used in C-FER calculations. MAOP reflects
the pressure at which the pipeline can be operated, and thus the hazard
that could be experienced. This is an inherent conservatism in the C-
FER model, and has likely contributed to the successful validation of
the equation against accident experience.
The final rule specifies that nominal pipeline diameter is to be
used in C-FER calculations. It also provides, as did the proposed rule,
that a different constant factor must be used when making the
calculation for gases other than natural gas, and refers to ASME/ANSI
B31.8S for this determination. RSPA/OPS does not agree that further
derivation of a unique equation for other gases is necessary.
System Considerations
Numerous operators, including Peoples Energy, Houston Pipeline and
Puget Sound, asked for clarification on the need to do additional
studies or calculations if and when they deem their entire systems to
be HCAs. They asserted there would be no need for the additional effort
if all parts of their system were designated as HCAs and any additional
effort would be a waste of company resources and time. Oleska and
Associates shared this sentiment and recommended allowing operators to
classify pipelines as being in an HCA without going through any
analysis.
The Iowa Utilities Board commented that the rule should allow a
pipeline operator to exclude its own facilities when determining if
pipeline is in a high consequence area.
Response: RSPA/OPS agrees that further analysis to identify HCAs is
not necessary if an operator elects to treat its entire system as a
high consequence area. The final rule requires that identification of
HCAs include documentation of the Potential Impact Radius ``when
utilized.''
The high consequence area definition, as modified by this rule,
focuses on identifying areas where large numbers of people could be at
risk from a pipeline rupture. RSPA/OPS expects that pipeline operator
facilities should be treated the same way as other facilities. The only
operator facilities that could affect the determination are facilities
in which more than 20 operator employees gather for the number of days
appropriate to the type of gathering place (i.e., at least 50 days per
year if outdoors, 5 days per week in at least 10 weeks per year if
indoor). The number of such facilities is expected to be small. Where
they exist, however, RSPA/OPS believes it is appropriate to provide
consideration of those gatherings in the same manner as for gatherings
of non-operator personnel.
Moderate Risk Areas (MRAs)
The NPRM proposed to include Moderate Risk Areas, areas located
within a Class 3 or 4 location but not within the Potential Impact
Zone. These areas would require less frequent assessment or enhanced
preventive and mitigative measures. In the preamble to the NPRM, RSPA/
OPS requested comment on two issues related to these areas:
[sbull] Comments on designating rural buildings, such as rural
churches, as Moderate Risk Areas instead of as High Consequence Areas
(68 FR 4278, 4296).
[sbull] Comments and cost information on an option to not require
an assessment of a segment located within a Moderate Risk Area, but,
rather, to require enhanced preventive and mitigative measures on the
segment (68 FR 4278, 4284). The premise was that if houses are mostly
clustered in one area of a
[[Page 69789]]
Class 3 rectangle, a pipeline failure in an area beyond the cluster may
have little, if any, impact on the area with the cluster of homes.
Comments on MRAs ranged from urging elimination to full support for
their use. Williston Basin and National Fuel recommended eliminating
MRAs because they require significant resources and provide few safety
benefits. Both the Northeast Gas Association and Kern River saw
potential value in MRAs but suggested their use and implementation
should be optional. PECO recommended that the MRA definition be
clarified because it was unclear when buildings should or should not be
designated as MRAs when they are located in HCAs.
Northeast Gas Association responded that rural buildings, such as
churches, in Class 3 and 4 areas, should be designated as MRAs whether
or not they fall within an impact circle and that such areas should be
subjected to less frequent assessment and lesser mitigation
requirements. Several other industry commenters concurred, including
Southwest Gas and Paiute. PG&E would not support the inclusion of
churches in the examples of outside areas.
Taking the opposite position, the Washington City and County
Pipeline Safety Consortium commented that if such facilities
incorporate outside areas that are HCAs fall under the definition of an
HCA, then such rural churches should be captured in the HCA definition.
Vectren and PG&E noted that areas outside the Potential Impact
Zones have little probability of being affected by a failure and
concurred with the suggested option. Northeast Gas Association,
Southwest Gas Corporation, and other commenters maintained that if MRAs
remain in the regulation, these areas should be subject only to
enhanced preventive and mitigative measures.
Response: The concept of Moderate Risk Areas is not included in the
final rule. This concept was intended to address areas that met the
definition as HCAs, but because the areas were more remote and less
populated, the potential risk of an accident was less than in other
HCAs. The likelihood of this occurring has been reduced, or eliminated,
by the changes made in the definition of HCAs. These areas are defined
in the final rule based on the calculated hazard for operators using
the Potential Impact Circle option. Additional margin, in the form of
threshold radii, designation of all Class 3 and 4 areas, or an
arbitrary margin applied to C-FER calculations, has been eliminated.
Accordingly, all areas meeting the definition of HCAs require treatment
as such, and no category of reduced actions is needed.
As explained in the section on ``identified sites,'' we have
modified the definition of HCAs to clarify the differences between
outside open structures and rural buildings. In both cases the
occupancy threshold is 20 people. For rural buildings, people must
congregate five days a week for at least ten weeks in year as in the
current class location 3 definition. For open structures and outside
gathering areas, people must congregate at least fifty days in a year.
4. Program Requirements and Implementation, Including Integrity
Assessment Time Frames, Assessment Methods, and Criteria
The topics covered in this section encompass the majority of the
comments that addressed the requirements for and implementation of an
integrity management program. We have grouped in this subsection
comments addressing general program requirements and compliance time
frames, baseline assessments and their quality, the use of prior
assessments, the requirements associated with using Direct Assessment,
Confirmatory Direct Assessment, and Internal Corrosion Direct
Assessment, reassessment intervals and overlap, pressure testing
requirements, cyclic loading, ERW pipe seam issues, and training
requirements.
Time Frame for compliance. The proposed rule required operators to
identify all covered segments within one year from the rule's effective
date. Northeast Gas Association asked that operators be allowed two
years after the final rule to identify all pipeline segments and
conduct a risk analysis.
Response: The statute requires that RSPA/OPS issue regulations
prescribing integrity management program standards. These regulations
must require operators to conduct a risk analysis and adopt an
integrity management program no later than 24 months after the date of
enactment, i.e., by December 17, 2004. Therefore, RSPA/OPS does not
have the flexibility to allow operators two years to complete the
segment identification. RSPA/OPS has tried to accommodate concerns
about the time frame for developing a program through use of the
framework concept.
Framework: The proposed rule required an operator to develop and
follow a written integrity management program within one year from the
effective date of a final rule. However, the proposal allowed the
operator to begin with a framework addressing each of the required
program elements. Puget Sound Energy suggested that the requirement for
a framework should be deleted. The company commented that a framework
is either an additional document above and beyond the integrity
management plan or is telling the operator how to develop a plan. The
company noted that the term is used in ASME/ANSI B31.8S as an umbrella
for the elements of a plan and not to describe a separate document. The
Northeast Gas Association requested that a rule have enough flexibility
to allow operators the time necessary to develop a thorough and
effective plan. The Association further commented that it may not be
possible for operators to develop a plan within the time frame
specified in the proposed rule.
Response: The intent of allowing a framework was to acknowledge
that an operator cannot develop a complete, fully mature integrity
management plan in a year. Nevertheless, it is important that an
operator have thought through how the various elements of its plan
relate to each other early in the development of its plan. The
framework serves this purpose. Each operator is required to develop a
framework within one year that describes the process for implementing
each program element, how relevant decisions will be made and by whom,
and a time line for completing the work to implement the program
element. It need not be fully developed or at the level of detail
expected of final integrity management plans. The framework is an
initial document that evolves into a more detailed and comprehensive
program. A separate document is not necessary. For some operators
(e.g., those with only a few miles of covered pipeline) it may be
possible to prepare a fully-developed integrity management plan within
a year. In that case, no separate framework is required. The discussion
of the framework in the final rule has been modified to reflect these
expectations.
Communications Plan: One of the proposed elements of an integrity
management program was a communications plan that includes the elements
from ASME/ANSI B31.8S. Northeast Gas Association questioned the need
for a communications plan requirement because a consensus standard on a
Recommended Practice for Pipeline Public Awareness Programs is now
being developed under the auspices of the American Petroleum Institute
(API).
Response: This rule requires that integrity management plans
include communications plans that follow the
[[Page 69790]]
guidelines in ASME/ANSI B31.8S, a standard that has been incorporated
by reference into the final rule. Industry and government
representatives working on the API standard are aware of the ASME/ANSI
B31.8S guidelines, and RSPA/OPS expects that the final API standard
will not conflict with them. RSPA/OPS will consider adoption of the API
standard, for public awareness, not IMP communications, including
whether changes to the communication provisions in this rule are
appropriate, when that standard is approved.
Best Practices. Northeast Gas Association commented on proposed
requirements that operators adopt ``best practices.'' The Association
noted that the best practices for one company are not always applicable
to other companies, because of the variability in system
configurations, physical pipeline attributes, and business
perspectives. Northeast Gas recommended elimination of all references
to incorporation of best practices.
Response: RSPA/OPS recognizes that practices applicable at one
operator might not be as useful or effective at another. Nevertheless,
RSPA/OPS believes that it is important that operators learn from the
experience of the industry at large. The standards development process
is a means of combining industry experience to identify lessons that
should be applied to other operators. RSPA/OPS has modified the final
rule to rely on that process. The rule requires that practices in ASME/
ANSI B31.8S be used. The consensus process of gathering, reviewing, and
publishing best practices in a manner suitable for use at all operators
should resolve the applicability questions.
Baseline and Prior Assessments. The proposed rule allowed an
assessment conducted up to five years before the date of enactment of
the Pipeline Safety Improvement Act of 2002 as a baseline assessment.
The Act was signed into law on December 17, 2002. The proposed rule
established time periods for the baseline assessment. If the assessment
were done by pressure test or internal inspection, the operator would
have to complete the baseline by December 17, 2012, with 50% of the
highest risk pipe being done by December 17, 2007. However, if the
segment were in a Moderate Risk Area, the assessment would have to be
done by December 17, 2015. If the operator used direct assessment, the
baseline would have to be done by December 17, 2009, with 50% of the
highest risk segments assessed by December 17, 2006, or by December 17,
2012 if it was in a Moderate Risk Area.
Southwest Gas Corporation and Paiute Pipeline noted there was no
provision to incorporate new pipelines into an integrity management
plan and recommended that for pipelines installed after December 17,
2002, the installation pressure test be accepted as the baseline
inspection. Northeast Gas Association supported the proposed
requirement that 50% of the facilities posing the highest risk be
baseline-assessed during the first half of the assessment cycle.
Dominion commented that the proposed language is not clear about when a
baseline assessment is complete. It suggested the baseline assessment
start when the first inspection tool is run and that the start of the
reassessment interval would be when the company runs the final
assessment tool, analyzes the data from the final tool report, and
remediates all immediate indications for the baseline assessment.
Several commenters noted that the date for prior assessments was
incorrectly listed as 2007 rather than1997. El Paso asserted there is
no technical basis for the five-year limit on a previous assessment and
argued that an assessment conducted before December 17, 2002 should be
allowed as a baseline if it substantially meets the requirements of the
rule and referenced standards. Dominion concurred with El Paso and
added that the proposed rule penalizes operators for using prior
assessments because it requires an operator to reassess immediately or
within the next 2 years. Instead, Dominion suggested that the
reassessment interval of seven years should start after the baseline
assessment information is realigned and analyzed based on the
operator's current program. INGAA took exception to the proposed 1997
cutoff date and argued that RSPA/OPS was judging the applicability of
earlier assessment technology without providing technical rationale.
INGAA commented that RSPA/OPS should allow operators to use prior
assessment data to encourage them to use the performance-based option.
Response: Commenters are correct that the date listed for prior
assessments was incorrect and should have been listed as December 17,
1997 in the NPRM. However, that date is no longer relevant because the
final rule has been revised to allow an assessment conducted any time
prior to the date the Pipeline Safety Improvement Act was signed into
law, December 17, 2002, as a baseline assessment if the prior
assessment satisfies the requirements of Subpart O. There is no longer
a five-year cut-off date for prior assessments.
The final rule also allows prior assessments as part of the
qualification basis for the performance-based option. For this option,
an operator must demonstrate that the prior assessments effectively
addressed the identified threats to the covered segment. Although these
assessments may not meet all the requirements for a baseline, because
the performance-based option sets additional and more stringent
requirements, RSPA/OPS believes it could allow some flexibility in
relying on prior assessments.
RSPA/OPS has clarified the language concerning the time period for
conducting the baseline assessment. The final rule no longer requires
the baseline period to depend on the assessment technique used. The
period is now the same, no matter the assessment method. Furthermore,
as discussed earlier in this document, RSPA/OPS has eliminated the
concept of Moderate Risk Areas. An operator must complete the baseline
assessment of all covered segments by December 17, 2012, and assess at
least 50% of the covered segments, beginning with the highest risk
segments, by December 17, 2007. Consistent with the advisory
committee's recommendation, we have revised the final rule to require
that the first reassessment for a pipeline segment on which a prior
assessment is credited as baseline must occur by December 17, 2009,
seven years after enactment of the Pipeline Safety Improvement Act of
2002.
Any new pipeline that is installed in a high consequence area would
be subject to the requirements of the rule. The final rule has been
revised to require that newly-installed pipeline be included in the
integrity management plan, and that the baseline assessments on any
high consequence area segment be completed within ten years of
installation. The rule provides that the installation pressure test,
conducted in accordance with subpart J of part 192, would satisfy the
requirements of a baseline assessment. Intervals for reassessment would
be measured from the date of the baseline assessment, as for any other
covered pipeline segment.
RSPA/OPS has not specified in the rule what constitutes completion
of an assessment on a covered segment, and therefore the date from
which future assessment requirements toll. Such details were not
included in the integrity management rule for hazardous liquid
pipelines, but rather were addressed through additional guidance for
implementing the rule. That guidance specifies that the end of field
activities, e.g., completion of the final
[[Page 69791]]
tool run or completion of a hydrostatic test, is considered the end of
an assessment. RSPA/OPS will issue similar guidance for this rule.
Pressure Testing. We received comments on the proposal to allow
pressure testing as an assessment method and that to address
manufacturing and construction defects, a pressure test be conducted at
least once in the life of the segment.
NTSB noted that although defining HCAs can help to set priorities,
risk management programs should ensure that pipelines are appropriately
tested at all locations where there is public exposure and cited
Carlsbad as an example. Advanced Technology Corporation asserted that
there are other fracture mechanics assessment methods which would be
preferable to pressure testing, which can cause crack growth.
The majority of comments centered on the proposal to pressure test
all segments once in the life of the pipeline. INGAA asserted, with
numerous commenters echoing INGAA's comments, that experience has shown
manufacturing and construction threats to be stable unless activated
through a change in operations or the environment. The Association of
Texas Intrastate Natural Gas Pipelines commented that once-in-a-
lifetime pressure testing should be eliminated and that testing
conducted upon installation (post 1971) or based upon historical
operation, provides adequate evidence of safety. Several commenters,
including INGAA, suggested that the rule should be aligned with ASME/
ANSI B31.8S.
Response: Pressure testing has long been considered the definitive
method of testing pipeline integrity. RSPA/OPS has received no
information that would challenge this historical practice, and pressure
testing remains an acceptable assessment method in the final rule.
RSPA/OPS has been convinced by the public comments, including
discussions at the public meetings, that it is not necessary to require
a once-in-a-lifetime pressure test to address the threat of material
and construction defects. Historical safe operation, which in many
cases involves several decades, provides confidence that latent defects
will not result in pipeline failure as long as operating conditions
remain unchanged. The final rule requires that an assessment be
performed if operating pressure is increased above the historic level
or if operating conditions change in a manner that would promote cyclic
fatigue.
Direct Assessment. There were numerous comments about the proposed
requirements for using Direct Assessment (DA). In the proposed rule,
direct assessment was allowed to address the threats of external
corrosion, internal corrosion or stress corrosion cracking, and then
only if certain preconditions were met. The proposed assessment
intervals using this method were shorter than the ones proposed using
the other assessment methods.
In the NPRM, RSPA/OPS also requested comments on:
[sbull] Whether it should allow an operator using Direct Assessment
on a pipeline operating at less than 30% SMYS a maximum ten-year
reassessment interval regardless of whether the operator excavates and
remediates all anomalies on that pipeline, or at least remediates the
highest risk anomalies. (68 FR 4278, 4281)
[sbull] Whether the benefits of the proposed requirements for
External Corrosion Direct Assessment, which were more extensive than
the NACE Recommended Practices under development, were worth the cost.
(68 FR 4278, 4282)
Several commenters expressed serious concerns. Carol Parker
commented that the method needs further study before being approved and
Cook Inlet Keeper maintained that more stringent criteria are needed as
compared to other assessment methods. Accufacts supported the proposed
shorter assessment period for DA because it is a developing and
unproven technology and further asserted that the related ICDA
approaches are seriously deficient.
In contrast, at least 125 comments, primarily from the pipeline
industry, supported the use of Direct Assessment. For example,
Northeast Gas Association supported using DA in the integrity
management process because its research had showed that DA has a high
degree of reliability. Numerous commenters asked that we incorporate
the new NACE DA standard into the rule rather than duplicate the
requirements. Most of the same commenters argued that DA should be
considered equal to inline inspections and hydrostatic tests as an
assessment method. Laclede Gas, along with other operators, asserted
that DA is the only practical option for many local distribution
companies and is better than inline inspection at finding coating
damage that has not yet resulted in corrosion with wall loss. Other
commenters maintained that DA should be explicitly identified as a
technique for detecting potential third-party damage, and that the
proposed treatment of DA is so prescriptive as to effectively eliminate
it as an option.
Commenters, including Southwest Gas, Paiute, Peoples Energy, PG&E,
Kansas Gas Service, and Puget Sound commented that the proposed
additional requirements were unnecessary, and were not beneficial. More
than 20 commenters recommended incorporating by reference the NACE DA
standard.
Nine commenters agreed with the proposal to allow low-stress
pipelines a ten-year reassessment interval. Over 30 commenters
maintained that DA should be allowed the same schedules as those for
inline inspections and hydrostatic tests. Other commenters, such as
Sempra and the Iowa Utilities Board, supported less stringent rules for
pipelines operating below 30% SMYS because of the lesser hazard posed
by failure of such pipelines.
Response: The process of Direct Assessment for evaluating the
integrity of pipelines is new. Therefore, the proposed rule included
restrictions on use of DA, including shorter baseline and reassessment
intervals, because of concerns about the efficacy of the process. The
NACE DA standard was still being developed when the proposed rule was
issued.
Although the process is new, the techniques involved in DA are not
new. There are no new and untested technologies involved. Pipeline
operators have used indirect examination tools in DA for many years,
and there is a wealth of experience. Although exposing a pipeline for
direct observation and evaluation of potential problems is the most
reliable means of understanding pipeline condition, it is not practical
to excavate and examine entire pipelines. The DA process is a method
that involves structured use of the time-tested indirect examination
tools, and integration of the information gained from use of those
tools with other information about the pipeline, to determine where it
is necessary to excavate and examine the pipe.
A group of operators coordinated by Battelle and Gas Technology
Institute, and co-funded by RSPA/OPS, conducted and documented
additional research and validation of direct assessment after the
proposed rule was published. RSPA/OPS personnel reviewed the results of
this research, recognized the importance of careful inspections to
ensure effective application of direct assessment, and recommended
focused training of RSPA/OPS inspectors in the characteristics of an
effective DA program. In addition, RSPA/OPS has included qualification
requirements in the final rule for individuals that carry
[[Page 69792]]
out DA for those that interpret the results.
Early results from the research have underlined the importance of
operator vigilance in applying DA and of continuous incorporation of
lessons learned in implementation procedures. The results of this
research were discussed at the public meetings held during the comment
period. These efforts have significantly improved RSPA/OPS's confidence
in this method for assessing pipelines. RSPA/OPS has additionally been
persuaded that many distribution companies operating transmission
pipelines will need to rely heavily on this method. These companies'
transmission pipelines are closely integrated with their distribution
systems, are generally not amenable to inline inspection, and are often
impractical to remove from service for pressure testing. Most also
operate at low pressures, presenting relatively smaller risks than
other transmission pipelines. Placing more restrictive requirements on
use of DA would increase the burden, and costs, for operators of these
low-risk pipelines without commensurate benefits.
For all of these reasons, RSPA/OPS has concluded that it is
unnecessary to place significant restrictions on the use of direct
assessment. The final rule has been revised to make the required
baseline and reassessment periods the same for DA as for other
assessment methods. Conditions on the use of DA as a primary assessment
method have been eliminated. These changes have rendered moot the
question of whether a ten-year reassessment interval should be allowed
for low-pressure pipelines even if all anomalies are not excavated.
In the proposed section on using direct assessment to address
external corrosion, we had drawn from a draft of the NACE standard on
external corrosion that was close to completion. Since the proposed
rule was published, NACE issued its recommended practice on external
corrosion direct assessment (NACE Recommended Practice RP-0502-2002).
RSPA/OPS has reviewed the recommended practice and concluded it has all
the necessary requirements and safeguards to ensure the efficacy of the
process.
The NACE ECDA recommended practice (RP) has been incorporated into
the final rule in the section addressing requirements for external
corrosion direct assessment. The existence of NACE RP has allowed us to
eliminate constraints on use of DA that were the subject of the
questions in the preamble. Incorporating the standard is responsive to
public comments, contributes to simplifying the rule, and is consistent
with our overall practice of referencing consensus standards where they
are available and meet regulatory needs. In addition, the rule
specifies requirements beyond those in the NACE RP. Requirements in the
rule that go beyond the NACE recommended practice address documentation
criteria used in making decisions in implementing direct assessment.
This documentation is needed to support oversight by RSPA/OPS and state
pipeline safety authorities.
NACE has not completed development of recommended practices for
internal corrosion and stress corrosion cracking. The final rule
references requirements in ASME/ANSI B31.8S applicable to these methods
and includes additional requirements. RSPA/OPS will consider
incorporating NACE standards for these techniques when those standards
have been completed.
Confirmatory Direct Assessment (CDA). The NPRM proposed allowing an
operator to use Confirmatory Direct Assessment (CDA) as an assessment
method at seven-year intervals if the operator established a longer
reassessment interval using one of the other assessment methods. CDA is
a more focused application of DA to address known threats in a pipeline
segment.
Industry generally embraced the concept of CDA. Dominion
recommended allowing CDA as the first reassessment following a baseline
assessment conducted after December 17, 2002. Houston Pipeline
maintained that CDA should also be available for use on all pipelines
previously assessed, not just those assessed using pressure testing or
inline inspection. Sempra supported the use of CDA and suggested
utilizing Section 5.10 of NACE RP0502 to determine the number and
locations of excavations and direct examinations to be made if ECDA was
used for the previous assessment.
Although Northeast Gas Association supported the CDA concept, it
suggested basing the CDA process on a technical industry standard, and
streamlining the process so that only one dig in each segment is
required as per the NACE standard instead of the proposed two digs.
Peoples North Shore Gas stated that the proposed process only provides
minimal relief as compared to full DA, echoed the need for
streamlining, and provided several streamlining suggestions.
Opposing the use of CDA, Cook Inlet Keeper maintained that CDA is
not as effective as internal inspection or pressure testing. Cook Inlet
suggested OPS compare the results for pipelines using CDA for
reassessment to the results for pipelines using internal inspection or
pressure testing for reassessment, and should CDA prove less effective
than the latter two methods, reevaluate allowing its use.
Response: CDA is a more focused version of Direct Assessment. The
additional research and validation conducted in a project managed by
the Gas Technology Institute, carried out by several operators working
with Battelle, and funded by RSPA/OPS and the industry has increased
RSPA/OPS's confidence in DA (as described above), as well as our
confidence in CDA. The research had overview and partial funding by
RSPA/OPS. It included comparison of results from various above-ground
assessment tools with internal inspection runs completed on the same
segments. The results are compelling enough to allow RSPA/OPS to
support use of the technology under very careful oversight and with the
assumption of continuing development and validation. The final rule
requires that the baseline assessment on all covered segments must be
by internal inspection, pressure testing, Direct Assessment, or other
equivalent technology (with prior notice to RSPA/OPS) and that the
reassessment must be by one of these methods at intervals specified in
the rule and in ASME/ANSI B31.8S. CDA is an interim assessment
technique designed for use when the reassessment interval by one of
these methods exceeds seven years.
The rule provides that CDA for external corrosion can be conducted
using only one indirect measurement tool, rather than two complementary
tools as required for Direct Assessment. The rule also provides for a
more limited number of excavations, requiring excavation of only one
scheduled indication in each ECDA region. Any ``immediate indications''
that are identified must also be excavated. The final rule also
provides that additional assessment, using one of the other methods,
must be performed if the CDA results do not confirm the integrity of
the pipeline.
Internal Corrosion Direct Assessment (ICDA). The NPRM proposed
requirements for the use of Direct Assessment to address internal
corrosion in a pipeline segment.
Numerous commenters noted problems with the proposed ICDA language
used in some of the requirements. Suggestions included: Rewording to
clarify that internal corrosion can result from more than upset
conditions, deleting references to chlorides, replacing ``moisture''
with ``electrolytes,'' replacing ``MIC'' with
[[Page 69793]]
``microorganisms,'' allowing the use of other measurement techniques
that may be developed, referencing Graph E.III.1 when it is not a
complete flow model, and replacing the word fluids with liquids,
because gas is also a fluid.
Both Paiute Pipeline and Southwest Gas asserted that ASME/ANSI
B31.8S should be exclusively referenced rather than writing a procedure
for ICDA within Part 192. The Northeast Gas Association questioned the
need to excavate additional locations if, upon excavation of the first
location most likely to corrode, no internal corrosion was found.
NTSB commented that its investigation of the Carlsbad pipeline
accident revealed areas where cleaning pigs had not been used that were
likely locations for internal corrosion. NTSB suggested that RSPA/OPS
highlight the increased corrosion potential of pipeline sections not
subject to the periodic use of cleaning pigs.
Response: NACE is developing recommended practices for ICDA, but
none has yet been finalized. Discussion of ICDA in ASME/ANSI B31.8S is
limited, but the final rule does reference the requirements in Appendix
B2 of that standard. The final rule includes basic requirements
consistent with the recommended practices now under development. These
recommended practices, when completed, will provide additional guidance
for implementing these requirements. The requirements provide for a
minimum of two excavations in each ICDA region. RSPA/OPS has concluded
that more than one excavation is needed, because predicting the
locations at which internal corrosion could occur is not an exact
science. There are different types of locations in which such corrosion
can occur. Multiple excavations, and direct examination of potentially
affected pipe, are necessary to ensure that internal corrosion will be
found.
RSPA/OPS has revised the language in the final rule to incorporate
many of the suggested editorial comments. The final rule has also been
revised to highlight the potential for increased corrosion of locations
not subject to periodic use of cleaning pigs or in which cleaning pigs
could deposit collected liquids.
Reassessment Intervals: RSPA/OPS proposed that the reassessment
interval begin when the baseline assessment of a covered segment was
completed. This had been proposed consistent with the statutory
requirement in 49 U.S.C. 60109(c)(3)(A) that an integrity management
program include ``[a] baseline integrity assessment of each of the
operator's facilities * * *.'' The length of the proposed reassessment
intervals depended on the assessment method, although some form of
reassessment would have to be done by the seventh year of the interval.
If an operator used pressure testing or internal inspection, the
maximum reassessment interval proposed was ten years for a pipeline
operating at or above 50% SMYS and 15 years if operating below 50%
SMYS. If an operator established the maximum interval, the notice
proposed that a Confirmatory Direct Assessment would have to be done in
the seventh and fourteenth years. If an operator used DA, the notice
proposed a five-year interval if examining and remediating defects by
sampling, or ten years if directly examining and remediating all
anomalies. Again, if the ten-year interval were established, the notice
proposed a CDA be conducted by the seventh year.
In the NPRM, OPS requested comment on whether a rule should allow a
maximum 20-year reassessment interval on pipelines operating at less
than 30% SMYS, and reassessment by CDA method every seven years,
without the need for reassessment by some other method, for pipelines
operating below 20% SMYS (68 FR 4278, 4281). RSPA/OPS also sought
comment on whether the rule should allow a maximum ten-year
reassessment interval when DA is used on a pipeline operating at less
than 30% SMYS.
Cook Inlet Keeper supported the proposal to reassess a covered
segment every seven years, rather than to begin the reassessment
interval only after the baseline assessment of all covered segments in
a transmission system was complete. Cook Inlet maintained the proposal
was consistent with the Congressional intent to ensure covered segments
are reassessed every seven years. Cook Inlet argued that without such
an interpretation, a segment assessed early during the baseline
assessment period might be assessed late during the reassessment
period, resulting in over 16 years between assessments.
Contrary to Cook Inlet's position, the vast majority of commenters
argued that reassessment intervals should begin after the initial ten-
year baseline period, i.e., the reassessment interval should not begin
until all segments have been initially assessed. INGAA requested that
the rule clarify that the initiation of the first reassessment is not
mandatory until completion of the baseline period for the system. INGAA
asserted that without this change, operators will be conducting
reassessments on their systems in HCAs at the same time as they are
conducting baseline assessments, resulting in a potential for
significant gas price spikes caused by outages on multiple pipeline
systems occurring at the same time. INGAA claimed this would conflict
with the intent of the legislation and preclude the ability to adjust
priorities based on prior findings. Numerous commenters echoed INGAA's
comments.
Expanding on INGAA's position, NiSource asserted that without the
change, outages in overlap years are likely to make it difficult to
refill storage during summer months and lead to shortages and price
spikes the following winters. Kansas Gas Service maintained that if the
overlap were not eliminated, a bubble of demand for assessment services
much greater than any other year would be created during the overlap
years and would not be sustained beyond the bubble, resulting in
operators facing difficulty obtaining services and experiencing supply
interruptions. PSNC Energy also recommended eliminating the overlap
because it would cause economic and labor-related hardships and lead to
shortcomings from cutbacks in remaining baseline assessments. Northeast
Gas Association and several other commenters noted that the
reassessment intervals should be the same as identified in ASME/ANSI
B31.8S.
AGA proposed that the rule incorporate the maximum interval set for
pipelines operating below 30% SMYS in the ASME/ANSI B31.8 standard,
with interim preventive and mitigative measure being applied every
seven years. Ten commenters, including Vectren, Dominion, and Northeast
Gas Association, supported AGA's proposal that the rule allow a maximum
20-year reassessment period for pipelines operating under 30% SMYS.
Northeast Gas Association also recommended the 20-year interval also
apply for Direct Assessment. Sempra, the Iowa Utilities Board, and
other commenters supported less stringent requirements for pipelines
operating below 30% SMYS because of the lesser hazard posed by failure
of these low-stress pipelines.
There were many comments on the proposed shorter reassessment
intervals for operators using Direct Assessment. American Public Gas
Association, American Gas Association, and several other commenters
argued that DA reassessment intervals should be the same as for other
methods. Williams Gas Pipeline maintained that having shorter DA
intervals is not justified and Panhandle Eastern suggested that the
reassessment intervals should be based on ASME/ANSI B31.8S. PG&E
[[Page 69794]]
supported a ten-year DA interval on pipelines operating at less than
30% SMYS, which would be consistent with ASME/ANSI B31.8S. Sempra
asserted that accelerating DA assessment schedules could result in
assessment on some higher risk pipelines being deferred and suggested
basing assessments on risk ranking of the various pipeline segments
independent of the assessment method. The Association of Texas
Intrastate Natural Gas Pipelines contended that Congress treated DA as
equivalent to other methods of assessment and that RSPA cannot do
differently. The Energy Association of Pennsylvania claimed the
proposed seven-year interval is not consistent with the statute or
Executive Order 13211, Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use.
In contrast, the New York Department of Public Service contended
that extending the DA reassessment interval from five to ten years is
unreasonable because external corrosion direct assessment is an
immature process. New York asserted that although the Northeast Gas
demonstration on the ECDA process showed that the process was reliable
in identifying locations of current or potential corrosion activity,
more experience is needed to characterize uncertainties and increase
confidence that serious anomalies will be detected.
With respect to the proposed CDA reassessment intervals, the State
of New York asserted that CDA should not be considered a reliable
assessment method and that full DA should be required every seven
years. In contrast, Duke Energy opined that CDA should count as a valid
reassessment and that a subsequent follow-up reassessment to CDA should
not be scheduled for another seven years. Duke Energy recommended
changing the rule to reflect that CDA is a valid reassessment technique
on its own.
Response: Congress required ``[a] baseline integrity assessment of
each of the operator's facilities in areas identified pursuant to
subsection (a)(1) [i.e., high consequence areas],'' and ``periodic
reassessment of the facility, at a minimum of once every 7 years'' (49
U.S.C. 60109).
Industry commenters argued that this language can, and should, be
read to require reassessments within seven years after the ten-year
period in which baseline assessment of all covered segments had been
completed. RSPA/OPS finds that the plain language of the statute
precludes this interpretation. Industry suggests that the meaning of
the word ``facility'' is key, and RSPA/OPS agrees. Elsewhere in the
section requiring baseline assessments within 10 years of enactment,
the statute states, ``At least 50 percent of such facilities shall be
assessed not later than 5 years after such date of enactment. The
operator shall prioritize such facilities for assessment based on all
risk factors * * *'' (emphasis added). In contrast, the language
requiring reassessment refers to periodic reassessment of the facility.
Congress differentiated between individual pipeline segments and an
operator's entire pipeline system. The statutory language is clear that
an assessment of each covered segment is required at least every seven
years.
RSPA/OPS acknowledges that the requirements of the final rule will
require that some reassessments be conducted before all baseline
assessments have been completed. The rule has been written, however, in
a manner intended to minimize the impact of this overlap to the extent
practicable.
The rule allows different methods for reassessment, and the maximum
reassessment interval depends on the method used and the operating
pressure of the pipeline. However, the reassessment required at seven-
year interval, the interval required by law, can be by Confirmatory
Direct Assessment. CDA provides for much less potential disruption of
pipeline operations than other assessment methods. No shut-down or
curtailment of operation is needed to perform the indirect surveys that
are a part of this method. Operators will likely reduce pressure when
conducting excavations to protect personnel involved in that work, but
the number of excavations required for CDA is less than for DA.
Reassessment intervals for DA have been revised to be the same as
those required for other assessment methods. This reduces the amount of
pipeline that must be assessed each year when compared to the five-year
reassessment requirement in the proposed rule.
For pipelines operating below 30% SMYS, the final rule provides
that the seven-year reassessment requirement can be met by a low-stress
reassessment that includes indirect examinations, leak surveys, and
other measures. The requirements for low-stress pipelines are discussed
in item 7 of Comments to NPRM. This provision recognizes the relatively
low risk posed by these pipelines and the likelihood that failures will
result in leakage rather than rupture. Operators who implement this
low-stress reassessment option also have the option of performing CDA.
Reassessment for these low-pressure pipelines by the other methods
allowed by the rule (i.e., pressure test, internal inspection, direct
assessment) are required only every 20 years, the maximum interval
allowed by ASME/ANSI B31.8S.
ERW Pipe. Several comments concerned ERW pipe. The Gas Piping
Technology Committee (GPTC) commented that the only way to assess seam
issues is to conduct both an internal inspection and a pressure test,
but such a requirement would not be practical. GPTC further commented
that there are economic and technical barriers related to both
Transverse Flux Inspection (TFI) and Ultrasonic tools. GPTC suggested
the rule require that if an operator selects one of the multiple
possible methods for assessment, it must consider the other method for
reassessment. Sempra maintained the language on ERW pipe is unclear and
that assessment should only be performed when a pipeline is subject to
internal corrosion or when operating conditions could result in
propagation of seam imperfections by fatigue.
Response: If a covered pipeline segment contains low frequency
electric resistance welded pipe (ERW) or lap welded pipe with a history
of seam failure, an operator is required to select an assessment
technology or technologies with a proven application capable of
assessing seam integrity and of detecting seam corrosion anomalies. The
operator is required to prioritize the covered segment as a high risk
segment in its data integration and risk evaluation model.
Training. Duke Energy argued that the appropriate place for the
training requirements is under the existing operator qualification
requirements of Subpart N and not within the integrity management
requirements. Oleska and Associates contended that the proposed
training requirements for supervisors are too broad and that
understanding should be commensurate with job responsibilities and
relationship to the program.
Response: It is critical that personnel involved in integrity
management programs and in conducting assessments have the appropriate
training and qualifications for their functions. These functions are
not, generally, within the scope of those covered by the Operator
Qualification rule, because they are not tasks performed ``on the
pipeline.'' In the final rule, RSPA/OPS has clarified the requirements
for training, but continues to believe they are a necessary part of the
rule.
Other comments about program requirements. We received a number of
miscellaneous comments on some of the
[[Page 69795]]
proposed integrity management program requirements. Cook Inlet Keeper
requested that OPS review its database to ascertain whether there are
additional threats to pipeline integrity, such as human error,
maintenance problems, and valve and patch failures.
Peoples Energy opined that the proposal to consider cyclic loading
is specious because it requires operators to assume ``deep dents'' are
present and further to determine if the loading conditions will lead to
failure of the assumed ``deep dents.''
Advanced Technology Corporation suggested redefining ``toughness''
as ``fracture toughness'' for older pipe materials to calculate the
``critical defect size'' and to ensure the proper use of relevant
information.
Response: A systematic search of recorded incidents to identify
threats to pipelines was conducted while developing the standard on
integrity management, ASME/ANSI B31.8S. The rule is structured around
evaluating susceptibility to these threats and protecting against them.
RSPA/OPS believes that the best way to address threats associated with
human errors is through training and qualification, since failures from
this cause usually occur immediately.
With respect to cyclic loading, it is important that a realistic
analysis of the condition be conducted to ascertain the susceptibility
of pipelines to failure from this cause. Such analyses require the
postulation of some flaw, because the effect of cyclic loading is to
propagate existing flaws. Flawless pipe can generally withstand
significant cyclic loading, but little pipe is completely without
flaws. The final rule requires an operator to use the results from the
evaluation together with the criteria used to evaluate the significance
of this threat to the covered segment to prioritize the next integrity
assessment.
In the final rule, we have substituted the term ``fracture
toughness'' for ``toughness.''
5. Review, Notification and Enforcement Processes
There were several comments related to review, approval, and
enforcement processes but the majority related to the use of and
practicality of waivers. RSPA/OPS had proposed to allow a waiver of a
reassessment interval greater than seven years in two limited
instances: Lack of internal inspection tools and to maintain local
product supply. The statute limits a waiver to these two instances.
The proposal included prior notification requirements to OPS in
several instances: When using other technology as an assessment method
(180 days), When making a significant change to the integrity
management program (30 days), and when seeking a longer reassessment
period (180 days before the end of the required period).
Sempra commented that the potential impact on customers is greater
than perceived primarily because of the impact to numerous large
customers served by a single source pipeline, and therefore the need
for waivers may have been greatly underestimated. Panhandle Eastern
asserted that waiting 180 days for a decision on a waiver is excessive.
The Washington Utilities and Transportation Commission suggested that
we include provisions that would require RSPA/OPS to approve or
disapprove of an operator's request for waiver.
Enron was concerned about the proposed program change requirements
and asserted that the terms ``significantly'' and ``substantially'' are
vague and subject to varying interpretations. Enron further argued that
requiring separate, subjectively determined notifications is not
productive or useful when changes could be effectively reviewed during
regular pipeline program reviews.
Several commenters, including Advanced Technology Corporation,
suggested that RSPA/OPS better define the process by which new
technologies are approved. Both PECO and El Paso objected to the 180-
day notification prior to the use of new technology and El Paso
suggested that the notification period be reduced to 90 days, which
would be consistent with Sec. 195.452. El Paso also suggested that
provision be made for the ongoing use of other technology via a single
notification.
Sempra encouraged RSPA/OPS to address the coordination of
environmental review and the permit process for pipeline repairs and
for retrofitting and inspection of pipelines per Section 16 of the
Pipeline Safety Improvement Act of 2002.
Response: RSPA/OPS acknowledges that the number of waivers likely
to be sought by operators is not known at this time. Nevertheless, 49
U.S.C. 60109 requires that an assessment be performed on a pipeline
segment in a high consequence area at seven-year intervals and further
provides that operators may seek waivers only under two circumstances.
The waiver requirements in this rule follow the statute. Because of the
statutory limitations, RSPA/OPS cannot make other changes in
anticipation of a large number of waivers possibly being submitted many
years hence. RSPA/OPS believes that careful planning can help avoid the
need for waivers. Careful planning also will identify the need for
waivers in sufficient time to allow operators and RSPA/OPS to conduct
careful reviews. RSPA/OPS is working on expediting the waiver process
to prevent potential supply shortfalls. RSPA/OPS expects that a
requirement to apply for a waiver 180 days before the end of the
required reassessment interval is reasonable, except when local product
supply issues may make that period impractical. In such an instance, an
operator would need to apply for the waiver as soon as the need for the
waiver becomes known. The waiver process is governed by 49 U.S.C.
60118, the Federal pipeline safety law. Currently, a waiver must be
published for public comment. Therefore, 180 days is a reasonable
period to allow for publication in the Federal Register and to address
public comments on the a proposed waiver.
To address the TPSSC's recommendation we have revised the language
in the final rule to include the exact language of the statute
pertaining to waivers. Therefore, a waiver may be sought to maintain
local product supply or because of unavailability of internal
inspection devices. In either case, RSPA/OPS must determine that a
waiver would not be inconsistent with pipeline safety.
The Pipeline Safety Improvement Act of 2002 also requires that
operators notify RSPA/OPS when they make changes to their integrity
management programs. RSPA/OPS cannot eliminate this requirement from
the rule. The requirement has been conditioned to require notification
only of changes that may substantially affect the program's
implementation or may significantly modify the program or schedule for
carrying out the program elements. These qualifiers are intended to
preclude notifications for minor, even editorial, changes.
We have revised this requirement, however, to require an operator
to notify, in addition to OPS, a State or local pipeline safety
authority when a covered segment is located in a State where OPS has an
interstate agent agreement, and a State or local pipeline safety
authority that regulates a covered pipeline segment within that State.
These changes were made to address comments from advisory committee
members and State pipeline safety authorities.
RSPA/OPS continues to believe that 180-day notice before an
operator uses ``other technology'' is a reasonable notification period.
There are reasons why the corresponding period in the rule for
hazardous liquid pipelines is 90
[[Page 69796]]
days. The reassessment period for hazardous liquid pipelines is five
years, a period about 70 percent of the shortest reassessment period in
this rule. Therefore, planning decisions must be made for liquid
reassessments on a shorter time frame. In addition, the ``other
technology'' most likely to be used by hazardous liquid operators is
direct assessment, an assessment method specifically allowed in the gas
integrity management rule but not in the liquid rule. Because there is
now an industry standard and more information about the process is
known, the review of the notification is likely to be shorter. ``Other
technologies'' that gas transmission pipeline operators may use are
expected to involve methods and techniques that are more developmental
and about which less information is known. This will require that RSPA/
OPS take more time in reviewing these notifications before the ``other
technology'' is implemented.
Section 16 of the Pipeline Safety Improvement Act of 2002 (49
U.S.C. 60133) requires the establishment of an interagency coordinating
committee and that this committee take actions to help ensure that
pipeline operators will be able to obtain permits when required to
perform required repairs. The interagency committee has been
established. RSPA/OPS is participating on the committee. Those actions
are related to, but independent of this rule, and will not be described
here in detail. It is important to note, however, that the rule
provides a mechanism for operators to address situations in which
repairs cannot be made due to inability to obtain permits. The rule
provides that operators can reduce operating pressure or take other
action to ensure the integrity of the pipeline. If neither can be done,
the operator is required to notify RSPA/OPS. RSPA/OPS expects that
operators will exercise due diligence in seeking permits for repairs.
6. Consensus Standard on Pipeline Integrity
The Standards-Developing Organizations Coordinating Council (SDOCC)
urged RSPA/OPS to incorporate industry standards by reference in their
entirety into the regulations. The Council asserted this will help
avoid misinterpretations that can result from parts of standards being
used out of context, or from text taken from standards being used in
regulations without reference to the source. Similarly, both New Jersey
Natural Gas and Advanced Technology Corporation suggested that inline
inspection consensus standards must both be developed and then
supported by OPS.
Many commenters wrote to request that OPS utilize performance-based
options that are both measurable and achievable, and suggested using
the ASME/ANSI B31.8S consensus standard to achieve those ends.
Northeast Gas Association recommended that the rule refer to ASME/ANSI
B31.8S for performance versus prescriptive requirements. El Paso went
further and asserted that the proposed requirements for the
performance-based option are not measurable or achievable and should be
revised to allow the ASME/ANSI B31.8S standard to provide the structure
and framework. Cook Inlet Keeper recommended that RSPA/OPS review the
ASME/ANSI B31.8S standard to ensure that the standard is enforceable
and where necessary provide clarification in the final rule.
Response: The final rule incorporates ASME/ANSI B31.8S--2001,
Managing System Integrity of Gas Pipelines, and uses that standard for
many of the rule's requirements, including those for the performance-
based option. RSPA/OPS has reviewed ASME/ANSI B31.8S to ensure it is
enforceable. The rule has been written to ensure that the requirements
are enforceable.
7. Low-Stress Pipelines
The proposed rule did not differentiate requirements for low-stress
pipelines. However, as discussed in previous sections of this document,
RSPA/OPS sought comment on less stringent requirements for these
pipelines, particularly with respect to--
[sbull] Whether to allow an operator using direct assessment on a
pipeline operating at less than 30% SMYS a maximum ten-year
reassessment interval regardless of whether the operator excavates and
remediates all anomalies on that pipeline, or at least remediates the
highest risk anomalies. (68 FR 4278, 4281)
[sbull] Whether to allow a maximum 20-year reassessment interval on
pipelines operating at less than 30% SMYS, and reassessment by
confirmatory direct assessment method every seven years (without the
need for reassessment by some other method) for pipelines operating
below 20% SMYS. (68 FR 4278, 4281)
Several commenters suggested that the assessment requirements
proposed for low-stress pipelines (i.e., pipelines operating at below
30 percent SMYS) were unnecessary and overly burdensome. Many industry
commenters pointed out that low-stress pipelines tend to fail by
leakage rather than by rupture and, therefore, pose considerably less
risk than pipelines operating at higher stresses. The commenters
proposed various alternatives, including use of the inspection
intervals in ASME/ANSI B31.8S (which calls for inspections at 20-year
intervals for low-stress pipelines), allowing use of confirmatory
direct assessment for baseline assessments, implementation of
preventive and mitigative measures in lieu of assessment requirements,
and changing the definition of transmission pipeline to exclude
pipelines operating at less than 20% SMYS. National Fuel contended that
pipelines that operate at less than 20% SMYS cannot create high
consequences and, therefore, the high consequence area definition
should exclude such pipelines. National Fuel recommended that, if RSPA/
OPS must include these pipelines by statute, enhanced preventive and
mitigative measures should be allowed for the baseline assessment and
reassessment.
AGA recommended that the intervals in ASME/ANSI B31.8S be used. AGA
provided suggested preventive and mitigative measures for all pipeline
in Class 3 and 4 areas and numerous commenters supported AGA's
comments. AGA also proposed, at public meetings held during the comment
period, that pipelines operating at less than 20% SMYS be subject to
requirements for baseline assessments and for reassessment at the
intervals specified in ASME/ANSI B31.8S. The AGA recommendations
included electrical surveys, which would inspect for cathodic
protection problems that would precede corrosion damage, and leak
surveys, which would inspect for the failure mechanism most likely on
low-stress pipelines, as a reassessment method suitable to meet the
statutory seven-year requirement.
AGA further proposed a set of preventive and mitigative measures as
alternate assessment methods for reassessment of pipelines inside HCAs.
The additional measures targeted external and internal corrosion and
third-party damage. Other commenters supported this alternative,
including TXU Gas, National Fuel, and the New York State Department of
Public Service.
The Iowa Utilities Board agreed that less stringent requirements
should be applied to pipelines operating below 30% SMYS. New York
Department of Public Service suggested that 20 years was too long an
interval between assessments, and pointed out that although a low-
stress pipeline is likely to fail by leakage, these pipelines are
located in highly populated areas.
[[Page 69797]]
Response: Pipelines that operate at less than 20% SMYS are
transmission pipelines if they meet the functional definition in Sec.
192.3. The statute (49 U.S.C. 60109) does not except low-stress
pipelines from the integrity management program requirements, including
the requirement for reassessment at seven-year intervals. RSPA/OPS has
revised the requirements, however, in recognition of the relatively low
risk posed by pipelines operating at less than 30% SMYS. First, the
rule allows two methods to define a high consequence area, so that an
operator of a low-stress pipeline can rely on data it has already
collected to identify the areas.
Second, the rule allows an alternative method of reassessment that
focuses on the type of risk posed by these low-stress pipelines. RSPA/
OPS agrees with AGA that these pipelines should be assessed initially
and at the 20-year interval by the methods being used to assess higher
stress pipelines, and has so required in the rule. During the 20-year
interval, a low-stress line must be reassessed at seven year intervals
by a low-stress reassessment, which is described below, or by
confirmatory direct assessment. The rule incorporates confirmatory
direct assessment (CDA) as a focused method of performing these interim
assessments for pipelines operating at higher pressure. However, for
low-stress pipelines, RSPA/OPS agrees that even CDA could be unduly
burdensome. Therefore, the final rule adopts AGA's suggestion that
electrical surveys are appropriate for conducting these interim low-
stress reassessments between the assessments performed by methods being
used to assess higher stress pipelines.
The rule allows operators of low-stress pipelines an option. They
can perform CDA on seven-year intervals or they can conduct a low-
stress reassessment that focuses on the types of threats these
pipelines experience. A low-stress reassessment includes an electrical
survey at least every seven years. For cathodically unprotected
pipeline or areas where electrical surveys are impractical, increased
leak surveys are required at a rate twice the current requirement. The
additional measures also include provisions to protect against internal
corrosion and third-party damage. RSPA/OPS has concluded that these
measures provide appropriate interim protection for low-pressure
pipelines, where the failure mode is predominantly leakage instead of
rupture.
RSPA/OPS has also adopted AGA's suggestion that enhanced preventive
and mitigative measures be required for low-stress pipelines located in
Class 3 and 4 areas. These measures protect against third-party damage,
the type of threat most likely to result in a significant failure on
these pipelines.
8. Remedial Actions--Sec. 192.931 (Formerly Sec. 192.763(i))
There were numerous comments about the proposed remediation
requirements particularly with respect to the proposed time periods for
discovery, pressure reduction and remediation, and the proposed repair
criteria in general and for dents.
The proposed requirements for scheduling remediation of anomalous
conditions found during an assessment provided for immediate repair
conditions, 180-day conditions, and conditions where remediation would
take longer than 180 days. The 180-day conditions included certain
dents. The proposed rule also referenced B31.8S as the basis for making
repairs.
Industry commenters generally supported INGAA's suggestion that the
repair criteria should be based on the industry standards, ASME/ANSI
B31.8 and B31.8S. INGAA further suggested that the proposed 180-day
time frame for evaluation and remediation of certain conditions should
be changed to one year. INGAA explained that the 180-day limit would
require remediation during winter months when the demand for gas is
high. One year would allow operators one complete operating cycle in
which to complete the work. Industry commenters supported this
suggestion. INGAA also submitted recommended rule language that allowed
time frames of one-year, more than one-year and monitored conditions,
i.e., conditions that would not have to be scheduled for remediation.
INGAA, and other industry commenters such as El Paso and Panhandle
Eastern, contended that the requirement to remediate dents should be
reconsidered and should be revised to distinguish between bottom-side
and top-side dents. These commenters explained that constrained dents
are not a threat. Depressions or dents in the bottom of the pipe are
constrained; dents on the top of the pipe that are relatively
unconstrained. Commenters recommended that the distinction be made by
specifying remediation for dents between the 8 and 4 positions and on
monitoring dents that do not need to be remediated.
The proposed remediation requirements provided that a pressure
reduction could not exceed 365 days unless the operator took further
remedial action to ensure the safety of the pipeline. Many commenters,
including the Gas Piping Technology Committee and Nicor Gas, argued
that there is no basis for the proposed 365-day limit on pressure
reduction and that operators should be allowed to use long-term
pressure reduction if it provides equal or better safety. Public
Service Electric and Gas Company asserted that the 365-day limit is not
supported by any data analysis or risk assessment and should be
removed. El Paso argued that pressure reductions should not be based on
the pressure at the time of discovery but based possibly on either the
MAOP or the highest pressure in the last 30 days. Sempra suggested we
use technical information from a Pipeline Research Council
International report that stated a pressure reduction in these
circumstances may be determined using the highest pressure survived by
the flaw since the time that it occurred.
The proposed discovery requirements were also a concern to many
operators. The proposed rule provided that discovery occurs when an
operator had adequate information about the condition to determine that
the condition presents a potential threat to the integrity of the
pipeline, and that discovery could occur no later than 180 days after
conducting an integrity assessment unless the 180-day period is
impracticable. Dominion contended the proposed language is confusing
and suggested that discovery be tied to a time when the operator has
adequate information concerning the conditions to determine that an
indication requires a response as defined in ASME/ANSI B31.8S. INGAA
and many other industry comments suggested that the proposed 180-day
requirement associated with the discovery date be extended to one year
to be consistent with ASME/ANSI B31.8S.
Response: We have revised the remediation requirements in the final
rule. The rule provides that an operator be able to demonstrate that
the remediation of the condition will ensure that the condition is
unlikely to pose a threat to the integrity of the pipeline until the
next reassessment of the covered segment. We thought this language more
definite than being able to demonstrate a remediation will ensure the
condition does not pose a threat to the long-term integrity of the
pipeline. The final rule continues to provide that discovery occurs
when an operator has adequate information about the condition to
determine that the condition presents a potential threat to the
integrity of the pipeline. Adequate information to make this
determination would include information that the condition is one
included in ASME/
[[Page 69798]]
ANSI B31.8S as needing a response. The rule also continues to specify
that this must occur within 180 days after conducting the assessment,
unless the operator demonstrates the 180-day period is impracticable.
This is the same period used for the corresponding requirement for
hazardous liquid pipelines. RSPA/OPS considers that identified
anomalies should be dealt with promptly, and that delaying the
requirement for discovery to occur until one year after an assessment
is not consistent with that need.
The basis on which RSPA has accepted the recommendation to change
the time allowed for evaluation and remediation of certain defects from
180 days to one year is that gas pipelines typically do not operate
with pressure fluctuations sufficient to cause cyclic fatigue.
Therefore, the subject defects can be allowed to remain for up to one
year. In addition, this position is consistent with provisions of ASME/
ANSI B31.8S.
The remediation requirements associated with dents have been
revised in response to the comments to distinguish between bottom-side
and top-side dents. The rule now provides that dents greater than 6% of
the pipe diameter in depth in the top two-thirds of the pipe (i.e., 8
o'clock to 4 o'clock), or greater than 2% and affecting curvature at a
weld, must be remediated in one year. The rule allows such dents to be
treated as monitored conditions if an operator obtains information and
performs engineering analyses to demonstrate that critical strain
levels have not been exceeded. An operator must also monitor dents on
the bottom-third of the pipeline. The rule now also differentiates
between smooth and abrupt dents because abrupt dents need to be
prioritized for evaluation before smooth dents.
We have revised the requirement for pressure reduction. If an
operator is unable to respond within the required time limits for
certain conditions, the operator must temporarily reduce the operating
pressure of the pipeline or take other action that ensures the safety
of the covered segment. Thus, a pressure reduction is not automatic. If
the operator reduces pressure, the reduction cannot exceed 365 days
without an operator providing a technical justification that the
continued pressure restriction will not jeopardize the integrity of the
pipeline. The requirement that a pressure reduction cannot last more
than 365 days without further action is identical to a requirement in
the integrity management rule for hazardous liquid pipelines. The
reduction provides an increased margin of safety in the interim, while
repair can be planned and implemented.
9. Additional Preventive and Mitigative Measures, Including, Leak
Detection Devices and Automatic Shut-Off and Remote Control Valves--
Sec. 192.933 (Formerly Sec. 192.763(j))
We received a large number of comments on the proposed additional
preventive and mitigative measures.
INGAA asserted that excavation damage is the primary cause of 28%
of reportable incidents and that the proposed rule focuses primarily on
previously damaged pipe which is associated with only 4% of reportable
incidents. INGAA proposed additional requirements be incorporated for
the prevention of third-party damage and that the assessment for
previously damaged pipe be integrated into the assessment processes for
other failure causes. Dominion suggested eliminating the proposed
requirement to conduct an internal inspection looking for third-party
damage because it is ineffective. Equitable opposed pressure testing
for third-party damage detection asserting there is no technical
justification. These and many other commenters opposed the proposal to
utilize an assessment tool to identify third-party damage. Commenters
agreed that direct assessment is the number one tool for assessing
third-party damage. Numerous commenters, including Enron and the
Northeast Gas Association, argued that prevention is the best approach
and urged RSPA/OPS to champion efforts to eliminate exemptions to the
various state one-call programs.
AGA proposed a set of additional preventive and mitigative measures
as assessment methods for addressing external and internal corrosion
and third-party damage for pipelines operating below 30% SMYS and not
in HCAs but in Class 3 and 4 locations. Again, numerous commenters
supported these additional preventive and mitigative measures including
NiSource, Laclede Gas, and the Association of Texas Intrastate Natural
Gas Pipelines.
Several comments related to the proposal to install automatic shut-
off valves and remote control valves as potential risk mitigative
measures. None of those commenters supported their use. PSE&G asserted
there is no technical justification for their use and Enron asserted
that it has been demonstrated that these valves provide no additional
safety benefit. Panhandle Eastern referenced a Gas Research Institute
Report which, according to Panhandle Eastern, concludes that the cost
of installing the valves is not justified by the limited benefit.
One company commented that its leak detection system would be
effective on gas pipeline systems and asked that RSPA review the system
for potential use on natural gas pipelines to better monitor leaks.
Response: The final rule incorporates additional requirements to
help prevent accidents caused by third-party damage, including
requiring participation by pipeline operators in one-call systems. We
have not included the proposed requirement to conduct assessments
specifically to evaluate possible third-party damage.
The rule also incorporates additional prevention and mitigation
requirements for low-stress pipelines that are located in Class 3 and 4
areas but not HCAs. This was not an issue in the proposed rule, because
all Class 3 and 4 areas would have been defined as HCAs. The revised
definition for HCAs included in the final rule will mean that some
pipeline in populated areas (i.e., Class 3 and 4) will not be
determined to be in HCAs. RSPA/OPS agrees with AGA that it is
appropriate that additional measures be implemented in these populated
areas to protect the pipeline. The final rule incorporates the
provisions recommended by AGA.
With respect to automatic and remotely-operated shut-off valves,
RSPA/OPS acknowledges generic work, some sponsored by RSPA/OPS that
concluded that installation of such valves is usually not cost-
beneficial. The conclusions of those studies were based, however, on
generic, average conditions. It is possible that conditions particular
to individual pipeline segments in HCAs may change this conclusion,
making it appropriate to install or modify valves. The rule requires
operators to make this determination and to install a valve if it would
be an efficient means of adding protection to a high consequence area
in the event of a gas release. RSPA/OPS does not expect that operators
will perform detailed technical analyses that duplicate the work done
in the generic studies. Instead, operators will use the generic work as
a starting point and then evaluate whether the generic conclusions are
applicable to their high consequence area pipeline segments. The
results of this evaluation must be documented for review during RSPA/
OPS inspections.
As for the leak detection system the commenter described, RSPA/OPS
does not require that operators install particular safety systems, nor
does it endorse them. Vendors who believe their systems will allow
companies to
[[Page 69799]]
meet requirements of this rule in a cost-effective manner should
approach pipeline operators directly.
10. Methods To Measure Program Effectiveness--Sec. 192.941 (Formerly
Sec. Sec. 192.763(c)(5) and 192.763(l))
Reporting requirements associated with the proposed rule generated
a number of comments, most in opposition to the proposed requirements.
Proposed requirements included an operator making accessible in real
time the four overall performance measures and the additional
performance measures, if trying to qualify for exceptional performance
under the performance-based option.
New Jersey Natural Gas Company and New York State Department of
Public Service commented that a rule will need to clarify ``real
time.'' Northeast Gas Association also requested a definition and
clarification of what is meant by ``real time'' and suggested that we
use the performance measures identified in Section 9.4 of ASME/ANSI
B31.8S instead of those in the proposed rule.
Many commenters, including Nicor Gas, Kern River, and Consumers
Energy, opposed the use of ``real time'' accessibility to performance
data and suggested alternatives ranging from quarterly to annually. El
Paso suggested a web-based reporting system and PECO was concerned
about security of database systems housing this data.
Numerous commenters supported INGAA's proposal about how to make
the collection of data on performance measures more efficient and
reflective of the effectiveness of an integrity management program.
INGAA proposed that real time mean on a quarterly basis for reporting
the number of miles assessed and the number of repairs. In addition
INGAA recommended that information fields be added to the Annual report
form submitted by gas transmission operators to track and compare the
number of leaks eliminated or repaired in HCAs with those not in HCAs.
Response: RSPA/OPS has eliminated the requirement for operators to
post performance measures in a manner that would allow regulators to
access them electronically in real time. Instead, the general
performance measures (which are those specified in Section 9.4 of ASME/
ANSI B31.8S) must be submitted to OPS semi-annually. This periodicity
results from discussions at the public meetings held during the comment
period and with the Technical Pipeline Safety Standards Committee, and
is consistent with the recommendation adopted by the committee. RSPA/
OPS will compile this information and make it available electronically
to other pipeline safety officials and to the public.
Other suggestions by INGAA concerned forms that were not part of
the rulemaking. We will consider these suggestions and if the forms
should be revised to incorporate fields for the data.
11. Information for Local Officials and the Public
The proposed rule did not propose that operators provide
information to the public. The proposed rule proposed that an operator
have a means to provide a copy of its integrity management program to a
State with which OPS has an interstate agent agreement and a
communications plan that included a process for addressing safety
concerns raised by OPS or an interstate agent. These requirements were
mandated by statute. The notice further proposed that the performance
measures be provided in real time to state pipeline safety officials.
At the advisory committee meeting, the Committee noted that State
authorities need to be aware of these reports for intrastate pipelines,
and for interstate pipelines in states in which the State acts as an
interstate agent.
Carol Parker suggested that a requirement should be included to
notify people who frequent areas where pipelines are not inspected.
Cook Inlet Keeper commented that the four overall performance
measures that OPS proposed an operator maintain (i.e., the measures in
Section 9.4 of ASME/ANSI B31.8S standard), should be made available to
the public in a web-based analyzable format. In addition, Cook Inlet
suggested providing other information such as the primary threats to
covered segments, the assessment tools and their schedules, along with
other non security-related data.
Similarly, the Inline Inspection Association suggested that
operators should be required to report to OPS certain information from
their plans, including segments to be inspected, diameters, potential
threats, and planned assessment methods. OPS should then make this
information available to the public to allow the inline inspection
industry to develop and procure the appropriate tools and train
personnel to provide the needed services.
Accufacts asserted that a rule should include ``Right-to-Know''
provisions, to include reporting specific information to RSPA/OPS such
as mileage in HCAs and total mileage by Class area. Accufacts further
commented that high consequence area information should be reported to
state and local governmental agencies when requested.
As previously discussed, both the Washington State Advisory
Committee on Pipeline Safety and the Washington City and County
Pipeline Safety Consortium suggested that operators work with local
cities or municipalities to identify additional HCAs within their
territories. They asserted that cities and municipalities have the best
information on facilities and on growth trends for their areas which
would be beneficial in identifying HCAs.
The Iowa Utilities Board commented that the proposed rule appears
to reserve all reporting and oversight for RSPA/OPS, with no
recognition of the role played by the states. Iowa opined that the
proposed rule recognizes only interstate pipelines, when by including
all gas transmission pipelines within the scope of the rule, large
numbers of transmission pipelines belonging to intrastate operators
will be affected. Iowa suggested that the rule recognize the
traditional role of state pipeline safety programs and their oversight
of intrastate pipeline operators.
Industry commenters had many concerns about the security of
providing information to the public. Consolidated Edison requested that
OPS clarify how security will be maintained if the detailed information
submitted by operators is made available to the public. Duke Energy
contended that implementation of the proposed integrity management
regulations have implications for national security that have not been
considered or addressed. Duke Energy noted that at the public meeting
in Houston, RSPA/OPS had agreed to look into how to control access to
this information.
Response: RSPA/OPS agrees that information concerning gas
transmission pipeline integrity management should be made available to
the public. At the same time, RSPA/OPS agrees that there are issues,
including security concerns, regarding how much information is
provided. RSPA/OPS recognizes that not every state has laws to protect
the release of proprietary or sensitive information. In the final rule,
RSPA/OPS has tried to balance the need to know against the need to keep
certain critical information secure. RSPA/OPS believes that the four
performance measures an operator is required to include in its program
(as specified in Section 9.4 of ASME/ANSI B31.8S) provide the
appropriate level of information for members of the public to see how
pipeline operators are doing in their integrity management program. The
rule provides that operators submit this information to OPS semi-
annually.
[[Page 69800]]
OPS will assemble this information and will make it available, on the
internet, to the public and to state safety agencies.
RSPA/OPS does not consider it appropriate to collect additional
information relevant to integrity management for public dissemination.
RSPA/OPS will implement an inspection program to evaluate operator
implementation of this rule. Those inspections will ensure that
operators have proper commitment to integrity management, that they are
scheduling and conducting their assessments as required, that they are
using appropriate assessment methods, and that they are adequately
integrating data. Regulators will take enforcement action when
appropriate, and records of such enforcement will be available to the
public as they are now.
The pipeline safety statute (49 U.S.C. 60109) requires that an
operator provide a copy of its risk assessment and integrity management
program to an interstate agent. Although we recognize an operator's
security concerns with providing this information, we must include the
requirement with respect to interstate agents. We recognize the role of
State pipeline safety authorities with respect to intrastate
transmission pipeline. But because of the comments and concerns about
security and protecting this information, we do not want to require
that operators also provide the States this information on intrastate
pipelines. Each State's laws vary and a State may not be able to
protect this information from public release. We will look into a means
of how RSPA/OPS can share this information with a state pipeline safety
authority while ensuring the information is protected. However, the
rule does provide that when a State regulates a covered pipeline
segment within that State, an operator provide the State notice about
changes made to the operator's integrity management program and when
making a repair, the operator cannot meet the required schedule for
repair and cannot temporarily reduce pressure or take other action to
ensure the integrity of the pipeline.
As discussed above, RSPA/OPS agrees that local safety officials are
key elements in the identification of HCAs, and has revised the final
rule to so specify. OPS expects that the regular interaction between
pipeline operators and those officials will also serve to increase
local officials' level of knowledge regarding the operators' integrity
management efforts.
It would be inappropriate to include requirements in a safety rule
simply to elicit information that a vendor can use to develop its
business.
12. Cost-Benefit Analysis
In the preamble of the proposed rule RSPA/OPS stated that it has
never received comments from small gas transmission operators
concerning the burdens of its regulations and that RSPA/OPS believed
that the costs of its proposal would be proportionate to the amount of
mileage the pipeline company operates. RSPA/OPS requested public input
on any potential undue impact that this proposal would have on any
small entities. (68 FR 4278, 4313.)
Very few commenters specifically addressed this question. Vectren
stated there would be significant undue impacts associated with this
new rule and provided estimated information relative to Vectren through
2013. Vectren's estimates showed in excess of 11% per year reductions
in annual income through 2012. Similarly, the Iowa Utilities Board
commented that burdens on small pipelines and operators should be
minimized.
Carol Parker suggested that RSPA/OPS use the impact on the
California economy in dollars to support the cost-benefit analysis of
required inspection programs. Taking a somewhat opposing view, the Iowa
Utilities Board asserted that the proposed requirements for pressure
testing do not adequately recognize the tremendous social and economic
consequences of interrupting service from the majority of intrastate
pipelines. The Association of Intrastate Natural Gas Pipelines
contended that the supply interruptions that may be caused by the rule
have been understated, particularly during the period of any overlap.
Questar asserted that RSPA/OPS has understated the true costs and this
will be problematic if rate regulators adopt the RSPA/OPS analysis as a
benchmark. New Jersey Natural Gas Company was concerned that the cost
estimates for retrofitting are not accurate. INGAA provided a series of
alternatives to the proposed regulations and provided their own
estimates of savings associated with those changes.
The Energy Association of Pennsylvania estimated that over
$2,341,000,000 will be saved if the baseline overlap is eliminated.
AGA estimated that over $1,100,000,000 will be saved if preventive
and mitigative measures are used to perform reassessments along with
the lengthened reassessment intervals provided in ASME/ANSI B31.8S.
Response: RSPA/OPS has made significant changes to the cost-benefit
analysis. Included in these changes is full consideration of the impact
of the Pipeline Safety Improvement Act of 2002. The Act significantly
changed the regulatory environment in which the new rule will be
implemented. The Act requires that gas transmission pipeline operators
develop integrity management plans, perform risk analyses, and perform
certain tests, including retests at specified intervals. These
requirements forever change the regulatory landscape. The notice of
proposed rulemaking was issued in January, only one month after the Act
was signed into law. RSPA/OPS modified the notice to acknowledge that
the law was passed and that it imposed some requirements, but RSPA/OPS
had not taken time to analyze thoroughly the impacts the Act would
have.
RSPA/OPS has since performed extensive analyses to consider the
impacts of the Act and to evaluate ways to make the rule more cost-
beneficial. RSPA/OPS has estimated the costs to implement the
requirements in the Act, without modification, to be approximately $11
billion over 20 years. By comparison, we conclude the cost of
implementing this rule will be $4.7 billion over the same period. The
difference reflects changes made in this rule in the definition of HCAs
(which will have the effect of reducing the amount of pipeline mileage
that must be tested) and provisions for limited scope reassessments
every seven years. The Act requires that pipelines be assessed every
seven years. The Act further requires that these assessments be
performed using one of three specified assessment methods or ``an
alternative method that the Secretary [of Transportation] determines
would provide an equal or greater level of safety.'' The alternative
methods included in this rule will reduce costs significantly over the
cost of performing periodic assessments using only the methods
specified in the Act. There is therefore a benefit in adopting this
rule of approximately $6.2 billion in cost reduction for assuring
pipeline integrity.
Benefits will also accrue in improved ability to site pipelines in
certain critical markets. It is difficult to quantify this benefit, but
RSPA/OPS believes it is real. Inability to site future pipelines could
affect the Nation's ability to use the increased quantities of natural
gas that the Energy Information Administration estimates will be needed
to fuel our economy over the next 20 years.
The rule will significantly reduce the likelihood of pipeline
accidents that result in deaths and serious injuries. Based on the
historical record, RSPA/OPS has estimated this benefit to be on
[[Page 69801]]
the order of $800 million over 20 years. It is quite likely, though,
that future accidents could be worse than the historical experience.
Population near pipelines is growing. This places more people at risk
than in the past. While some historical accidents have resulted in
several deaths and serious injuries, and significant property damage,
accidents with even greater consequences could occur. RSPA/OPS has
analyzed the likelihood that an accident could occur in an area along
the pipeline that is more densely populated. Even though the amount of
pipeline mileage along which such high population densities might be
found is small (RSPA/OPS estimated 0.1% of total mileage for this
analysis) the consequences of an accident are potentially large enough
that the averted costs are still high. RSPA/OPS estimates that an
additional $277 million is realized by avoiding the likelihood of this
more significant accident.
The rule will also result in avoiding significant costs associated
with unexpected interruptions in natural gas supply. The Carlsbad
accident in 2000 resulted in curtailment of supply of natural gas to
California. RSPA/OPS estimates that this resulted in an impact on the
California economy of $17.25 million per day. The total benefit
afforded by this rule in avoiding future economic impacts of this type
is estimated to be $1 billion over the next 20 years.
Another benefit to be realized from implementing this rule is
reduced cost to the pipeline industry for assuring safety in areas
along pipelines with relatively more population. The improved knowledge
of pipeline integrity that will result from implementing this rule will
provide a technical basis for providing relief to operators from
current requirements to reduce operating stresses in pipelines when
population near them increases. Regulations currently require that
pipelines with higher local population density operate at lower
pressures. This is intended to provide an extra safety margin in those
areas. Operators typically replace pipeline when population increases,
because reducing pressure to reduce stresses reduces the ability of the
pipeline to carry gas. Areas with population growth typically require
more, not less, gas. Replacing pipeline, however, is very costly.
Providing safety assurance in another manner, such as by implementing
this rule, could allow RSPA/OPS to waive some pipe replacement. RSPA/
OPS estimates that such waivers could result in a reduction in costs to
industry of $1 billion over the next 20 years, with no reduction in
public safety.
A more detailed discussion of how public comments were addressed in
the revised cost-benefit analysis can be found in the final regulatory
analysis.
The Final Rule
RSPA/OPS has created a new Subpart O in Part 192 for Pipeline
Integrity Management and reformatted the rule into sections analogous
to existing Part 192 rules. RSPA/OPS recognizes that a simple format
and clarity are important features to assist pipeline operators in
using and complying with each requirement.
Section 192.901 What Do the Regulations in This Subpart Cover?
The new Subpart O prescribes minimum requirements for an integrity
management program on gas transmission pipelines that could affect an
HCA. HCAs are defined in Sec. 192.903, and Sec. 192.905 describes how
an operator identifies these areas. Section 192.905 is based on the
recent guidance RSPA/OPS issued on how to identify these areas. The
definitions of gas and transmission pipeline are found in Sec. 192.3.
This final rule does not apply to gas gathering pipelines or to gas
distribution pipelines. Because most of the requirements are applicable
to metal pipelines, not plastic, only certain requirements apply to
plastic gas transmission pipelines. Requirements for a continuing
threat analysis (Sec. Sec. 192.917, 192.937), a baseline assessment if
a threat other than third-party damage is identified (Sec. 192.921),
and additional preventive and mitigative measures (Sec. 192.935) apply
to plastic gas transmission pipelines.
Section 192.903 What Definitions Apply to This Subpart?
In the final rule RSPA/OPS has made changes to the definitions in
the new Sec. 192.903 based on the petition for reconsideration,
written comments in the docket, comments received at post-NPRM public
meetings and the recommendations given by the gas advisory committee.
The proposed definitions Potential Impact Zone, Threshold Radius, and
Moderate Risk Areas have been deleted. New definitions of Assessment,
Covered pipeline segment, Identified site, and Remediation have been
added.
The High consequence area definition was modified to allow an
operator two methods to identify the areas.
In method (a) high consequence areas are--
1. Current Class 3 location;
2. Current Class 4 location;
3. Any areas areas outside a Class 3 or 4 location where the
Potential Impact Radius is greater than 660 feet (200 meters), and the
area within a Potential Impact Circle contains 20 or more buildings
intended for human occupancy. However, if the radius of the Potential
Impact Circle is greater than 660 feet (200 meters), the operator may
identify a high consequence area based on a prorated number of
buildings intended for human occupancy within a distance 660 feet (200
meters) from the centerline of the pipeline until December 17, 2006. If
an operator chooses this approach, the operator must prorate the number
of buildings intended for human occupancy based on the ratio of an area
with a radius of 660 feet (200 meters) to the area of the Potential
Impact Circle (i.e., the prorated number of buildings intended for
human occupancy is equal to [20 x (660 feet [or 200 meters ]/Potential
Impact Radius in feet [or meters]) \2\]).
4. The area within a Potential Impact Circle containing an
identified site.
In method (b) high consequence areas are--
1. The area within a Potential Impact Circle containing 20 or more
buildings intended for human occupancy, (unless the exception described
above in method (a) applies);
2. The area within a Potential Impact Circle containing an
identified site.
When a Potential Impact Circle is calculated under either of the
methods to establish a high consequence area, the length of the high
consequence area extends axially along the length of the pipeline from
the outermost edge of the first Potential Impact Circle that contains
an identified site or 20 or more buildings intended for human occupancy
to the outermost edge of the last contiguous Potential Impact Circle
that contains either an identified site or 20 or more buildings
intended for human occupancy. Appendix E, Figure E.I.A gives a graphic
representation.
The identified site component of the high consequence area
definition was also modified to distinguish between rural buildings and
outside open areas and to simplify the identification process. An
identified site is an area meeting one of three criteria--
1. An outside area or open structure that is occupied by twenty
(20) or more persons on at least 50 days in any twelve (12) month
period (the days need not be consecutive). Examples included in the
definition are beaches, playgrounds, recreational facilities, camping
grounds, outdoor theaters, stadiums, recreational areas near a body of
water, or areas outside a rural building such as a religious facility,
or
[[Page 69802]]
2. A building that is occupied by twenty (20) or more persons on at
least five (5) days a week for ten (10) weeks in any twelve (12) month
period (the days and weeks need not be consecutive). Examples included
in the definition are religious facilities, office buildings, community
centers, general stores, 4-H facilities, and roller rinks.
3. A facility occupied by persons who are confined, are of impaired
mobility, or would be difficult to evacuate. Examples included in the
definition are hospitals, prisons, schools, day-care facilities,
retirement facility and assisted-living facilities.
Section 192.905 How Does an Operator Identify a High Consequence Area?
An operator is required to select method (a) or method (b) from the
definition in Sec. 192.903 to identify a high consequence area. One
method may be applied to an entire pipeline system, or the methods may
be applied individually to portions of the pipeline system. An operator
has to describe in its integrity management program which method is
applicable for each portion of the operator's system, and show the
Potential Impact Radius when utilized for each covered segment. The
rule also includes guidance in Appendix E.I. on identifying HCAs.
This section also prescribes how an operator must identify HCAs
that include ``identified sites.'' The rule is consistent with the
advisory bulletin RSPA/OPS recently issued (68 FR 42458). An operator
identifies an identified site from information the operator has
obtained from routine operation and maintenance activities and from
public officials with safety or emergency response or planning
responsibilities who indicate to the operator that they know of
locations that meet the identified site criteria. These public
officials could include officials on a local emergency planning
commission or relevant Native American tribal officials.
The rule further provides that if a public official with safety or
emergency response or planning responsibilities informs an operator
that she/he does not have the information to identify an identified
site, the operator is required to use one of several listed sources, as
appropriate, to identify these sites. The listed sources include--
1. Visible marking (e.g., a sign); or
2. The site is licensed or registered by a Federal, State, or local
government agency; or
3. The site is on a list (including a list on an Internet Web site)
or map maintained by or available from a Federal, State, or local
government agency and available to the general public.
The rule provides requirements for identifying new HCAs. When an
operator has information that the area around a pipeline segment not
previously identified as a high consequence area could satisfy any of
the definitions of a high consequence area (as defined in Sec.
192.903), the operator must complete the evaluation using
identification method (1) or (2). If the segment is determined to meet
the definition as a high consequence area, then it must be incorporated
into the operator's baseline assessment plan as a high consequence area
within one year from the date the area is identified.
Section 192.907 What Must an Operator Do To Implement This Subpart?
The rule requires that no later than December 17, 2004, an operator
must develop and follow a written integrity management program that
contains all the elements described in Sec. 192.911 and that addresses
the risks on each covered transmission pipeline segment. The one-year
time frame is based on the statutory requirement to issue regulations
requiring an operator to conduct a risk analysis and adopt an integrity
management program no later than December 17, 2004. Initially, the
integrity management program can consist of a framework that describes
the process for implementing each program element, how relevant
decisions will be made and by whom, a time line for completing the work
to implement the program element, and how information gained from
experience will be continuously incorporated into the program. The
framework will evolve into a more detailed and comprehensive program.
An operator must make continual improvements to the program.
The rule requires an operator to follow ASME/ANSI B31.8S, and its
appendices, where specified, as well as the requirements in Subpart O
in implementing its integrity management program. ASME/ANSI B31.8S, the
Supplement to ASME/ANSI B31.8, is an industry consensus standard that
specifically addresses system integrity of gas pipelines. The rule
allows an operator to follow an equivalent standard or practice only
when the operator demonstrates the alternative standard or practice
provides an equivalent level of safety to the public and property. The
rule clarifies that in the event of a conflict between Subpart O and
ASME/ANSI B31.8S, the requirements in Subpart O control.
Section 192.909 How Can an Operator Change Its Integrity Management
Program?
The rule requires that prior to implementing any change to its
program, an operator must document the change and the reasons for the
change, and notify OPS within 30 days after the operator adopts the
change into its program. The notification is required for any change to
the program that--
[sbull] May substantially affect the program's implementation; or
[sbull] May significantly modify the program or schedule for
carrying out the program elements.
An operator must also notify a State or local pipeline safety
authority when a covered segment is located in a State where OPS has an
interstate agent agreement and a State or local pipeline safety
authority that regulates a covered pipeline segment within that State.
Section 192.911 What Are the Elements of an Integrity Management
Program?
The rule requires an operator to include certain minimum elements
in its integrity management program. Minimum elements are those listed
in the rule and when referenced in the rule those in the ASME/ANSI
B31.8S standard. The Supplement to ASME/ANSI B31.8 is an industry
standard that specifically addresses system integrity of gas pipelines.
The required program elements include:
[sbull] An identification of all high consequence areas.
[sbull] A baseline assessment plan. Requirements governing these
plans are in Sec. 192.919 and Sec. 192.921.
[sbull] An identification of threats to each covered pipeline
segment, which must include data integration and a risk assessment to
evaluate the failure likelihood of each covered segment. An operator
must use the threat identification and risk assessment to prioritize
covered segments for assessment (Sec. 192.917) and to evaluate the
merits of additional preventive and mitigative measures (Sec. 192.935)
for each covered segment.
[sbull] A direct assessment plan, if the operator is going to use
direct assessment. The plan must comply with Sec. 192.923, and
depending on the threat assessed, with Sec. 192.925 (external
corrosion), Sec. 192.927 (internal corrosion), or Sec. 192.929
(stress corrosion cracking).
[sbull] Provisions for remediating conditions found during an
integrity assessment. (Sec. 192.933.)
[sbull] A process for continual evaluation and assessment. (Sec.
192.937.)
[[Page 69803]]
[sbull] A plan for confirmatory direct assessment (Sec. 192.931)
if the operator plans to use this method for reassessment.
[sbull] Provisions for adding preventive and mitigative measures to
protect the high consequence area. (Sec. 192.935.)
[sbull] A performance plan as outlined in Section 9 of ASME/ANSI
B31.8S that includes the required performance measures in Sec.
192.943.
[sbull] Record keeping provisions (Sec. 192.947).
[sbull] A management of change process as outlined in Section 11 of
ASME/ANSI B31.8S.
[sbull] A quality assurance process as outlined in Section 12 of
ASME/ANSI B31.8S.
[sbull] A communication plan that includes the elements of Section
10 of ASME/ANSI B31.8S, and that includes procedures for addressing
safety concerns raised by (1) OPS; and (2) a State or local pipeline
safety authority when a covered segment is located in a State where OPS
has an interstate agent agreement. This process for addressing safety
concerns raised by interstate agents is a requirement imposed by
statute.
[sbull] Procedures for providing (when requested), by electronic or
other means, a copy of the operator's risk analysis or integrity
management program to OPS or to a State or local pipeline safety
authority when a covered segment is located in a State where OPS has an
interstate agent agreement. This requirement to provide the information
to an interstate agent is imposed by statute.
[sbull] Procedures for ensuring that each integrity assessment is
being conducted in a manner that minimizes environmental and safety
risks.
[sbull] A process for identification and assessment of newly-
identified high consequence areas.(Sec. 192.905 and Sec. 192.921)
Section 192.913 When May an Operator Deviate Its Program From Certain
Requirements of This Subpart and Use a Performance-Based Option?
ASME/ANSI B31.8S allows an operator to deviate from some specific
provisions of the standard if the operator has a mature integrity
management program that addresses the intent of those provisions in a
different manner. This is called a performance-based program, as
compared to a prescriptive program (i.e., one meeting the literal
provisions of the standard). The rule describes the essential features
of a performance-based or a prescriptive integrity management program.
The rule allows an operator to deviate from certain integrity
management program requirements if it has a performance-based program
that has demonstrated exceptional performance.
To qualify for exceptional performance an operator must--
[sbull] Have completed at least two integrity assessments of all
covered pipeline segments.
[sbull] Be able to demonstrate that each assessment effectively
addressed the identified threats on the covered segments.
[sbull] Remediate all anomalies identified in the more recent
assessment according to the remediation requirements in the rule. The
remediation requirements are set forth in Sec. 192.933.
[sbull] Incorporate the results and lessons learned from the more
recent assessment into the operator's data integration and risk
assessment.
[sbull] Have a performance-based integrity management program that
meets or exceeds the performance-based requirements of ASME/ANSI
B31.8S, and includes certain minimum elements. The minimum elements
are: (1) A comprehensive process for risk analysis; (2) all risk factor
data used to support the program; (3) A comprehensive data integration
process; (4) A procedure for applying lessons learned from assessment
of covered pipeline segments to non covered pipeline segments. A
covered segment is one within the scope of Subpart O; (5) A procedure
for evaluating incidents within the operator's sector of the pipeline
industry for implications both to the operator's pipeline system and to
the operator's integrity management program; (6) A performance matrix
that demonstrates the program has been effective in ensuring the
integrity of the covered segments by controlling the identified threats
to the covered segments; (7) Semi-annual performance measures beyond
those required in Sec. 192.943 that are part of the operator's
performance plan (see Sec. 192.911(i)); and (8) An analysis that
supports the desired integrity reassessment interval and the
remediation methods to be used for all covered segments.
Once an operator has demonstrated that it has satisfied the
requirements for exceptional performance, the operator may deviate from
the prescriptive requirements of ASME/ANSI B31.8S and of Subpart O in
two instances:
[sbull] The time frame for reassessment as provided in Sec.
192.939 except that reassessment by an allowable method (e.g.,
confirmatory direct assessment) must be carried out at intervals no
longer than seven years; and
[sbull] The time frame for remediation as provided in Sec.
192.933, as long as the operator demonstrates that the revised time
frame will not jeopardize the safety of the covered segment.
Section 192.915 What Knowledge and Training Must Personnel Have To
Carry Out an Integrity Management Program?
The rule has requirements for supervisory personnel and for other
personnel with integrity management program functions. These
requirements apply to both personnel employed by the operator and
contractor personnel used to perform integrity management program
functions.
For supervisory personnel, the integrity management program must
provide that each supervisor whose responsibilities relate to the
integrity management program possesses and maintains a thorough
knowledge of the integrity management program and of the elements for
which he or she is responsible. The program must provide that any
person who qualifies as a supervisor for the integrity management
program has appropriate training or experience in the area for which
the person is responsible.
The integrity management program must provide criteria for the
qualification of any person
[sbull] Who conducts assessments;
[sbull] Who reviews and analyzes the results from an integrity
assessment; or
[sbull] Who makes decisions on actions to be taken based on these
assessments.
The program must also include criteria for the qualification of
persons
[sbull] Who implement preventive and mitigative measures to carry
out the requirements of the rule, including the marking and locating of
buried structures; or
[sbull] Who directly supervise excavation work carried out in
conjunction with an integrity assessment.
Section 192.917 How Does an Operator Identify Potential Threats to
Pipeline Integrity and Use the Threat Identification in Its Integrity
Program?
The rule requires that an operator's integrity management program
begin with an identification of the potential threats to which the
pipeline is subjected. The program then is constructed to deal with
those threats.
Threat identification. The rule requires an operator to identify
and evaluate all potential threats to each covered pipeline segment.
These potential threats include, but are not limited to:
[sbull] The threats listed in Section 2 of ASME/ANSI B31.8S and
[sbull] Time dependent threats such as internal corrosion, external
corrosion, and stress corrosion cracking;
[[Page 69804]]
[sbull] Static or resident threats, such as fabrication or
construction defects;
[sbull] Time independent threats such as third-party damage and
outside force damage; and
[sbull] Human error.
Data gathering and integration. The rule requires that to identify
and evaluate the potential threats to a covered pipeline segment, an
operator must gather and integrate data and information concerning the
entire pipeline that could be relevant to the covered segment. Section
4 of ASME/ANSI B31.8S provides requirements for performing this data
gathering and integration, and the operator must follow those
requirements. At a minimum, an operator has to gather and evaluate the
set of data specified in Appendix A to ASME/ANSI B31.8S, and consider
both on the covered segment and similar non-covered segments, past
incident history, corrosion control records, continuing surveillance
records, patrolling records, maintenance history, internal inspection
records and all other conditions specific to each pipeline.
Risk assessment. The rule requires an operator to conduct a risk
assessment that follows Section 5 of ASME/ANSI B31.8S and considers the
identified threats for each covered segment, and then use the risk
assessment to prioritize the covered segments for the baseline and
continual reassessments (Sec. Sec. 192.919, 192.921, 192.937), and to
determine what additional preventive and mitigative measures are needed
(Sec. 192.935).
On a plastic transmission pipeline, an operator has to conduct a
threat analysis to the covered segments by using data on threats unique
to plastic pipe, and information in Sections 4 and 5 of ASME/ANSI
B31.8S. A good source of data information may be found in plastic pipe
database collection (PPDC) with AGA.
Particular threats. The rule requires that an operator take
specific actions to address particular threats the operator has
identified. Those threats, and the required actions, are for third-
party damage, cyclic fatigue, manufacturing and construction defects,
ERW or lap welded pipe, and corrosion. These threats have been
identified for specific action because of their significance to
pipeline integrity and because the unique operational characteristics
of gas transmission pipelines dictate that they be treated uniquely.
The primary difference in the operation of gas transmission pipeline
related to these defects is the absence of significant pressure cycling
and the associated absence of the cyclic fatigue driving force for
crack growth. The absence of significant cyclic fatigue implies that
the failure of pipelines from these threats has unique causes that need
to be addressed in an integrity management program for gas transmission
pipelines.
An operator must utilize the required data integration and Appendix
A7 of ASME/ANSI B31.8S to determine the susceptibility of each covered
segment to the threat of third-party damage. If an operator identifies
the threat of third-party damage, the operator--
[sbull] Must implement comprehensive additional preventive measures
in accordance with Sec. 192.935 and monitor the effectiveness of the
preventive measures.
[sbull] If, in conducting a baseline assessment under Sec. 191.921
or a reassessment under Sec. 192.937, an operator uses an internal
inspection tool, such as a caliper, geometry or magnetic flux leakage
tool to address other identified threats on the covered segment, the
operator must integrate data from these tool runs with data related to
any encroachment or foreign pipeline crossing on the covered segment,
to define where potential indications of third-party damage may exist
in the covered segment.
[sbull] Have a procedure in its integrity management program
addressing actions it will take in response to findings from this data
integration.
The rule requires an operator to evaluate whether cyclic fatigue or
other loading conditions (including ground movement, suspension bridge
condition) could lead to a failure of a deformation, including a dent
or gouge, or other defect in the covered segment. The evaluation must
include an assumption that there are threats in the covered segment
that could be exacerbated by cyclic fatigue. An operator must use the
results from the evaluation together with the criteria used to evaluate
the significance of this threat to the covered segment and to
prioritize the integrity assessment.
The rule requires that if an operator identifies the threat of
manufacturing and construction defects (including seam defects) in the
covered segment, the operator must analyze the covered segment to
determine the risk of failure from these mechanisms. Manufacturing and
construction related defects are considered to be stable defects if the
operating conditions have not significantly changed since December 17,
1998, since successful operation demonstrates that the defects do not
threaten pipeline integrity. Changes in operating conditions, such as a
significant increase in pressure, could cause latent defects to grow.
Therefore, if the pipeline operating conditions change such that
operating pressure will be above the historic operating pressure, if
MAOP increases, or if stresses that could lead to cyclic fatigue
increase, the operator must treat the covered segment as a high-risk
segment.
If a covered pipeline segment contains low frequency electric
resistance welded pipe (ERW) or lap welded pipe that satisfies the
conditions specified in Appendix A4.3 and A4.4 of ASME/ANSI B31.8 S,
the rule requires an operator to select an assessment technology or
technologies capable of assessing seam integrity and of detecting seam
corrosion anomalies. The operator must prioritize the covered segment
as a high risk segment for the baseline assessment or reassessment. If
an operator finds corrosion on a covered pipeline segment that could
adversely affect the integrity of the pipeline; the operator has to
evaluate and remediate, as necessary, all pipeline segments (both
covered and non-covered) where similar corrosion might be found (i.e.,
with similar material coating and environmental characteristics). The
evaluation and remediation, if remediation is needed, must be completed
in a time frame consistent with the operator's operation and
maintenance procedures under part 192 for required testing and repair.
Section 192.919 What Must Be in the Baseline Assessment Plan?
Each operator's integrity management program must contain a
baseline assessment plan that has certain elements. These elements
are--
(a) Identification of the potential threats to each covered
pipeline segment and the information supporting the threat
identification. Requirements are in Sec. 192.917.
(b) The methods selected to assess the integrity of the line pipe,
including an explanation of why the assessment method was selected to
address the identified threats affecting each covered segment. The
methods allowed are listed in Sec. 192.921 and include internal
inspection, pressure test, direct assessment or alternative equivalent
technology. More than one method may be required to address all the
threats to the covered pipeline segment;
(c) A schedule for completing the integrity assessment of all
covered segments, including the risk factors considered in establishing
the assessment schedule;
(d) If an operator plans to use direct assessment, a direct
assessment plan that complies with the requirements in Sec. 192.923,
and depending on the threat
[[Page 69805]]
for which direct assessment is used, Sec. 192.925 (external
corrosion), Sec. 192.927 (internal corrosion), or Sec. 192.929
(stress corrosion cracking).
(e) A procedure to ensure that the baseline assessment is conducted
in a manner that minimizes environmental and safety risks.
Section 192.921 How Is the Baseline Assessment To Be Conducted?
The rule requires an operator assess the integrity of the line pipe
in each covered segment by using one or more of the allowable
assessment methods. An operator has to select the method or methods
best suited to address the threats identified for each covered segment.
Threat identification requirements are in Sec. 192.917. The methods
the rule allows are:
(1) Internal inspection tool or tools capable of detecting
corrosion, and any other threats to which the covered segment is
susceptible. An operator must follow Section 6.2 of ASME/ANSI B31.8S in
selecting the appropriate internal inspection tools for the covered
segment.
(2) Pressure test conducted in accordance with Subpart J of 49 CFR
Part 192;
(3) Direct assessment for the threats of external corrosion,
internal corrosion, and stress corrosion cracking. An operator must
conduct the direct assessment in accordance with the requirements
listed in Sec. 192.923 and with, as applicable, the requirements
specified in Sec. Sec. 192.925, 192.927 or 192.929. Requirements
depend on the threat the operator is using direct assessment to
address.
(4) Other technology that an operator demonstrates can provide an
equivalent understanding of the condition of the line pipe. An operator
intending to use other technology must notify the Office of Pipeline
Safety (OPS) in accordance with the notification requirements in Sec.
192.949, 180 days before conducting the assessment, so that OPS has an
opportunity to review those intentions.
The rule requires an operator to prioritize the covered pipeline
segments for the baseline assessment according to a risk analysis that
considers the potential threats identified for each covered segment.
The risk analysis must comply with the requirements in Sec. 192.917.
To choose an assessment method for the baseline assessment of each
covered segment, an operator must take the actions required to address
particular threats that it has identified. These actions are set forth
in Sec. 192.917.
The rule sets time periods for the baseline assessment. These time
periods were set by statute. The statute requires that the baseline be
completed not later than ten years after date of enactment (December
17, 2002) and at least 50% of the facilities assessed no later than
five years after date of enactment. Thus, the rule requires an operator
to assess at least 50% of the covered segments beginning with the
highest risk segments, by December 17, 2007, and complete the baseline
assessment of all covered segments by December 17, 2012.
The rule allows prior assessments conducted before the date the act
mandating integrity management programs for gas operators was signed
into law (December 17, 2002) to be used as baseline assessments. An
operator may use a prior integrity assessment as a baseline assessment
for the covered segment, if the integrity assessment meets the baseline
requirements in Subpart O and the operator has taken subsequent
remedial actions to address the conditions that are listed in Sec.
192.933. However, if an operator uses this prior assessment as its
baseline assessment, the operator must reassess the line pipe in the
covered segment according to the reassessment requirements of
Sec. Sec. 192.937and 192.939. The reassessment of the covered segment
must be done no later than December 17, 2009.
The rule requires that when an operator identifies a new high
consequence area, the baseline assessment of the line pipe in that area
be completed within 10 years from the date the area is identified.
On newly-installed pipe, a baseline assessment has to be done
within ten years from the date the pipe is installed. If a post-
installation pressure test has been conducted on the new pipe in
accordance with Subpart J, that pressure test satisfies the baseline
assessment requirement.
For plastic transmission pipelines an operator has to conduct a
baseline assessment of a covered segment if the operator has identified
a threat, other than third-party damage to the segment. The operator
will have to justify the assessment method the operator intends to use.
Section 192.923 How Is Direct Assessment Used and for What Threats?
The rule allows an operator to use direct assessment either as a
primary assessment method or as a supplement to the other assessment
methods allowed under this subpart. If used as the primary assessment
method, it can only be used to address the identified threats of
external corrosion (ECDA), internal corrosion (ICDA), or stress
corrosion cracking (SCCDA).
The rule requires an operator to have a direct assessment plan. The
requirements for the plan depend on the threat being addressed. If
addressing external corrosion, the plan must comply with the
requirements in Section 6.4 of ASME/ANSI B31.8S; NACE RP0502-2002; and
Sec. 192.925. If addressing internal corrosion, the plan must comply
with Section 6.4 and Appendix B2 of ASME/ANSI B31.8S, and Sec.
192.927. And if direct assessment is used to address stress corrosion
cracking, the plan must comply with Appendix A3 of ASME/ANSI B31.8S,
and Sec. 192.929.
If direct assessment is used as a supplemental assessment method
the plan must follow the requirements for confirmatory direct
assessment in Sec. 192.931.
Section 192.925 What Are the Requirements for Using External Corrosion
Direct Assessment (ECDA)?
This section specifies requirements an operator must follow in
using External Corrosion Direct Assessment (ECDA). The rule defines
ECDA as a four-step process that combines preassessment, indirect
inspections, direct examination, and post assessment to evaluate the
impact of external corrosion on the integrity of a pipeline.
The rule requires the operator to follow Section 6.4 of ASME/ANSI
B31.8S, and NACE RP 0502-2002. The Supplement to ASME/ANSI B31.8 is an
industry standard that specifically addresses system integrity of gas
pipelines. The NACE standard is an industry recommended practice that
addresses methodology for a pipeline external corrosion direct
assessment. The rule requires an operator's direct assessment plan to
have procedures addressing preassessment, indirect inspections, direct
examination, and post-assessment. For all four steps, the procedures
must provide for applying more restrictive criteria when conducting
ECDA for the first time on a covered segment.
The preassessment procedures must follow the requirements in
Section 6.4 of ASME/ANSI B31.8S and Section 3 of NACE RP 0502-2002, and
also include the basis on which the operator selects at least two
different, but complementary indirect assessment tools to assess each
ECDA Region. If an operator utilizes an indirect inspection method that
is not discussed in Appendix A of NACE RP0502-2002, the operator must
demonstrate the applicability, validation basis, equipment used,
application procedure and utilization of data for the inspection
method.
[[Page 69806]]
The plans procedures for indirect examination must follow the
requirements in Section 6.4 of ASME/ANSI B31.8S and Section 4 of NACE
RP0502-2002, and include criteria for:
[sbull] Identifying and documenting those indications that must be
considered for excavation and direct examination;
[sbull] For defining the urgency of excavation and direct
examination of each indication identified during the direct
examination; and
[sbull] For scheduling excavation of indications for each urgency
level.
The procedures for direct examination must follow the requirements
in Section 6.4 of ASME/ANSI B31.8S and Section 5 of NACE RP0502-2002,
and include criteria for:
[sbull] Deciding what action should be taken if either corrosion
defects are discovered that exceed allowable limits (Section 5.5.2.2 of
NACE RP0502-2002), or root cause analysis reveals conditions for which
ECDA is not suitable (Section 5.6.2 of NACE RP0502-2002);
[sbull] 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
[sbull] That describe how and on what basis an operator will relax
any of the criteria that NACE RP0502-2002 specifies can be relaxed.
The plan's procedures for post assessment of the effectiveness of
the ECDA process must follow the requirements in Section 6.4 of ASME/
ANSI B31.8S and Section 6 of NACE RP0502-2002, and also include
measures for evaluating the long-term effectiveness of ECDA in
addressing external corrosion in covered segments and criteria for
evaluating whether conditions discovered by direct examination of
indications in each ECDA region indicate a need for reassessment of the
covered segment at an interval less than that specified in Sec.
192.939. (Appendix D of NACE RP0502-2002 provides guidance for
performing this evaluation).
Section 192.927 What Are Requirements for Using Internal Corrosion
Direct Assessment (ICDA)?
This section specifies requirements an operator must follow in
using Internal Corrosion Direct Assessment (ICDA). An operator must
follow the requirements in Section 6.4 and Appendix B2 of ASME/ANSI
B31.8S, as well as those listed in this section. The ICDA process
described in this rule applies only for a segment of pipe transporting
nominally dry natural gas and not for a segment with electrolyte
nominally present in the gas stream. If an operator uses ICDA to assess
a covered segment operating with electrolyte present in the gas stream,
the operator must develop a plan that demonstrates how it will conduct
ICDA in the segment to effectively address internal corrosion.
The rule defines ICDA as a process an operator can use to identify
areas along the pipeline where fluid or other electrolyte that might be
introduced during normal operation or by an upset condition may reside.
ICDA then focuses direct examination on the locations in each area
where internal corrosion is most likely to exist. The process
identifies the potential for internal corrosion caused by
microorganisms, or fluid with CO2, O2, hydrogen
sulfide or other contaminants present in the gas.
The rule requires that an operator's ICDA plan must provide for
preassessment, identification of ICDA regions and excavation locations,
detailed examination of pipe at excavation locations, and post-
assessment evaluation and monitoring.
In the preassessment stage, an operator must gather and integrate
data and information needed to evaluate the feasibility of ICDA for the
covered segment, to identify the locations in the covered segment where
electrolyte may accumulate, to identify ICDA regions within the covered
segment, and to support the use of a model to identify areas within the
covered segment where liquids may potentially be entrained. This data
and information includes, but is not limited to--
[sbull] All data elements listed in Appendix A2 of ASME/ANSI
B31.8S.
[sbull] Information needed to support use of a model that an
operator must use to identify areas along the pipeline where internal
corrosion is most likely to occur. This information, includes, but is
not limited to, location of all gas input and withdrawal points on the
pipeline; location of all low points on covered segments such as sags,
drips, inclines, valves, manifolds, dead-legs, and traps; the elevation
profile of the pipeline in sufficient detail that angles of inclination
can be calculated for all pipe segments; and the diameter of the
pipeline, and the range of expected gas velocities in the pipeline.
[sbull] Operating experience data that would indicate historic
upsets in gas conditions, locations where these upsets have occurred,
and potential damage resulting from these upset conditions.
[sbull] Identification of covered segments where cleaning pigs may
not have been used or where cleaning pigs may deposit electrolytes.
The plan must define all ICDA Regions within each covered pipeline
segment. An ICDA region extends from the location where liquid may
first enter the pipeline and encompasses the entire area along the
pipeline where internal corrosion may occur and where further
evaluation is needed. In the identification process, an operator must
use the model in GRI 02-0057 ``Internal Corrosion Direct Assessment of
Gas Transmission Pipelines--Methodology'' or an equivalent model if the
operator demonstrates it is equivalent to the GRI model. A model must
consider changes in pipe diameter, locations where gas enters a
pipeline (potential to introduce liquid) and locations downstream of
gas draw-offs (where gas velocity is reduced) to define the critical
pipe angle of inclination above which water film cannot be transported
by the gas.
An operator's plan must identify the locations where internal
corrosion is most likely in each ICDA region. In the location
identification process, an operator must identify a minimum of two
locations for excavation within each ICDA Region and must perform a
direct examination for internal corrosion at each location, using
ultrasonic thickness measurements, radiography, or other generally
accepted measurement techniques. One location must be the low point
(e.g., sags, drips, valves, manifolds, dead-legs, traps) nearest to the
beginning of the ICDA Region, and the second must be at the upstream
end of the pipe containing a covered segment, having a slope not
exceeding the critical angle of inclination nearest the end of the ICDA
Region. If corrosion exists at either location, the operator must
evaluate the severity of the defect (remaining strength) and remediate
the defect in accordance with Sec. 192.933; as part of the operator's
current integrity assessment either perform additional excavations in
covered segments within the ICDA region or use an alternative allowed
assessment method to assess the line pipe in the covered segment for
internal corrosion; and evaluate the potential for internal corrosion
in all pipeline segments (both covered and non-covered) in the
operator's pipeline system with similar characteristics to the covered
segment in which the corrosion was found, and as appropriate, remediate
the conditions the operator finds in accordance with Sec. 192.933.
An operator's plan must provide for evaluating the effectiveness of
the ICDA process and continued monitoring of covered segments where
internal corrosion has been identified. The evaluation and monitoring
process includes:
[[Page 69807]]
[sbull] Evaluating the effectiveness of ICDA as an assessment
method for addressing internal corrosion and determining whether a
covered segment should be reassessed at more frequent intervals than
those specified in Sec. 192.939. This evaluation must be carried out
in the same year in which ICDA used.
[sbull] Continually monitoring each covered segment where internal
corrosion has been identified using techniques such as coupons, UT
sensors or electronic probes, periodically drawing off liquids at low
points and chemically analyzing the liquids for the presence of
corrosion products. An operator must base the frequency of the
monitoring and liquid analysis on results from all integrity
assessments that have been conducted in accordance with the integrity
management program rule, and risk factors specific to the covered
segment. If an operator finds any evidence of corrosion products in the
covered segment, the operator must take one of two required actions and
remediate the conditions the operator finds in accordance with Sec.
192.933. These actions are to conduct excavations of covered segments
at locations downstream from where the electrolyte might have entered
the pipe, or to assess the covered segment using another integrity
assessment method allowed by this subpart.
The ICDA plan must also include criteria an operator will apply in
making key decisions (e.g., ICDA feasibility, definition of ICDA
Regions, conditions requiring excavation) in implementing each stage of
the ICDA process, and provisions for applying more restrictive criteria
when conducting ICDA for the first time on a covered segment and that
become less stringent as the operator gains experience and for carrying
out an analysis on the entire pipeline in which covered segments are
present, but limiting excavation and remediation to the covered
segments.
Section 192.929 What Are the Requirements for Using Direct Assessment
for Stress Corrosion Cracking (SCCDA)?
This section specifies requirements an operator must follow in
using direct assessment for stress corrosion cracking (SCCDA) which is
defined as a process to assess a covered pipe segment for the presence
of SCC primarily by systematically gathering and analyzing excavation
data for pipe having similar operational characteristics and residing
in a similar physical environment.
The rule provides that an operator's direct assessment plan to
identify this threat must at least provide for a systematic process to
collect and evaluate data for all covered segments to identify whether
the conditions for SCC are present and to prioritize the covered
segments for assessment. This process must include gathering and
evaluating data related to SCC at all excavated sites during conduct of
its operation where the criteria in Appendix A3.3 of ASME/ANSI B31.8S
indicate the potential for SCC. This data includes at minimum, the data
specified in Appendix A3 of ASME/ANSI B31.8S. The plan must further
provide that if conditions for SCC are identified in a covered segment,
the operator must assess the covered segment using an integrity
assessment method specified in Appendix A3 of ASME/ANSI B31.8S, and
remediate the threat in accordance with Appendix A3.4 of ASME/ANSI
B31.8S.
Section 192.931 How May Confirmatory Direct Assessment (CDA) Be Used?
Confirmatory direct assessment (CDA) is used where external or
internal corrosion is the threat of concern to the covered segment. An
operator is allowed to use CDA as a method to reassess the line pipe in
a covered segment at seven-year intervals. The rule provides that an
operator's CDA plan for identifying external corrosion must comply with
the requirements for external corrosion direct assessment in Sec.
192.925 with the following exceptions.
[sbull] The procedures for indirect examination may allow for use
of only one indirect examination tool suitable for the application.
[sbull] The procedures for direct examination and remediation must
provide that all immediate action indications must be excavated for
each ECDA region and that at least one high risk indication that meets
the criteria of scheduled action must be excavated in each ECDA region.
An operator's CDA plan identifying internal corrosion must comply
with the requirements for internal corrosion direct assessment in Sec.
197.927 except that the plan's procedures for identifying locations for
excavation may require excavation of only one high risk location in
each ICDA region.
The premise behind CDA is that it is used to confirm the acceptable
integrity of a pipeline, already ensured by assessments in accordance
with ASME/ANSI B31.8S. If confirmation is not successful, i.e., if
problems are found, then an operator needs to take additional actions.
If an assessment carried out using CDA reveals defects requiring
remediation prior to the next scheduled assessment, the operator must
schedule the next assessment at a time defined by the requirements in
Section 6.2 and 6.3 of NACE RP 0502-2002. If the defect requires
immediate remediation, then the operator must reduce pressure
consistent with Sec. 192.933 until it has completed reassessment using
one of the assessment techniques allowed in Sec. 192.937.
Section 192.933 What Actions Must Be Taken To Address Integrity Issues?
The rule requires an operator to take prompt action to address all
anomalous conditions that the operator discovers through the integrity
assessment. In addressing all conditions, an operator must evaluate all
anomalous conditions and must remediate those that could reduce a
pipeline's integrity. An operator must be able to demonstrate that the
remediation of the condition will ensure that the condition is unlikely
to pose a threat to the integrity of the pipeline until the next
reassessment of the covered segment. The rule gives an operator an
option if it is unable to respond within the specified time limits for
certain conditions. The operator can either temporarily reduce the
operating pressure of the pipeline or take other action that ensures
the safety of the covered segment. If pressure is reduced, an operator
must determine the temporary reduction in operating pressure of the
pipeline using ASME/ANSI B31G or RSTRENG or the operator must reduce
the operating pressure to a level not exceeding 80% of the level at the
time the condition was discovered. A reduction in operating pressure
cannot exceed 365 days without an operator providing a technical
justification that the continued pressure restriction will not
jeopardize the integrity of the pipeline.
Discovery of condition. It is important to know when a condition
has been ``discovered'', because the time periods for remediation begin
upon discovery. The rule provides that discovery of a condition occurs
when an operator has adequate information about the condition to
determine that it presents a potential threat to the integrity of the
pipeline. An operator must promptly, but no later than 180 days after
conducting an integrity assessment, obtain sufficient information about
a condition to make that determination, unless the operator
demonstrates that the 180-day period is impracticable.
Schedule for evaluation and remediation. The rule provides that an
operator complete remediation of a condition according to a schedule
that prioritizes the conditions for evaluation and remediation. Unless
a special
[[Page 69808]]
requirement for remediating certain conditions applies (these are
listed in the rule as immediate repair, one-year and monitored
conditions), an operator must follow the schedule in Section 7, Figure
4 of ASME/ANSI B31.8S. If an operator cannot meet the schedule for any
condition, the operator must justify the reasons why it cannot meet the
schedule and that the changed schedule will not jeopardize public
safety. An operator must notify OPS if it cannot meet the schedule and
cannot provide safety through a temporary reduction in operating
pressure or other action. An operator must also notify a State or local
pipeline safety authority when a covered segment is located in a State
where OPS has an interstate agent agreement, and a State or local
pipeline safety authority that regulates a covered pipeline segment
within that State.
Special requirements for scheduling remediation. The rule lists
immediate repair conditions, one-year conditions and monitored
conditions. If a condition is an immediate repair condition, the
operator must either temporarily reduce operating pressure or shut down
the pipeline until the repair is completed. The one-year period begins
from when the condition is discovered. Certain dents on the top of the
pipe are listed as one-year conditions. Monitored conditions are those
that an operator must record and monitor during subsequent risk
assessments and integrity assessments for any change that may require
remediation.
Section 192.935 What Additional Preventive and Mitigative Measures Must
An Operator Take To Protect the High Consequence Area?
The requirements in this section apply to all gas transmission
pipelines, including plastic gas transmission pipelines. The rule
requires an operator to take additional measures beyond those already
required in Part 192 to prevent a pipeline failure and to mitigate the
consequences of a pipeline failure in a high consequence area. An
operator must base the additional measures on the threats the operator
has identified to each pipeline segment. (Threat identification is in
Sec. 192.917.) The rule requires an operator to conduct, in accordance
with one of the risk assessment approaches in Section 5 of ASME/ANSI
B31.8S, a risk analysis of its pipeline to identify additional measures
to protect the high consequence area and enhance public safety.
Examples of additional measures listed in the rule are: installing
Automatic Shut-off Valves or Remote Control Valves, installing
computerized monitoring and leak detection systems, replacing pipe
segments with pipe of heavier wall thickness, providing additional
training to personnel on response procedures, conducting drills with
local emergency responders and implementing additional inspection and
maintenance programs. These are not the only measures an operator
should consider or use.
The rule requires an operator to enhance its current damage
prevention program required under Sec. 192.614 with respect to a
covered segment to prevent and minimize the consequences of a release
due to third-party or outside force damage. The rule lists examples of
enhanced damage prevention program measures. These are the minimum
actions an operator can take to enhance its current program.
[sbull] Using qualified personnel for work an operator is
conducting that could adversely affect the integrity of a covered
segment, such as marking, locating, and direct supervision of known
excavation work.
[sbull] Collecting in a central database information that is
location specific on excavation damage that occurs in covered and non-
covered segments in the transmission system and the root cause analysis
to support identification of targeted additional preventative and
mitigative measures in the high consequence areas. This information
must include recognized damage that is not required to be reported as
an incident under Part 191.
[sbull] Participating in one-call systems in locations where
covered segments are present.
[sbull] Monitoring of excavations conducted on covered pipeline
segments by pipeline personnel. When there is physical evidence of
encroachment involving excavation near a covered segment, an operator
must either excavate the area near the encroachment or conduct an above
ground survey using methods defined in NACE RP-0502-2002. An operator
must excavate, and remediate, in accordance with ASME/ANSI B31.8S and
Sec. 192.933 any indication of coating holidays or discontinuity
warranting direct examination.
If an operator determines that outside force, such as earth
movement, floods, or an unstable suspension bridge, is a threat to the
integrity of a covered segment, the rule requires the operator to take
measures to minimize the consequences to covered segments from outside
force damage. The minimum measures an operator can take are: increasing
the frequency of aerial, foot or other methods of patrols, adding
external protection, reducing external stress, and relocating the
pipeline.
The requirements for third-party damage and outside force damage
also apply to plastic transmission pipelines.
The rule allows that there may be limited instances in which an
operator will determine that installing an automatic shut off or remote
control valve is necessary. The rule provides that if an operator
determines, based on a risk analysis, that such a valve would be an
efficient means of adding protection to a high consequence area in the
event of a gas release, an operator must install the valve. In making
that determination, an operator must, at least, consider the swiftness
of leak detection and pipe shutdown capabilities, the type of gas being
transported, operating pressure, the rate of potential release,
pipeline profile, the potential for ignition, and location of nearest
response personnel.
Because under the revised definition of a high consequence area,
some low-stress pipelines may not be in a high consequence area,
although the pipeline is in a populated area, the rule adds additional
requirements for these pipelines. Thus, if a transmission pipeline
operates below 30% SMYS and is located in a Class 3 or 4 area but not
in a high consequence area, an operator must apply the enhanced third-
party damage prevention requirements for using qualified personnel and
participating on one-call centers to the pipeline and either monitor
excavations near the pipeline, or conduct patrols of the pipeline at
bi-monthly intervals. If an operator finds any indication of unreported
construction activity, the operator must conduct a follow up
investigation to determine if mechanical damage has occurred.
Section 192.937 What Is a Continual Process of Evaluation and
Assessment To Maintain a Pipeline's Integrity?
After completing the baseline integrity assessment of a covered
segment, the rule provides that an operator must continue to assess the
line pipe of that segment at specified intervals (in Sec. 192.939) and
to periodically evaluate the integrity of each covered pipeline
segment. If an operator had used a prior assessment as the baseline
assessment, the reassessment must be done by no later than December 17,
2009. If a prior assessment is not used as the baseline, a reassessment
of a covered segment must be done by no later than seven years after
the baseline assessment of that covered segment unless the periodic
evaluation indicates earlier reassessment.
The rule requires a periodic evaluation as frequently as needed to
[[Page 69809]]
ensure the integrity of each covered segment. The periodic evaluation
must be based on a data integration and risk assessment of the entire
pipeline. The data integration and risk assessment requirements are in
Sec. 192.917. For plastic transmission pipelines, the periodic
evaluation is based on the threat analysis specified in Sec.
192.917(d) considering the data on unique threats to a plastic
pipeline. For all other transmission pipelines, the evaluation must
consider the past and present integrity assessment results, data
integration and risk assessment information, and decisions about
remediation (Sec. 192.933) and additional preventive and mitigative
actions (Sec. 192.935). An operator must use the results from this
evaluation to identify the threats specific to each covered segment and
the risk represented by these threats.
The rule allows several assessment methods for a reassessment. In
conducting the integrity reassessment, an operator must assess the
integrity of the line pipe in the covered segment by any of the
following methods as appropriate for the threats to which the covered
segment is susceptible (see Sec. 192.917), or by confirmatory direct
assessment under the conditions specified in Sec. 192.931. The methods
allowed for reassessment are--
[sbull] Internal inspection tool or tools capable of detecting
corrosion, and any other threats to which the covered segment is
susceptible. An operator must follow Section 6.2 of ASME/ANSI B31.8S in
selecting the appropriate internal inspection tools for the covered
segment.
[sbull] Pressure test conducted in accordance with Subpart J;
[sbull] Direct assessment to address threats of external corrosion
and internal corrosion or stress corrosion cracking. An operator must
conduct the direct assessment in accordance with the requirements
listed in Sec. 192.923 and with as applicable, the requirements
specified in Sec. Sec. 192.925 (external corrosion), 192.927 (internal
corrosion) or 192.929 (stress corrosion cracking);
[sbull] Other technology that an operator demonstrates can provide
an equivalent understanding of the condition of the line pipe. An
operator choosing this option must notify the Office of Pipeline Safety
(OPS) 180 days before conducting the assessment.
[sbull] Confirmatory direct assessment when used on a covered
segment that is scheduled for reassessment at a period longer than
seven years. An operator using this reassessment method must comply
with Sec. 192.931.
Section 192.939 What Are the Required Reassessment Intervals?
The required reassessment interval depends on the assessment method
and the operating pressure of the pipeline. Some form of reassessment
must be done at least every seven years.
For pipelines operating at or above 30% SMYS, the rule allows
reassessment by--
1. Pressure test or internal inspection, or other equivalent
technology. An operator that uses pressure testing or internal
inspection as an assessment method must establish the reassessment
interval for a covered pipeline segment by--
[sbull] Basing the intervals on the identified threats for the
segment as listed in Sec. 192.915 of this section and in Section 8,
Tables 6 and 7 of ASME/ANSI B31.8S, and on the analysis of the results
from the last integrity assessment and from the data integration and
risk assessment required by Sec. 192.911; or
[sbull] Using the intervals for different stress levels of pipeline
specified in Table 3, Section 5 of ASME/ANSI B31.8S.
2. External Corrosion Direct assessment. An operator that uses
external corrosion direct assessment must determine the reassessment
interval according to the requirements in paragraphs 6.2 and 6.3 of
NACE RP0502-2002.
3. Internal Corrosion or SCC Direct Assessment. An operator that
uses ICDA or SCCDA must determine the reassessment interval by
determining the largest defect most likely to remain in the covered
segment and the corrosion rate appropriate for the pipe, soil and
protection conditions, taking the largest remaining defect as the size
of the largest defect discovered in the SCC or ICDA segment and
estimating the reassessment interval as half the time required for the
largest defect to grow to a critical size. However, the reassessment
interval cannot exceed those specified for direct assessment in Table
3, Section 5 of ASME/ANSI B31.8S.
If using one of these allowable methods, an operator establishes a
reassessment interval that is greater than seven years, the operator
must within the seven-year period, conduct a confirmatory direct
assessment on the covered segment, and then conduct the follow-up
reassessment at the interval the operator has established. A
reassessment done by confirmatory direct assessment must follow the
requirements in Sec. 192.931.
For pipelines operating below 30% SMYS the rule allows reassessment
by--
1. Pressure test, internal inspection or other equivalent
technology following the requirements for pipelines operating above 30%
SMYS, except that the stress level would be adjusted to reflect the low
operating stress level. If an established interval is more than seven
years, the operator must conduct by the seventh year of the interval
either a confirmatory direct assessment in accordance with Sec.
192.931, or a low-stress reassessment in accordance with Sec. 192.941.
2. External Corrosion Direct assessment following the requirements
described for pipelines operating above 30% SMYS.
3. Internal Corrosion or SCC Direct Assessment following the
requirements described for higher stress pipelines.
4. Confirmatory direct assessment at seven-year intervals in
accordance with Sec. 192.931, with reassessment by one of the other
allowed methods (pressure test, internal inspection or direct
assessment) by year 20 of the interval.
5. Low-stress assessment method at seven-year intervals in
accordance with Sec. 192.941 with reassessment by one of the other
allowed methods (pressure test, internal inspection or direct
assessment) by year 20 of the interval.
Section 192.941 What Is a Low-Stress Reassessment?
The rule provides for a low-stress reassessment for transmission
pipelines that operate below 30% SMYS. This reassessment addresses the
threats that are more common to these low-stress pipelines. The low-
stress method only applies to a reassessment.
To address the threat of external corrosion on cathodically
protected pipe in a covered segment, an operator must--
[sbull] Perform an electrical survey (i.e., indirect examination
tool/method) at least every seven years on the covered segment.
[sbull] Use the results of each survey as part of an overall
evaluation of the cathodic protection and corrosion threat for the
covered segment. This evaluation must consider, at minimum, the leak
repair and inspection records, corrosion monitoring records, exposed
pipe inspection records, and the pipeline environment.
If an electrical survey is impractical on the covered segment an
operator must instead
[sbull] Conduct leakage surveys at 4-month intervals; and
[sbull] Every 1\1/2\ years, identify and remediate areas of active
corrosion by evaluating leak repair and inspection records, corrosion
monitoring records,
[[Page 69810]]
exposed pipe inspection records, and the pipeline environment.
To address the threat of internal corrosion on a covered segment,
an operator must--
[sbull] Conduct a gas analysis for corrosive agents at least once
each calendar year;
[sbull] Conduct periodic testing of fluids removed from the
segment. At least once each calendar year test the fluids removed from
each storage field that may affect a covered segment; and
[sbull] At least every seven years, integrate data from this
analysis and testing with applicable internal corrosion leak records,
incident reports, safety-related condition reports, repair records,
patrol records, exposed pipe reports, and test records, and define and
implement appropriate remediation actions.
Section 192.943 When Can an Operator Deviate From These Reassessment
Intervals?
The rule provides for a waiver from the reassessment intervals in
two limited instances. In either instance the waiver has to be done in
accordance with 49 U.S.C. 60118(c), which requires public notice and
comment, and OPS has to find that the waiver would not be inconsistent
with pipeline safety. The rule requires an operator to apply for a
waiver at least 180 days before the end of the required reassessment
interval, unless local product supply issues make that period
impractical. The two instances when an operator may apply for a waiver
are--
1. Lack of internal inspection tools.
In this instance an operator who uses internal inspection as an
assessment method may be able to justify a longer assessment period for
a covered segment if internal inspection tools are not available to
assess the line pipe. To justify this, the operator must demonstrate
that it cannot obtain the internal inspection tools within the required
assessment period and that the actions the operator is taking in the
interim ensure the integrity of the covered segment.
2. To maintain product supply.
An operator may be able to justify a longer reassessment period for
a covered segment if the operator demonstrates that it cannot maintain
local product supply if it conducts the reassessment within the
required interval.
Section 192.945 What Methods Must an Operator Use To Measure Program
Effectiveness?
The rule requires an operator have performance measures to measure,
on a semi-annual basis, whether the program is effective in assessing
and evaluating the integrity of each pipeline segment and in protecting
the HCAs. These measures must include the four overall performance
measures specified in Section 9.4 of ASME/ANSI B31.8S and the specific
measures for each identified threat specified in Appendix A of ASME/
ANSI B31.8S. An operator must submit the four overall performance
measures electronically on a semi-annual frequency to OPS.
In addition to the general requirements for performance measures
the rule requires that if an operator uses direct assessment to assess
the external corrosion threat, the operator must also must define and
monitor measures to determine the effectiveness of the ECDA process.
These measures must meet the external corrosion direct assessment
requirements in Sec. 192.925.
Section 192.947 What Records Must an Operator Keep?
The rule provides that an operator must maintain, for the useful
life of the pipeline, records that demonstrate compliance with the
requirements of the integrity management program rule. This section
lists the minimum records an operator has to maintain for review during
an inspection.
Section 192.949 How Does an Operator Notify OPS?
For any of the required notification, the rule allows an operator
to submit the notification by one of three methods.
[sbull] Sending the notification by mail to the Information
Resources Manager, Office of Pipeline Safety, Research and Special
Programs Administration, U.S. Department of Transportation, Room 7128,
400 Seventh Street, SW, Washington DC 20590;
[sbull] Sending the notification by facsimile to (202) 366-7128; or
[sbull] Entering the information directly on the Integrity
Management Database (IMDB) Web site at http://primis.rspa.dot.gov/gasimp/
.
Section 192.951 Where Does an Operator File a Report?
The rule has certain reporting requirements. An operator must send
these reports to OPS by one of three methods.
[sbull] By mail to the Office of Pipeline Safety, Research and
Special Programs Administration, U.S. Department of Transportation,
Room 7128, 400 Seventh Street, SW, Washington, DC 20590;
[sbull] Via facsimile to (202) 366-7128; or
[sbull] Through the online reporting system provided by OPS for
electronic reporting available at the OPS Home Page at http://ops.dot.gov
.
This rule also adds a new Appendix E to Part 192, Guidance on
Determining High Consequence Areas, and on carrying out requirements in
the Integrity Management Rule. The guidance in the appendix describes
the process an operator must use to determine whether a pipeline
segment is in a high consequence area.
The new Appendix also provides guidance on alternative assessment
methods for transmission pipeline operating at below 30% SMYS. That
guidance is provided in the form of three tables:
--Table E.II.1 gives guidance to help an operator implement
requirements on assessment methods for addressing time dependent and
independent threats, for transmission pipelines operating below 30%
SMYS not in HCAs (i.e., outside of Potential Impact Circles) but
located within Class 3 and 4 locations.
--Table E.II.2 gives guidance to help an operator implement
requirements on assessment methods for addressing time dependent and
independent threats, for transmission pipelines operating below 30%
SMYS in HCAs.
--Table E.II.3 gives guidance on preventative & mitigative measures
addressing time dependent and independent threats for transmission
pipelines that operate below 30% SMYS, in HCAs.
Regulatory Analyses and Notices
Executive Order 12866 and DOT Regulatory Policies and Procedures
The Department of Transportation (DOT) considers this action to be
a significant regulatory action under section 3(f) of Executive Order
12866 (58 FR 51735; October 4,1993). Therefore, it was forwarded to the
Office of Management and Budget. This final rule is significant under
DOT's regulatory policies and procedures (44 FR 11034: February 26,
1979) because of its significant public and government interest.
A regulatory evaluation of this final rule on Integrity Management
for gas transmission pipelines has been prepared and placed in the
docket.
Cost-Benefit Analysis
A copy of the final regulatory evaluation has been placed in the
docket for this final rule. The following section summarizes the
regulatory evaluation's findings.
Natural and other gas pipeline ruptures can adversely affect human
health and property. However, the magnitude of this impact differs from
area to area. There are some areas in
[[Page 69811]]
which the impact of an accident will be more significant than it would
be in others due to greater concentrations of people who could be
affected. Because of the potential for dire consequences of pipeline
failures in certain areas, these areas merit a higher level of
protection. RSPA/OPS is requiring this regulation to afford the
necessary additional protection to these HCAs.
Numerous investigations by RSPA/OPS and NTSB have highlighted the
importance of protecting the public from pipeline failures. NTSB has
made several recommendations to ensure the integrity of pipelines near
populated areas. These recommendations included requiring periodic
testing and inspection to identify corrosion and other damage,
establishing criteria to determine appropriate intervals for
inspections and tests, determining hazards to public safety from
electric resistance welded pipe and requiring installation of automatic
or remotely-operated mainline valves on high-pressure pipelines to
provide for rapid shutdown of failed pipelines.
Congress also directed RSPA/OPS to undertake additional safety
measures in areas that are densely populated. These statutory
requirements included having RSPA/OPS prescribe standards for
identifying pipelines in high density population areas and issue
standards requiring periodic inspections. The Pipeline Safety
Improvement Act of 2002 requires that RSPA/OPS adopt regulations
requiring operators of gas transmission pipelines in HCAs to adopt
integrity management plans.
This final rulemaking addresses the target problem described above,
and is a comprehensive approach to certain NTSB recommendations and
Congressional mandates, as well as pipeline safety and environmental
issues raised over the years.
This final rule focuses on a systematic approach to integrity
management to reduce the potential for natural and other gas
transmission pipeline failures that could affect populated areas. This
final rulemaking requires pipeline operators to develop and follow an
integrity management program that continually assesses, through
internal inspection, pressure testing, direct assessment or equivalent
alternative technology, the integrity of those pipeline segments that
could affect areas we have defined as HCAs, i.e., areas with specified
population densities, buildings containing populations of limited
mobility, and areas where people gather, that occur along the route of
the pipeline. The program must also evaluate the segments through
comprehensive information analysis, remediate integrity problems and
provide additional protection through preventive and mitigative
measures.
This final rule (the fourth in a series of integrity management
program regulations) covers operators of transmission pipelines for
natural and other gases. RSPA/OPS chose to start the series with
hazardous liquid pipeline operators because the pipelines they operate
have the greatest potential to adversely affect the environment. This
final rule completes the application of integrity management to all
interstate (and many intrastate) pipelines.
Benefits
RSPA/OPS has made significant changes to the cost-benefit analysis
since the analysis prepared to support the proposed rule. Included in
these changes is full consideration of the impact of the Pipeline
Safety Improvement Act of 2002. The Act significantly changed the
regulatory environment in which the new rule will be implemented. The
Act requires that gas transmission pipeline operators develop integrity
management plans, perform risk analyses, and perform certain tests,
including tests at specified intervals. These requirements forever
change the regulatory landscape. The notice of proposed rulemaking was
issued in January, only one month after the Act was signed into law.
RSPA/OPS modified the notice to acknowledge that the law was passed and
that it imposed some requirements, but RSPA/OPS had not taken time to
analyze thoroughly the impacts the Act would have.
RSPA/OPS has since performed extensive analyses to consider the
impacts of the Act and to evaluate ways to make the rule more cost-
beneficial. RSPA/OPS has estimated the costs to implement the
requirements in the Act, without modification, to be approximately $11
billion over 20 years. By comparison, we conclude the cost of
implementing this rule will be $4.7 billion over the same period. The
difference reflects changes made in this rule in the definition of HCAs
(which will have the effect of reducing the amount of pipeline mileage
that must be tested) and provisions for limited scope reassessments
every seven years. The Act requires that pipelines be assessed every
seven years. The Act further requires that these assessments be
performed using one of three specified assessment methods or ``an
alternative method that the Secretary [of Transportation] determines
would provide an equal or greater level of safety.'' The alternative
methods included in this rule will reduce costs significantly over the
cost of performing periodic assessments using only the methods
specified in the Act. There is therefore a benefit in adopting this
rule of approximately $6.2 billion in cost reduction for assuring
pipeline integrity.
Benefits will also accrue in improved ability to site pipelines in
certain critical markets. It is difficult to quantify this benefit, but
RSPA/OPS believes it is real. Inability to site future pipelines could
affect the Nation's ability to use the increased quantities of natural
gas that the Energy Information Administration estimates will be needed
to fuel our economy over the next 20 years.
The Energy Information Administration (EIA), in its Annual Energy
Outlook 2003, estimates that total consumption of natural gas in the
United States was 22.64 trillion cubic feet in 2001. EIA's Outlook
projects, in its reference case, that this figure will grow to 32.14
trillion cubic feet by 2020. The EIA projection is for consumption of
34.59 trillion cubic feet by 2020 for its high economic growth
scenario. These figures represent an increase of 42 and 53 percent from
total 2001 consumption. Additional transmission pipeline capacity is
likely to be needed to support these estimates, and to deliver the gas
that the American economy will need in 2020. The increased public
confidence in pipeline safety that will result from this rule will make
it easier to site and construct this additional pipeline capacity. The
ability to build to support the need of the U.S. economy is a principal
benefit of this rule.
The rule will significantly reduce the likelihood of pipeline
accidents that result in deaths and serious injuries. Based on the
historical record, RSPA/OPS has estimated this benefit to be on the
order of $800 million over 20 years. It is quite likely, though, that
future accidents could be worse than the historical experience.
Population near pipelines is growing. This places more people at risk
than in the past. While some historical accidents have resulted in
several deaths and serious injuries, and significant property damage,
accidents with even greater consequences could occur. RSPA/OPS has
analyzed the likelihood that an accident could occur in an area along
the pipeline that is more densely populated. Even though the amount of
pipeline mileage along which such high population densities might be
found is small (RSPA/OPS estimated 0.1% of total mileage for this
analysis) the consequences of an accident are potentially large enough
that the averted costs are still high. RSPA/OPS estimates
[[Page 69812]]
that an additional $277 million is realized by avoiding the likelihood
of this more significant accident.
The rule will also result in avoiding significant costs associated
with unexpected interruptions in natural gas supply. The 2000 Carlsbad
accident resulted in curtailment of supply of natural gas to
California. RSPA/OPS estimates that this resulted in an impact on the
California economy of $17.25 million per day. The total benefit
afforded by this rule in avoiding future economic impacts of this type
is estimated to be $1 billion over the next 20 years.
Another benefit to be realized from implementing this rule is
reduced cost to the pipeline industry for assuring safety in areas
along pipelines with relatively more population. The improved knowledge
of pipeline integrity that will result from implementing this rule will
provide a technical basis for providing relief to operators from
current requirements to reduce operating stresses in pipelines when
population near them increases. Regulations currently require that
pipelines with higher local population density operate at lower
pressures. This is intended to provide an extra safety margin in those
areas. Operators typically replace pipeline when population increases,
because reducing pressure to reduce stresses reduces the ability of the
pipeline to carry gas. Areas with population growth typically require
more, not less, gas. Replacing pipeline, however, is very costly.
Providing safety assurance in another manner, such as by implementing
this rule, could allow RSPA/OPS to waive some pipe replacement. RSPA/
OPS estimates that such waivers could result in a reduction in costs to
industry of $1 billion over the next 20 years, with no reduction in
public safety.
Costs
Comments submitted in response to the draft regulatory analysis
pointed out that the costs to do much work associated with pipeline
integrity assessments, e.g., excavating pipe for direct examination,
are much higher in urban areas than they are in rural locations. The
comments suggested that use of a single set of unit costs (i.e., costs
per-mile) to represent all pipeline was unreasonable. RSPA/OPS accepts
that work in urban areas is more costly. In the final regulatory
analysis, RSPA/OPS has used different unit costs for work on long-
distance pipelines, traversing largely rural areas, and for shorter
transmission pipelines owned by gas distribution companies, which are
generally in urban areas. RSPA/OPS has relied on comments submitted by
INGAA, whose members consist of operators of long-distance pipelines,
and the American Gas Association (AGA) and American Public Gas
Association (APGA), whose members are gas distribution companies, for
the unit costs used in the final regulatory analysis.
RSPA/OPS analyzed two scenarios in the draft regulatory analysis,
varying the amount of pipeline that operators are expected to modify to
accommodate in-line inspection. This approach was taken, because of
industry comments that significant amounts of pipeline would likely be
modified and the costs for that work. Some pipe already can accommodate
in-line inspection tools. Some can be modified to accommodate the in-
line inspection tools with relatively simple modifications. Others
require much more extensive retrofits. RSPA/OPS was uncertain whether
operators would incur the significant costs to modify this ``hard-to-
pig'' pipeline or, instead, rely on direct assessment for those
pipeline segments. One of the analyzed scenarios assumed that only the
piping that can easily be modified would be changed. The other scenario
was based on the assumption that a portion of the pipe requiring more
extensive changes would also be modified.
Comments submitted in response to the draft regulatory analysis
strongly supported the premise that operators will modify much hard-to-
pig pipeline. Discussions at public meetings and at the Technical
Pipeline Safety Standards Committee indicated a strong preference for
pigging, and a full intent, on the part of the industry, to pursue that
approach in most cases. This is, in part, because pigging provides an
operator with much more information about the pipeline. Faced with
these comments, RSPA/OPS believes it would be unreasonable to continue
to analyze a scenario in which no hard-to-pig pipe is changed. As
demonstrated by the two scenarios considered in the draft regulatory
analysis, costs are much higher during the baseline assessment period
when hard-to-pig pipe is assumed to be modified.
Initial experience with direct assessment, however, indicates
higher costs for using this method than originally estimated, making
reassessment costs lower if a larger proportion of affected pipeline is
pigged. This adds an economic incentive to modify pipeline for pigging
and further supports eliminating the ``Limited Modification'' scenario.
We have estimated the cost for operators to identify pipeline
segments that can affect HCAs at approximately $15.05 million, the cost
to develop the necessary programs at approximately $104.13 million and
an annual cost for program upkeep and reporting of $12.91 million. An
operator's program begins with a baseline assessment plan and a
framework that addresses each required program element. The framework
indicates how decisions will be made to implement each element. As
decisions are made and operators evaluate the effectiveness of the
program in protecting HCAs, the program will be updated and improved,
as needed.
The final rule requires a baseline assessment of covered pipeline
segments through internal inspection, pressure test, direct assessment
or use of other technology capable of equivalent performance. The
baseline assessment must be completed within ten years after December
17, 2002 (the date the Pipeline Safety Improvement Act of 2002 was
signed into law), with at least 50% of covered segments being assessed
within five years.
After this baseline assessment, the rule further requires that an
operator periodically reassess and evaluate the pipeline segment to
ensure its integrity. The interval in which reassessments must be
performed varies with the operating stress levels in the pipe.
Pipelines operating at greater than 50 percent of specified minimum
yield strength (SMYS) must be reassessed at least every 10 years.
Pipelines operating between 30 and 50 percent SMYS must be reassessed
every fifteen-years. Pipelines operating below 30 percent SMYS require
reassessment on a twenty-year interval.
RSPA/OPS believes that the higher the operating pressure of a
pipeline, the greater the potential risk the pipeline poses to the
general public. That is because a failure of a pipeline operating at a
higher pressure will result in a larger impact area and potentially
more significant consequences. It is under this assumption that RSPA/
OPS has established the shortest assessments intervals for pipelines
that operate at or above pressures of 50 percent of SMYS. By basing the
assessment interval according to pipeline pressure, operators will have
to focus their safety resources on pipelines that pose the greatest
danger. RSPA/OPS believes that varying the assessment interval
according to the risk provides the greatest safety reward per dollar
operators will expend.
The Pipeline Safety Improvement Act of 2002 requires reassessment
of all pipelines in HCAs every seven years. To meet this requirement an
operator must conduct some assessment at that
[[Page 69813]]
frequency. The final rule provides a means to fulfill this requirement
at reduced burden, and lower financial impact. If an operator takes
advantage of the longer reassessment intervals provided in this final
rule, the rule requires that the operator conduct an interim
reassessment at least every seven years using a more focused direct
assessment (Confirmatory Direct Assessment) method.
Confirmatory direct assessment is a more focused application of the
principles and techniques of direct assessment, that is concentrated on
identifying critical segments of suspected corrosion and third-party
damage. RSPA/OPS has structured the requirements for confirmatory
direct assessment in a manner intended to allow maximum flexibility for
operators. Indirect examinations may be performed using only one,
rather than two, tools. Corrosion regions may be larger than for
regular direct assessments. The number of excavations required per
region is less. These changes will allow operators to plan and conduct
confirmatory direct assessments in a manner that is most cost-
effective, i.e., identifies areas of concern at lowest cost.
RSPA/OPS estimates that the cost of periodic reassessment will
generally not occur until the eighth year, unless the baseline
assessment indicates significant defects that would require earlier
reassessment. Operators must begin CDA interim assessments in the
eighth year. Additionally, some operators of higher-pressure pipelines,
who must perform regular reassessments in ten years, may elect to
perform those assessments at seven-year intervals instead of using CDA.
The cost-benefit analysis assumes that half of the affected pipeline
operating above 50 percent SMYS will be assessed using the higher-cost
methods every seven years.
The analysis of costs RSPA/OPS expects operators to incur in
implementing the rule results in an estimated annual cost of $262.1
million to conduct baseline testing. This includes the cost to modify
pipelines. All necessary modifications will be completed during the
baseline period, making annual costs for reassessments considerably
lower. Our analysis estimates that annual reassessment costs will be
approximately $50 million, varying slightly in different years
depending on which pipeline is due for reassessment.
Integrating information related to the pipeline's integrity is a
key element of the integrity management program. Costs will be incurred
to recover historical data about the pipeline and incorporate it in
modern data management systems that will allow it to be used more
readily. RSPA/OPS estimates that most of these costs will be incurred
in the first year after the effective date of the rule. Operators will
incur annual costs thereafter to incorporate new data, including the
results from assessments, and for integration and analysis by
knowledgeable pipeline safety professionals. RSPA/OPS estimated in the
draft regulatory analysis that the total costs for the information
integration requirements would be $31.5 million in the first year and
$15.75 million annually thereafter. Comments indicated that these
estimates, particularly for the first year, were very low. The
Interstate Natural Gas Association of America (INGAA) pointed out that
costs to gather old data, much of which is in paper records and not
easily retrieved, would be much higher. INGAA estimated that operators
would incur costs of $1,359 per mile for the initial data gathering and
setup and $113 per mile for annual updates and analysis. RSPA/OPS
accepts that costs to retrieve old data will be high, and that
estimating these costs on a per-mile basis is reasonable. RSPA/OPS has
adopted the INGAA-provided unit costs. Applying them results in an
estimated total cost for data integration of $387.3 million in the
first year and $32.21 million annually thereafter.
The final rule also requires operators to evaluate the risk of
pipeline segments that can affect HCAs to determine if additional
preventive or mitigative measures that would enhance public safety
should be implemented. One of the additional preventive or mitigative
actions that an operator can take is to install automatic shutoff
valves or remotely controlled valves. RSPA/OPS could not estimate the
total cost of installing such valves in response to this rule, because
there are too many factors that would have to be analyzed in order to
produce a valid estimate of how many operators will install them. RSPA/
OPS completed a generic study in 1999, however, in which we concluded
that conversion of existing sectional block valves to remote operation
was not economically feasible in most cases. Operator- and location-
specific factors could change this conclusion for individual valves but
RSPA/OPS could not analyze these specific factors for individual block
valves and therefore, did not estimate the total cost for installing
remote valves. RSPA/OPS presumes that operators will analyze valve-
specific factors and will not replace valves unless that action is
cost-beneficial. RSPA/OPS estimates that the cost to operators to
perform the required risk analyses will be approximately $11.5 million.
Consideration by Advisory Committee
RSPA/OPS discussed the final regulatory analysis with the Technical
Pipeline Safety Standards Committee (TPSSC) in a public teleconference
on July 31, 2003. The TPSSC, composed equally of representatives of
industry, government, and groups representative of public involvement
in pipeline safety issues, agreed that the analysis provides a basis to
justify proceeding with this rulemaking. The committee unanimously
concluded that the expected benefit in terms of improved public
confidence in pipeline safety is substantial and justifies the expected
costs.
Conclusions
RSPA/OPS concludes that the benefits are about the same as the
costs. Quantified benefits total $4.7 billion over the 20 years
analyzed. Costs over this same period are estimated to be $4.7 billion.
There are additional benefits for which it was difficult to estimate
monetary values. These include an improved basis for public confidence
in pipeline safety, with attendant improvements in the ability to site
new pipelines; reduced consequential damages from an unexpected
interruption of gas service, providing a technical basis that will
allow increases in pressure, and thus in delivery of gas, during future
energy emergencies; and providing incentives to foster additional
improvements in pipeline testing technology.
The estimated costs for implementing this rule are significant.
They need to be considered in the context of the size of the overall
U.S. market for natural gas. Energy Information Administration figures
show that total U.S. consumption of natural gas in 2001 amounted to
20,477,009 million cubic feet. Residential consumption was 4,716,186
million cubic feet. When the total estimated first-year costs for
implementing this rule are divided over these quantities, they result
in an increase in cost of 3.6 cents per thousand cubic feet. An average
residential consumer would see an increase of $3.07 per year if these
costs were passed on. This would mean an increase of 26 cents on an
average monthly bill, or a 0.39 percent rise.
RSPA/OPS considers these costs reasonable to realize the benefits
associated with this rule. Additionally, promulgating this rule will
result in savings of approximately $6.2 billion
[[Page 69814]]
over the expected costs to industry of complying with legislative
requirements absent this rule. Publishing this final rule, and
requiring that gas transmission pipeline operators comply, is clearly
the appropriate course of action.
Regulatory Flexibility Act
Under the Regulatory Flexibility Act, 5 U.S.C. 601 et seq., RSPA/
OPS must consider whether this rulemaking would have a significant
impact on a substantial number of small entities. RSPA/OPS in its draft
regulatory analysis used an estimate of 668 gas transmission operators
that could potentially be impacted by the gas integrity management
proposed rule. For the final regulatory evaluation RSPA/OPS performed
an extensive computer search of gas transmission operators and found
that many operators were in fact subsidiaries of large gas transmission
companies and that there are 275 gas transmission operators that could
potentially be impacted by this final rulemaking. A pipeline company
would be impacted if its pipeline could affect a high consequence area
(HCA). HCA's are located primarily urban areas but include rural areas
where more than 20 people congregate.
Of these 275 companies, approximately 35 could be considered small
companies. About 25 of these are municipally operated gas distribution
companies who also operate a transmission pipeline. The Small Business
Administration (SBA) had concerns with the regulatory flexibility
certification performed for the proposed gas integrity management
regulation. In discussions with SBA OPS suggested that it would contact
the American Public Gas Association (APGA) which is the trade
organization which represents municipal gas distribution companies
which make up the majority of the small entities among gas pipeline
operators. OPS has asked that APGA help to disseminate information on
rulemakings that could impact small pipeline operators. APGA has agreed
to perform this function. While OPS has in the past solicited comments
from small pipeline operators concerning potential impacts of pipeline
safety regulations few if any small pipeline operators have ever
submitted comments.
The Interstate Natural Gas Association of America (INGAA) estimates
that its members account for 80% of the gas pipeline transmission
mileage in the United States. INGAA has only 24 members however, 3 of
these members are not U.S. gas transmission operators. Therefore,
approximately 21 companies account for 80% of the U.S. gas transmission
pipeline mileage. The remainder of the pipeline companies in this
industry share only 20% of the total pipeline mileage.
The majority of the remaining 20% of transmission pipelines belong
to large gas distribution companies and large industrial companies. The
approximately 35 small entities own and operate very little mileage.
Because they operate such little mileage (in most cases less than 30
miles of pipeline), the compliance costs to these small entities if
they are impacted by this rule will be significantly lower than those
operators thousands of miles of pipeline as the costs of inspection and
planning should be considerably lower. Specifically, OPS has estimated
that the program planning and paperwork costs to operators with 30
miles or less of pipeline will be considerably less than for long
distance pipeline operators. If a small pipeline operator has for
example only 30 miles of pipeline it is likely that they will have only
a few miles of pipeline that will fall under this rule. If they choose
to perform direct assessment which the APGA has said is the likely
choice of their members the cost to inspect this will likely fall under
$100,000. On the other hand a large transmission operator performing
internal inspection on more than a thousand miles of pipeline is likely
to cost that operator several million dollars. RSPA/OPS believes that
this rule does not unduly burden small entities. Nevertheless, RSPA/OPS
stands ready to provide special help to any small operators to assist
them in complying with this final rule. Conversations with some small
transmission companies indicates that state pipeline offices have been
particularly effective in assisting small entities. Based on the above
discussion I certify that this final rule will not have a significant
impact on a substantial number of small entities.
Paperwork Reduction Act
This final rule contains information collection requirements. As
required by the Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)),
the Department of Transportation has submitted a copy of the Paperwork
Reduction Act analysis to the Office of Management and Budget for its
review. The name of the information collection is ``Pipeline Integrity
Management in HCAs Gas Transmission Pipeline Operators. OMB Control
Number 2137-0610'' The purpose of this information collection is
designed to require operators of gas transmission pipelines to develop
a program to provide direct integrity testing and evaluation of gas
transmission pipelines in HCAs.
The following is a summary of the highlights of the paperwork
reduction act analysis. The complete analysis can be found in the
public docket. The costs and hour burden is based on 275 companies with
a loaded labor cost of $60 per hour.
In the first year of promulgating this rule operators will have to
identify which segments are in HCAs. This will take 167 hours per
company plus 5 hours per impact circle. Impact circle is a measure of
how wide the HCAs will be. The total hours for the entire industry will
be 25,083 hours in the first year only.
The development of the integrity management plan will take 8333
hours for an operator with more than 30 miles of pipelines and 2,083
for operators with less than 30 miles of pipeline in the first year.
The time to update the plans annually will be 833 hours for operators
with more than 30 miles and 417 for operators with less than 30 miles.
The one time requirement to examine the need for remotely
controlled valves is estimated to take operators with more than 30
miles of pipeline 833 hours and 417 hours for operators with less than
30 miles of pipeline.
Additionally, all the operators will be required to integrate the
new data they collect into their current management systems. The time
to integrate the data the first year will be 22\1/3\ hours per mile and
1.9 hours per mile annually thereafter.
Additional paperwork and recordkeeping beyond those already
discussed, will add 833 hours in the first year for companies with more
than 30 miles of pipeline and 417 hours for operators with less than 30
miles of pipeline. In subsequent years this should add 83 hours of
paperwork burden for all operators.
The total initial time to perform all paperwork is 8,818,500
million hours at a cost of $529.1 million. The subsequent annual time
to update the paperwork is 752,000 hours costing $45.1 million dollars.
Comments concerning this information collection should include the
docket number of this rule. They should be sent within 30 days of the
publication of this notice directly to the Office of Management and
Budget, Office of Information and Regulatory Affairs, 726 Jackson
Place, NW., Washington, DC 20503, ATTN: Desk Officer for the Department
of Transportation (DOT).
Comments are specifically requested concerning:
[sbull] Whether the collection is necessary for the proper
performance of the functions of the Department, including
[[Page 69815]]
whether the information would have a practical use;
[sbull] The accuracy of the Department's estimate of the burden of
collection of information including the validity of assumptions used;
[sbull] The quality, usefulness and clarity of the information to
be collected; and minimizing the burden of collection of information on
those who are to respond, including through the use of appropriate
automated electronic, mechanical, or other technological collection
techniques or other forms of information technology e.g., permitting
electronic submission of responses.
According to the Paperwork Reduction Act of 1995, no persons are
required to respond to a collection of information unless a valid OMB
control number is displayed. The valid OMB control number for this
information collection will be published in the Federal Register after
it is approved by the OMB. For details see, the complete Paperwork
Reduction analysis available for copying and review in the public
docket.
Executive Order 13084
This final rule has been analyzed in accordance with the principles
and criteria contained in Executive Order 13084 (``Consultation and
Coordination with Indian Tribal Governments''). Because this final rule
does not significantly or uniquely affect the communities of the Indian
tribal governments and does not impose substantial direct compliance
costs, the funding and consultation requirements of Executive Order
13084 do not apply.
Executive Order 13132
This final rule has been analyzed in accordance with the principles
and criteria contained in Executive Order 13132 (``Federalism''). This
final rule does not have any requirement that:
(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 States and local
governments; or
(3) Preempts state law.
Therefore, the consultation and funding requirements of Executive
Order 13132 (64 FR 43255; August 10, 1999) do not apply. Nevertheless,
in November 18-19, 1999, and in February 12-14, 2001 public meetings,
RSPA/OPS invited National Association of Pipeline Safety
Representatives (NAPSR), which includes State pipeline safety
regulators, to participate in a general discussion on pipeline
integrity. Since then, RSPA/OPS has held conference calls with NAPSR,
to receive their input before proposing an HCA definition and integrity
management rule. RSPA/OPS has invited NAPSR representatives to all the
public meetings held subsequent to the publication of the pipeline
integrity management NPRM.
Executive Order 13211
This rulemaking is not a ``significant energy action'' within the
meaning of Executive Order 13211 (``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use''). It is a
significant regulatory action under Executive Order 12866 because of
its significant public and government interest. As concluded from our
Energy Impact Statement discussed in the following section, the
rulemaking 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.
Summary of the Energy Impact Statement
(For the detailed Energy Impact Statement, refer to Docket RSPA-00-
7666)
The Research and Special Program Administration's Office of
Pipeline Safety (RSPA/OPS) is currently promulgating regulations to
assess, evaluate, remediate, and validate the integrity of natural gas
transmission pipelines through comprehensive analysis and inspection of
pipeline systems. The current rule applies to all gas transmission
pipelines, including pipelines transporting petroleum gas, hydrogen,
and other gas products covered under 49 CFR Part 192.
In compliance with the Executive Order 13211 (66 FR 28355), the
RSPA/OPS has evaluated the effects of the natural gas IMP rule on
energy supply, distribution, or use. The RSPA/OPS has determined that
this regulatory action would not have significant adverse effects on
energy supply, distribution, or use nationally, however there may be
some regional effect on natural gas distribution.
The current rule will not have any significant impact on the
wellhead production capacity or prices. The rule affects natural gas
transmission pipelines in HCAs and has no effect on the wellhead
production capacity or prices. The rule does not impact gas gathering
pipelines and offshore gas transmission pipelines, and has limited
effect on the onshore gas transmission lines that are not located in
the HCAs. Therefore, the rule will have no significant impact on
natural gas production or wellhead prices. The RSPA/OPS estimates that
about 22,000 miles of gas transmission pipelines are located in the
HCAs in a network of 300,000 miles of gas transmission pipelines, as
well as 900,000 miles of gas distribution pipelines. Therefore, a
relatively small proportion of pipelines, less than 1 percent of the
total gas transmission pipelines, are located in the HCAs.
This rule may affect the movement of natural gas in certain areas
during integrity inspection. Inspection requirements may temporarily
affect transportation capacity in some pipelines, but not in all
pipelines. Built-in redundancies, such as loop lines, multiple lines,
storage facilities, are part of natural gas transportation
infrastructures. The intricate interconnections between pipelines, the
availability of storage at the market centers, and a well-developed
capacity release market all contribute towards meeting natural gas
demand with efficient movement of supply. Therefore, inspections can be
conducted without any significant disruption of throughput especially
during off-peak seasons.
This rule may not have any significant price effects on end-use
consumers. In general, inter-fuel competition and gas-storage
availability play significant roles in short-term price determination
in U.S. because of extensive fuel switching capability in industry and
power generation and the existence of a sizable storage capacity.
Weather is the other significant player determining the spot market
prices. Transportation cost only accounts for a small proportion of the
cost paid by the end-users. The pipeline capacity reduction due to the
integrity rule would be pre-planned and the market would have time to
adjust for the reduction, minimizing shortages and avoiding short-term
price increases. The RSPA/OPS recognizes that there may be some
temporary and regional natural gas price impact due to the increased
assessment and inspection requirements of the rule. While RSPA/OPS did
not estimate the size of such temporary impacts, it could lead to small
changes in natural gas prices for certain areas on the spot market if
the inspection coincides with peak season and there is no other
pipeline (no parallel, lateral, or loop lines) serving that particular
area. Recognizing the possibility of temporary spot price fluctuations
at the regional level, RSPA/OPS believes this regulation will not
significantly impact
[[Page 69816]]
the overall energy supply, distribution, and use.
Unfunded Mandates
This final rule does impose unfunded mandates under the Unfunded
Mandates Reform Act of 1995, because it may result in the expenditure
by the private sector of 100 million or more in any one year. The cost-
benefit analysis estimating yearly cost for operators to meet the final
rule requirements has been placed in the docket. State pipeline safety
programs will share inspection and enforcement responsibilities for the
integrity management regulation. State regulators have participated in
our meetings with the industry and research institutions on various
integrity management issue discussions and have provided
recommendations during our meetings and conference calls. State
pipeline safety officials have expressed concern that the rule is to be
sufficiently clear to enable them to enforce it and that there needs to
be training for state inspectors. The final rule has been significantly
modified to improve its clarity and enforceability and specific state
comments on these areas have been addressed in sections discussing the
changes. RSPA/OPS has planned an approach to enforcement that includes
the extensive use of protocols for inspectors (both Federal and State)
to use for compliance inspections and for training in the use of these
protocols. RSPA/OPS has included funding for training inspectors within
the budget for implementation of integrity management program. RSPA/OPS
does not charge states tuition for pipeline safety training. In
addition, 50 percent of a state's incidental costs of attending
training is reimbursable through the grants program. Similar training
is already underway regarding the integrity rule for hazardous liquid
pipelines. Local public safety officials will be asked, but not
required, to assist in identifying HCAs for the additional protections.
In addition, industry associations are planning workshops in the
development process to assist in identification of HCAs. We believe
there are no disproportionate budgetary effects upon any particular
region of the nation. We believe it is the least burdensome alternative
that achieves the objective of the rule, because it gives options to
industry on how to implement the rule.
National Environmental Policy Act
We have evaluated the final rule for purposes of the National
Environmental Policy Act (42 U.S.C. 4321 et seq.) and have concluded
that this action would not significantly affect the quality of the
environment. The Environmental Assessment determined that the combined
impacts of the baseline assessment (pressure testing, internal
inspection, or direct assessment), the periodic reassessments, and the
additional preventive and mitigative measures that may be implemented
for gas pipeline segments that could affect HCAs will result in
positive environmental impacts. The number of incidents and the
environmental damage from failures near HCAs is likely to be reduced.
However, from a national perspective, the impact is not expected to be
significant.
Although the effects of the final rule will likely lead to fewer
incidents, gas pipeline leaks that lead to adverse environmental
impacts are rare under current conditions. Although the damage from
failures could be reduced, the environmental damage resulting from gas
pipeline failures is usually minor under current conditions. The
effects are typically negligible, but can consist of localized,
temporary damage to the environment in the immediate vicinity of the
failure location on the pipeline.
Some operators covered by the final rule already have integrity
assessment programs. These operators typically consider the pipeline's
proximity to populated areas when making decisions about where and when
to inspect and test pipelines. As a result, some pipeline segments that
could impact high consequence areas have already been recently
assessed, and others would be assessed in the next several years
without the provisions of the final rule. The primary effect of the
final rule--accelerating integrity assessment in some high consequence
areas--shifts increased integrity assurance forward for a few years for
some segments that could affect high consequence areas. Because
pipeline failure rates are low, shifting the time at which these
segments are assessed forward by a few years has only a small effect on
the likelihood of pipeline failure in these locations.
The final rule does require operators to conduct an integrated
assessment of the potential threats to pipeline integrity, and to
consider additional preventive and mitigative risk control measures to
provide enhanced protection. If there is a vulnerability to a
particular failure cause, these assessments should result in additional
risk controls to address these threats. However, without knowing the
specific high consequence area locations, the specific risks present at
these locations, and the existing operator risk controls (including
those that surpass the current minimum regulatory requirements), it is
difficult to determine the impact of this requirement.
Some gas pipeline operators already perform integrity evaluations
or risk assessments that consider the environmental impacts. These
evaluations have already led to additional risk controls beyond
existing requirements to improve protection for these locations. For
many segments, it is probable that operators will determine that the
existing preventive and mitigative activities provide adequate
protection to high consequence areas, and that the small additional
risk reduction benefits of additional risk controls are not justified.
The primary benefit of the final rule will be to establish
requirements for conducting integrity assessments and periodic
evaluations of integrity of segments that could impact high consequence
areas. This will codify the integrity management programs and
assessments operators are currently implementing. It will also require
other operators, who have little, or no, integrity assessment and
evaluation programs to raise their level of performance. Thus, the
final rule is expected to ensure a more consistent, and overall higher
level of protection for high consequence areas across the industry.
The Environmental Assessment of this final rule is available for
review in the docket.
List of Subjects in 49 CFR Part 192
High consequence areas, Incorporation by reference, Integrity
management, Pipeline safety, Potential impact areas, Reporting and
recordkeeping requirements.
0
In consideration of the foregoing, RSPA/OPS is amending part 192 of
title 49 of the Code of Federal Regulations as follows:
PART 192--[AMENDED]
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.
Sec. 192.761 [Removed]
0
2. Section 192.761 is removed.
0
3. In part 192, under the heading of Pipeline Integrity Management, a
new subpart O is added to read as follows:
Subpart O--Pipeline Integrity Management
Sec.
192.901 What do the regulations in this subpart cover?
[[Page 69817]]
192.903 What definitions apply to this subpart?
192.905 How does an operator identify a high consequence area?
192.907 What must an operator do to implement this subpart?
192.909 How can an operator change its integrity management program?
192.911 What are the elements of an integrity management program?
192.913 When may an operator deviate its program from certain
requirements of this subpart?
192.915 What knowledge and training must personnel have to carry out
an integrity management program?
192.917 How does an operator identify potential threats to pipeline
integrity and use the threat identification in its integrity
program?
192.919 What must be in the baseline assessment plan?
192.921 How is the baseline assessment to be conducted?
192.923 How is direct assessment used and for what threats?
192.925 What are the requirements for using External Corrosion
Direct Assessment (ECDA)?
192.927 What are the requirements for using Internal Corrosion
Direct Assessment (ICDA)?
192.929 What are the requirements for using Direct Assessment for
Stress Corrosion Cracking (SCCDA)?
192.931 How may Confirmatory Direct Assessment (CDA) be used?
192.933 What actions must be taken to address integrity issues?
192.935 What additional preventive and mitigative measures must an
operator take to protect the high consequence area?
192.937 What is a continual process of evaluation and assessment to
maintain a pipeline's integrity?
192.939 What are the required reassessment intervals?
192.941 What is a low stress reassessment?
192.943 When can an operator deviate from these reassessment
intervals?
192.945 What methods must an operator use to measure program
effectiveness?
192.947 What records must an operator keep?
192.949 How does an operator notify OPS?
192.951 Where does an operator file a report?
Appendix A to Part 192--Incorporated by Reference
Appendix E to Part 192--Guidance on Determining High Consequence
Areas and on carrying out requirements in the Integrity Management
Rule
Subpart O--Pipeline Integrity Management
Sec. 192.901 What do the regulations in this subpart cover?
This subpart prescribes minimum requirements for an integrity
management program on any gas transmission pipeline covered under this
part. For gas transmission pipelines constructed of plastic, only the
requirements in Sec. Sec. 192.917, 192.921, 192.935 and 192.937 apply.
Sec. 192.903 What definitions apply to this subpart?
The following definitions apply to this subpart:
Assessment is the use of nondestructive testing techniques as
allowed in this subpart to ascertain the condition of a covered
pipeline segment.
Confirmatory direct assessment is an assessment method using more
focused application of the principles and techniques of direct
assessment to identify internal and external corrosion in a covered
transmission pipeline segment.
Covered segment or covered pipeline segment means a segment of gas
transmission pipeline located in a high consequence area. The terms gas
and transmission line are defined in Sec. 192.3.
Direct assessment is an integrity assessment method that utilizes a
process to evaluate certain threats (i.e., external corrosion, internal
corrosion and stress corrosion cracking) to a covered pipeline
segment's integrity. The process includes the gathering and integration
of risk factor data, indirect examination or analysis to identify areas
of suspected corrosion, direct examination of the pipeline in these
areas, and post assessment evaluation.
High consequence area means an area established by one of the
methods described in paragraphs (1) or (2) as follows:
(1) An area defined as--
(i) A Class 3 location under Sec. 192.5; or
(ii) A Class 4 location under Sec. 192.5; or
(iii) Any area outside a Class 3 or Class 4 location where the
potential impact radius is greater than 660 feet (200 meters), and the
area within a potential impact circle contains 20 or more buildings
intended for human occupancy; or
(iv) The area within a potential impact circle containing an
identified site.
(2) The area within a potential impact circle containing
(i) 20 or more buildings intended for human occupancy, unless the
exception in paragraph (d) applies; or
(ii) An identified site.
(3) Where a potential impact circle is calculated under either
method (1) or (2) to establish a high consequence area, the length of
the high consequence area extends axially along the length of the
pipeline from the outermost edge of the first potential impact circle
that contains either an identified site or 20 or more buildings
intended for human occupancy to the outermost edge of the last
contiguous potential impact circle that contains either an identified
site or 20 or more buildings intended for human occupancy. (See Figure
E.I.A. in appendix E.)
(4) If in identifying a high consequence area under paragraph
(1)(iii) of this definition or paragraph (2)(i) of this definition, the
radius of the potential impact circle is greater than 660 feet (200
meters), the operator may identify a high consequence area based on a
prorated number of buildings intended for human occupancy within a
distance 660 feet (200 meters) from the centerline of the pipeline
until December17, 2006. If an operator chooses this approach, the
operator must prorate the number of buildings intended for human
occupancy based on the ratio of an area with a radius of 660 feet (200
meters) to the area of the potential impact circle (i.e., the prorated
number of buildings intended for human occupancy is equal to [20 x (660
feet [or 200 meters ]/ potential impact radius in feet [or meters])
\2\]).
Identified site means each of the following areas:
(a) An outside area or open structure that is occupied by twenty
(20) or more persons on at least 50 days in any twelve (12)-month
period. (The days need not be consecutive.) Examples include but are
not limited to, beaches, playgrounds, recreational facilities, camping
grounds, outdoor theaters, stadiums, recreational areas near a body of
water, or areas outside a rural building such as a religious facility);
or
(b) A building that is occupied by twenty (20) or more persons on
at least five (5) days a week for ten (10) weeks in any twelve (12)-
month period. (The days and weeks need not be consecutive.) Examples
include, but are not limited to, religious facilities, office
buildings, community centers, general stores, 4-H facilities, or roller
skating rinks); or
(c) A facility occupied by persons who are confined, are of
impaired mobility, or would be difficult to evacuate. Examples include
but are not limited to hospitals, prisons, schools, day-care
facilities, retirement facilities or assisted-living facilities.
Potential impact circle is a circle of radius equal to the
potential impact radius (PIR).
Potential impact radius (PIR) means the radius of a circle within
which the potential failure of a pipeline could have significant impact
on people or property. PIR is determined by the formula r = 0.69*
(square root of (p*d \2\)), where `r' is the radius of a circular area
in feet surrounding the
[[Page 69818]]
point of failure, `p' is the maximum allowable operating pressure
(MAOP) in the pipeline segment in pounds per square inch and `d' is the
nominal diameter of the pipeline in inches.
Note: 0.69 is the factor for natural gas. This number will vary
for other gases depending upon their heat of combustion. An operator
transporting gas other than natural gas must use section 3.2 of
ASME/ANSI B31.8S-2001 (Supplement to ASME B31.8; ibr, see Sec.
192.7) to calculate the impact radius formula.
Remediation is a repair or mitigation activity an operator takes on
a covered segment to limit or reduce the probability of an undesired
event occurring or the expected consequences from the event.
Sec. 192.905 How does an operator identify a high consequence area?
(a) General. To determine which segments of an operator's
transmission pipeline system are covered by this subpart, an operator
must identify the high consequence areas. An operator must use method
(1) or (2) from the definition in Sec. 192.903 to identify a high
consequence area. An operator may apply one method to its entire
pipeline system, or an operator may apply one method to individual
portions of the pipeline system. An operator must describe in its
integrity management program which method it is applying to each
portion of the operator's pipeline system. The description must include
the potential impact radius when utilized to establish a high
consequence area. (See appendix E.I. for guidance on identifying high
consequence areas.)
(b)(1) Identified sites. An operator must identify an identified
site, for purposes of this subpart, from information the operator has
obtained from routine operation and maintenance activities and from
public officials with safety or emergency response or planning
responsibilities who indicate to the operator that they know of
locations that meet the identified site criteria. These public
officials could include officials on a local emergency planning
commission or relevant Native American tribal officials.
(2) If a public official with safety or emergency response or
planning responsibilities informs an operator that it does not have the
information to identify an identified site, the operator must use one
of the following sources, as appropriate, to identify these sites.
(i) Visible marking (e.g., a sign); or
(ii) The site is licensed or registered by a Federal, State, or
local government agency; or
(iii) The site is on a list (including a list on an internet web
site) or map maintained by or available from a Federal, State, or local
government agency and available to the general public.
(c) Newly identified areas. When an operator has information that
the area around a pipeline segment not previously identified as a high
consequence area could satisfy any of the definitions in Sec. 192.903,
the operator must complete the evaluation using method (1) or (2). If
the segment is determined to meet the definition as a high consequence
area, it must be incorporated into the operator's baseline assessment
plan as a high consequence area within one year from the date the area
is identified.
Sec. 192.907 What must an operator do to implement this subpart?
(a) General. No later than December 17, 2004, an operator of a
covered pipeline segment must develop and follow a written integrity
management program that contains all the elements described in Sec.
192.911 and that addresses the risks on each covered transmission
pipeline segment. The initial integrity management program must
consist, at a minimum, of a framework that describes the process for
implementing each program element, how relevant decisions will be made
and by whom, a time line for completing the work to implement the
program element, and how information gained from experience will be
continuously incorporated into the program. The framework will evolve
into a more detailed and comprehensive program. An operator must make
continual improvements to the program.
(b) Implementation Standards. In carrying out this subpart, an
operator must follow the requirements of this subpart and of ASME/ANSI
B31.8S (ibr, see Sec. 192.7) and its appendices, where specified. An
operator may follow an equivalent standard or practice only when the
operator demonstrates the alternative standard or practice provides an
equivalent level of safety to the public and property. In the event of
a conflict between this subpart and ASME/ANSI B31.8S, the requirements
in this subpart control.
Sec. 192.909 How can an operator change its integrity management
program?
(a) General. An operator must document any change to its program
and the reasons for the change before implementing the change.
(b) Notification. An operator must notify OPS, in accordance with
Sec. 192.949, of any change to the program that may substantially
affect the program's implementation or may significantly modify the
program or schedule for carrying out the program elements. An operator
must also notify a State or local pipeline safety authority when a
covered segment is located in a State where OPS has an interstate agent
agreement, and a State or local pipeline safety authority that
regulates a covered pipeline segment within that State. An operator
must provide the notification within 30 days after adopting this type
of change into its program.
Sec. 192.911 What are the elements of an integrity management
program?
An operator's initial integrity management program begins with a
framework (see Sec. 192.907) and evolves into a more detailed and
comprehensive integrity management program, as information is gained
and incorporated into the program. An operator must make continual
improvements to its program. The initial program framework and
subsequent program must, at minimum, contain the following elements.
(When indicated, refer to ASME/ANSI B31.8S (ibr, see Sec. 192.7) for
more detailed information on the listed element.)
(a) An identification of all high consequence areas, in accordance
with Sec. 192.905.
(b) A baseline assessment plan meeting the requirements of Sec.
192.919 and Sec. 192.921.
(c) An identification of threats to each covered pipeline segment,
which must include data integration and a risk assessment. An operator
must use the threat identification and risk assessment to prioritize
covered segments for assessment (Sec. 192.917) and to evaluate the
merits of additional preventive and mitigative measures (Sec. 192.935)
for each covered segment.
(d) A direct assessment plan, if applicable, meeting the
requirements of Sec. 192.923, and depending on the threat assessed, of
Sec. Sec. 192.925, 192.927, or 192.929.
(e) Provisions meeting the requirements of Sec. 192.933 for
remediating conditions found during an integrity assessment.
(f) A process for continual evaluation and assessment meeting the
requirements of Sec. 192.937.
(g) If applicable, a plan for confirmatory direct assessment
meeting the requirements of Sec. 192.931.
(h) Provisions meeting the requirements of Sec. 192.935 for adding
preventive and mitigative measures to protect the high consequence
area.
(i) A performance plan as outlined in ASME/ANSI B31.8S, section 9
that includes performance measures meeting the requirements of Sec.
192.943.
[[Page 69819]]
(j) Record keeping provisions meeting the requirements of Sec.
192.947.
(k) A management of change process as outlined in ASME/ANSI B31.8S,
section 11.
(l) A quality assurance process as outlined in ASME/ANSI B31.8S,
section 12.
(m) A communication plan that includes the elements of ASME/ANSI
B31.8S, section 10, and that includes procedures for addressing safety
concerns raised by--
(1) OPS; and
(2) A State or local pipeline safety authority when a covered
segment is located in a State where OPS has an interstate agent
agreement.
(n) Procedures for providing (when requested), by electronic or
other means, a copy of the operator's risk analysis or integrity
management program to--
(1) OPS; and
(2) A State or local pipeline safety authority when a covered
segment is located in a State where OPS has an interstate agent
agreement.
(o) Procedures for ensuring that each integrity assessment is being
conducted in a manner that minimizes environmental and safety risks.
(p) A process for identification and assessment of newly-identified
high consequence areas. (See Sec. 192.905 and Sec. 192.921.)
Sec. 192.913 When may an operator deviate its program from certain
requirements of this subpart?
(a) General. ASME/ANSI B31.8S (ibr, see Sec. 192.7) provides the
essential features of a performance-based or a prescriptive integrity
management program. An operator that uses a performance-based approach
that satisfies the requirements for exceptional performance in
paragraph (b) of this section may deviate from certain requirements in
this subpart, as provided in paragraph (c) of this section.
(b) Exceptional performance. An operator must be able to
demonstrate the exceptional performance of its integrity management
program through the following actions.
(1) To deviate from any of the requirements set forth in paragraph
(c) of this section, an operator must have a performance-based
integrity management program that meets or exceed the performance-based
requirements of ASME/ANSI B31.8S and includes, at a minimum, the
following elements--
(i) A comprehensive process for risk analysis;
(ii) All risk factor data used to support the program;
(iii) A comprehensive data integration process;
(iv) A procedure for applying lessons learned from assessment of
covered pipeline segments to pipeline segments not covered by this
subpart;
(v) A procedure for evaluating every incident, including its cause,
within the operator's sector of the pipeline industry for implications
both to the operator's pipeline system and to the operator's integrity
management program;
(vi) A performance matrix that demonstrates the program has been
effective in ensuring the integrity of the covered segments by
controlling the identified threats to the covered segments;
(vii) Semi-annual performance measures beyond those required in
Sec. 192.943 that are part of the operator's performance plan. (See
Sec. 192.911(i).) An operator must submit these measures, by
electronic or other means, on a semi-annual frequency to OPS in
accordance with Sec. 192.951; and
(viii) An analysis that supports the desired integrity reassessment
interval and the remediation methods to be used for all covered
segments.
(2) In addition to the requirements for the performance-based plan,
an operator must--
(i) Have completed at least two integrity assessments of all
covered pipeline segments, and be able to demonstrate that each
assessment effectively addressed the identified threats on the covered
segments.
(ii) Remediate all anomalies identified in the more recent
assessment according to the requirements in Sec. 192.933, and
incorporate the results and lessons learned from the more recent
assessment into the operator's data integration and risk assessment.
(c) Deviation. Once an operator has demonstrated that it has
satisfied the requirements of paragraph (b) of this section, the
operator may deviate from the prescriptive requirements of ASME/ANSI
B31.8S and of this subpart only in the following instances.
(1) The time frame for reassessment as provided in Sec. 192.939
except that reassessment by some method allowed under this subpart
(e.g., confirmatory direct assessment) must be carried out at intervals
no longer than seven years;
(2) The time frame for remediation as provided in Sec. 192.933 if
the operator demonstrates the time frame will not jeopardize the safety
of the covered segment.
Sec. 192.915 What knowledge and training must personnel have to carry
out an integrity management program?
(a) Supervisory personnel. The integrity management program must
provide that each supervisor whose responsibilities relate to the
integrity management program possesses and maintains a thorough
knowledge of the integrity management program and of the elements for
which the supervisor is responsible. The program must provide that any
person who qualifies as a supervisor for the integrity management
program has appropriate training or experience in the area for which
the person is responsible.
(b) Persons who carry out assessments and evaluate assessment
results. The integrity management program must provide criteria for the
qualification of any person--
(1) Who conducts an integrity assessment allowed under this
subpart; or
(2) Who reviews and analyzes the results from an integrity
assessment and evaluation; or
(3) Who makes decisions on actions to be taken based on these
assessments.
(c) Persons responsible for preventive and mitigative measures. The
integrity management program must provide criteria for the
qualification of any person--
(1) Who implements preventive and mitigative measures to carry out
this subpart, including the marking and locating of buried structures;
or
(2) Who directly supervises excavation work carried out in
conjunction with an integrity assessment.
Sec. 192.917 How does an operator identify potential threats to
pipeline integrity and use the threat identification in its integrity
program?
(a) Threat identification. An operator must identify and evaluate
all potential threats to each covered pipeline segment. Potential
threats that an operator must consider include, but are not limited to,
the threats listed in ASME/ANSI B31.8S (ibr, see Sec. 192.7), section
2 and the following:
(1) Time dependent threats such as internal corrosion, external
corrosion, and stress corrosion cracking;
(2) Static or resident threats, such as fabrication or construction
defects;
(3) Time independent threats such as third party damage and outside
force damage; and
(4) Human error.
(b) Data gathering and integration. To identify and evaluate the
potential threats to a covered pipeline segment, an operator must
gather and integrate
[[Page 69820]]
data and information on the entire pipeline that could be relevant to
the covered segment. In performing this data gathering and integration,
an operator must follow the requirements in ASME/ANSI B31.8S, section
4. At a minimum, an operator must gather and evaluate the set of data
specified in appendix A to ASME/ANSI B31.8S, and consider both on the
covered segment and similar non-covered segments, past incident
history, corrosion control records, continuing surveillance records,
patrolling records, maintenance history, internal inspection records
and all other conditions specific to each pipeline.
(c) Risk assessment. An operator must conduct a risk assessment
that follows ASME/ANSI B31.8S, section 5, and considers the identified
threats for each covered segment. An operator must use the risk
assessment to prioritize the covered segments for the baseline and
continual reassessments (Sec. Sec. 192.919, 192.921, 192.937), and to
determine what additional preventive and mitigative measures are needed
(Sec. 192.935) for the covered segment.
(d) Plastic transmission pipeline. An operator of a plastic
transmission pipeline must assess the threats to each covered segment
using the information in sections 4 and 5 of ASME B31.8S, and consider
any threats unique to the integrity of plastic pipe.
(e) Actions to address particular threats. If an operator
identifies any of the following threats, the operator must take the
following actions to address the threat.
(1) Third party damage. An operator must utilize the data
integration required in paragraph (b) of this section and ASME/ANSI
B31.8S, appendix A7 to determine the susceptibility of each covered
segment to the threat of third party damage. If an operator identifies
the threat of third party damage, the operator must implement
comprehensive additional preventive measures in accordance with Sec.
192.935 and monitor the effectiveness of the preventive measures. If,
in conducting a baseline assessment under Sec. 192.921, or a
reassessment under Sec. 192.937, an operator uses an internal
inspection tool, such as a caliper, geometry or magnetic flux leakage
tool, to address other identified threats on the covered segment, the
operator must integrate data from these tool runs with data related to
any encroachment or foreign line crossing on the covered segment, to
define where potential indications of third party damage may exist in
the covered segment. An operator must also have procedures in its
integrity management program addressing actions it will take to respond
to findings from this data integration.
(2) Cyclic fatigue. An operator must evaluate whether cyclic
fatigue or other loading condition (including ground movement,
suspension bridge condition) could lead to a failure of a deformation,
including a dent or gouge, or other defect in the covered segment. An
evaluation must assume the presence of threats in the covered segment
that could be exacerbated by cyclic fatigue. An operator must use the
results from the evaluation together with the criteria used to evaluate
the significance of this threat to the covered segment to prioritize
the integrity baseline assessment or reassessment.
(3) Manufacturing and construction defects. If an operator
identifies the threat of manufacturing and construction defects
(including seam defects) in the covered segment, an operator must
analyze the covered segment to determine the risk of failure from these
defects. An operator may consider manufacturing and construction
related defects to be stable defects if the operating conditions on the
covered segment have not significantly changed since December 17, 1998.
If any of the following changes occur in the covered segment, an
operator must prioritize the covered segment as a high risk segment for
the baseline assessment or a subsequent reassessment.
(i) Operating pressure increases above the historic operating
pressure (i.e. the highest pressure recorded since December 17, 1998);
(ii) MAOP increases; or
(iii) The stresses leading to cyclic fatigue increase.
(4) ERW pipe. If a covered pipeline segment contains low frequency
electric resistance welded pipe (ERW) or lap welded pipe that satisfies
the conditions specified in ASME/ANSI B31.8 S, appendix A4.3 and A4.4,
an operator must select an assessment technology or technologies with a
proven application capable of assessing seam integrity and of detecting
seam corrosion anomalies. The operator must prioritize the covered
segment as a high risk segment for the baseline assessment or a
subsequent reassessment.
(5) Corrosion. If an operator identifies corrosion on a covered
pipeline segment that could adversely affect the integrity of the line
(conditions specified in Sec. 192.931), the operator must evaluate and
remediate, as necessary, all pipeline segments (both covered and non-
covered) with similar material coating and environmental
characteristics. An operator must establish a schedule for evaluating
and remediating, as necessary, the similar segments that is consistent
with the operator's established operating and maintenance procedures
under part 192 for testing and repair.
Sec. 192.919 What must be in the baseline assessment plan?
An operator must include each of the following elements in its
written baseline assessment plan:
(a) Identification of the potential threats to each covered
pipeline segment and the information supporting the threat
identification. (See Sec. 192.917.);
(b) The methods selected to assess the integrity of the line pipe,
including an explanation of why the assessment method was selected to
address the identified threats to each covered segment. The integrity
assessment method an operator uses must be based on the threats
identified to the covered segment. (See Sec. 192.917.) More than one
method may be required to address all the threats to the covered
pipeline segment;
(c) A schedule for completing the integrity assessment of all
covered segments, including risk factors considered in establishing the
assessment schedule;
(d) If applicable, a direct assessment plan that meets the
requirements of Sec. Sec. 192.923, and depending on the threat to be
addressed, of Sec. 192.925, Sec. 192.927, or Sec. 192.929; and
(e) A procedure to ensure that the baseline assessment is being
conducted in a manner that minimizes environmental and safety risks.
Sec. 192.921 How is the baseline assessment to be conducted?
(a) Assessment methods. An operator must assess the integrity of
the line pipe in each covered segment by applying one or more of the
following methods depending on the threats to which the covered segment
is susceptible. An operator must select the method or methods best
suited to address the threats identified to the covered segment (See
Sec. 192.917).
(1) Internal inspection tool or tools capable of detecting
corrosion, and any other threats to which the covered segment is
susceptible. An operator must follow ASME/ANSI B31.8S (ibr, see Sec.
192.7), section 6.2 in selecting the appropriate internal inspection
tools for the covered segment.
(2) Pressure test conducted in accordance with subpart J of this
part;
(3) Direct assessment to address threats of external corrosion,
internal corrosion, and stress corrosion cracking. An operator must
conduct the direct
[[Page 69821]]
assessment in accordance with the requirements listed in Sec. 192.923
and with, as applicable, the requirements specified in Sec. Sec.
192.925, 192.927 or 192.929;
(4) Other technology that an operator demonstrates can provide an
equivalent understanding of the condition of the line pipe. An operator
choosing this option must notify the Office of Pipeline Safety (OPS)
180 days before conducting the assessment, in accordance with Sec.
192.949.
(b) Prioritizing segments. An operator must prioritize the covered
pipeline segments for the baseline assessment according to a risk
analysis that considers the potential threats to each covered segment.
The risk analysis must comply with the requirements in Sec. 192.917.
(c) Assessment for particular threats. In choosing an assessment
method for the baseline assessment of each covered segment, an operator
must take the actions required in Sec. 192.917(d) to address
particular threats that it has identified.
(d) Time period. An operator must prioritize all the covered
segments for assessment in accordance with Sec. 192.917 (c) and
paragraph (b) of this section. An operator must assess at least 50% of
the covered segments beginning with the highest risk segments, by
December 17, 2007. An operator must complete the baseline assessment of
all covered segments by December 17, 2012.
(e) Prior assessment. An operator may use a prior integrity
assessment conducted before December 17, 2002 as a baseline assessment
for the covered segment, if the integrity assessment meets the baseline
requirements in this subpart and subsequent remedial actions to address
the conditions listed in Sec. 192.933 have been carried out. In
addition, if an operator uses this prior assessment as its baseline
assessment, the operator must reassess the line pipe in the covered
segment according to the requirements of Sec. 192.937 and Sec.
192.939.
(f) Newly identified areas. When an operator identifies a new high
consequence area (see Sec. 192.205), an operator must complete the
baseline assessment of the line pipe in the newly identified high
consequence area within ten (10) years from the date the area is
identified.
(g) Newly installed pipe. An operator must complete the baseline
assessment of a newly installed segment of pipe covered by this subpart
within ten (10) years from the date the pipe is installed. An operator
may conduct a post-installation pressure test, in accordance with
subpart J of part 192, to satisfy the requirement for a baseline
assessment.
(h) Plastic transmission pipeline. If the threat analysis required
in Sec. 192.917(d) on a plastic transmission pipeline indicates that a
covered segment is susceptible to failure from causes other than third-
party damage, an operator must conduct a baseline assessment of the
segment in accordance with the requirements of this section and of
Sec. 192.917. The operator must justify the use of an alternative
assessment method that will address the identified threats to the
covered segment.
Sec. 192.923 How is direct assessment used and for what threats?
(a) General. An operator may use direct assessment either as a
primary assessment method or as a supplement to the other assessment
methods allowed under this subpart. An operator may only use direct
assessment as the primary assessment method to address the identified
threats of external corrosion (ECDA), internal corrosion (ICDA), and
stress corrosion cracking (SCCDA).
(b) Primary method. An operator using direct assessment as a
primary assessment method must have a plan that complies with the
requirements in--
(1) ASME/ANSI B31.8S (ibr, see Sec. 192.7), section 6.4; NACE
RP0502-2002 (ibr, see Sec. 192.7); and Sec. 192.925 if addressing
external corrosion (ECDA).
(2) ASME/ANSI B31.8S, section 6.4 and appendix B2, and Sec.
192.927 if addressing internal corrosion (ICDA).
(3) ASME/ANSI B31.8S, appendix A3, and Sec. 192.929 if addressing
stress corrosion cracking (SCCDA).
(c) Supplemental method. An operator using direct assessment as a
supplemental assessment method for any applicable threat must have a
plan that follows the requirements for confirmatory direct assessment
in Sec. 192.931.
Sec. 192.925 What are the requirements for using External Corrosion
Direct Assessment (ECDA)?
(a) Definition. ECDA is a four-step process that combines
preassessment, indirect inspection, direct examination, and post
assessment to evaluate the threat of external corrosion to the
integrity of a pipeline.
(b) General requirements. An operator that uses direct assessment
to assess the threat of external corrosion must follow the requirements
in this section, in ASME/ANSI B31.8S (ibr, see Sec. 192.7), section
6.4, and NACE RP 0502-2002 (ibr, see Sec. 192.7). An operator must
develop and implement a direct assessment plan that has procedures
addressing preassessment, indirect inspections, direct examination, and
post-assessment.
(1) Preassessment. In addition to the requirements in ASME/ANSI
B31.8S section 6.4 and NACE RP 0502-2002, section 3, the plan's
procedures for preassessment must include--
(i) Provisions for applying more restrictive criteria when
conducting ECDA for the first time on a covered segment; and
(ii) The basis on which an operator selects at least two different,
but complementary indirect assessment tools to assess each ECDA Region.
If an operator utilizes an indirect inspection method that is not
discussed in appendix A of NACE RP0502-2002, the operator must
demonstrate the applicability, validation basis, equipment used,
application procedure, and utilization of data for the inspection
method.
(2) Indirect Examination. In addition to the requirements in ASME/
ANSI B31.8S section 6.4 and NACE RP 0502-2002, section 4, the plan's
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 covered segment;
(ii) Criteria for identifying and documenting those indications
that must be considered for excavation and direct examination. Minimum
identification criteria include the known sensitivities of assessment
tools, the procedures for using each tool, and the approach to be used
for decreasing the physical spacing of indirect assessment tool
readings when the presence of a defect is suspected;
(iii) Criteria for defining the urgency of excavation and direct
examination of each indication identified during the indirect
examination. These criteria must specify how an operator will define
the urgency of excavating the indication as immediate, scheduled or
monitored; and
(iv) Criteria for scheduling excavation of indications for each
urgency level.
(3) Direct examination. In addition to the requirements in ASME/
ANSI B31.8S section 6.4 and NACE RP 0502-2002, section 5, the plan's
procedures for direct examination of indications from the indirect
examination must include--
(i) Provisions for applying more restrictive criteria when
conducting ECDA for the first time on a covered segment;
(ii) Criteria for deciding what action should be taken if either
(a) corrosion
[[Page 69822]]
defects are discovered that exceed allowable limits (section 5.5.2.2 of
NACE RP0502-2002), or
(b) root cause analysis reveals conditions for which ECDA is not
suitable (section 5.6.2 of NACE RP0502-2002);
(iii) Criteria and notification procedures for any changes in the
ECDA Plan, including changes that affect the severity classification,
the priority of direct examination, and the time frame for direct
examination of indications; and
(iv) Criteria that describe how and on what basis an operator will
reclassify and reprioritize any of the provisions that are specified in
section 5.9 of NACE RP0502-2002.
(4) Post assessment and continuing evaluation. In addition to the
requirements in ASME/ANSI B31.8S section 6.4 and NACE RP 0502-2002,
section 6, the plan's procedures for post assessment of the
effectiveness of the ECDA process must include--
(i) Measures for evaluating the long-term effectiveness of ECDA in
addressing external corrosion in covered segments; and
(ii) Criteria for evaluating whether conditions discovered by
direct examination of indications in each ECDA region indicate a need
for reassessment of the covered segment at an interval less than that
specified in Sec. 192.939. (See appendix D of NACE RP0502-2002.)
Sec. 192.927 What are the requirements for using Internal Corrosion
Direct Assessment (ICDA)?
(a) Definition. Internal Corrosion Direct Assessment (ICDA) is a
process an operator uses to identify areas along the pipeline where
fluid or other electrolyte introduced during normal operation or by an
upset condition may reside, and then focuses direct examination on the
locations in covered segments where internal corrosion is most likely
to exist. The process identifies the potential for internal corrosion
caused by microorganisms, or fluid with CO2, O2, hydrogen sulfide or
other contaminants present in the gas.
(b) General requirements. An operator using direct assessment as an
assessment method to address internal corrosion in a covered pipeline
segment must follow the requirements in this section and in ASME/ANSI
B31.8S (ibr, see Sec. 192.7), section 6.4 and appendix B2. The ICDA
process described in this section applies only for a segment of pipe
transporting nominally dry natural gas, and not for a segment with
electrolyte nominally present in the gas stream. If an operator uses
ICDA to assess a covered segment operating with electrolyte present in
the gas stream, the operator must develop a plan that demonstrates how
it will conduct ICDA in the segment to effectively address internal
corrosion.
(c) The ICDA plan. An operator must develop and follow an ICDA plan
that provides for preassessment, identification of ICDA regions and
excavation locations, detailed examination of pipe at excavation
locations, and post-assessment evaluation and monitoring.
(1) Preassessment. In the preassessment stage, an operator must
gather and integrate data and information needed to evaluate the
feasibility of ICDA for the covered segment, and to support use of a
model to identify the locations along the pipe segment where
electrolyte may accumulate, to identify ICDA regions, and to identify
areas within the covered segment where liquids may potentially be
entrained. This data and information includes, but is not limited to--
(i) All data elements listed in appendix A2 of ASME/ANSI B31.8S;
(ii) Information needed to support use of a model that an operator
must use to identify areas along the pipeline where internal corrosion
is most likely to occur. (See paragraph (a) of this section.) This
information, includes, but is not limited to, location of all gas input
and withdrawal points on the line; location of all low points on
covered segments such as sags, drips, inclines, valves, manifolds,
dead-legs, and traps; the elevation profile of the pipeline in
sufficient detail that angles of inclination can be calculated for all
pipe segments; and the diameter of the pipeline, and the range of
expected gas velocities in the pipeline;
(iii) Operating experience data that would indicate historic upsets
in gas conditions, locations where these upsets have occurred, and
potential damage resulting from these upset conditions; and
(iv) Information on covered segments where cleaning pigs may not
have been used or where cleaning pigs may deposit electrolytes.
(2) ICDA region identification. An operator's plan must identify
where all ICDA Regions are located in the transmission system, in which
covered segments are located. An ICDA Region extends from the location
where liquid may first enter the pipeline and encompasses the entire
area along the pipeline where internal corrosion may occur and where
further evaluation is needed. An ICDA Region may encompass one or more
covered segments. In the identification process, an operator must use
the model in GRI 02-0057, ``Internal Corrosion Direct Assessment of Gas
Transmission Pipelines--Methodology,'' (ibr, see Sec. 192.7). An
operator may use another model if the operator demonstrates it is
equivalent to the one shown in GRI 02-0057. A model must consider
changes in pipe diameter, locations where gas enters a line (potential
to introduce liquid) and locations down stream of gas draw-offs (where
gas velocity is reduced) to define the critical pipe angle of
inclination above which water film cannot be transported by the gas.
(3) Identification of locations for excavation and direct
examination. An operator's plan must identify the locations where
internal corrosion is most likely in each ICDA region. In the location
identification process, an operator must identify a minimum of two
locations for excavation within each ICDA Region within a covered
segment and must perform a direct examination for internal corrosion at
each location, using ultrasonic thickness measurements, radiography, or
other generally accepted measurement technique. One location must be
the low point (e.g., sags, drips, valves, manifolds, dead-legs, traps)
within the covered segment nearest to the beginning of the ICDA Region.
The second location must be at the upstream end of the pipe containing
a covered segment, having a slope not exceeding the critical angle of
inclination nearest the end of the ICDA Region. If corrosion exists at
either location, the operator must--
(i) Evaluate the severity of the defect (remaining strength) and
remediate the defect in accordance with Sec. 192.933;
(ii) As part of the operator's current integrity assessment either
perform additional excavations in each covered segment within the ICDA
region, or use an alternative assessment method allowed by this subpart
to assess the line pipe in each covered segment within the ICDA region
for internal corrosion; and
(iii) Evaluate the potential for internal corrosion in all pipeline
segments (both covered and non-covered) in the operator's pipeline
system with similar characteristics to the ICDA region containing the
covered segment in which the corrosion was found, and as appropriate,
remediate the conditions the operator finds in accordance with Sec.
192.933.
(4) Post-assessment evaluation and monitoring. An operator's plan
must provide for evaluating the effectiveness of the ICDA process and
continued monitoring of covered segments where internal corrosion has
been identified.
[[Page 69823]]
The evaluation and monitoring process includes--
(i) Evaluating the effectiveness of ICDA as an assessment method
for addressing internal corrosion and determining whether a covered
segment should be reassessed at more frequent intervals than those
specified in Sec. 192.939. This evaluation must be carried out in the
same year in which ICDA is used; and
(ii) Continually monitoring each covered segment where internal
corrosion has been identified using techniques such as coupons, UT
sensors or electronic probes, periodically drawing off liquids at low
points and chemically analyzing the liquids for the presence of
corrosion products. An operator must base the frequency of the
monitoring and liquid analysis on results from all integrity
assessments that have been conducted in accordance with the
requirements of this subpart, and risk factors specific to the covered
segment. If an operator finds any evidence of corrosion products in the
covered segment, the operator must take prompt action in accordance
with one of the two following required actions and remediate the
conditions the operator finds in accordance with Sec. 192.933.
(A) Conduct excavations of covered segments at locations downstream
from where the electrolyte might have entered the pipe; or
(B) Assess the covered segment using another integrity assessment
method allowed by this subpart.
(5) Other requirements. The ICDA plan must also include--
(i) Criteria an operator will apply in making key decisions (e.g.,
ICDA feasibility, definition of ICDA Regions, conditions requiring
excavation) in implementing each stage of the ICDA process;
(ii) Provisions for applying more restrictive criteria when
conducting ICDA for the first time on a covered segment and that become
less stringent as the operator gains experience; and
(iii) Provisions that analysis be carried out on the entire
pipeline in which covered segments are present, except that application
of the remediation criteria of Sec. 192.933 may be limited to covered
segments.
Sec. 192.929 What are the requirements for using Direct Assessment
for Stress Corrosion Cracking (SCCDA)?
(a) Definition. Stress Corrosion Direct Assessment (SCCDA) is a
process to assess a covered pipe segment for the presence of SCC
primarily by systematically gathering and analyzing excavation data for
pipe having similar operational characteristics and residing in a
similar physical environment.
(b) General requirements. An operator using direct assessment as an
integrity assessment method to address stress corrosion cracking in a
covered pipeline segment must have a plan that provides, at minimum,
for--
(1) Data gathering and integration. An operator's plan must provide
for a systematic process to collect and evaluate data for all covered
segments to identify whether the conditions for SCC are present and to
prioritize the covered segments for assessment. This process must
include gathering and evaluating data related to SCC at all sites an
operator excavates during the conduct of its pipeline operations where
the criteria in ASME/ANSI B31.8S (ibr, see Sec. 192.7), appendix A3.3
indicate the potential for SCC. This data includes at minimum, the data
specified in ASME/ANSI B31.8S, appendix A3.
(2) Assessment method. The plan must provide that if conditions for
SCC are identified in a covered segment, an operator must assess the
covered segment using an integrity assessment method specified in ASME/
ANSI B31.8S, appendix A3, and remediate the threat in accordance with
ASME/ANSI B31.8S, appendix A3, section A3.4.
Sec. 192.931 How may Confirmatory Direct Assessment (CDA) be used?
An operator using the confirmatory direct assessment (CDA) method
as allowed in Sec. 192.937 must have a plan that meets the
requirements of this section and of Sec. Sec. 192.925 (ECDA) and Sec.
192.927 (ICDA).
(a) Threats. An operator may only use CDA on a covered segment to
identify damage resulting from external corrosion or internal
corrosion.
(b) External corrosion plan. An operator's CDA plan for identifying
external corrosion must comply with Sec. 192.925 with the following
exceptions.
(1) The procedures for indirect examination may allow use of only
one indirect examination tool suitable for the application.
(2) The procedures for direct examination and remediation must
provide that--
(i) All immediate action indications must be excavated for each
ECDA region; and
(ii) At least one high risk indication that meets the criteria of
scheduled action must be excavated in each ECDA region.
(c) Internal corrosion plan. An operator's CDA plan for identifying
internal corrosion must comply with Sec. 192.927 except that the
plan's procedures for identifying locations for excavation may require
excavation of only one high risk location in each ICDA region.
(d) Defects requiring near-term remediation. If an assessment
carried out under paragraph (b) or (c) of this section reveals any
defect requiring remediation prior to the next scheduled assessment,
the operator must schedule the next assessment in accordance with NACE
RP 0502-2002 (ibr, see Sec. 192.7), section 6.2 and 6.3. If the defect
requires immediate remediation, then the operator must reduce pressure
consistent with Sec. 192.933 until the operator has completed
reassessment using one of the assessment techniques allowed in Sec.
192.937.
Sec. 192.933 What actions must be taken to address integrity issues?
(a) General requirements. An operator must take prompt action to
address all anomalous conditions that the operator discovers through
the integrity assessment. In addressing all conditions, an operator
must evaluate all anomalous conditions and remediate those that could
reduce a pipeline's integrity. An operator must be able to demonstrate
that the remediation of the condition will ensure that the condition is
unlikely to pose a threat to the integrity of the pipeline until the
next reassessment of the covered segment. If an operator is unable to
respond within the time limits for certain conditions specified in this
section, the operator must temporarily reduce the operating pressure of
the pipeline or take other action that ensures the safety of the
covered segment. If pressure is reduced, an operator must determine the
temporary reduction in operating pressure using ASME/ANSI B31G (ibr,
see Sec. 192.7) or AGA Pipeline Research Committee Project PR-3-805
(``RSTRENG''; ibr, see Sec. 192.7) or reduce the operating pressure to
a level not exceeding 80% of the level at the time the condition was
discovered. (See appendix A to this part 192 for information on
availability of incorporation by reference information). A reduction in
operating pressure cannot exceed 365 days without an operator providing
a technical justification that the continued pressure restriction will
not jeopardize the integrity of the pipeline.
(b) Discovery of condition. Discovery of a condition occurs when an
operator has adequate information about the condition to determine that
the condition presents a potential threat to the integrity of the
pipeline. An operator must promptly, but no later than 180 days after
conducting an integrity assessment, obtain sufficient
[[Page 69824]]
information about a condition to make that determination, unless the
operator demonstrates that the 180-day period is impracticable.
(c) Schedule for evaluation and remediation. An operator must
complete remediation of a condition according to a schedule that
prioritizes the conditions for evaluation and remediation. Unless a
special requirement for remediating certain conditions applies, as
provided in paragraph (d) of this section, an operator must follow the
schedule in ASME/ANSI B31.8S (ibr, see Sec. 192.7), section 7, Figure
4. If an operator cannot meet the schedule for any condition, the
operator must justify the reasons why it cannot meet the schedule and
that the changed schedule will not jeopardize public safety. An
operator must notify OPS in accordance with Sec. 192.949 if it cannot
meet the schedule and cannot provide safety through a temporary
reduction in operating pressure or other action. An operator must also
notify a State or local pipeline safety authority when a covered
segment is located in a State where OPS has an interstate agent
agreement, and a State or local pipeline safety authority that
regulates a covered pipeline segment within that State.
(d) Special requirements for scheduling remediation.--(1) Immediate
repair conditions. An operator's evaluation and remediation schedule
must follow ASME/ANSI B31.8S, section 7 in providing for immediate
repair conditions. To maintain safety, an operator must temporarily
reduce operating pressure in accordance with paragraph (a) of this
section or shut down the pipeline until the operator completes the
repair of these conditions. An operator must treat the following
conditions as immediate repair conditions:
(i) A calculation of the remaining strength of the pipe shows a
predicted failure pressure less than or equal to 1.1 times the maximum
allowable operating pressure at the location of the anomaly. Suitable
remaining strength calculation methods include, ASME/ANSI B31G;
RSTRENG; or an alternative equivalent method of remaining strength
calculation. These documents are incorporated by reference and
available at the addresses listed in appendix A to part 192.
(ii) A dent that has any indication of metal loss, cracking or a
stress riser.
(iii) An anomaly that in the judgment of the person designated by
the operator to evaluate the assessment results requires immediate
action.
(2) One-year conditions. Except for conditions listed in paragraph
(d)(1) and (d)(3) of this section, an operator must remediate any of
the following within one year of discovery of the condition:
(i) A smooth dent located between the 8 o'clock and 4 o'clock
positions (upper \2/3\ of the pipe) with a depth greater than 6% of the
pipeline diameter (greater than 0.50 inches in depth for a pipeline
diameter less than Nominal Pipe Size (NPS) 12).
(ii) A dent with a depth greater than 2% of the pipeline's diameter
(0.250 inches in depth for a pipeline diameter less than NPS 12) that
affects pipe curvature at a girth weld or at a longitudinal seam weld.
(3) Monitored conditions. An operator does not have to schedule the
following conditions for remediation, but must record and monitor the
conditions during subsequent risk assessments and integrity assessments
for any change that may require remediation:
(i) A dent with a depth greater than 6% of the pipeline diameter
(greater than 0.50 inches in depth for a pipeline diameter less than
NPS 12) located between the 4 o'clock position and the 8 o'clock
position (bottom \1/3\ of the pipe).
(ii) A dent located between the 8 o'clock and 4 o'clock positions
(upper \2/3\ of the pipe) with a depth greater than 6% of the pipeline
diameter (greater than 0.50 inches in depth for a pipeline diameter
less than Nominal Pipe Size (NPS) 12), and engineering analyses of the
dent demonstrate critical strain levels are not exceeded.
(iii) A dent with a depth greater than 2% of the pipeline's
diameter (0.250 inches in depth for a pipeline diameter less than NPS
12) that affects pipe curvature at a girth weld or a longitudinal seam
weld, and engineering analyses of the dent and girth or seam weld
demonstrate critical strain levels are not exceeded. These analyses
must consider weld properties.
Sec. 192.935 What additional preventive and mitigative measures must
an operator take to protect the high consequence area?
(a) General requirements. An operator must take additional measures
beyond those already required by Part 192 to prevent a pipeline failure
and to mitigate the consequences of a pipeline failure in a high
consequence area. An operator must base the additional measures on the
threats the operator has identified to each pipeline segment. (See
Sec. 192.917) An operator must conduct, in accordance with one of the
risk assessment approaches in ASME/ANSI B31.8S (ibr, see Sec. 192.7),
section 5, a risk analysis of its pipeline to identify additional
measures to protect the high consequence area and enhance public
safety. Such additional measures include, but are not limited to,
installing Automatic Shut-off Valves or Remote Control Valves,
installing computerized monitoring and leak detection systems,
replacing pipe segments with pipe of heavier wall thickness, providing
additional training to personnel on response procedures, conducting
drills with local emergency responders and implementing additional
inspection and maintenance programs.
(b) Third party damage and outside force damage--(1) Third party
damage. An operator must enhance its damage prevention program, as
required under Sec. 192.614 of this part, with respect to a covered
segment to prevent and minimize the consequences of a release due to
third party or outside force damage. Enhanced measures to an existing
damage prevention program include, at a minimum--
(i) Using qualified personnel (see Sec. 192.915) for work an
operator is conducting that could adversely affect the integrity of a
covered segment, such as marking, locating, and direct supervision of
known excavation work.
(ii) Collecting in a central database information that is location
specific on excavation damage that occurs in on covered and noncovered
segments in the transmission system and the root cause analysis to
support identification of targeted additional preventative and
mitigative measures in the high consequence areas. This information
must include recognized damage that is not required to be reported as
an incident under part 191.
(iii) Participating in one-call systems in locations where covered
segments are present.
(iv) Monitoring of excavations conducted on covered pipeline
segments by pipeline personnel. When there is physical evidence of
encroachment involving excavation near a covered segment, an operator
must either excavate the area near the encroachment or conduct an above
ground survey using methods defined in NACE RP-0502-2002 (ibr, see
Sec. 192.7). An operator must excavate, and remediate, in accordance
with ANSI/ASME B31.8S and Sec. 192.933 any indication of coating
holidays or discontinuity warranting direct examination.
(2) Outside force damage. If an operator determines that outside
force (e.g., earth movement, floods, unstable suspension bridge) is a
threat to the integrity of a covered segment, the operator must take
measures to minimize the consequences to the covered segment from
outside force damage. These measures include, but are not limited to,
increasing the
[[Page 69825]]
frequency of aerial, foot or other methods of patrols, adding external
protection, reducing external stress, and relocating the line.
(c) Automatic shut-off valves (ASV) or Remote control valves (RCV).
If an operator determines, based on a risk analysis, that an ASV or RCV
would be an efficient means of adding protection to a high consequence
area in the event of a gas release, an operator must install the ASV or
RCV. In making that determination, an operator must, at least, consider
the following factors--swiftness of leak detection and pipe shutdown
capabilities, the type of gas being transported, operating pressure,
the rate of potential release, pipeline profile, the potential for
ignition, and location of nearest response personnel.
(d) Pipelines operating below 30% SMYS. With respect to a
transmission pipeline operating below 30% SMYS located in a class 3 or
4 area but not in a high consequence area, an operator must--
(1) Apply the requirements in paragraphs (b)(1)(i) and (b)(1)(iii)
of this section to the pipeline; and
(2) Either monitor excavations near the pipeline, or conduct
patrols as required by Sec. 192.705 of the pipeline at bi-monthly
intervals. If an operator finds any indication of unreported
construction activity, the operator must conduct a follow up
investigation to determine if mechanical damage has occurred.
(e) Plastic transmission pipeline. An operator of a plastic
transmission pipeline must apply the requirements in paragraphs
(b)(1)(i), (b)(1)(iii) and (b)(1)(iv) of this section to the covered
segments of the pipeline.
Sec. 192.937 What is a continual process of evaluation and assessment
to maintain a pipeline's integrity?
(a) General. After completing the baseline integrity assessment of
a covered segment, an operator must continue to assess the line pipe of
that segment at the intervals specified in Sec. 192.939 and
periodically evaluate the integrity of each covered pipeline segment as
provided in paragraph (b) of this section. An operator must reassess a
covered segment on which a prior assessment is credited as a baseline
under Sec. 192.921(e) by no later than December 17, 2009. An operator
must reassess a covered segment on which a baseline assessment is
conducted during the baseline period specified in Sec. 192.921(d) by
no later than seven years after the baseline assessment of that covered
segment unless the evaluation under paragraph (b) of this section
indicates earlier reassessment.
(b) Evaluation. An operator must conduct a periodic evaluation as
frequently as needed to assure the integrity of each covered segment.
The periodic evaluation must be based on a data integration and risk
assessment of the entire pipeline as specified in Sec. 192.917. For
plastic transmission pipelines, the periodic evaluation is based on the
threat analysis specified in 192.917(d). For all other transmission
pipelines, the evaluation must consider the past and present integrity
assessment results, data integration and risk assessment information
(Sec. 192.917), and decisions about remediation (Sec. 192.933) and
additional preventive and mitigative actions (Sec. 192.935). An
operator must use the results from this evaluation to identify the
threats specific to each covered segment and the risk represented by
these threats.
(c) Assessment methods. In conducting the integrity reassessment,
an operator must assess the integrity of the line pipe in the covered
segment by any of the following methods as appropriate for the threats
to which the covered segment is susceptible (see Sec. 192.917), or by
confirmatory direct assessment under the conditions specified in Sec.
192.931.
(1) Internal inspection tool or tools capable of detecting
corrosion, and any other threats to which the covered segment is
susceptible. An operator must follow ASME/ANSI B31.8S (ibr, see Sec.
192.7), section 6.2 in selecting the appropriate internal inspection
tools for the covered segment.
(2) Pressure test conducted in accordance with subpart J of this
part;
(3) Direct assessment to address threats of external corrosion,
internal corrosion, or stress corrosion cracking. An operator must
conduct the direct assessment in accordance with the requirements
listed in Sec. 192.923 and with as applicable, the requirements
specified in Sec. Sec. 192.925, 192.927 or 192.929;
(4) Other technology that an operator demonstrates can provide an
equivalent understanding of the condition of the line pipe. An operator
choosing this option must notify the Office of Pipeline Safety (OPS)
180 days before conducting the assessment, in accordance with Sec.
192.949.
(5) Confirmatory direct assessment when used on a covered segment
that is scheduled for reassessment at a period longer than seven years.
An operator using this reassessment method must comply with Sec.
192.931.
Sec. 192.939 What are the required reassessment intervals?
An operator must comply with the following requirements in
establishing the reassessment interval for the operator's covered
pipeline segments.
(a) Pipelines operating at or above 30% SMYS. An operator must
establish a reassessment interval for each covered segment operating at
or above 30% SMYS in accordance with the requirements of this section.
The minimum reassessment interval by an allowable reassessment method
is seven years. If an operator establishes a reassessment interval that
is greater than seven years, the operator must, within the seven-year
period, conduct a confirmatory direct assessment on the covered
segment, and then conduct the follow-up reassessment at the interval
the operator has established. A reassessment carried out using
confirmatory direct assessment must be done in accordance with Sec.
192.931. (For ease of reference, the table that follows this section
sets forth the required reassessment intervals.)
(1) Pressure test or internal inspection or other equivalent
technology. An operator that uses pressure testing or internal
inspection as an assessment method must establish the reassessment
interval for a covered pipeline segment by--
(i) Basing the interval on the identified threats for the segment
as listed in Sec. 192.917 of this section and in ASME/ANSI B31.8S
(ibr, see Sec. 192.7), section 9, Tables 6 and 7, and on the analysis
of the results from the last integrity assessment and from the data
integration and risk assessment required by Sec. 192.911; or
(ii) Using the intervals specified for different stress levels of
pipeline (operating at or above 30% SMYS) listed in ASME/ANSI B31.8S,
section 5, Table 3.
(2) External Corrosion Direct Assessment. An operator that uses
ECDA that meets the requirements of this subpart must determine the
reassessment interval according to the requirements in paragraphs 6.2
and 6.3 of NACE RP0502-2002 (ibr, see Sec. 192.7).
(3) Internal Corrosion or SCC Direct Assessment. An operator that
uses ICDA or SCCDA in accordance with the requirements of this subpart
must determine the reassessment interval according to the following
calculation. However, the reassessment interval cannot exceed those
specified for direct assessment in ASME/ANSI B31.8S, section 5, Table
3.
(i) Determine the largest defect most likely to remain in the
covered segment
[[Page 69826]]
and the corrosion rate appropriate for the pipe, soil and protection
conditions;
(ii) Use the largest remaining defect as the size of the largest
defect discovered in the SCC or ICDA segment; and
(iii) Estimate the reassessment interval as half the time required
for the largest defect to grow to a critical size.
(b) Pipelines Operating Below 30% SMYS. An operator must establish
a reassessment interval for each covered segment operating below 30%
SMYS in accordance with the requirements of this section. The minimum
reassessment interval by an allowable reassessment method is seven
years. An operator must establish reassessment by at least one of the
following--
(1) Reassessment by pressure test, internal inspection or other
equivalent technology following the requirements in paragraph (a)(1) of
this section except that the stress level referenced in paragraph
(a)(1)(ii) of this section would be adjusted to reflect the lower
operating stress level. If an established interval is more than seven
years, the operator must conduct by the seventh year of the interval
either a confirmatory direct assessment in accordance with Sec.
192.931, or a low stress reassessment in accordance with Sec. 192.941.
(2) Reassessment by ECDA following the requirements in paragraph
(a)(2) of this section.
(3) Reassessment by ICDA or SCCDA following the requirements in
paragraph (a)(3) of this section.
(4) Reassessment by confirmatory direct assessment at 7-year
intervals in accordance with Sec. 192.931, with reassessment by one of
the methods listed in paragraphs (b)(1) through (b)(3) of this section
by year 20 of the interval.
(5) Reassessment by the low stress assessment method at 7-year
intervals in accordance with Sec. 192.941 with reassessment by one of
the methods listed in paragraphs (b)(1) through (b)(3) of this section
by year 20 of the interval.
For ease of reference, the following table sets forth the required
reassessment intervals. Also refer to appendix E.II for guidance on
Assessment Methods and Assessment schedule for Transmission Pipelines
Operating Below 30% SMYS. In case of conflict between the rule and the
guidance in the appendix, the requirements of the rule control.
An operator must comply with the following requirements in
establishing a reassessment interval for a covered segment:
Maximum Reassessment Interval
----------------------------------------------------------------------------------------------------------------
Pipeline operating at
Assessment method Pipeline operating at or above 30% SMYS, up Pipeline operating
or above 50% SMYS to 50% SMYS below 30% SMYS
----------------------------------------------------------------------------------------------------------------
Internal Inspection Tool, Pressure 10 years (*)........... 15 years (*)........... 20 years.(**)
Test or Direct Assessment.
Confirmatory Direct Assessment....... 7 years................ 7 years................ 7 years.
Low Stress Reassessment.............. Not applicable......... Not applicable......... 7 years + ongoing
actions specified in
Sec. 192.941.
----------------------------------------------------------------------------------------------------------------
(*) A Confirmatory direct assessment as described in Sec. 192.931 must be conducted by year 7 in a 10-year
interval and years 7 and 14 of a 15-year interval.
(**) A low stress reassessment or Confirmatory direct assessment must be conducted by years 7 and 14 of the
interval.
Sec. 192.941 What is a low stress reassessment?
(a) General. An operator of a transmission line that operates below
30% SMYS may use the following method to reassess a covered segment in
accordance with Sec. 192.939. This method of reassessment addresses
the threats of external and internal corrosion. The operator must have
conducted a baseline assessment of the covered segment in accordance
with the requirements of Sec. Sec. 192.919 and 192.921.
(b) External corrosion. An operator must take one of the following
actions to address external corrosion on the low stress covered
segment.
(1) Cathodically protected pipe. To address the threat of external
corrosion on cathodically protected pipe in a covered segment, an
operator must perform an electrical survey (i.e. indirect examination
tool/method) at least every 7 years on the covered segment. An operator
must use the results of each survey as part of an overall evaluation of
the cathodic protection and corrosion threat for the covered segment.
This evaluation must consider, at minimum, the leak repair and
inspection records, corrosion monitoring records, exposed pipe
inspection records, and the pipeline environment.
(2) Unprotected pipe or cathodically protected pipe where
electrical surveys are impractical. If an electrical survey is
impractical on the covered segment an operator must--
(i) Conduct leakage surveys as required by Sec. 192.706 at 4-month
intervals; and
(ii) Every 1\1/2\ years, identify and remediate areas of active
corrosion by evaluating leak repair and inspection records, corrosion
monitoring records, exposed pipe inspection records, and the pipeline
environment.
(c) Internal corrosion. To address the threat of internal corrosion
on a covered segment, an operator must--
(1) Conduct a gas analysis for corrosive agents at least once each
calendar year;
(2) Conduct periodic testing of fluids removed from the segment. At
least once each calendar year test the fluids removed from each storage
field that may affect a covered segment; and
(3) At least every seven (7) years, integrate data from the
analysis and testing required by paragraphs (c)(1)-(c)(2) with
applicable internal corrosion leak records, incident reports, safety-
related condition reports, repair records, patrol records, exposed pipe
reports, and test records, and define and implement appropriate
remediation actions.
Sec. 192.943 When can an operator deviate from these reassessment
intervals?
(a) Waiver from reassessment interval in limited situations. In the
following limited instances, OPS may allow a waiver from a reassessment
interval required by Sec. 192.939 if OPS finds a waiver would not be
inconsistent with pipeline safety.
(1) Lack of internal inspection tools. An operator who uses
internal inspection as an assessment method may be able to justify a
longer assessment period for a covered segment if internal inspection
tools are not available to assess the line pipe. To justify this, the
operator must demonstrate that it cannot obtain the internal inspection
tools within the required assessment period and that the actions the
operator is taking in the interim ensure the integrity of the covered
segment.
(2) Maintain product supply. An operator may be able to justify a
longer reassessment period for a covered
[[Page 69827]]
segment if the operator demonstrates that it cannot maintain local
product supply if it conducts the reassessment within the required
interval.
(b) How to apply. If one of the conditions specified in paragraph
(a) (1) or (a) (2) of this section applies, an operator may seek a
waiver of the required reassessment interval. An operator must apply
for a waiver in accordance with 49 U.S.C. 60118(c), at least 180 days
before the end of the required reassessment interval, unless local
product supply issues make the period impractical. If local product
supply issues make the period impractical, an operator must apply for
the waiver as soon as the need for the waiver becomes known.
Sec. 192.945 What methods must an operator use to measure program
effectiveness?
(a) General. An operator must include in its integrity management
program methods to measure, on a semi-annual basis, whether the program
is effective in assessing and evaluating the integrity of each covered
pipeline segment and in protecting the high consequence areas. These
measures must include the four overall performance measures specified
in ASME/ANSI B31.8S (ibr, see Sec. 192.7), section 9.4, and the
specific measures for each identified threat specified in ASME/ANSI
B31.8S, appendix A. An operator must submit these measures, by
electronic or other means, on a semi-annual frequency to OPS in
accordance with Sec. 192.951.
(b) External Corrosion Direct assessment. In addition to the
general requirements for performance measures in paragraph (a) of this
section, an operator using direct assessment to assess the external
corrosion threat must define and monitor measures to determine the
effectiveness of the ECDA process. These measures must meet the
requirements of Sec. 192.925. An operator must submit these measures,
by electronic or other means, on a semi-annual frequency to OPS in
accordance with Sec. 192.951.
Sec. 192.947 What records must an operator keep?
An operator must maintain, for the useful life of the pipeline,
records that demonstrate compliance with the requirements of this
subpart. At minium, an operator must maintain the following records for
review during an inspection.
(a) A written integrity management program in accordance with Sec.
192.907;
(b) Documents supporting the threat identification and risk
assessment in accordance with Sec. 192.917;
(c) A written baseline assessment plan in accordance with Sec.
192.919;
(d) Documents to support any decision, analysis and process
developed and used to implement and evaluate each element of the
baseline assessment plan and integrity management program. Documents
include those developed and used in support of any identification,
calculation, amendment, modification, justification, deviation and
determination made, and any action taken to implement and evaluate any
of the program elements;
(e) Documents that demonstrate personnel have the required
training, including a description of the training program, in
accordance with Sec. 192.915;
(f) Schedule required by Sec. 192.933 that prioritizes the
conditions found during an assessment for evaluation and remediation,
including technical justifications for the schedule.
(g) Documents to carry out the requirements in Sec. Sec. 192.923
through 192.929 for a direct assessment plan;
(h) Documents to carry out the requirements in Sec. 192.931 for
confirmatory direct assessment;
(i) Verification that an operator has provided any documentation or
notification required by this subpart to be provided to OPS, and when
applicable, a State authority with which OPS has an interstate agent
agreement, and a State or local pipeline safety authority that
regulates a covered pipeline segment within that State.
Sec. 192.949 How does an operator notify OPS?
An operator must provide any notification required by this subpart
by--
(1) Sending the notification to the Information Resources Manager,
Office of Pipeline Safety, Research and Special Programs
Administration, U.S. Department of Transportation, Room 7128, 400
Seventh Street, SW., Washington, DC 20590;
(2) Sending the notification to the Information Resources Manager
by facsimile to (202) 366-7128; or
(3) Entering the information directly on the Integrity Management
Database (IMDB) Web site at http://primis.rspa.dot.gov/gasimp/.
Sec. 192.951 Where does an operator file a report?
An operator must send any performance report required by this
subpart to the Information Resources Manager--
(1) By mail to the Office of Pipeline Safety, Research and Special
Programs Administration, U.S. Department of Transportation, Room 7128,
400 Seventh Street SW., Washington, DC 20590;
(2) Via facsimile to (202) 366-7128; or
(3) Through the online reporting system provided by OPS for
electronic reporting available at the OPS Home Page at http://ops.dot.gov
.
0
3. Appendix A to part 192 is amended by adding paragraph (9) to section
II.D, and by adding new sections II.F and II.G to read as follows:
Appendix A to Part 192--Incorporated by Reference
* * * * *
II. * * *
D. * * *
(9) ASME/ANSI B31.8S-2001 (Supplement to B31.8), ``Managing
System Integrity of Gas Pipelines,'' July 19, 2002.
E. * * *
F. NACE International
(1) NACE RP-0502-2002 ``Pipeline External Corrosion Direct
Assessment Methodology,'' 2002.
G. Gas Research Institute
(1) GRI 02-0057, ``Internal Corrosion Direct Assessment of Gas
Transmission Pipelines--Methodology,'' April 1, 2002.
0
4. A new Appendix E to Part 192 is added to part 192 to read as
follows:
Appendix E to Part 192--Guidance on Determining High Consequence Areas
and on Carrying Out Requirements in the Integrity Management Rule
I. Guidance on Determining a High Consequence Area
To determine which segments of an operator's transmission
pipeline system are covered for purposes of the integrity management
program requirements, an operator must identify the high consequence
areas. An operator must use method (1) or (2) from the definition in
Sec. 192.903 to identify a high consequence area. An operator may
apply one method to its entire pipeline system, or an operator may
apply one method to individual portions of the pipeline system.
(Refer to figure E.I.A for a diagram of a high consequence area)
(a) If an operator selects method (1), then:
(1) All pipeline in class 3 and class 4 locations is considered
to be in a high consequence area.
(2) The operator is to calculate potential impact circles, as
defined in Sec. 192.903, centered on the centerline of the pipeline
for:
(i) Any areas of its pipeline system that are not in class 3 or
class 4 locations which could include an identified site as defined
in Sec. 192.903, and
(ii) Any pipeline in class 3 and class 4 locations for which the
potential impact radius would be greater than 660 feet (200 meters)
and for which an identified site may exist in the area more than 660
feet (200 meters) but less than the potential impact radius from the
pipeline.
(3) The operator is to evaluate the potential impact circles to
determine if they contain
[[Page 69828]]
identified sites, as defined in Sec. 192.903, in accordance with
paragraph (c) of the same section.
(4) The operator is to complete identification of high
consequence areas by December 17, 2004.
(b) If an operator selects method (2) then:
(1) The operator is to calculate potential impact circles, as
defined in Sec. 192.903, centered on the centerline of the pipeline
for all areas of its pipeline where the circles could contain 20
buildings intended for human occupancy or an identified site.
(2) The operator is to evaluate the potential impact circles to
determine if they contain 20 buildings intended for human occupancy.
Each separate dwelling unit in a multiple dwelling unit building is
counted as a separate building intended for human occupancy.
(i) If the radius of the potential impact circle is greater than
660 feet (200 meters), the operator may identify a high consequence
area based on a prorated number of buildings intended for human
occupancy until December 17, 2006. If an operator chooses this
approach, the operator must prorate the number of buildings intended
for human occupancy based on the ratio of an area with a radius of
660 feet (200 meters) to the area of the potential impact circle
(i.e., the prorated number of buildings intended for human occupancy
is equal to [20 x (660 feet [or 200 meters ]/ potential impact
radius in feet [or meters])2]).
(3) The operator is to evaluate the potential impact circles to
determine if they contain identified sites, as defined in Sec.
192.903, in accordance with paragraph (c) of this section.
(4) The operator is to complete identification of high
consequence areas by December 17, 2004.
(c) Operators are to identify sites meeting the criteria of
identified sites, as defined in Sec. 192.903. The process for
identification is in Sec. 192.905. Further guidance was provided in
(68 FR 42456; July 17, 2003) titled issuance of advisory bulletin.
Operators must document, and retain for review during inspections,
their rationale for selecting the source(s) used, including why it/
they are appropriate for use.
(d) Requirements for incorporating newly identified high
consequence areas into an integrity management program are in Sec.
192.905.
BILLING CODE 4910-60-P
[[Page 69829]]
[GRAPHIC] [TIFF OMITTED] TR15DE03.000
II. Guidance on Assessment Methods for Transmission Pipelines
Operating Below 30% SMYS
(a) Table E.II.1 gives guidance to help an operator implement
requirements on assessment methods for addressing time dependent and
independent threats, for transmission pipelines operating below 30%
SMYS not in HCAs (i.e. outside of potential impact circle) but
located within Class 3 and 4 Locations.
(b) Table E.II.2 gives guidance to help an operator implement
requirements on assessment methods for addressing time dependent and
independent threats, for transmission pipelines operating below 30%
SMYS in HCAs.
(c) Table E.II.3 gives guidance on preventative & mitigative
measures addressing time dependent and independent
[[Page 69830]]
threats for transmission pipelines that operate below 30% SMYS, in
HCAs.
[GRAPHIC] [TIFF OMITTED] TR15DE03.001
[[Page 69831]]
[GRAPHIC] [TIFF OMITTED] TR15DE03.002
[[Page 69832]]
[GRAPHIC] [TIFF OMITTED] TR15DE03.003
[[Page 69833]]
[GRAPHIC] [TIFF OMITTED] TR15DE03.004
[[Page 69834]]
[GRAPHIC] [TIFF OMITTED] TR15DE03.005
[[Page 69835]]
[GRAPHIC] [TIFF OMITTED] TR15DE03.006
[[Page 69836]]
[GRAPHIC] [TIFF OMITTED] TR15DE03.007
[[Page 69837]]
Issued in Washington, DC, on December 2, 2003.
Samuel G. Bonasso,
Deputy Administrator.
[FR Doc. 03-30280 Filed 12-12-03; 8:45 am]
BILLING CODE 4910-60-C