Rule2022-17031
Pipeline Safety: Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments
Primary source
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Published
August 24, 2022
Effective
May 24, 2023
Issuing agencies
Transportation DepartmentPipeline and Hazardous Materials Safety Administration
Abstract
PHMSA is revising the Federal Pipeline Safety Regulations to improve the safety of onshore gas transmission pipelines. This final rule addresses several lessons learned following the Pacific Gas and Electric Company incident that occurred in San Bruno, CA, on September 9, 2010, and responds to public input received as part of the rulemaking process. The amendments in this final rule clarify certain integrity management provisions, codify a management of change process, update and bolster gas transmission pipeline corrosion control requirements, require operators to inspect pipelines following extreme weather events, strengthen integrity management assessment requirements, adjust the repair criteria for high-consequence areas, create new repair criteria for non-high consequence areas, and revise or create specific definitions related to the above amendments.
Full Text
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[Federal Register Volume 87, Number 163 (Wednesday, August 24, 2022)]
[Rules and Regulations]
[Pages 52224-52279]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2022-17031]
[[Page 52223]]
Vol. 87
Wednesday,
No. 163
August 24, 2022
Part IV
Department of Transportation
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Pipeline and Hazardous Materials Safety Administration
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49 CFR Part 192
Pipeline Safety: Safety of Gas Transmission Pipelines: Repair Criteria,
Integrity Management Improvements, Cathodic Protection, Management of
Change, and Other Related Amendments; Final Rule
Federal Register / Vol. 87 , No. 163 / Wednesday, August 24, 2022 /
Rules and Regulations
[[Page 52224]]
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DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
49 CFR Part 192
[Docket No. PHMSA-2011-0023; Amdt. No. 192-132]
RIN 2137-AF39
Pipeline Safety: Safety of Gas Transmission Pipelines: Repair
Criteria, Integrity Management Improvements, Cathodic Protection,
Management of Change, and Other Related Amendments
AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
Department of Transportation (DOT).
ACTION: Final rule.
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SUMMARY: PHMSA is revising the Federal Pipeline Safety Regulations to
improve the safety of onshore gas transmission pipelines. This final
rule addresses several lessons learned following the Pacific Gas and
Electric Company incident that occurred in San Bruno, CA, on September
9, 2010, and responds to public input received as part of the
rulemaking process. The amendments in this final rule clarify certain
integrity management provisions, codify a management of change process,
update and bolster gas transmission pipeline corrosion control
requirements, require operators to inspect pipelines following extreme
weather events, strengthen integrity management assessment
requirements, adjust the repair criteria for high-consequence areas,
create new repair criteria for non-high consequence areas, and revise
or create specific definitions related to the above amendments.
DATES: The final rule is effective May 24, 2023. The incorporation by
reference of certain publications listed in the rule is approved by the
Director of the Federal Register as of May 24, 2023. The incorporation
by reference of other publications listed in this rule was approved by
the Director of the Federal Register on July 1, 2020.
FOR FURTHER INFORMATION CONTACT: Technical questions: Steve Nanney,
Senior Technical Advisor, by telephone at 713-272-2855. General
information: Robert Jagger, Senior Transportation Specialist, by
telephone at 202-366-4361.
SUPPLEMENTARY INFORMATION:
I. Executive Summary
A. Purpose of the Regulatory Action
B. Summary of the Major Provisions of the Final Rule
C. Costs and Benefits
II. Background
A. Overview
B. Advance Notice of Proposed Rulemaking
C. Notice of Proposed Rulemaking and Subsequent Final Rule
III. Discussion of NPRM Comments, Gas Pipeline Advisory Committee
Recommendations, and PHMSA Response
A. IM Clarifications--Sec. Sec. 192.917(a)-(d), 192.935(a)
i. Threat Identification, Data Collection, and Integration--
Sec. 192.917(a) & (b)
ii. Risk Assessment Functional Requirements--Sec. 192.917(c)
iii. Threat Assessment for Plastic Pipe--Sec. 192.917(d)
iv. Preventive and Mitigative Measures--Sec. 192.935(a)
B. Management of Change--Sec. Sec. 192.13 & 192.911
C. Corrosion Control--Sec. Sec. 192.319, 192.461, 192.465,
192.473, 192.478, and 192.935 and Appendix D
i. Applicability
ii. Installation of Pipe in the Ditch and Coating Surveys--
Sec. Sec. 192.319 & 192.461
iii. Interference Surveys--Sec. 192.473
iv. Internal Corrosion--Sec. 192.478
v. Cathodic Protection--Sec. 192.465 & Appendix D
vi. P&M Measures--Sec. 192.935(f) & (g)
D. Inspections Following Extreme Weather Events--Sec. 192.613
E. Strengthening Requirements for Assessment Methods--Sec. Sec.
192.923, 192.927, 192.929
i. Internal Corrosion Direct Assessment--Sec. Sec. 192.923,
192.927
ii. Stress Corrosion Cracking Direct Assessment--Sec. Sec.
192.923(c), 192.929
F. Repair Criteria--Sec. Sec. 192.714, 192.933
i. Repair Criteria in HCAs--Sec. 192.933
ii. Repair Criteria in non-HCAs--Sec. 192.714
iii. Cracking Criteria--Sec. Sec. 192.714 & 192.933
iv. Dent Criteria--Sec. Sec. 192.714 & 192.933
v. Corrosion Metal Loss Criteria--Sec. Sec. 192.714 & 192.933
vi. General Discussion
G. Definitions--Sec. 192.3
i. Close Interval Survey
ii. Distribution Center
iii. Dry Gas or Dry Natural Gas
iv. Electrical Survey
v. Hard Spot
vi. ILI and In-Line Inspection Tool or Instrumented Internal
Inspection Device
vii. Transmission Line
viii. Wrinkle Bend
IV. Section-by-Section Analysis
V. Standards Incorporated by Reference
VI. Regulatory Analysis and Notices
I. Executive Summary
A. Purpose of the Regulatory Action
This final rule concludes a decade-long effort by PHMSA to amend
its regulations governing onshore natural gas transmission pipelines in
response to the tragic September 9, 2010, incident at a Pacific Gas and
Electric Company (PG&E) gas transmission pipeline in San Bruno, CA,
which resulted in the death of 8 people, injuries to more than 60 other
people, and the destruction or damage of over 100 homes. PHMSA expects
the new requirements in this final rule will reduce the frequency and
consequences of failures and incidents from onshore natural gas
transmission pipelines through earlier detection of threats to pipeline
integrity, including those from corrosion or following extreme weather
events. The safety enhancements in this final rule, therefore, are
expected to improve public safety, reduce threats to the environment
(including, but not limited to, reduction of greenhouse gas emissions
released during natural gas pipeline incidents), and promote
environmental justice for minority populations, low-income populations,
and other underserved and disadvantaged communities that are located
near interstate gas transmission pipelines.
Although the Federal Pipeline Safety Regulations (49 Code of
Federal Regulations (CFR) parts 190 through 199; PSR) applicable to gas
transmission and gathering pipeline systems set forth in parts 191 and
192 have increased the level of safety associated with the
transportation of gas, serious safety incidents continue to occur on
gas transmission and gathering pipeline systems, resulting in serious
risks to life and property. In its investigation of the 2010 PG&E
incident, the National Transportation Safety Board (NTSB) found among
several causal factors that PG&E had an inadequate integrity management
(IM) program that failed to detect and repair or remove a defective
pipe section on its gas transmission line.\1\ PG&E based its IM program
on incomplete and inaccurate pipeline information, which led to, among
other issues, faulty risk assessments, improper assessment method
selections, and internal assessments of the program that were
superficial and resulted in no meaningful improvement.\2\
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\1\ NTSB, NTSB/PAR-11-01, ``Pipeline Accident Report: Pacific
Gas and Electric Company, Natural Gas Transmission Pipeline Rupture
and Fire, San Bruno, California, September 9, 2010'' (2011) (NTSB
Incident Report on San Bruno).
\2\ NTSB Incident Report on San Bruno at 107-115.
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Prior to the PG&E incident, PHMSA had initiated an advance notice
of proposed rulemaking (ANPRM) to seek comment on whether the IM
requirements in part 192 should be changed and whether other issues
related to pipeline system integrity should be addressed by
strengthening or expanding non-IM requirements.
[[Page 52225]]
PHMSA published the ANPRM on August 25, 2011.\3\
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\3\ ``Safety of Gas Transmission Pipelines,'' 76 FR 53086 (Aug.
25, 2011).
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Based on the comments on the ANPRM, PHMSA published a notice of
proposed rulemaking (NPRM) on April 8, 2016, to seek public comments on
proposed changes to the PSR governing transmission and gathering
lines.\4\ A summary of those proposed changes pertaining to this
rulemaking, corresponding stakeholder feedback, and PHMSA's responses
to stakeholder feedback on the individual provisions, is provided below
in section III of this document (Discussion of NPRM Comments, GPAC
Recommendations, and PHMSA Response).
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\4\ ``Safety of Gas Transmission and Gathering Pipelines,'' 81
FR 20722 (Apr. 8, 2016).
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PHMSA determined that the most efficient way to manage the
proposals in the NPRM was to divide them into three separate final rule
actions. The first of these final rules was published on October 1,
2019, and addressed topics primarily relating to congressional mandates
and safety recommendations, including maximum allowable operating
pressure (MAOP) reconfirmation and material properties verification,
the expansion of integrity assessments beyond high-consequence areas
(HCA), the consideration of seismicity, in-line inspection (ILI)
launcher and receiver safety, MAOP exceedance reporting, and
strengthened requirements for assessment methods (2019 Gas Transmission
Rule).\5\ Provisions related to gas gathering pipelines were addressed
in a separate rulemaking.\6\ This rulemaking finalizes the remaining
provisions from the NPRM as outlined below.
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\5\ ``Safety of Gas Transmission Pipelines: MAOP Reconfirmation,
Expansion of Assessment Requirements, and Other Related
Amendments,'' 84 FR 52180 (Oct. 1, 2019).
\6\ ``Safety of Gas Gathering Pipelines: Extension of Reporting
Requirements, Regulations of Large, High-Pressure Lines, and Other
Related Amendments,'' 86 FR 63266 (Nov. 15, 2021) (Gas Gathering
Final Rule).
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B. Summary of the Major Provisions of the Final Rule
To reduce the risks of pipeline incidents, PHMSA is amending the
PSR applicable to gas transmission pipelines to improve the protection
of the public, property, and the environment; close regulatory gaps;
and adopt additional safety measures to improve safety inside and
outside of HCAs. Specifically, PHMSA is making changes to clarify the
IM requirements; improve the management of change (MOC) process;
strengthen corrosion control requirements; provide parameters for
inspections following extreme weather events; strengthen requirements
related to the IM assessment methods; and improve the repair criteria
for pipeline anomalies. PHMSA is also amending certain definitions in
part 192 in support of these provisions.
PHMSA is modifying the IM regulations by adding specificity to the
data integration language. The final rule establishes several pipeline
attributes that must be included in an operator's risk analysis when an
operator determines what threats are applicable to a pipeline segment.
PHMSA is also explicitly requiring that operators integrate analyzed
information into their IM programs and is requiring that data be
verified and validated. Additionally, PHMSA is issuing requirements for
applying knowledge gained through an operator's IM program, including
provisions for analyzing interacting threats, potential failures, and
worst-case incident scenarios from the initial failure to incident
termination. Several of these items were proposed in response to NTSB
findings following the PG&E incident that suggested pipeline operators
were often not conducting data analysis, data integration, threat
identification, and risk assessment in the manner originally intended
and specified in subpart O of part 192.
Similarly, following the PG&E incident, PHMSA, informed by (inter
alia) the NTSB's evaluation of the incident and ANPRM comments,
determined that the existing MOC requirements and industry practices
were not sufficient \7\ and looked to align the regulatory requirements
with the standards outlined in American Society of Mechanical
Engineers/American National Standards Institute (ASME/ANSI) B31.8S.\8\
Specifically, this final rule requires each operator of an onshore gas
transmission pipeline to develop and follow a MOC process, as outlined
in ASME/ANSI B31.8S, section 11, that addresses technical, design,
physical, environmental, procedural, operational, maintenance, and
organizational changes to the pipeline or processes, whether permanent
or temporary.
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\7\ See 81 FR 20796; NTSB Incident Report on San Bruno at 95-97
(concluding that the probable cause of the PG&E incident was PG&E's
inadequate quality assurance and quality control in 1956 during its
Line 132 relocation project, and noting that PG&E had poor quality
control during a pipe installation project that later failed in 2008
in Rancho Cordova, CA).
\8\ ASME/ANSI ``B31.8S-2004: Supplement to B31.8 on Managing
System Integrity of Gas Pipelines'' (Jan. 14, 2005).
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This final rule also improves and updates the corrosion control
requirements for gas transmission pipeline operators. Based on lessons
PHMSA has learned following several pipeline failures, and following
PHMSA's workshop on pipeline construction in Fort Worth, TX, on April
23, 2009,\9\ PHMSA determined that construction practices, including
the installation of pipe in-ditch, can result in damaged coating that
can compromise corrosion control. Therefore, this rule requires that
operators perform assessments to identify suspected damage promptly
after backfilling and then remediate any coating damage found. Further,
PHMSA has noted that the existing regulations were not always effective
at eliminating deficiencies in cathodic protection \10\ corrosion
control or at preventing incidents from internal corrosion. Therefore,
this rule strengthens the requirements for internal and external
corrosion controls related to monitoring requirements and surveys.
PHMSA also determined that additional prescriptive preventive and
mitigative (P&M) measures are needed for managing electrical
interference currents.
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\9\ <a href="https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=58">https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=58</a>.
\10\ Cathodic protection is a technique used to control
corrosion by making the metal pipe a cathode of an electrochemical
cell. Essentially, the pipeline is connected to a more easily
corroded metal that acts as an anode. That ``sacrificial anode''
metal corrodes instead of the metal that is being protected. For
pipelines, passive galvanic cathodic protection is often not
adequate, and an external direct current (DC) electrical power
source is used to provide sufficient current.
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Extreme weather has been a contributing factor in several pipeline
failures. PHMSA issued Advisory Bulletins in 2015, 2016, and 2019 to
communicate the potential for damage to pipeline facilities caused by
severe flooding, including actions that operators should consider
taking to ensure the integrity of pipelines in the event of flooding,
river scour, river channel migration, and earth movement.\11\ As PHMSA
has noted in another series of Advisory Bulletins, hurricanes are also
capable of causing extensive damage to both offshore and inland
pipelines.\12\
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\11\ ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Flooding, River Scour, and River Channel
Migration,'' 80 FR 19114 (Apr. 9, 2015); ``Pipeline Safety:
Potential for Damage to Pipeline Facilities Caused by Flooding,
River Scour, and River Channel Migration,'' 81 FR 2943 (Jan. 19,
2016); ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Earth Movement and Other Geological Hazards,''
84 FR 18919 (May 2, 2019).
\12\ ``Potential for Damage to Pipeline Facilities Caused by the
Passage of Hurricane Ivan,'' 69 FR 57135 (Sept. 23, 2004);
``Pipeline Safety Advisory: Potential for Damage to Pipeline
Facilities Caused by the Passage of Hurricane Katrina,'' 70 FR 53272
(Sept. 7, 2005); ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by the Passage of Hurricanes,'' 76 FR 54531 (Sept.
1, 2011) (alerting operators to the potential for damage from
Hurricane Ivan).
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[[Page 52226]]
Because of the frequency and severe consequences of these
events,\13\ operators must protect the public from pipeline risks in
the event of a natural disaster or extreme weather. While many prudent
operators might voluntarily perform inspections following such events,
the potential risk to public safety and environment merits codification
of those practices in regulatory requirements. Therefore, PHMSA is
amending the PSR to require that operators commence inspection of their
potentially affected facilities within 72 hours after the operator
determines the affected area can be safely accessed following the
cessation of an extreme weather event such as a hurricane, landslide,
flood; a natural disaster, such as an earthquake; or another similar
event that has the likelihood to damage infrastructure. If an operator
finds an adverse condition during the inspection, the operator must
take appropriate remedial action to ensure the safe operation of the
pipeline.\14\
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\13\ For the impacts of climate change on precipitation;
droughts, floods, and wildfire; and extreme storms, see U.S. Global
Change Research Program, ``Climate Science Special Report: Fourth
National Climate Assessment, Volume 1,'' at ch. 7-9 (2017).
\14\ PHMSA notes that these part 192 amendments are consistent
with similar provisions adopted for part 195 for hazardous liquid
pipelines. See ``Pipeline Safety: Safety of Hazardous Liquid
Pipelines,'' 84 FR 52260 (Oct. 1, 2019).
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PHMSA is also strengthening the standards for performing pipeline
assessments by incorporating by reference certain consensus standards
for both stress corrosion cracking (NACE International Standard
Practice 0204-2008, ``Stress Corrosion Cracking Direct Assessment
Methodology'' (2008) (NACE 0204-2008)) and internal corrosion direct
assessments (NACE International Standard Practice 0206-2006, ``Internal
Corrosion Direct Assessment Methodology for Pipelines Carrying Normally
Dry Natural Gas'' (2006) (NACE SP0206-2006)). Operators are already
required to assess the condition of gas transmission pipelines in HCAs
and certain non-HCAs periodically in accordance with Sec. Sec.
192.710, 192.921, and 192.937. When the initial IM regulations creating
subpart O were issued in 2003 (2003 IM rule), industry standards did
not exist for these types of assessments.\15\ By incorporating by
reference the standards subsequently published by NACE
International,\16\ PHMSA is ensuring greater consistency, accuracy, and
quality when operators perform these assessments.
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\15\ ``Pipeline Safety: Pipeline Integrity Management in High
Consequence Areas (Gas Transmission Pipelines): Final Rule,'' 68 FR
69778 (Dec. 15, 2003).
\16\ In 2021, NACE International merged with the Society for
Protective Coatings, becoming the Association for Materials
Protection and Performance (AMPP). They will continue to be referred
to as NACE International throughout this document.
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This final rule also updates the existing repair criteria for HCAs
by incorporating criteria for additional anomaly types such as crack
anomalies, certain corrosion metal loss defects, and certain mechanical
damage defects. Such revisions will provide greater assurance that
operators will repair injurious anomalies and defects before those
defects grow to a size that causes a leak or rupture. PHMSA also is
finalizing explicit repair criteria for non-HCAs. Prior to this final
rule, there were only general requirements in the regulations for
operators to perform repairs in non-HCAs. The content of the non-HCA
repair criteria being finalized in this rule is consistent with the
criteria for HCAs; however, PHMSA has provided longer timeframes for
the remediation of conditions that are not categorized as ``immediate''
conditions to provide operators the ability to prioritize remediating
anomalous conditions in HCAs where consequences of a pipeline failure
may be greater.
The various changes in this rule have also prompted additions and
changes to certain definitions in part 192. PHMSA has created or made
changes to the following terms: ``close interval survey,''
``distribution center,'' ``dry gas or dry natural gas,'' ``hard spot,''
``in-line inspection (ILI),'' ``in-line inspection tool or instrumented
internal inspection device,'' ``transmission line,'' and ``wrinkle
bend.''
C. Costs and Benefits
PHMSA has prepared an assessment of the benefits and costs of the
final rule as well as reasonable alternatives. PHMSA estimates the
annual costs of the rule to be approximately $17 million, calculated
using a 7 percent discount rate. The costs reflect improvements made to
the MOC process, additional corrosion control requirements, the
provisions related to inspections following extreme weather events, and
the changes made to the repair criteria. PHMSA finds that the other
final rule requirements will not result in incremental costs.
PHMSA is posting the Regulatory Impact Analysis (RIA) for this rule
in the public docket. PHMSA has determined that the regulatory
amendments adopted in this final rule will improve public safety,
reduce threats to the environment (including, but not limited to,
reduction of methane emissions contributing to the climate crisis), and
promote environmental justice for minority populations, low-income
populations, and other underserved and disadvantaged communities. PHMSA
finds the regulatory amendments adopted in this final rule are
technically feasible, reasonable, cost-effective, and practicable
because the public safety, environmental, and equity benefits of its
regulatory amendments described herein and within its supporting
documents (including the RIA and environmental assessment, each
available in the docket for this rulemaking) will justify any
associated costs and demonstrate and the superiority of the final rule
compared to alternatives.
II. Background
A. Overview
On September 9, 2010, a 30-inch-diameter natural gas transmission
pipeline, owned and operated by PG&E, ruptured in a residential
neighborhood in San Bruno, CA. The rupture produced a crater
approximately 72 feet long by 26 feet wide. The segment of pipe that
ruptured weighed approximately 3,000 pounds, was 28 feet long, and was
found 100 feet south of the crater. When the escaping gas ignited, the
resulting fire killed 8 people, injured approximately 60 more,
destroyed or damaged 108 homes, and caused the evacuation of over 300
people. In its pipeline accident report for the incident, the NTSB
determined that the probable cause of the incident was PG&E's
inadequate quality control and assurance when it relocated the line in
1956 and its inadequate IM program. The NTSB determined that PG&E's IM
program was deficient and ineffective because it was based on
incomplete and inaccurate pipeline information, did not consider how
the pipeline's design and materials contributed to the risk of a
pipeline failure, and failed to consider the presence of previously
identified welded seam cracks as part of its risk assessment. These
deficiencies resulted in the selection of an assessment method that
could not detect welded seam defects and led to internal assessments of
PG&E's IM program that were superficial and resulted in no
improvements. Ultimately, this inadequate IM program failed to detect
and repair or replace the defective pipe section.
[[Page 52227]]
In response to this incident, Congress, the NTSB, and the
Government Accountability Office (GAO) called for PHMSA to improve IM
and address other weaknesses and gaps in the PSR. As described in more
detail in the sections that follow, this is the second of three planned
rulemakings that are the culmination of this rulemaking initiative.
B. Advance Notice of Proposed Rulemaking
On August 25, 2011, PHMSA published an ANPRM to seek public
comments regarding potential revisions to the PSR pertaining to the
safety of gas transmission and gathering pipelines. PHMSA requested
comments on 122 questions spread across 15 broad issues involving IM
and non-IM requirements. The issues related to IM requirements included
whether the definition of an HCA should be revised and whether
additional restrictions should be placed on the use of certain pipeline
assessment methods. The issues related to non-IM requirements included
whether revised requirements were needed for mainline valve spacing and
actuation, whether requirements for corrosion control should be
strengthened, and whether new regulations were needed to govern the
safety of gas gathering lines and underground natural gas storage
facilities. Based on the comments received on several of the ANPRM
topics, PHMSA developed specific proposals for some of those topics in
an NPRM that was the basis for this final rule.
C. Notice of Proposed Rulemaking and Subsequent Final Rule
On April 8, 2016, PHMSA published an NPRM seeking public comments
on proposed revisions to the PSR pertaining to the safety of onshore
gas transmission pipelines and gas gathering pipelines. PHMSA
considered the comments it received from the ANPRM and proposed new
pipeline safety requirements and revisions of existing requirements in
several major topic areas. A summary of the NPRM proposals and topics
pertinent to this rulemaking, the comments received on those specific
proposals, and PHMSA's response to the comments received, is provided
under section III (Discussion of NPRM Comments, GPAC Recommendations,
and PHMSA Response).
On October 1, 2019, PHMSA promulgated a subset of the rules
proposed in the NPRM by issuing the first of three planned final rules.
In that rule, PHMSA addressed gas transmission pipelines and
established minimum Federal safety standards for MAOP reconfirmation,
pipeline physical material properties verification, the expansion of
integrity assessments beyond HCAs, the consideration of seismicity in
an operator's risk assessment and P&M measures, ILI tool launcher and
receiver safety, MAOP exceedance reporting, and strengthened
requirements for IM assessment methods.
This final rule, the second of three planned rules, finalizes
several proposed amendments in the NPRM related to gas transmission
pipelines, including provisions related addressing repair criteria, IM
improvements, cathodic protection, MOC processes, and other related
amendments. A separate rulemaking, dealing with the safety of onshore
gas gathering pipelines, was the subject of a final rule published on
November 15, 2021, and extended reporting and safety requirements to
certain gathering pipelines that were formerly not subject to Federal
safety oversight. PHMSA estimated in that Gas Gathering Final Rule that
there were over 400,000 miles of gas gathering pipelines that were not
subject to minimum Federal pipeline safety standards, including basic
incident and mileage reporting. The Gas Gathering Final Rule extended
annual and incident reporting requirements to all gathering pipelines
and defined a new category of ``Type C'' gathering pipelines to address
the safety of larger-diameter, higher-pressure onshore gathering
pipelines that were formerly unregulated. The scope of the requirements
for Type C gas gathering pipelines are risk-based; basic damage
prevention provisions apply to all Type C gas gathering pipelines while
other safety requirements apply to larger-diameter Type C gas gathering
pipelines or those Type C gas gathering pipelines that are located near
buildings intended for human occupancy.
III. Discussion of NPRM Comments, Gas Pipeline Advisory Committee
Recommendations, and PHMSA Response
The comment period for the NPRM ended on July 7, 2016. PHMSA
received approximately 300 submissions to the docket containing
thousands of comments on the NPRM. Submissions were received from the
NTSB; groups representing the regulated pipeline industry; groups
representing public interests, including environmental groups; State
utility commissions and regulators; members of Congress; individual
pipeline operators; and private citizens. PHMSA also received late-
filed comments to this rulemaking from the major industry trade
associations and others following advisory committee meetings as
discussed below. Consistent with DOT Order 2100.6 and 190.323, PHMSA
considered all comments, including those that were filed late, given
their relevance to the rulemaking and the absence of additional expense
or delay resulting from considering these comments.
Some of the comments PHMSA received in response to the NPRM were
considered in finalizing the 2019 Gas Transmission Rule targeted at
statutory mandates, while other comments were considered in response to
the third final rule on gas gathering pipelines (under RIN 2137-AE38).
In this final rule, PHMSA considers those comments that are relevant to
repair criteria, IM improvements, cathodic protection, MOC, and other
related amendments. PHMSA does not address the comments on pipeline
safety issues that were beyond the scope of the NPRM and, therefore,
beyond the scope of this final rule. However, that does not mean that
PHMSA determined the comments lack merit or do not support additional
rules or amendments. Such issues may be the subject of other existing
rulemaking proceedings or may be addressed in future rulemaking
proceedings. The remaining comments reflect a wide variety of views on
the merits of particular sections of the proposed regulations.
The Technical Pipeline Safety Standards Committee, commonly known
as the Gas Pipeline Advisory Committee (GPAC or ``the committee''), is
a statutorily mandated advisory committee that advises and comments on
PHMSA's proposed safety standards, risk assessments, and safety
policies for natural gas pipelines prior to their final adoption. The
GPAC is one of two pipeline advisory committees focused on technical
safety standards that were established under the Federal Advisory
Committee Act (Pub. L. 92-463) and section 60115 of the Federal
Pipeline Safety Statutes (49 U.S.C. 60101 et seq.). Each committee
consists of approximately 15 members, with membership equally divided
among Federal and State agencies, regulated industry, and the public.
The committees consider the ``technical feasibility, reasonableness,
cost-effectiveness, and practicability'' of each proposed pipeline
safety standard and provide PHMSA with recommended actions pertaining
to those proposals.
Due to the size and technical detail of the NPRM, the GPAC met 5
times in 2017 and 2018 to discuss the proposed
[[Page 52228]]
regulations applicable to gas transmission pipelines. The GPAC convened
one time in 2019 to discuss the provisions related specifically to gas
gathering pipelines.\17\ During those meetings, the GPAC considered the
specific regulatory proposals of the NPRM and discussed various
comments made on the NPRM's proposal by stakeholders, including the
pipeline industry at large, public interest groups, and government
entities. To assist the GPAC in its deliberations, PHMSA presented a
description and summary of the major proposals in the NPRM and the
comments received on those issues. Stakeholders could comment on the
proposals during the meeting prior to the committee discussion. PHMSA
assisted the committee in fostering discussion and developing
recommendations by providing direction on which issues were most
pressing.
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\17\ Specifically, the committee met on January 11-12, 2017;
June 6-7, 2017; December 14-15, 2017; March 2, 2018; March 26-28,
2018; and June 25-26, 2019. Information on these meetings can be
found at <a href="http://regulations.gov">regulations.gov</a> under docket no. PHMSA-2011-0023 and at
PHMSA's public meeting page: <a href="https://primis.phmsa.dot.gov/meetings/">https://primis.phmsa.dot.gov/meetings/</a>.
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For the proposals addressed in this final rule, the committee came
to consensus when voting on the technical feasibility, reasonableness,
cost-effectiveness, and practicability of the NPRM's provisions. In
many instances, the committee recommended changes to certain proposals
that the committee found would make the rule more feasible, reasonable,
cost-effective, or practicable.
This section discusses the substantive comments on the NPRM that
were submitted to the docket, as well as the GPAC's recommendations.
They are organized by topic and include PHMSA's response to, and
resolution of, those comments.
A. IM Clarifications--Sec. Sec. 192.917(a)-(d), 192.935(a)
i. Threat Identification, Data Collection, and Integration--Sec.
192.917(a) and (b)
1. Summary of PHMSA's Proposal
Subpart O of 49 CFR part 192 prescribes requirements for managing
pipeline integrity in HCAs and requires that operators identify and
evaluate all potential threats to each covered pipeline segment.
Operators are required to identify threats to which the pipeline is
susceptible, collect data for analysis, and perform a risk assessment
that informs the operator's baseline assessment schedule and
reassessment intervals as well as any additional P&M measures that may
be needed for the covered segment. The regulations also require
operators to address particular threats, such as third-party damage and
manufacturing and construction defects. For these requirements, the
regulations reference, through incorporation, ASME/ANSI B31.8S.
For threat identification, the regulations in Sec. 192.917 specify
that the potential threats operators must consider include, but are not
limited to, the threats listed in section 2 of ASME/ANSI B31.8S. Those
threats are grouped into time-dependent threats, static or resident
threats, time-independent threats, and human error. In performing data
gathering and integration, operators must follow the requirements in
ASME/ANSI B31.8S, section 4. At a minimum, operators must gather and
evaluate the set of data specified in Appendix A to ASME/ANSI B31.8S,
which are the year of installation; pipe inspection reports; leak
history; wall thickness; diameter; past hydrostatic test information;
gas, liquid, or solid analysis; bacteria culture test results;
corrosion detection devices; operating parameters; and operating stress
level. An operator must also conduct a risk assessment that follows
ASME/ANSI B31.8S section 5.
In a risk-based IM approach, data collection and integration is the
backbone of an effective IM program. The PG&E incident exposed several
problems in the way operators collect and manage pipeline condition
data, showing that some operators have inadequate records regarding the
physical and operational characteristics of their pipelines. The use of
erroneous information leads to insufficient understanding of pipeline
risks and incorrect integrity-related decision making. PG&E's IM
program was missing or misidentified data elements that were necessary
to characterize risk correctly and establish and validate MAOP, which
is critically important for providing an appropriate margin of safety
to the public.
Threat identification, data collection, and data integration are
basic pillars on which IM was founded with the issuance of the 2003 IM
rule. As specified in Sec. 192.907(a), operators were to start with a
framework, evolve that framework into a more detailed and comprehensive
program, and continually improve their IM programs.\18\ Operators would
accomplish this constant improvement, in part, through learning about
the IM process itself and learning more about the physical condition of
their pipelines via IM assessments and the development of that data.
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\18\ See 68 FR 69789.
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Data collection for new pipeline construction is relatively simple.
However, collecting missing material property records for pipeline
segments that have been in the ground for years can be challenging, as
such data collection must be completed through integrity assessments or
excavations. Operators are required to identify missing data and apply
conservative assumptions, but incomplete data presents issues for risk
assessment. The over-application of assumptions in the absence of real
data, even if those assumptions are conservative, can lead to skewed or
otherwise inaccurate risk analysis results.
In the NPRM, PHMSA proposed to revise Sec. 192.917 to include
specific requirements for collecting, validating, and integrating
pipeline data. These requirements would add further specificity to the
data integration regulations, list specific pipeline attributes that
must be included in these analyses, explicitly require that operators
integrate analyzed information, and require that data be verified and
validated. PHMSA also proposed to require that operators use validated,
objective data to the maximum extent practical. To the degree that
subjective data from subject matter experts (SME) must be used, PHMSA
would require that operator programs include specific features to
compensate for SME bias, including training SMEs to recognize or avoid
bias, and using outside technical experts or independent expert reviews
to assess SME judgment and logic. Further, in Sec. 192.917(b)(3),
PHMSA proposed to require operators to identify and analyze spatial
relationships among anomalous information (e.g., corrosion coincident
with foreign line crossings and evidence of pipeline damage where
overhead imaging shows evidence of encroachment), stating that storing
or recording the information in a common location, including a
geographic information system (GIS) alone, is not sufficient.
2. Summary of Public Comment
Many stakeholders agreed with PHMSA that verified and validated
data is important for data integration and threat analysis. The NTSB
expressed support for the proposed additions to the IM analysis
requirements and commented that expanded pipeline record and data
requirements are a significant safety improvement in the management of
pipelines through their service lifecycle. However, certain
[[Page 52229]]
stakeholders had concerns with PHMSA's specific proposed changes.
PHMSA also received comments from the industry on the feasibility
of threat identification, data gathering, and integration. The American
Petroleum Institute (API) stated that while the totality of attributes
listed in proposed Sec. 192.917 should not pose a major burden on the
industry, some specific attributes listed may not be feasible to obtain
in practice. Enterprise Products stated that including just four or
five attributes that point to a specific conclusion would be more
useful than the lengthy list of attributes in the proposed provisions.
A few commenters requested PHMSA clarify what they meant by ``data
integration, verification, and validation,'' as these terms were not
clear.
The Interstate Natural Gas Association of America (INGAA) and the
Texas Pipeline Association (TPA) expressed concern that the proposed
provisions are more prescriptive than the ASME/ANSI standard that is
referenced in the current IM requirements. INGAA also commented that
PHMSA's proposed inclusion of specific attributes from ASME/ANSI B31.8S
in the regulatory text alongside the existing incorporation by
reference of that standard could cause confusion. INGAA further stated
that PHMSA should retain the current regulatory language requiring
operators to ``consider'' the relevant data for covered segments and
similar non-covered segments, instead of adopting the proposed
provisions that would require data evaluation for non-covered segments.
INGAA also stated that many of the data elements required by ASME/ANSI
B31.8S are not available for older pipelines, which can include non-
covered segments. INGAA and other commenters also asserted that PHMSA
should provide sufficient time for operators to comply with the
proposed data validation and integration requirements given the
expansion of Sec. 192.917(b)(1) to non-covered segments.
Several commenters provided input on PHMSA's proposed requirements
to address SME bias. INGAA suggested PHMSA should delete the references
to SME bias listed in Sec. 192.917(b)(2) and replace the text with
more general language to include peer reviews and external SME
verification, citing this alternative as more consistent and clearer
than what PHMSA proposed. National Fuel stated that using outside
technical experts for bias control would be unnecessarily costly to
pipeline operators. The American Gas Association (AGA) asserted that
using outside technical subject matter experts for bias control is
already standard practice within the industry and that it is not
necessary to codify it into regulation. PG&E also suggested
improvements to the section, stating that there is not an existing
industry standard to provide guidance on what constitutes an outside
technical expert to perform this specific function, and PHMSA should
provide further guidance on this topic.
Several industry trade groups provided input on the proposed
language in Sec. 192.917(b)(3) that would require operators to
identify and analyze the spatial relationship among anomalous
information (e.g., corrosion coincident with foreign line crossings and
evidence of pipeline damage where overhead imaging shows evidence of
encroachment). TPA stated that it disagreed with PHMSA's proposal in
this paragraph and commented that this requirement would impose a
financial burden on smaller operators. PG&E asserted that the proposed
language in Sec. 192.917(b)(3) should be removed entirely since it was
not clear how to comply with these requirements.
At the GPAC meeting on June 7, 2017, the committee noted that the
NPRM's proposed revisions to Sec. 192.917 do not include a way for
operators to address the lack of availability of some data sets. The
committee suggested that operators could assume the pipeline segment is
susceptible to the threat associated with the missing data. The
committee also questioned the purpose for the extensive, prescriptive
data list, with some members believing it would turn into a compliance
paperwork exercise without safety benefit. This, in turn, led to a
discussion of how an operator demonstrates to a regulator that it is
performing an effective risk analysis and whether that is a checklist
of items or performing actions to generate better safety outcomes. Some
committee members suggested PHMSA clarify that operators should only
collect the pertinent data for operations and maintenance (O&M) tasks.
Committee members representing the industry noted the rule has no
timeframe for the implementation of data collection and challenged the
conclusion in the preliminary regulatory impact assessment (PRIA) that
the data collection elements had a cost of zero, as databases may need
to be upgraded to implement the listed attributes. Members representing
the industry also requested PHMSA remove the proposed requirement to
address SME bias; however, other committee members representing the
public noted that SME bias in risk analysis is recognized across
different disciplines and reflects a need to address how humans think
about risk. Certain committee members representing the industry were
also concerned that the requirements mandated the use of a GIS, which
might be impractical for small operators.
Following the discussion, the committee voted 11-0 that the
proposed rule, as published in the Federal Register, with regard to the
provisions for IM clarifications regarding threat identification, data
collection, and data integration, were technically feasible,
reasonable, cost-effective, and practicable if PHMSA revised the list
of pipeline attributes in the section to be more consistent with the
existing regulations and the ASME/ANSI B31.8S standard, and if PHMSA
also added language requiring operators to collect data that is
pertinent and that a prudent operator would collect. The committee also
recommended PHMSA require operators to have implementation procedures
in place 1 year after the effective date of the rule, with full
incorporation of all listed attributes by 3 years after the effective
date of the rule, and strike requirements for operators to use a GIS in
complying with these provisions. Finally, the committee recommended
that PHMSA address SME bias by considering some of the specific
suggestions made by committee members at the meeting, including
striking or revising the last sentence of the provisions.
3. PHMSA Response
The current regulations at Sec. 192.917(b) explicitly require
that, at a minimum, an operator must gather and evaluate the set of
data specified in Appendix A to ASME/ANSI B31.8S. Operators may not
ignore that requirement to collect the minimum set of data needed for a
robust threat evaluation and risk assessment. PHMSA agrees that some
assumptions regarding threat applicability based upon pipe type,
operating parameters, and operating environment (i.e., weld seam type,
manufacturing date, coating type, operating pressure versus percentage
specified minimum yield strength (SMYS), operating temperature, lack of
cathodic protection (CP) or the time when CP was placed on the system,
and location) can be made even if the pertinent data is missing. For
example, a lack of CP on a pipeline system would mean that the pipeline
is more prone to external corrosion, no matter what type of external
coating is on the pipe. High operating temperatures, pressures, and a
lack of quality pipe coating can also be risk factors for cracking.
Regarding INGAA's comment on retaining the current regulatory
[[Page 52230]]
language requiring operators to ``consider'' the relevant data for
covered segments and similar non-covered segments rather than adopting
the proposed provisions that would require data evaluation for non-
covered segments, PHMSA reminds operators that the current requirement
states that operators must gather and integrate existing data and
information on the entire pipeline that could be relevant to the
covered segment. At a minimum, operators 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 the data
and conditions specific to each pipeline. PHMSA's clarification in this
final rule that operators must ``analyze'' the information that they
are already required to collect, integrate, and consider, is consistent
with the existing requirement, as performing those actions is,
essentially, an analysis. Nevertheless, PHMSA is changing ``consider''
to ``analyze'' to reinforce that operators must have documentation
demonstrating that they have reviewed the data for similar vintage pipe
to determine whether they have threats or not that should be
remediated.
PHMSA further disagrees that it is appropriate to allow industry to
continue to ``consider'' data elements selectively or that only
specifying a few required data elements is the best approach. While
some pipelines without associated data may not pose a risk, some may
pose a significant risk. Comprehensive data is the best way to ensure
an appropriate assessment and, in turn, reduction of risk. The addition
of the specific data elements in the regulatory text clarifies PHMSA's
expectations of data collection. PHMSA agrees, however, that some data
elements may not be pertinent to all pipeline segments. Therefore, in
this final rule, PHMSA is revising the proposed requirement to specify
that the operator must collect ``pertinent'' data ``about pipeline
attributes to assure safe operation and pipeline integrity, including
information derived from operations and maintenance activities,'' as
recommended by the GPAC. Regarding the cost of this data collection,
all the proposed elements were listed in ASME/ANSI B31.8S. As that
standard has been incorporated by reference since 2004 for covered
segments (i.e., HCAs), collecting the listed data should not be a new
or an extensive exercise for any prudent operator with appropriate
processes in place. While specifying the list of data elements in the
regulatory text is new, the elements listed have been incorporated by
reference since the promulgation of subpart O and are not more
prescriptive than the current regulations. Further, PHMSA disagrees
that continuing to incorporate by reference ASME/ANSI B31.8S as well as
specifying individual data elements will confuse operators.
Additionally, in response to comments and the GPAC recommendation,
PHMSA is revising the listing of data elements to be more consistent
with ASME/ANSI B31.8S. In some cases, PHMSA has clarified the meaning
of generic terms in the data collection list found in ASME/ANSI B31.8S
within this final rule. For example, where the ASME/ANSI standard lists
``material properties,'' PHMSA has elaborated by specifying these are
``material properties including, but not limited to, grade, SMYS, and
ultimate tensile strength.'' In another example, where the standard
lists ``pipe inspection reports,'' PHMSA has itemized, in this final
rule, the pipe inspections required by part 192 and that are commonly
performed by operators.
PHMSA agrees with commenters that sufficient time should be
allotted for operators to comply with the data integration
requirements. However, PHMSA also agrees with the comments made that
operators should have been collecting and accounting for the pertinent
items of this data set since the publication of the original IM rule
almost 20 years ago. Therefore, in this final rule, PHMSA is providing
a phased-in timeframe. The GPAC recommended that the implementation
timeframe should begin in year 1, with full incorporation by 3 years.
Given the existing requirements for collecting and using the data
elements from ASME/ANSI B31.8S, and given the discussion at the GPAC
meetings and the public comments received, PHMSA has revised this final
rule to require that an operator must begin data integration on the
effective date of the rule and integrate all attributes within 18
months of this rule's publication date.
Regarding comments calling for clarification of what ``data
integration, verification, and validation'' meant, PHMSA notes that, at
a minimum, an operator should consider the same set of data on a
periodic basis and analyze changes and trends that would indicate the
need for additional integrity evaluations.
Regarding SME bias, PHMSA believes that it is important for
operators to address SME bias in data collection and risk assessment to
account for the reality of how humans think about risk. Operators
should take this into consideration when incorporating SME opinion as
fact or when treating input from all SMEs as equivalent. While some
operators may effectively account for SME bias, PHMSA has not observed
this to be universal practice in the industry. To the point commenters
made that using outside technical experts for bias control is
unnecessarily costly, PHMSA notes that the use of outside technical
experts would be optional: this final rule contemplates that operators
could also employ training to ensure information provided by their own
SMEs is consistent and accurate. While commenters also correctly noted
that there is not an existing industry standard as to what constitutes
an outside technical expert or an independent technical expert for SME
bias control, an operator is ultimately responsible for determining the
appropriateness and conductors of such a review. As a part of such a
review, should an operator decide to have another SME review input from
another SME, the operator must use a qualified SME--e.g., an individual
with formal or on-the-job technical training in the technical or
operational area being analyzed, evaluated, or assessed. Operators
would be required to document that the SME is appropriately
knowledgeable and experienced in the subject being assessed.
PHMSA was persuaded, consistent with a GPAC recommendation, that
some adjustments to the rule language are appropriate for clarity, or
to eliminate redundant language, within the non-exhaustive list of
specific types of data to be collected at Sec. 192.179(a) and (b).
Specific changes adopted in this final rule include the following:
<bullet> Section 192.917(a)(2): deleted a redundant reference to
``or equipment defects;''
<bullet> Section 192.917(b)(1)(iii): deleted explicit material
properties (e.g., hardness, chemical composition) from a non-exhaustive
list of material properties;
<bullet> Section 192.917(b)(1)(xxiv): added ``seam cracking''
within the list of pipe operational and maintenance inspection reports
to be reviewed;
<bullet> Section 192.917(b)(1)(xxv): deleted a redundant reference
to ``outer/inner diameter corrosion monitoring;''
<bullet> Section 192.917(b)(1)(xxviii): eliminated specific
examples of ``encroachments;'' and
<bullet> Section 192.917(b)(1)(xxxvi): deleted a redundant savings
clause for ``other pertinent information'' when the lead-in to the
section noted that the information listed was non-exhaustive.
[[Page 52231]]
PHMSA has also, consistent with a recommendation by the GPAC
revised the rule by (1) requiring that operators employ adequate
control measures for SME input to ensure consistent and accurate
information rather than ``correct'' SME ``bias;'' and (2) requiring
that operators document the names and qualifications of individuals who
approve SME input rather than document the names of the SMEs and the
information provided.
Concerning the use of a GIS, the NPRM's proposed revisions to Sec.
192.917 were not intended to imply that all operators were required to
implement a GIS system but were meant to clarify that data integration
is not achieved solely by maintaining spatially located data in a GIS
system. Accordingly, PHMSA has revised this final rule as recommended
by the GPAC to delete reference to the use of a GIS system and maintain
the core requirement to identify and analyze spatial relationships
among anomalous information.
A. IM Clarifications--Sec. Sec. 192.917(a)-(d), 192.935(a)
ii. Risk Assessment Functional Requirements--Sec. 192.917(c)
1. Summary of PHMSA's Proposal
Section 192.917(c) requires operators to perform a risk assessment
as part of an effective IM program. A risk assessment is an important
element of a good IM plan. PHMSA analyzed the issues related to risk
assessments that the NTSB identified in its investigation and held a
workshop on July 21, 2011, to address perceived shortcomings in the
implementation of IM risk assessments. PHMSA also sought input from
stakeholders on these issues in the ANPRM. Based on the input received
from both the ANPRM and the workshop, PHMSA determined that additional
clarification was needed to emphasize the functions that risk
assessments must accomplish and to elaborate on effective processes for
risk management, both of which are critical to effective IM.
To address these issues, PHMSA proposed to clarify the risk
assessment aspects of the IM regulations at subpart O by including the
following functional requirements for risk assessments that operators
should perform to assure pipeline integrity:
<bullet> Evaluate the effects of interacting threats;
<bullet> Ensure validity of the methods used to conduct the risk
assessment;
<bullet> Determine additional P&M measures needed;
<bullet> Analyze how a potential failure could affect an HCA,
including the consequences of the entire worst-case incident scenario,
from initial failure to incident termination;
<bullet> Identify how each risk factor, or each combination of risk
factors that simultaneously interact, contribute to risk at a common
location;
<bullet> Account and compensate for uncertainties in the model and
the data used in the risk assessment; and
<bullet> Evaluate risk reduction associated with candidate
activities, such as P&M measures.
2. Summary of Public Comment
Public interest groups supported PHMSA's proposed revisions at
Sec. 192.917(c) to strengthen the functional requirements for risk
assessment models. The Pipeline Safety Trust (PST) stated that the risk
assessment models currently used by pipeline operators are inadequate
and further noted that the proposed provisions could go farther to
advance risk assessment quality. Other GPAC members representing the
public supported the proposed revisions at Sec. 192.917(c) during the
committee meetings and noted that the NPRM language for this topic was
written using a risk-informed approach that articulated the functions
and purposes of risk assessments without being prescriptive as to the
method or process to be used, which is consistent with IM principles.
Multiple industry trade associations and individual operators
acknowledged the importance of risk assessments but believed that the
proposed revisions at Sec. 192.917(c) were too prescriptive. Several
individual operators emphasized their voluntary efforts to improve
their risk models and disagreed that the industry's risk models needed
further prescription.
Many commenters emphasized that different pipeline systems are
susceptible to different threats and believed that operators are best
suited to determine which threat analyses are relevant to their
systems. Multiple operators expressed the opinion that the proposed
revisions at Sec. 192.917(c) would require operators to expand
datasets substantially but would contribute little benefit to risk
identification, suggesting instead that integrating unnecessary
datasets would distract from other safety efforts. AGA and several
individual operators requested that PHMSA give operators discretion to
select which data sets to incorporate into risk assessments for their
system.
Some commenters requested that PHMSA specify what the NPRM meant
when it proposed to revise Sec. 192.917(c) to require operators to
``validate'' data. These commenters expressed doubts regarding the
technical feasibility of implementing the proposed regulations in Sec.
192.917(c), noting that some of the data PHMSA proposed requiring for
the validation of risk assessment models is not available. These
commenters proposed that operators be permitted to apply conservative
values or values determined using engineering judgement. Southwest Gas
Corporation, Paiute Pipeline, and Consumers Pipeline expressed concern
that developing the newly required datasets would require the usage of
ILI tools that their pipelines are not configured to accommodate. These
commenters stated that gathering these datasets would present costs
that were not captured by PHMSA's PRIA because PHMSA did not account
for the cost of making lines piggable.
Multiple commenters were concerned that the proposed revisions
would make operators' current relative risk models invalid and would
require a transition to quantitative or probabilistic risk models.
Similarly, API agreed with that assessment and noted that quantitative
and probabilistic models are not useful or appropriate for the
analysis, prediction, or prevention of low-frequency, high-consequence
events such as the PG&E incident. Further, API noted that the
probabilities of certain infrequent circumstances and conditions
occurring at a single location and single time are so low that the
quantitative or probabilistic risk models would not identify them
because there are no statistics available from which to predict them.
AGA asserted that the proposed requirements deviate from industry
standards and that PHMSA did not provide sufficient justification for
this departure. Commenters also emphasized the high costs associated
with implementing quantitative risk models, which can include the
procurement of specialist expertise, development of new datasets, and
transition to a GIS or other new database management system.
Kern River requested clarification regarding which elements of
Sec. 192.917 need to be included in an operator's risk model and which
elements only need to be included in the overall IM plan. They noted
that integrity assessment method determinations, repair decisions, P&M
measures selection, root cause analyses, and similar pipe studies all
play a part in the overall IM plan and have at times overlapping, but
also unique, requirements for data gathering, integration, and threat
analysis.
[[Page 52232]]
AGA and several individual operators expressed concerns that the
proposed rule does not provide a timeline for implementing new risk
assessment requirements, thereby implying that operators must implement
new requirements by the rule's effective date. Multiple operators and
industry trade associations requested that operators be permitted to
develop their own implementation schedules or provided suggestions for
specific implementation schedules. For example, Enterprise Products
requested that PHMSA include a 2-year implementation period for
operators to incorporate the data integration and risk assessment
requirements into their IM programs.
At the GPAC meeting on January 12, 2017, some committee members
noted that any revisions to the risk assessment requirements should be
deferred until after PHMSA's Pipeline Risk Modeling Work Group issues
its pipeline system risk modeling technical document.\19\ There was
broad support from the committee for the revisions to Sec. 192.917(c)
proposed in the NPRM, with members noting the language was consistent
with IM principles and was written using a performance-based approach
that articulated the functions and purposes of risk assessment without
being prescriptive as to the method or process needing to be used.
However, some committee members representing the industry expressed
concern with the use of the term ``probability'' in the NPRM's proposed
revisions to Sec. 192.917(c), which seemed to imply PHMSA intended for
operators to be using probabilistic risk assessment techniques.
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\19\ For more information on the work group and its efforts, see
<a href="https://www.phmsa.dot.gov/pipeline/risk-modeling-work-group/risk-modeling-work-group-overview">https://www.phmsa.dot.gov/pipeline/risk-modeling-work-group/risk-modeling-work-group-overview</a>.
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Following the discussion, the committee voted 11-0 that the
proposed provisions for the risk assessment requirements were
technically feasible, reasonable, cost-effective, and practicable if
PHMSA modified the proposed rule to restore the reference to ASME/ANSI
B31.8S, section 5, to clarify that other methods besides probabilistic
techniques may be used; change the term ``probability'' to
``likelihood'' and delete the term ``risk factors'' from Sec. 192.917
(c)(2); and provide a 3-year phase-in period for risk assessments to
meet the functional objectives specified in Sec. 192.917(c).
3. PHMSA Response
On March 6, 2020, PHMSA published the final report titled
``Pipeline Risk Modeling--Overview of Methods and Tools for Improved
Implementation'' from the joint PHMSA/industry working group on risk
modeling.\20\ However, PHMSA notes that the report is focused
exclusively on the models employed and ``best practices'' for using
them. The working group did not address other aspects of the proposed
rule, including how a risk assessment is used.
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\20\ <a href="https://www.phmsa.dot.gov/news/now-available-phmsa-report-pipeline-risk-modeling-overview-methods-and-tools-improved-0">https://www.phmsa.dot.gov/news/now-available-phmsa-report-pipeline-risk-modeling-overview-methods-and-tools-improved-0</a>.
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PHMSA believes that the revisions to Sec. 192.917(c) are important
to include in this rulemaking now, as many operators have not
substantially improved their risk assessment techniques or models since
the early initial efforts to prioritize baseline assessment plans in
2004, with the findings from the PG&E incident being a prime, national
example. Therefore, PHMSA is establishing explicit minimum standards
for the functional requirements of a risk assessment to help assure
that operators will achieve this specific aspect of a ``more detailed
and comprehensive'' program as discussed in the 2003 IM rule.
In the NPRM's proposed revisions to Sec. 192.917(c), when PHMSA
used terms such as ``probability'' and ``risk factors,'' it was not
intended to imply that an operator must perform probabilistic risk
analysis. To address this, PHMSA has modified the rule language to
replace the term ``probability'' with ``likelihood'' and restored the
reference to ASME/ANSI B31.8S, section 5, for acceptable risk
assessment methodologies as recommended by the GPAC. Similarly, and as
also recommended by the GPAC, PHMSA has deleted the phrase ``or risk
factors'' from paragraph Sec. 192.917(c)(2) for clarity. Whichever
risk assessment methodology an operator chooses, the result must meet
the functional requirements and accomplish the purposes specified in
this final rule.
PHMSA notes that all data elements specified in Sec. 192.917(b)
are important for a robust risk assessment. While operators do have the
discretion to expand their data collection efforts, this minimum
defined data set is required to be used. As was emphasized by multiple
operators in their comments, each pipeline system is susceptible to
different threats, and the individual operator is best suited to
determine these threats. However, an operator needs the specified data
elements to identify threats objectively. As noted in the previous
section, PHMSA has modified the rule to refer to the ``pertinent'' data
elements, including information derived from O&M activities that assure
safe operation and pipeline integrity. This revision clarifies that
data elements that are not pertinent for a given pipeline segment need
not be included in a risk assessment.
Pertaining to comments regarding the validity of the method used,
an operator must ensure the soundness of the risk modelling method they
are using applicable to the threats to a given pipeline segment,
including its specific leak or failure history. To Kern River's comment
as to which elements of Sec. 192.917 need to be included in an
operator's risk model and which elements need to be included in an
operator's IM plan, PHMSA will note that integrity assessment method
determinations, repair decisions, P&M measure selection, and root cause
analyses are examples of items that could be included in an operator's
risk model based on the particular types of threats being assessed. The
existing regulations state that a ``particular threat'' is an
identified threat being assessed for each covered segment.
As discussed above, some commenters claimed there would be high
costs associated with implementing quantitative risk models, which
might include the procurement of specialist expertise, the development
of new data sets, and a transition to a GIS or other new database
management system. PHMSA notes that operators can use the same data
they have been, and are currently, collecting when implementing a
quantitative risk model. Operators do not necessarily have to
``recollect'' or otherwise change their existing data to use a
probabilistic risk model.
Given the state of some operators' risk assessment programs, PHMSA
is persuaded that it is reasonable to allow operators a reasonable
amount of time to upgrade their risk assessment models, methodologies,
and analyses. However, this is an important provision that operators
need to implement as soon as practicable. Therefore, and to be more
consistent with the implementation for the data attributes discussed
earlier, PHMSA is modifying this final rule to allow an 18-month
implementation period for this provision.
A. IM Clarifications--Sec. Sec. 192.917(a)-(d), 192.935(a)
iii. Threat Assessment for Plastic Pipe--Sec. 192.917(d)
1. Summary of PHMSA's Proposal
PHMSA proposed to add to the regulations examples of threats unique
to plastic pipe that operators must consider, such as poor joint fusion
practices, pipe with poor slow crack
[[Page 52233]]
growth (SCG) resistance, brittle pipe, circumferential cracking,
hydrocarbon softening of the pipe, internal and external loads,
longitudinal or lateral loads, proximity to elevated heat sources, and
point loading. The proposed revisions would not otherwise change the
current requirements of Sec. 192.917(d).
2. Summary of Public Comment
PHMSA did not receive any public comments on this section. At the
GPAC meeting on June 7, 2017, PHMSA noted in its presentation to the
committee that there were no public comments on the issue.
Subsequently, the GPAC voted 11-0 that the proposed changes to the
provisions for IM clarifications for threat assessments for plastic
pipe were technically feasible, reasonable, cost-effective, and
practicable, and they did not recommend any additional changes to Sec.
192.917(d).
3. PHMSA Response
Since PHMSA did not receive any public comments or additional GPAC
recommendations regarding threat assessment for plastic pipe, the final
rule includes the requirement in Sec. 192.917(d) as proposed in the
NPRM. PHMSA proposed these changes to highlight these potential threats
to both operators and inspectors, and finalizing these requirements
will provide additional safety and enforcement awareness.
A. IM Clarifications--Sec. Sec. 192.917(a)-(d), 192.935(a)
iv. Preventive and Mitigative Measures--Sec. 192.935(a)
1. Summary of PHMSA's Proposal
PHMSA's inspection experience shows that some operators do not
implement additional P&M measures based on the evaluation required at
Sec. 192.935(a). PHMSA believes that strengthening requirements
related to operators' use of insights gained from their IM programs is
prudent to ensure effective risk management. Therefore, PHMSA proposed
to clarify the expectation that operators use knowledge from risk
assessments to establish and implement adequate P&M measures and
provided more explicit examples of the types of P&M measures for
operators to evaluate.
2. Summary of Public Comment
Several commenters requested that PHMSA revise the requirements at
Sec. 192.935(a) to remove the requirement for operators to perform all
the listed measures to prevent a pipeline failure and to mitigate the
consequences of a pipeline failure in an HCA. These commenters stated
that requiring operators to perform all the measures listed at Sec.
192.935(a) negates the need for a risk analysis, as the rule would then
require that operators perform each of the listed actions regardless of
whether conditions warrant these actions or whether past efforts have
been taken. INGAA suggested that PHMSA should keep the existing
language, which states that an operator must base the additional
measures on the threats the operator has identified to each pipeline
segment. GPAC members representing the industry echoed INGAA's claims
during the committee meetings.
During the GPAC meeting on June 7, 2017, the GPAC noted that
PHMSA's proposed changes removed a statement that an operator must base
additional P&M measures on the threats an operator has identified for
each pipeline segment. The proposed text, the members believed, implied
an operator would be required to evaluate and implement each listed P&M
measure every time. Based on PHMSA's webinars and other discussions,
the committee members didn't believe that was PHMSA's intent.
Following that discussion, the committee voted 11-0 that the
proposed provisions for strengthening the requirements for applying IM
knowledge were technically feasible, reasonable, cost-effective, and
practicable if PHMSA clarified it was not the agency's intent to
require that all listed P&M measures be implemented, and that operators
``must consider'' the listed items.
3. PHMSA Response
PHMSA agrees that all listed measures are not mandatory for
implementation in all cases. Requiring an operator to implement P&M
measures against threats that might not be applicable to their
particular system could be overly burdensome. However, PHMSA has
determined that requiring operators to consider the listed measures in
their risk analyses and apply them to threats as appropriate is a
practical requirement. As recommended by the GPAC, the final rule has
been modified to reflect that position; each operator will be required
to consider the listed measures and determine the appropriateness of
each for their system.
B. Management of Change--Sec. Sec. 192.13 & 192.911
1. Summary of PHMSA's Proposal
Section 192.911(k) requires that an operator's IM program include a
MOC process as outlined in ASME/ANSI B31.8S, section 11. That document
guides operators to develop formal MOC procedures to identify and
consider the impact of major and minor changes to pipeline systems and
their integrity. These changes can include technical, physical,
procedural, and organizational changes, and they can be either
temporary or permanent changes. Per ASME/ANSI B31.8S, section 11, an
operator's MOC process should include the reason for the change, the
authority for approving changes, an analysis of the implications of the
change, the proper acquisition of the necessary work permits,
appropriate documentation, communications of the change to any affected
parties, time limitations of the change, and the qualification of
staff. The document notes that changes to a pipeline system might
require changes to an operator's IM program; similarly, changes to an
IM program might also cause changes to a pipeline system. If changes in
land use (e.g., increased population) would affect the potential
consequence of an incident or the likelihood of an incident occurring,
such a change should be reflected in an operator's IM program. The
operator should also reevaluate threats accordingly. In short, the MOC
process outlined by ASME/ANSI B31.8S helps to ensure that an operator's
IM process remains viable and effective as changes to pipeline systems
occur or new data becomes available.
Inadequately reviewed or documented design, construction,
maintenance, or operational changes can contribute to pipeline
failures. In the PG&E incident, the NTSB investigation determined that
a substandard piece of pipe was substituted in the field without proper
authorization, design review, or approval. PHMSA has subsequently
determined that more specific attributes of the MOC process should be
explicitly codified within the text of Sec. Sec. 192.13 (general
requirements) and 192.911(k) (IM requirements). As a result, PHMSA
proposed to require that operators have a MOC process that includes the
reasons for the change; the authority for approving changes; an
analysis of implications; the acquisition of required work permits; and
evidence documenting communication of the change to affected parties,
time limitations, and the qualification of staff.
[[Page 52234]]
2. Summary of Public Comment
Public interest groups, such as the PST, and the National
Association of Pipeline Safety Representatives (NAPSR) agreed with and
supported the proposed MOC provisions, stating that these provisions
would enhance pipeline safety. Several individual pipeline operators
and trade associations opposed the proposed MOC provisions, stating
that the provisions are generally too broad and would be applied to
many routine activities that already have established procedures. More
specifically, AGA stated that they would create a new requirement for
each transmission operator to have a formal MOC process to document and
evaluate all changes to pipelines and processes. They further stated
that the proposed revisions are unnecessary due to current industry
progress related to MOC and the voluntary adoption of industry
consensus standards.
Several commenters opposed the proposed addition of four types of
changes (design, environmental, operational, and maintenance),
asserting that these elements are not included in current industry
standards or recommended practices. Similarly, INGAA asserted that
PHMSA should eliminate the changes it proposed to Sec. 192.13 that go
beyond the recommendations of ASME/ANSI B31.8S. These commenters stated
that PHMSA significantly underestimated the impact and burden caused by
codifying and expanding the scope of MOC.
Several commenters, including AGA, API, and INGAA, opposed the
proposed immediate implementation of the MOC provisions, with some
commenters requesting an implementation period of 1 to 5 years. These
commenters stated that the proposed changes were significant and would
need to be incorporated into existing MOC processes, and that
additional time would be needed to complete this in an effective
manner. Many commenters also expressed concern over the retroactive
application of the proposed MOC provisions.
At the GPAC meeting on January 12, 2017, the committee voted 8--2
that the proposed MOC revisions were technically feasible, reasonable,
cost-effective, and practicable if PHMSA provided a 2-year phase-in
period for the regulations as they pertain to non-IM pipeline assets,
provided a notification procedure for justified extensions, clarified
the requirements only covers significant changes that affect safety and
the environment, and clearly stated that the revisions do not apply to
distribution or gathering lines. The dissenters in the vote
(representatives from the Environmental Defense Fund (EDF) and PST)
were members representing the public, who thought that the proposed
revisions were acceptable as proposed in the NPRM, the phase-in period
recommended by the majority of the GPAC was too long, and that there
was no reason that the proposed revisions should not apply to gathering
lines.
3. PHMSA Response
PHMSA believes that an operator must understand the impacts that
their decisions have on safety and the environment. Therefore, PHMSA
believes that specifying the types of changes that must be addressed
under a MOC program is appropriate. PHMSA also believes that the
proposed changes to the MOC provisions conform with the requirements
and intent of ASME/ANSI B31.8S.
However, based on the comments received and GPAC recommendations,
PHMSA is persuaded that, as published in the NPRM, the language of
proposed Sec. 192.13(d) could be overly broad. Therefore, PHMSA has
revised the requirement to specify the requirement applies to a
``significant change that poses a risk to safety or the environment''
to limit the application of this requirement to significant changes, as
the GPAC recommended. Additionally, and as also recommended by the
GPAC, PHMSA is specifying that Sec. 192.13(d) is not retroactive and
applies only to onshore transmission pipelines (i.e., not gathering or
distribution pipelines).\21\
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\21\ PHMSA stated, in response to written comments submitted in
the docket and discussion during the January 2017 GPAC meeting, that
it would in the final rule limit application of the NPRM's proposed
management of change amendments at Sec. 192.13(d) to exclude gas
distribution and gathering lines. PHMSA notes, however, that (1)
PHMSA has undertaken a rulemaking (under RIN 2137-AF53) that will
consider extending those or similar requirements to gas distribution
pipelines as required by a mandate in section 204 of the Protecting
our Infrastructure of Pipelines and Enhancing Safety Act of 2020
(Pub. L. 116-260)); and (2) PHMSA may consider extending those or
similar requirements to gas gathering lines as PHMSA obtains more
information on the safety risks of such pursuant to enhanced
reporting requirements codified by PHMSA's Gas Gathering Final Rule.
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PHMSA agrees that operators should be afforded time to comply with
this new requirement, but also believes that operators can apply this
process to non-HCA assets more promptly than the period that the GPAC
recommended. Therefore, operators have 18 months for the MOC process to
be fully incorporated for non-HCA pipeline segments. PHMSA is also
including a notification procedure in accordance with Sec. 192.18 for
operators to apply for an extension, of up to 1 year, of the compliance
deadline. PHMSA believes including this compliance deadline strikes a
balance between the GPAC recommendation and the implementation of a
procedure that operators already have in place for HCA pipeline
segments, and including a notification procedure to provide operators
with more time, if necessary, effectively implements the GPAC
recommendations.
C. Corrosion Control--Sec. Sec. 192.319, 192.461, 192.465, 192.473,
192.478, and 192.935 and Appendix D
i. Applicability
1. Summary of PHMSA's Proposal
Incidents attributed to corrosion continue to occur, which
demonstrates that the current requirements can be more effective at
preventing incidents caused by certain types of corrosion. This
includes compromised pipe or pipe coating caused by damage from
construction, cathodic protection deficiencies, interference currents,
and internal corrosion. As a result, PHMSA proposed several changes to
the regulations for corrosion control, including new requirements for
pipe coating assessments, protective coating strength, P&M measures,
and additional mitigation of stray current (also referred to as
interference current). PHMSA also proposed changes regarding gas stream
monitoring program requirements to mitigate internal corrosion. These
proposed revisions were made in Sec. Sec. 192.319, 192.461, 192.465,
192.473, and 192.935(f) and (g) and are discussed more thoroughly in
this section. PHMSA also proposed to add a new Sec. 192.478 for the
monitoring and mitigation of internal corrosion.
2. Summary of Public Comment
The Coalition to Reroute Nexus, the Michigan Coalition to Protect
Public Rights-of-Way, NAPSR, and the PST supported the proposed changes
regarding corrosion control and pipeline condition monitoring.
Earthworks suggested that PHMSA issue even more stringent requirements
given the number of post-Carlsbad incidents that have occurred due to
corrosion.\22\ The Pipeline Safety Coalition, the Public Service
Commission of West Virginia, and the Pennsylvania Public Utility
[[Page 52235]]
Commission stated that not all gathering pipelines should be exempt
from corrosion monitoring.
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\22\ An incident near Carlsbad, NM, on August 19, 2000, which
was caused due to corrosion, killed 12 people and caused nearly $1
million in damage. The incident was a catalyst for PHMSA's IM
program requirements for pipelines.
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Some commenters requested clarification regarding whether the
proposed provisions were intended to include transmission,
distribution, and gathering pipelines. Other commenters provided input
on whether gathering pipelines should be included in the corrosion
control requirements, especially alternating current voltage gradient
(ACVG) and direct current voltage gradient (DCVG) inspections in
proposed Sec. 192.461.
During the meeting on June 7, 2017, GPAC committee members
questioned whether the corrosion control requirements would apply to
gathering lines--the presumption among the majority of the members was
that the requirements were not intended to include gathering or
distribution lines. The committee provided other feedback specific to
the applicability and implementation of specific corrosion topic areas,
which are discussed in the applicable sections below.
3. PHMSA Response
PHMSA has considered the comments received regarding the
applicability of the proposed corrosion control requirements. PHMSA
stated at the June 2017 GPAC meetings, in response to comments received
on the NPRM and the discussions during the GPAC meeting, that it would
in the final rule exclude gathering and distribution pipelines from the
NPRM's proposed requirements in subpart I related to corrosion control.
Accordingly, PHMSA has revised Sec. 192.9 to exempt gathering lines
from several of these requirements. PHMSA, however, may consider
expanding this provision to gathering lines in the future. Comments on
the specific provisions proposed for corrosion control are addressed in
the following sections.
As to commenters requesting the regulations be made even more
strict than proposed, PHMSA notes that changes more stringent than
those proposed would require further notice. PHMSA believes that
currently, there is also not sufficient data to justify more stringent
changes. PHMSA will continue to review all data sources on the subject,
including incident and annual reports, and consider more stringent
corrosion control safety requirements in a future rulemaking if there
is data supporting the need.
C. Corrosion Control--Sec. Sec. 192.319, 192.461, 192.465, 192.473,
192.478, and 192.935 and Appendix D
ii. Installation of Pipe in the Ditch and Coating Surveys--Sec. Sec.
192.319 and 192.461
1. Summary of PHMSA's Proposal
Section 192.319 prescribes requirements for installing pipe in a
ditch, including requirements to protect pipe coating from damage
during the process. While most operators perform the required high-
voltage holiday detection \23\ on the pipeline prior to it being placed
into the ditch, pipe coating can sometimes be damaged during the
handling, lowering, and backfilling process, which can compromise its
ability to prevent external corrosion. To address this problem, PHMSA
proposed to require that onshore gas transmission pipeline operators
perform an above-ground indirect assessment through an ACVG or DCVG
survey to identify locations of suspected damage promptly after an
operator completes the backfilling process. Per the proposal, operators
would remediate any moderate or severe coating damage issues identified
by such an assessment, which, was defined as where there are voltage
drops of greater than 35 percent for DCVG or 50 dB[mu]V for ACVG.
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\23\ ``Holidays'' are essentially holes or gaps in the coating
film that exposes the pipeline to corrosion. The inspections of
pipeline coating through electronic defect detectors is commonly
also referred to as ``jeeping.''
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Section 192.461 prescribes requirements for protective coating
systems. PHMSA notes that pipe coating can disbond \24\ from the pipe
and shield the pipe from CP. The NTSB determined that this was a
significant contributing factor in the major crude oil spill that
occurred near Marshall, MI, in 2010. As a result, PHMSA determined that
additional requirements are needed to specify that coating should not
impede cathodic protection. Further, and as discussed above, PHMSA
determined that additional requirements are needed so that operators
verify that pipeline coating systems for protection against external
corrosion have not become compromised or damaged during the
installation and backfill process performed during maintenance,
repairs, or pipe replacement.\25\
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\24\ Disbonding is the failure of a coating to adhere to the
underlying substance to which it was applied. Specific to pipelines,
it is a loss of adhesion between the cathodic coating and the pipe
due to a corrosive reaction taking place.
\25\ This is similar to a proposal in Sec. 192.319 for new
construction.
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In the NPRM, PHMSA proposed to revise Sec. 192.461(a) to require
that pipelines have sufficient coating to protect against damage from
being handled. PHMSA also proposed to add Sec. 192.461(f) to require
operators to perform an above-ground coating survey within 3 months of
placing the pipeline into service and require operators to repair
moderate or severe coating damage within 6 months of the assessment.
2. Summary of Public Comment
Stakeholders representing the public, including NAPSR and the PST,
generally agreed with and supported the revisions to this section,
stating that such requirements would increase safety and were a good
step towards reducing the number of incidents that occur due to
corrosion. Many commenters stated that ACVG/DCVG surveys are not always
feasible and that PHMSA should not limit the tools for performing
coating surveys to the two types specified in Sec. Sec. 192.319 and
192.461(f). For example, INGAA stated that PHMSA did not provide
justification for requiring coating surveys, such as ACVG and DCVG, to
be used to detect coating issues after construction or after performing
a repair or replacement. INGAA further stated that PHMSA should allow
operators to use other assessment technologies, such as close interval
surveys (CIS) and high- resolution geometry ILI inspection tools, to
detect and manage post-construction, post-repair, and post-replacement
conditions that contribute to external corrosion.
AGA and AGL Resources (now Southern Company Gas) commented that
depth of cover and excessive pavement can make indirect surveys
impossible. Further, AGA stated that while conducting post-construction
surveys is industry best practice, activities that are not always
feasible for operators to complete should not be codified within the
regulations.
NACE expressed concern that ACVG and DCVG surveys do not address
the stated goal of identifying coatings that impede cathodic protection
and objected to setting specific thresholds for these tests. Similarly,
INGAA stated that if the requirements for operators to perform coating
surveys using ACVG and DCVG are finalized, the proposed voltage drop
threshold value in Sec. 192.461(f) should be eliminated.
Industry commenters also stated objections or suggested limitations
to the timeframe proposed in Sec. 192.461(f) regarding when these
surveys should be performed, stating that the 3-month timeline is
inconsistent with the 1-year period allowed to install cathodic
protection after the construction of a
[[Page 52236]]
pipeline in existing Sec. 192.455(a)(2). New Jersey Natural Gas
expressed concern that 3 months may not be adequate both to procure
qualified personnel and to perform these surveys and have a fully
mature cathodic protection system to perform a successful coating
assessment. NAPSR believed that, unless there was a technical reason
for the 3-month deadline for the surveys, the timeline might be too
conservative due to service procurement and seasonal conditions.
Therefore, they recommended extending the assessment deadline.
API and Enterprise Products commented that PHMSA does not provide
any supporting evidence that backfilling a ditch for an onshore
transmission pipeline is, or has been, an issue meriting the need for
ACVG or DCVG surveys to assess coating integrity. Further, API and
Southern California Gas Company stated that Sec. 192.319(a) already
requires all operators of transmission gas pipelines to ``protect the
pipe coating from damage,'' either in initial installation, or any time
the pipe is exposed and backfill material is added. Therefore, the
proposed provisions may be duplicative with Sec. 192.461.
At the GPAC meeting on June 6 and 7, 2017, committee members
representing the industry echoed many of the comments received, noting
also that ACVG and DCVG surveys may not address issues related to
coatings impeding CP. Additionally, some of these members noted that
coating surveys are not always feasible, and that PHMSA should not
limit the tools for performing such surveys. Further, several GPAC
members representing the industry suggested that PHMSA should not set
specific repair thresholds in the regulations, and that the provisions
do not align with current NACE standards.\26\ Certain committee members
also recommended applying a greater-than-1000-feet standard for this
provision, which would match a proposed requirement for external
corrosion control under Sec. 192.461 and thought that the timeline for
the above-ground coating survey should be extended from 3 months to 1
year to synchronize with current CP installation requirements. The
committee also suggested PHMSA clarify the applicability of these
provisions is limited to transmission pipelines.
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\26\ When the ANPRM was being developed, NACE did have standards
for ACVG/DCVG surveys. Since the development of this final rule,
NACE has subsequently revised those standards, and there is no
longer a standard for these surveys.
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Therefore, the committee voted 10-0 that these provisions proposed
at Sec. Sec. 192.319 and 192.461 were technically feasible,
reasonable, cost-effective, and practicable if PHMSA: (1) raised the
repair threshold from ``moderate'' to ``severe'' indications, (2)
modified the requirements to apply to segments greater than 1,000 feet
in length to be consistent with other similar corrosion control
requirements, (3) extended the assessment and remediation timeframe to
6 months after a pipeline is placed into service and made allowances
for delayed permitting, (4) adjusted the recordkeeping requirements so
that operators would be required to make and retain for the life of the
pipeline records documenting indirect assessment findings and remedial
actions, and (5) provided flexibility for the use of alternative
technology unless the agency objected.
3. PHMSA Response
Operators have historically assumed that coating is functioning as
intended after construction. However, the NTSB report on the Enbridge
crude oil accident near Marshall, MI, identified shielded CP due to
disbonded coating as being a contributing cause of the failure.
Whenever an operator backfills a pipeline, there is the potential for
coating damage. PHMSA believes that conducting coating surveys after
backfill is a reasonable and reliable way for operators to identify
coating damage inflicted during the construction process before
significant corrosion occurs. This is a means for an operator to
confirm, after pipeline construction or replacement, that the pipe
coating is not compromised and is functioning as intended.
PHMSA believes that ACVG/DCVG surveys are currently the best and
most reliable means of detecting coating damage following construction,
as opposed to a CIS survey, which is a complementary survey employed to
assess the performance of CP systems. However, PHMSA desires to promote
the development of new technologies and methods and acknowledges that
other technology could be used for performing coating assessments.
Therefore, in this final rule, PHMSA is allowing an operator to notify
PHMSA of the intent to use other technology, which it may use unless an
objection is received, as was recommended by the GPAC. PHMSA's review
of such notification would evaluate whether an operator has
demonstrated that the ``other technology'' provides equivalent
protection to public safety and the environment compared the existing
technologies contemplated by this final rule. As a part of its
evaluation, PHMSA considers whether there are technical papers from
standard developing organizations that support the use of the new
technology, as well as any research that has been conducted on that
technology and any usage of the technology in other industries and non-
regulated pipelines.
PHMSA disagrees that the voltage drop threshold value used as the
remediation criterion should be eliminated from the regulation but does
agree that the values in the proposed revisions to Sec. Sec. 192.319
and 192.461 in the NPRM were conservative as they would indicate
``moderate'' coating damage. Therefore, in this final rule and as
recommended by the GPAC, PHMSA is specifying the voltage drop threshold
value associated with a ``severe'' indication of coating damage as
recommended by GPAC.
As recommended by the GPAC, PHMSA is persuaded that the 3-month
proposed timeline may not be practical in all situations and has
modified the final rule to allow operators up to 6 months after the
pipeline is placed into service to complete the necessary assessments
and remediation (with allowance for time required to obtain permits, if
required). PHMSA has also included a requirement for the associated
recordkeeping requirements of these provisions that includes the
editorial changes recommended by the GPAC; specifically, that operators
must make and retain for the life of the pipeline records documenting
the indirect assessment findings and remedial actions.
PHMSA also modified both sections to apply to segments greater than
1,000 feet in length to be consistent with other corrosion control
requirements that were similarly altered in this final rule. PHMSA
notes that the application of these requirements to segments greater
than 1,000 feet in length is also consistent with conditions that have
been applied in several special permit applications.
As a part of the requirements for these sections, PHMSA has
provided in the regulatory text that the applicable coating surveys
must be conducted, except in locations where effective coating surveys
are precluded by geographical, technical, or safety reasons.\27\ These
might include crossings of major interstates or rivers. An operator
must document, in accordance with a technically proven
[[Page 52237]]
analysis, any decision made not to perform such a coating survey.
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\27\ For example, coating surveys could require drilling holes
in roadways, or digging up pipe--each of which entail their own
risks to public safety and the environment. Some of the pipelines
that would be surveyed could either be cased or have thick-walls,
further complicating efforts to conduct coating surveys.
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As noted before, PHMSA did not intend for these provisions to apply
to gathering or distribution pipelines, and it has clarified the
applicability of these provisions to transmission lines only. However,
PHMSA may expand the application of these provisions in a future
rulemaking.
C. Corrosion Control--Sec. Sec. 192.319, 192.461, 192.465, 192.473,
192.478, and 192.935 and Appendix D
iii. Interference Surveys--Sec. 192.473
1. Summary of PHMSA's Proposal
Interference currents occur when metallic structures pick up a
stray electrical current from elsewhere and discharge the current,
thereby causing corrosion. These currents can negate the effectiveness
of cathodic protection systems. The sources of stray current problems
are commonplace; they can result from other underground facilities,
such as the cathodic protection systems from crossing or parallel
pipelines, light rail systems, commuter train systems, high-voltage
alternating current (HVAC) electrical lines, or other sources of
electrical energy in proximity to the pipeline. Stray current corrosion
is electrochemical corrosion that occurs when potential differences
between a high-conductivity steel pipeline and lower-conductivity
environments causes the stray current to flow through the pipe and
create a corrosion cell. If stray current or interference issues are
not remediated, accelerated corrosion could occur and potentially
result in a leak or rupture. Section 192.473 prescribes general
requirements to minimize the detrimental effects of interference
currents. However, specific requirements to monitor and mitigate
detrimental interference currents have not been prescribed in subpart I
of part 192. Therefore, in the NPRM, PHMSA proposed to explicitly
require operators to conduct interference surveys and remediate adverse
conditions in a timely manner. Specifically, PHMSA proposed to amend
Sec. 192.473 to require that an operator's program include
interference surveys to detect the presence of interference currents
and take remedial actions within 6 months of completing the survey.
Additionally, PHMSA proposed to require in Sec. 192.473 that operators
perform periodic interference surveys whenever needed.
2. Summary of Public Comment
Generally, stakeholders representing the public agreed with and
supported the revisions to this section, noting that the requirements,
as proposed, could help reduce the number of pipeline incidents caused
by corrosion. Numerous trade associations and pipeline companies were
concerned about the proposed requirements for interference surveys
under Sec. 192.473. Commenters, including Atmos Energy Corporation and
AGA, expressed doubt regarding the ability of individual operators to
obtain the necessary information from electric transmission providers.
APGA and INGAA urged PHMSA to limit this new requirement to specific
transmission lines, such as those pipelines subject to the threat of
stray electric current. Commenters, including INGAA, also stated that
the provisions should allow for the phased-in implementation of
remediation measures and provided timeframes from 12 to 18 months. Some
commenters suggested a lengthened implementation period for this
requirement due to the potential difficulties in obtaining the proper
permits.
At the GPAC meeting on June 7, 2017, certain committee members
believed that these requirements should apply only to lines that are
subject to stray current risks and noted that interference surveys
might not be feasible depending on the information operators can obtain
from electricity transmission companies. Committee members also
suggested a phased-in compliance period between 12 and 18 months for
these requirements, and noted, similarly to the proposed external
corrosion provisions, that the remediation period did not account for
activities like obtaining the necessary permits. There was also
extensive discussion at the meeting regarding PHMSA's proposed use of
the word ``significant'' in context of the level of corrosion that
would need to be remediated, with several committee members suggesting
that phrase be tied to a numeric threshold for easier compliance. The
committee also discussed, at length, what PHMSA's expectation for a
remediation ``plan'' is and what the necessary paper trail would look
like for compliance.
After discussion, the committee voted 9-0 that the provisions for
external corrosion interference currents are technically feasible,
reasonable, cost-effective, and practicable if PHMSA clarified that the
surveys are required for lines subject to stray currents and updated
the remediation timeframe to require operators create a remediation
procedure and apply for necessary permits within 6 months and complete
remediation activities within 12 months with allowances for delayed
permitting. The committee also specifically recommended that PHMSA
clarify that operators must take remedial action when the interference
is at a level that could cause significant corrosion as being 100 amps
per meter squared, or if it impedes the safe operating pressure of the
pipeline, or if it may cause a condition that would adversely affect
the environment or the public.
3. PHMSA Response
PHMSA agrees with commenters that every pipeline segment is not
equally subject to stray current. Therefore, in this final rule, PHMSA
is modifying Sec. 192.473 as recommended by the GPAC to clarify that
interference surveys are required when electric potential monitoring
indicates a significant increase in stray current, or new potential
stray current sources are introduced. Additionally, PHMSA recognizes
the need for objective remediation criteria and has included the
criteria recommended by the GPAC, specifically ``greater than or equal
to 100 amps per meter squared or if it impedes the safe operation of a
pipeline or may cause a condition that would adversely impact the
environment or the public.'' PHMSA has also revised this final rule to
establish a remediation timeframe of 15 months, with allowance for
delayed permitting, as recommended by the GPAC.
C. Corrosion Control--Sec. Sec. 192.319, 192.461, 192.465, 192.473,
192.478, and 192.935 and Appendix D
iv. Internal Corrosion--Sec. 192.478
1. Summary of PHMSA's Proposal
Section 192.477 prescribes requirements to monitor internal
corrosion by coupon testing or other means if corrosive gas is being
transported. However, the regulation is silent on standards for
determining whether corrosive gas is being transported or regarding any
changes occurring that could introduce corrosive contaminants in the
gas stream. The existing regulations also do not prescribe that
operators continually or periodically monitor the gas stream for the
introduction of corrosive constituents through system changes, changing
gas supply, abnormal conditions, or other changes. This could result in
pipelines that are not monitored for internal corrosion because an
initial assessment did not identify the presence of corrosive gas.
As such, PHMSA determined that additional requirements are needed
to ensure that operators effectively monitor gas stream quality to
identify if and when corrosive gas is being transported and to mitigate
deleterious gas stream constituents such as contaminants or
[[Page 52238]]
liquids. In the NPRM, PHMSA proposed to add a new Sec. 192.478 to
require onshore gas transmission pipeline operators monitor for
deleterious gas stream constituents and evaluate gas monitoring data
quarterly. The proposed Sec. 192.478 would also add a requirement for
onshore gas transmission pipeline operators to review their internal
corrosion monitoring and mitigation program semi-annually and adjust
the program as necessary to mitigate the presence of deleterious gas
stream constituents. These requirements would be in addition to the
existing requirements to check coupons or perform other measures to
monitor for the presence of internal corrosion when transporting a
known corrosive gas.
2. Summary of Public Comment
NAPSR generally agreed with and supported the addition of this
section. They did note, however, that PHMSA should consider the
applicability of these requirements to pipelines that are transporting
dry, tariff-quality gas. The PST noted that these proposed requirements
in this section provided an enforceable mechanism to hold operators
accountable for future incidents caused by internal corrosion.
Multiple commenters considered the proposed changes to requirements
for internal corrosion control in Sec. 192.478 to be overly
prescriptive, particularly regarding gas monitoring and the list of
corrosive constituents. INGAA stated that transmission operators are
already taking comprehensive steps to address internal corrosion under
subparts I and O of part 192 and that proposed Sec. 192.478 should be
eliminated for this reason. Atmos Energy Corporation and INGAA asserted
that the internal corrosion monitoring timeline proposed in Sec.
192.478(d) is unreasonable and too frequent, particularly for pipeline
systems that are not susceptible to internal corrosion. They further
stated that mitigation of internal corrosion is necessary only if a
pipeline is transporting, or has the potential to transport, corrosive
gas. At the GPAC meeting on June 6, 2017, committee members
representing the industry supported those comments made by Atmos Energy
Corporation and INGAA.
Commenters at the GPAC meeting, including committee members, noted
that some distribution operators rely on upstream transmission pipeline
gas suppliers to monitor gas quality and do not own any gas monitoring
equipment. A committee member noted that if pipeline operators are
getting gas from native sources, gathering lines, or underground
storage fields, it might be necessary to determine the quality of the
gas. Another committee member noted that there are tariffs that prevent
certain quantities of constituents that could be internally corrosive
from entering a transmission system. That commenter also noted that
operators continually monitor for internal corrosion on pipelines
transporting tariff-quality gas as a part of IM.
GPAC members also noted that PHMSA should consider harmonizing
these requirements with the existing corrosion control monitoring
requirements, as they appeared to be duplicative in certain areas.
After discussing the provisions, the committee voted 10-0 that the
proposed provisions related to internal corrosion were technically
feasible, reasonable, cost-effective, and practicable if PHMSA limited
the applicability of the requirements to those pipelines that are
transporting corrosive gas and provided additional guidance based on
the committee discussion; changed the reference from the use of ``gas-
quality monitoring equipment'' to ``gas-quality monitoring methods;''
specified types of technologies operators can use to mitigate
potentially corrosive gas streams; and changed the frequency of the
monitoring and program review requirements from twice per year to once
per calendar year, not to exceed 15 months. The committee also
specifically recommended deleting language that was duplicative to
existing requirements and instead recommended PHMSA cross-reference
those existing requirements in this section.
3. PHMSA Response
PHMSA noted during the GPAC meeting, that, in its experience,
transmission pipeline operators measure the quality of the gas coming
into their transmission systems. Based on the quality of the gas,
transmission pipeline operators are paying suppliers for the gas they
receive or are receiving money for the gas they deliver. Therefore,
PHMSA assumes transmission pipeline operators have monitoring systems
for the quality of the gas entering their systems. PHMSA's intent with
the proposed revision of this section was to help ensure that operators
were getting that data to the necessary people in their organization.
For instance, if an organization's accountants are getting gas quality
data due to their work with tariffs, the personnel responsible for
operations and integrity management should get that data.
Based on the comments received, PHMSA is revising the scope of
proposed Sec. 192.478 in this final rule to limit its applicability to
the transportation of corrosive gas and is modifying the proposed
language in paragraph (b)(1) to specify that operators perform
monitoring at points where gas with potentially corrosive contaminants
enters the pipeline. To address concerns regarding the monitoring
frequency, PHMSA is changing the requirement from twice per year to
once per calendar year, not to exceed 15 months. Making such a change
is more consistent with the timeframes for similar requirements in the
regulations as revised by this rulemaking and implements the
recommendation made by the GPAC.
Further, to harmonize this rule with other rule requirements, PHMSA
is deleting proposed paragraph (c), since Sec. 192.477 currently
requires the monitoring of internal corrosion. To address comments
regarding technology, PHMSA revised paragraph (b)(2) to read
``Technology to mitigate the potentially corrosive gas stream
constituents. Such technologies may include product sampling and
inhibitor injections.''
There have been instances where operators do transport corrosive
gas by pipeline without investigating the possibility of corrosive
effect of the gas on its pipeline and taking steps to minimize internal
corrosion.\28\ This has happened after operators have withdrawn gas
from storage facilities (e.g., caverns) where the gas that was injected
became corrosive over time because of properties of the storage
facilities. Therefore, there can be scenarios where corrosive gas can
enter a pipeline system even if the gas being delivered into the
upstream system is non-corrosive.
---------------------------------------------------------------------------
\28\ In the Matter of Transcontinental Gas Pipe Line Company,
LLC, CPF 1-2018-1005, available at <a href="https://primis.phmsa.dot.gov/comm/reports/enforce/documents/120181005/120181005_Final%20Order_06192019.pdf">https://primis.phmsa.dot.gov/comm/reports/enforce/documents/120181005/120181005_Final%20Order_06192019.pdf</a> (last visited March 27, 2020).
On December 12, 2016, Transcontinental Gas Pipe Line Company
reported an explosion and fire that severely damaged a portion of
one of its facilities and station piping, resulting in an estimated
$15 million in damage. The root cause was determined to be internal
corrosion caused by salt water produced from a storage field during
gas withdrawal.
---------------------------------------------------------------------------
C. Corrosion Control--Sec. Sec. 192.319, 192.461, 192.465, 192.473,
192.478, and 192.935 and Appendix D
v. Cathodic Protection--Sec. 192.465 & Appendix D
1. Summary of PHMSA's Proposal
Appendix D to part 192, ``Criteria for Cathodic Protection and
Determination of Measurements,'' which is referenced in Sec.
192.465(f), specifies requirements for CP of steel, cast iron, and
ductile pipelines. Appendix D has not been updated since 1971. The NPRM
[[Page 52239]]
proposed to update appendix D by eliminating outdated guidance on CP
and the interpretation of voltage measurement to better align with
current standards and PHMSA's understanding of current industry
practice.
Section 192.465 currently prescribes that operators monitor CP and
take prompt remedial action to correct deficiencies indicated by the
monitoring. The provisions in Sec. 192.465 do not specify the remedial
actions required to correct deficiencies and do not define ``prompt.''
To address this gap, the NPRM proposed to amend Sec. 192.465(d) to
require that operators must complete remedial action promptly, but no
later than the next monitoring interval specified in Sec. 192.465, or
within 1 year, whichever is less. Additionally, new paragraph (f)
proposed to add requirements for onshore gas transmission pipeline
operators to perform CIS if annual test station readings indicate CP is
below the level of protection required in subpart I. Unless it is
impractical to do so, PHMSA proposed to require that operators complete
CIS with the protective current interrupted. Whereas ACVG and DCVG are
performed at the time of construction, before electrical current is on
the pipe for CP, a CIS requires the pipe to be in the ground with the
rectifiers installed. A CIS will discover areas of low current where CP
might be weakened and can discover additional construction, operational
or environmental damage along the pipeline when performed as a post-
construction task. The NPRM's proposed revisions to Sec. 192.465 would
also require each operator to take remedial action to correct any
deficiencies indicated by the CIS.
2. Summary of Public Comment
NAPSR and the PST generally agreed with and supported the revisions
to Sec. 192.465. NAPSR believed that the inclusion of a timeframe for
operators to perform CIS and perform subsequent mitigation measures
would increase pipeline safety but noted that PHMSA should provide
further guidance on the intervals at which operators should perform the
surveys. Both PST and NAPSR supported the revisions to appendix D.
Several industry entities commented on the proposed revisions to
appendix D to part 192. INGAA stated that the proposed remaining
criteria in appendix D for determining the adequacy of cathodic
protection are too narrow, and that all industry standards provide for
additional methods of assessing voltage drop. These commenters
recommended that PHMSA follow the applicable paragraphs of NACE
Standard Practice SP0169. Enterprise noted that appendix D should be
consistent with Sec. 195.571, which outlines the criteria that
hazardous liquid pipeline operators must use when determining the
adequacy of cathodic protection.
Commenters stated that the proposed changes to appendix D, as
written, would apply to distribution pipelines as well as transmission
pipelines and expressed concern that PHMSA has offered neither
justification nor an estimate of the impact on distribution systems.
These commenters requested that PHMSA clarify that the proposed changes
to appendix D apply only to transmission pipelines.
Commenters, including committee members representing the industry
during the meeting on June 6, 2017, stated that PHMSA should amend
Sec. 192.465 to include a more realistic timeframe for remedial
action, specifically noting that the timeframe for remediation does not
account for difficulties in obtaining the necessary permits.
Additionally, commenters and GPAC committee members stated this
provision could lead to unnecessary and costly work, as there are
various situations that can produce a low CP reading that do not
require CIS for the identification of the root cause. Those commenters
stated there are certain conditions that do not require CIS and
recommended allowing operators to identify, troubleshoot, and remediate
these certain conditions on their own without the need to conduct CIS.
Further, GPAC members representing the industry disagreed with
PHMSA's proposed revisions to the appendix D criteria for determining
the adequacy of cathodic protection. Like their commentary on other
provisions, these committee members also noted that the impact of these
changes to distribution pipelines was not justified or analyzed, and
therefore, distribution pipelines should be exempt from the proposed
requirements.
Following their discussion, the committee voted 10-0 that the
provisions related to the CP of steel, cast iron, and ductile pipelines
were technically feasible, reasonable, cost-effective, and practicable
if PHMSA clarified that the new requirements in Sec. 192.465(d) only
apply to gas transmission pipelines and withdrew the proposed revisions
to appendix D. The committee also recommended that PHMSA address
situations where CIS may not be an effective response by instead
requiring operators investigate and mitigate any non-systemic or
location-specific causes of corrosion and require CIS if operators need
to address systemic causes of corrosion. Additionally, the committee
recommended PHMSA address its comments regarding the timeframe by which
the proposed provisions would need to be completed by requiring
operators make a remedial action plan and apply for any necessary
permits within 6 months and finish the remedial action within 1
calendar year, not to exceed 15 months, or as soon as practicable once
the operator obtains the necessary permits.
3. PHMSA Response
PHMSA intended that the amendments proposed in the NPRM would apply
only to transmission pipelines and has, in this final rule, added the
phrase ``onshore gas transmission pipelines'' to Sec. 192.465(d)(1) of
to clarify that limitation. PHMSA will consider expanding application
beyond onshore gas transmission pipelines in the future. PHMSA believes
that modifying the timeline for remediation is appropriate, and
therefore, is requiring operators develop a remedial action plan and
apply for the necessary permits within 6 months of the inspection, with
the completion of remediation activities to be completed prior to the
next monitoring interval or within 1 year, not to exceed 15 months.
Like the previous section, such a change is consistent with both the
GPAC recommendation on the issue and the timeframes for the related
regulations in this final rule. PHMSA understands that, in almost all
cases where an operator performs an excavation of 1,000 feet or more,
that excavation will probably require some permits. An operator should
obtain such permits in a manner to allow the performance of coating
surveys and any necessary repairs to the coating.
In the NPRM, PHMSA proposed to update appendix D but did not intend
to introduce any new requirements. PHMSA agrees with certain commenters
that the proposed revisions could have unintended consequences by
creating potential tension with analogous cathodic protection
evaluation criteria in NACE Standard Practice SP0169 and Sec. 195.571
governing hazardous liquid lines (which section incorporates NACE
Standard Practice SP0169 by reference). However, as PHMSA did not
propose incorporation by reference of NACE Standard Practice SP0169 in
appendix D, PHMSA is withdrawing the proposed changes to appendix D.
PHMSA will continue to examine appropriate evaluation criteria for
catholic protection of gas transmission pipelines and may pursue future
rulemaking on
[[Page 52240]]
this topic. These changes to the final rule for CP requirements are in
accordance with the GPAC recommendations.
C. Corrosion Control--Sec. Sec. 192.319, 192.461, 192.465, 192.473,
192.478, and 192.935 and Appendix D
vi. P&M Measures--Sec. 192.935(f) & (g)
1. Summary of PHMSA's Proposal
Currently, the gas transmission IM provisions do not explicitly
address additional P&M measures for the threats of external and
internal corrosion. For the same reasons that apply to the proposed
changes for general corrosion control as discussed above, PHMSA
proposed to address these gaps for HCAs. PHMSA determined that
additional P&M measures are needed in Sec. 192.935(f) and (g) to
assure that public safety is enhanced in HCAs through additional
protections from the time-dependent threats of internal and external
corrosion. Specifically, PHMSA proposed to add Sec. 192.935(f) and
(g), which would require that operators enhance their corrosion control
programs in HCAs to provide additional corrosion protections in
addition to the proposed standards in subpart I. Under proposed Sec.
192.935(f), operators would be required to enhance their internal
corrosion management programs by performing mitigative actions if
deleterious gas stream constituents are being transported and through
performing semi-annual reviews of their programs.
Regarding the internal corrosion provisions discussed earlier in
this document, Sec. 192.477 prescribes requirements to monitor
internal corrosion by coupon testing or other means if corrosive gas is
being transported. However, the existing regulations do not prescribe
that operators continually or periodically monitor the gas stream for
the introduction of corrosive constituents through system changes,
changing gas supply, abnormal conditions, or other changes. This could
result in pipelines that are not monitored for internal corrosion
because an operator's initial assessment did not identify the presence
of corrosive gas. To provide additional protections for HCAs in
addition to the standards proposed in subpart I, PHMSA proposed that
Sec. 192.935(f) would require operators use specific gas quality
monitoring equipment for HCA segments, including but not limited to, a
moisture analyzer, chromatograph, samplers for carbon dioxide, and
samplers for hydrogen sulfide. The proposed provisions would also
require operators sample at a certain frequency, use cleaning pigs to
sample accumulated liquids and solids, and use corrosion inhibitors
when corrosive constituents are present. PHMSA also proposed the
maximum amounts of carbon dioxide, moisture content, and hydrogen
sulfide that would require operator action.
Under proposed Sec. 192.935(g), operators would also be required
to enhance their external corrosion management programs, including
controlling both alternating and direct electrical interference
currents, confirming external corrosion control through indirect
assessment, and controlling external corrosion through CP.
As described in the discussion on interference surveys above,
interference currents can negate the effectiveness of CP systems.
Section 192.473 prescribes general requirements to minimize the
detrimental effects of interference currents. In the NPRM, PHMSA
proposed to amend Sec. 192.473 to require that an operator's corrosion
control program include interference surveys to detect the presence of
interference currents and require the operator take remedial actions
within 6 months of completing the survey. In HCAs, PHMSA proposed
additional prescriptive requirements in Sec. 192.935(g) to afford
extra protections for HCAs, including a maximum interval of 7 years for
an operator to perform interference surveys; more specificity regarding
the survey performance, including technical acceptance criteria; and a
requirement that pipe-to-soil test stations be located at half-mile
intervals within each HCA segment with at least one station in each
HCA, if practicable.
Lastly, PHMSA proposed to make conforming edits to appendix E,
which provides guidance for P&M measures for HCA segments subject to
subpart O. PHMSA proposed to accommodate the proposed revised
definition for ``electrical survey'' by replacing that term with
``indirect assessment'' to accommodate other techniques in addition to
CIS.
2. Summary of Public Comment
NAPSR and the PST agreed with and supported the proposed changes to
the P&M measures for addressing internal and external corrosion in HCAs
and suggested strengthening the proposed provisions further.
While trade associations and individual operators supported certain
aspects of the proposed provisions covering the P&M measures addressing
external corrosion and internal corrosion in HCAs, these commenters
objected to the specific requirements in Sec. 192.935. Many of these
commenters stated a preference for allowing operators the flexibility
to implement corrosion control based on their own judgment of the
severity of the threat. In general, many industry commenters stated
that individual sections of the proposed provisions were too broad and
prescriptive, and pipeline operators would incur greater costs without
justified benefit. Further, they stated that the monitoring frequency
of twice per year was too frequent. Some commenters recommended that
PHMSA reference ASME standards for implementing P&M measures, and other
commenters stated concern that some of the proposed provisions are not
consistent with NACE standards.
Many commenters objected to several of the proposed aspects of
internal corrosion control, such as the identification of threats,
monitoring, and filtering, and these commenters stated that operators
should have flexibility in implementing P&M measures. For example,
INGAA opposed the proposed requirement in Sec. 192.935(f) that
requires operators to install continuous gas quality monitoring
equipment at all points in which gas with potentially deleterious
contaminants enters the pipeline. INGAA recommended that Sec.
192.935(f) apply only to pipeline segments with a history of internal
corrosion and stated that this would be consistent with the required
risk analysis that operators perform to determine whether P&M measures
are necessary. Similarly, Atmos Energy recommended that gas sources be
monitored only at those sources suspected, in the judgment of the
operator, of having deleterious gas stream constituents, and that such
monitoring can be performed in real-time or periodically. INGAA stated
that PHMSA should modify proposed Sec. 192.935(g) to require that
operators conduct periodic indirect inspections only where a pipeline
segment has a known history of corrosion.
During the GPAC meeting on June 6, 2017, committee members
representing the industry reiterated that Sec. 192.935(f) and (g) were
too broad and prescriptive and should not apply to every HCA pipeline
segment indiscriminately. These members, echoing comments made by
INGAA, stated that operators should use their risk assessments to be
used to determine which specific P&M measures are needed in accordance
with the current IM approach.
The committee also suggested that PHMSA should reference specific
ASME standards for P&M measures and ensure they are consistent with
NACE
[[Page 52241]]
standards. Members representing the public suggested PHMSA review the
proposed changes throughout subpart I and ensure that they would be as
enforceable as the proposed P&M measures if the P&M measures were to be
deleted. Members also discussed the fact that distribution operators do
not always have gas monitoring equipment for their lines, as they
depend on the suppliers to monitor the gas quality.
Following the discussion, the committee voted 9-1 (with a
representative from PST dissenting) that the proposed rule, regarding
the provisions for P&M measures for internal and external corrosion,
were technically feasible, reasonable, cost-effective, and practicable
if PHMSA withdrew the specific provisions discussed in Sec. 192.935(f)
and (g) and appendix E, as the requirements would have been duplicative
with subpart I.
3. PHMSA Response
PHMSA noted during the GPAC meeting that it was persuaded by
commenters that the changes it is making to the general corrosion
control requirements in subpart I in this final rule are sufficient and
that the additional regulations proposed in Sec. 192.935(f) and (g)
and appendix E were duplicative. The proposed changes to subpart I that
PHMSA is finalizing in this rulemaking apply to pipelines in both HCAs
and non-HCAs, and they were similar to the P&M measures that PHMSA was
proposing regarding corrosion control in HCAs specifically. Therefore,
PHMSA believes that the changes to subpart I in this rule provide the
safety that the proposed changes at Sec. 192.935(f) and (g) intended
to provide. The proposed changes to appendix E incorporated the
proposed definition for ``electrical survey'' and did not contain
further substantive changes. After considering those comments, and as
recommended by the GPAC, PHMSA is withdrawing all the proposed changes
to Sec. 192.935(f) and (g) and appendix E.
D. Inspections Following Extreme Weather Events--Sec. 192.613
1. Summary of PHMSA's Proposal
Weather events and natural disasters that can cause river scour,
soil subsidence or ground movement may subject pipelines to additional
external loads, which could cause a pipeline to fail. These conditions
can pose a threat to the integrity of pipeline facilities if those
threats are not promptly identified and mitigated. While the existing
regulations provide for design standards that consider the load that
may be imposed by geological forces, weather events and natural
disasters can quickly impact the safe operation of a pipeline and have
severe consequences if not mitigated and remediated as quickly as
possible.
In the NPRM, PHMSA proposed revising Sec. 192.613 to require that
an operator inspect all potentially affected pipeline facilities after
an extreme weather event to help ensure that no conditions exist that
could adversely affect the safe operation of that pipeline. The
operator would be required to consider the nature of the event and the
physical characteristics, operating conditions, location, and prior
history of the affected pipeline in determining the appropriate method
for performing the inspection required. The NPRM's proposed revisions
to Sec. 192.613 also provided that the initial inspection must occur
within 72 hours after the cessation of the event, defined as the point
in time when the affected area can be safely accessed by available
personnel and equipment required to perform the inspection. If an
operator finds an adverse condition, the NPRM' s proposed revisions to
Sec. 192.613 would require an operator to take appropriate remedial
action to ensure the safe operation of a pipeline based on the
information obtained because of performing the inspection.
2. Summary of Public Comment
The PST, NAPSR, and EnLink Midstream supported the proposed
amendments to Sec. 192.613, with many other stakeholders supporting
the intent of the proposed provisions but requesting further
clarification on some of the terms used within the proposal.
Some commenters expressed concern with the broad requirements of an
``inspection'' and requested PHMSA clarify what an inspection following
an extreme weather event would entail. Additionally, these stakeholders
stated that the proposed definition of an extreme weather event was
vague and requested clarification. INGAA stated that operators are
already required to have procedures to ensure a prompt and effective
response to emergency conditions through Sec. 192.615 and suggested
that to avoid duplicative regulation, PHMSA should instead modify Sec.
192.615(a)(3) to incorporate additional specificity on weather events
that may trigger a response.
Many commenters objected to the proposed timeframe, stating that
the 72-hour requirement listed in the rule could be problematic.
Commenters stated that PHMSA should allow operators to determine when
an impacted area can be safely accessed, and that pipeline operators
are best positioned to evaluate the balance between the safety and the
need for inspections to ensure continued safe operation of their
systems. INGAA stated that the 72-hour requirement should either be
replaced with a more general statement such as ``as soon as
practicable,'' or that PHMSA should create a process to request an
exception to the requirement. Louisiana Mid-Continent Oil and Gas
Associations stated that extreme weather events vary significantly by
region and commented that not all local geography and extreme weather
events are the same. They further stated that the 72-hour deadline for
inspection may be too prescriptive depending on the extreme weather
event. They stated that because Louisiana is subjected to many unusual
extraordinary events, such as spillway openings, high/low river flows,
and rainwater flooding, PHMSA should clarify what ``other events''
means and how the cessation of an event is determined.
At the GPAC meeting of January 12, 2017, members noted concerns
with the provisions as proposed but voted 12-0 that the provisions were
technically feasible, reasonable, cost-effective, and practicable if
PHMSA modified the proposed rule to clarify that the timing for this
provision is to begin after the operator has made a reasonable
determination that the area is safe, clarify in the preamble that
operators are encouraged to consult with pipeline safety and public
safety officials in order to make such determinations, delete the
phrase ``whichever is sooner'' at the end of Sec. 192.613(c)(2), and
change the word ``infrastructure'' to ``facilities.''
3. PHMSA Response
PHMSA agrees that an operator's ability to inspect a pipeline
facility following an extreme weather event may vary greatly depending
on the type of extreme weather event that has taken place and the
specific location of the event. The NPRM's proposed revisions to Sec.
192.613 would require operators to inspect its pipeline facilities
after the cessation of an extreme weather event. Cessation of the event
was defined as the point of time when the affected area could be safely
accessed by the personnel and equipment, including availability of
personnel and equipment, required to perform the inspection. However,
in consideration of the comments received, PHMSA is persuaded that
additional clarification is warranted and that 72 hours after the
cessation of the event may not be enough time in all cases for operator
personnel and equipment to assess and inspect a pipeline safely.
[[Page 52242]]
Therefore, as recommended by the GPAC, PHMSA has modified this
final rule to require an operator perform an initial inspection 72
hours after the operator reasonably determines that the affected area
can be safely accessed by personnel and equipment, and the necessary
personnel and equipment required to perform such an inspection are
available. PHMSA encourages operators to consult with pipeline and
public safety officials, including the appropriate PHMSA regional
office, when making these determinations. If an operator is unable to
commence the inspection in the 72-hour timeframe due to the
unavailability of personnel or equipment, the operator must notify the
appropriate PHMSA Region Director as soon as practicable.
If an operator finds an adverse condition, the operator must take
appropriate remedial action to ensure the safe operation of a pipeline
based on the information obtained from the inspection. Such actions
might include, but are not limited to:
<bullet> Reducing the operating pressure or shutting down the
pipeline;
<bullet> Isolating pipelines in affected areas and performing
``stand up'' leak tests;
<bullet> Modifying, repairing, or replacing any damaged pipeline
facilities;
<bullet> Preventing, mitigating, or eliminating any unsafe
conditions in the pipeline rights-of-way;
<bullet> Performing additional patrols, depth of cover surveys and
adding cover over the pipeline, ILI or hydrostatic tests, or other
inspections to confirm the condition of the pipeline and identify any
imminent threats to the pipeline;
<bullet> Implementing emergency response activities with Federal,
State, or local personnel; and
<bullet> Notifying affected communities of the steps that can be
taken to ensure public safety.
PHMSA would not expect operators to comply with these provisions
for weather or other disruptive events when, considering the physical
characteristics, operating conditions, location, and prior history of
the affected system, the event would not be expected to impact the
integrity of the pipeline. For example, extreme weather events would
not include rain events that do not exceed the high-water banks of the
rivers, streams or beaches in proximity to the pipeline; rain events
that do not result in a landslide in the area of the pipeline; storms
that do not produce winds at tropical storm or hurricane level
velocities; or earthquakes that do not cause soil movement in the area
of the pipeline.
PHMSA is also modifying Sec. 192.613(c) introductory text and
(c)(1) as the GPAC recommended, by removing the phrase ``whichever is
sooner'' and replacing the term ``infrastructure'' with ``facilities.''
As discussed during the GPAC meeting, ``pipeline facilities'' is a
defined term at Sec. 192.3, and the use of that term will likely
provide additional clarity.
E. Strengthening Requirements for Assessment Methods--Sec. Sec.
192.923(b) & (c), 192.927, 192.929
i. Internal Corrosion Direct Assessment (ICDA)--Sec. Sec. 192.923(b) &
192.927
1. Summary of PHMSA's Proposal
The current regulations do not specify the quality and
effectiveness of ICDA. NACE International submitted a petition for
rulemaking on February 11, 2009, requesting that PHMSA address this
issue. In the NPRM, PHMSA proposed amendments to Sec. Sec. 192.923(b)
and 192.927 to incorporate by reference NACE SP0206-2006 and further
supplement the NACE standard to address issues observed by PHMSA.
For indirect inspections, PHMSA proposed to require that operators
use pipeline-specific data, exclusively in performing an indirect
inspection, and that the use of assumed pipeline or operational data
would be prohibited. PHMSA also proposed operators be required to
consider the accuracy, reliability, and uncertainty of data used to
make calculations regarding the critical inclination angle of liquid
holdup and the inclination profile of pipelines. Further, PHMSA
proposed that operators be required to select locations for direct
examination and establish the extent of pipe exposure needed, to
explicitly account for these uncertainties and their cumulative effect
on the precise location of predicted liquid dropout.
For detailed examinations as defined in NACE SP0206-2006, PHMSA
proposed to require that operators identify a minimum of two locations
for excavation within each covered segment associated with the ICDA
Region and perform a detailed examination for internal corrosion at
each location using ultrasonic thickness measurements, radiography, or
other generally accepted measurement techniques. One required location
would be the low point within the covered segment nearest to the
beginning of the ICDA Region. The second required location would be
near the end of the ICDA Region within the covered segment. If
corrosion was found at any location, the operator would be required to
evaluate the severity of the defect, expand the detailed examination
program to determine all locations that have internal corrosion within
the ICDA region, and expand the detailed examination program to
evaluate the potential for internal corrosion in all pipeline segments
(both covered and non-covered) with similar characteristics to the ICDA
Region in the operator's pipeline system.
For post-assessment evaluation and monitoring, PHMSA proposed to
require that operators evaluate 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 currently specified in the regulations at Sec.
192.939. PHMSA also proposed to require that operators validate their
flow modeling calculations by comparing locations of discovered
internal corrosion with locations predicted by the model. Additionally,
PHMSA proposed to require that operators continually monitor each ICDA
Region that contains a covered segment where internal corrosion was
identified and by periodically drawing off liquids at low points and
chemically analyzing the liquids for the presence of corrosion
products.
Finally, PHMSA proposed to require that operators include in their
plans the criteria used in making key decisions in implementing each
stage of the ICDA process and provisions that the analysis be carried
out on the entire pipeline in which covered segments are present.
2. Summary of Public Comment
NAPSR expressed its agreement with, and support for, the proposed
revisions to Sec. Sec. 192.923(b) and 192.927. Multiple pipeline
operators and industry trade associations commented that the proposed
provisions should simply incorporate the NACE standard by reference,
and should not exceed those established industry standards, be rigidly
prescriptive, or otherwise be mandatory. PG&E, commenting on the
incorporation of standards by reference, requested PHMSA replace the
phrase ``as required by'' with ``in accordance with'' so that operators
can meet the substantial requirement but have flexibility in the
implementation of that requirement if the industry publishes new
techniques to perform ICDA. NACE International expressed its belief
that, as described in NACE SP0206-2006, ICDA is an acceptable
standalone methodology for assessing pipeline integrity.
Atmos Energy commented that the proposed mandated monitoring for
all ICDA regions would be potentially excessive and recommended that
PHMSA delete the proposed language and restore the current language at
[[Page 52243]]
Sec. 192.927(c)(4)(ii).\29\ Another commenter recommended that PHMSA
remove the proposed notification requirement prior to an operator
performing an ICDA, noting that operators currently provide this
information as part of other annual reporting.
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\29\ PHMSA regulations at Sec. 192.927(c)(2) define an ICDA
region as a continuous length of pipe (including weld joints),
uninterrupted by any significant change in water or flow
characteristics, that includes similar physical characteristics or
operating history. 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 until a new
input introduces the possibility of water entering the pipeline.
---------------------------------------------------------------------------
At the GPAC meeting on December 15, 2017, the GPAC committee voted,
13-0, to revise Sec. Sec. 192.923(b)(2) and (3) and 192.927 according
to the recommendations by PHMSA staff at the meeting, which included
supplementing the NACE standard with additional requirements to address
specific issues that could adversely affect ICDA results.
3. PHMSA Response
PHMSA believes that it is appropriate to address ICDA by
incorporating by reference the NACE standard and supplementing it with
additional requirements pertaining to indirect inspections (a step in
the NACE standard's ICDA process to help in determining where direct
assessments need to be made), detailed examinations, and post-
assessments. For indirect inspections, PHMSA has implemented additional
requirements regarding the data an operator must use and accounting for
uncertainties in that data. Where an indirect inspection demonstrates
that detailed examinations are needed, PHMSA is expanding the
examinations that an operator must perform to evaluate for the
potential for internal corrosion in all pipeline segments if corrosion
is found in the ICDA region. Regarding post-assessments, PHMSA is
requiring operators to evaluate the effectiveness of ICDA as an
assessment method and determine whether a covered segment should be
reassessed more frequently than the intervals specified at Sec.
192.939. Additionally, PHMSA is requiring operators validate the flow
modelling calculations they use in the ICDA process as well as
continually monitor each ICDA region that contains a covered segment
where internal corrosion has been identified.
When the first IM regulations were promulgated in the 2003 IM rule,
there was no consensus industry standard for ICDA that could be adapted
or incorporated into the regulations to promote better pipeline safety
regarding internal corrosion. Incorporating by reference the NACE
standard into the regulations would improve pipeline safety because the
NACE standard (1) typically requires more direct examinations than the
current regulatory requirements; (2) encompasses the entire pipeline
segment and requires that all inputs and outputs be evaluated; and (3)
is considered by many to be an equivalent or superior indirect
inspection model compared to the Gas Technology Institute (GTI) model
currently referenced in Sec. 192.927. Its range of applicability with
respect to operating pressure is greater than the GTI model, thus
allowing the use of ICDA in pipelines with lower operating pressures
and higher flow velocities.
The existing requirements in Sec. 192.927 have one aspect that has
proven problematic: the definition of regions and requirements for
selection of direct examination locations in the regulations are tied
to the covered segment. A ``covered segment'' is defined in Sec.
192.903 as ``a segment of gas transmission pipeline located in a high
consequence area.'' The terms ``gas'' and ``transmission line'' are
defined in Sec. 192.3. Therefore, covered segment boundaries are
determined by population density and other consequence factors without
regard to the orientation of the pipe and the presence of locations at
which corrosive agents may be introduced or may collect and where
internal corrosion would most likely be detected (e.g., low spots).
Section 192.927 requires that locations selected for excavation and
detailed examination be within covered segments, meaning that the
locations at which internal corrosion would most likely be detected may
not be examined. Thus, the existing requirements do not always
facilitate the discovery of internal corrosion that could affect
covered segments. PHMSA is addressing this problem in this final rule
by incorporating NACE SP0206-2006 and by expanding the detailed
examination program, whenever internal corrosion is discovered, to
determine all locations that have internal corrosion within the ICDA
region.
PHMSA believes requiring a notification requirement for operators
is important so that PHMSA can review the specific proposal to use a
standard to assess pipe segments that are explicitly excluded from the
scope of the standard. PHMSA has also revised Sec. 192.927(c) to
clarify that an operator must conduct the ICDA process ``in accordance
with'' the NACE standard to avoid the implication that all non-
mandatory recommendations contained in the standard are required.
E. Strengthening Requirements for Assessment Methods--Sec. Sec.
192.923(b) & (c), 192.927, 192.929
ii. Stress Corrosion Cracking Direct Assessment (SCCDA)--Sec. Sec.
192.923 & 192.929
1. Summary of PHMSA's Proposal
The current regulations do not specify a number of issues that
affect the quality and effectiveness of SCCDA integrity assessments.
Specifically, Appendix A3 of ASME/ANSI B31.8S, which is referenced in
the regulations, provides some guidance for conducting SCCDA, but the
guidance is limited to stress corrosion cracking (SCC) that occurs in
high-pH environments. NACE International submitted a petition for
rulemaking to PHMSA on February 11, 2009, requesting that PHMSA address
this issue by incorporating by reference NACE SP0204-2008, which
addresses near-neutral SCC in addition to high-pH SCC. Accordingly, in
the NPRM, PHMSA proposed changes to Sec. Sec. 192.923 and 192.929 to
incorporate by reference NACE SP0204-2008 and supplement the NACE
standard to address issues observed by PHMSA in the areas of data
gathering and integration, indirect inspection, direct examinations,
remediation and mitigation, and post-assessments.
PHMSA proposed to require an operator's SCCDA plan to evaluate the
effects of a carbonate-bicarbonate environment; the effects of cyclic
loading conditions on the susceptibility and propagation of SCC in both
high-pH and near-neutral-pH environments; the effects of variations in
applied CP, such as overprotection, CP loss for extended periods, and
high negative potentials; the effects of coatings that shield CP when
disbonded from the pipe; and other factors that affect the mechanistic
properties associated with SCC.
For indirect inspections, PHMSA proposed to require an operator's
plan include provisions for conducting at least two above-ground
surveys using complementary measurement tools most appropriate for the
pipeline segment based on the data gathered.
For direct examinations, PHMSA proposed to require an operator's
procedures provide for conducting a minimum of three direct
examinations within the SCC segment at locations determined to be the
most likely for SCC to occur.
For post-assessments, PHMSA proposed to require that the operator's
procedures include the development of a reassessment plan based on the
[[Page 52244]]
susceptibility of the operator's pipe to SCC as well as on the
mechanistic behavior of identified cracking.
2. Summary of Public Comment
Multiple commenters supported the proposed changes to Sec. 192.929
for SCCDA. NAPSR expressed its agreement with, and support of, these
revisions. Spectra Energy Partners (SEP), which merged with Enbridge in
2017, provided comments in support of the proposed inclusion of
explicit requirements for SCCDA. SEP expressed its belief that SCCDA is
a diligent, practicable approach for assessments for SCC for cases
where the pipeline has not previously experienced an in-service failure
caused by SCC and provided specific edits to make the proposed
requirements for SCCDA clearer and more practicable. A commenter
recommended that the requirements for SCCDA specify that an operator is
required to conduct assessments in areas that are most likely to be
subject to SCC regardless of HCA designation.
Several other commenters questioned or opposed the proposed changes
to Sec. 192.929. Several commenters, including API, expressed their
support of NACE standards SP0204-2008 for SCCDA but recommended that
PHMSA not exceed those established industry standards and should not
make the recommendations within those standards mandatory. NACE
International stated it was unaware of any conclusive data regarding
overprotection or high-negative potentials as a factor in SCC of
pipelines, which is what the NPRM's proposed revisions to Sec. 192.929
suggested. Additionally, NACE International commented that PHMSA went
beyond the practices stated in NACE Standard SP0204-2008 by proposing
to require a minimum of two above-ground surveys and three direct
examinations.
INGAA proposed to clarify the way in which SCCDA can be used as an
IM method, asserting that SCCDA is a valid method to assess SCC threats
in gas pipeline segments that are susceptible to, but have no history
of, SCC.
Other commenters provided specific technical comments regarding
these proposed provisions. TransCanada asserted that applying the NACE
``significant SCC'' definition as the threshold for immediate repair is
both overly conservative and overly complicated, and they suggested
that PHMSA instead adopt the threshold of ``noteworthy'' as defined in
ASME STP-PT-011.
Enable Midstream Partners (EMP) agreed that operators should
consider the specific factors PHMSA proposed in Sec. 192.929(b)(1) and
(4) as part of the data gathering and integration and post-assessment
remediation and mitigation process for SCCDA. However, EMP asserted
that PHMSA should clarify these sections by including a referenced
standard that provides guidance to operators on how they should
consider these specific factors. Another commenter stated that PHMSA
should include a reference to ASME/ANSI B31.8S, Appendix A3, for
susceptibility criteria.
Commenters also suggested that PHMSA allow operators to use sound
engineering judgments when calculating the remaining strength of the
pipeline segment if the segment is subject to the pipeline material
properties and attributes verification requirements of Sec. 192.607
and those requirements have not yet been met.
At the GPAC meeting on December 15, 2017, the committee recommended
PHMSA revise the approach proposed in the NPRM by making the changes to
these provisions that were recommended by PHMSA staff during the
meeting, which were to replace the spike hydrostatic pressure test
requirements with a reference to Sec. 192.506(e) to eliminate
redundancy; address the gap pertaining to failure pressure calculations
when data is not available; codify, as applicable, the expectation that
the recommendations within the NACE standard are not mandatory;
communicate additional guidance as needed during rule implementation;
and consider how to structure the rule to apply results from non-HCAs
to HCAs.
3. PHMSA Response
When the first IM rule was promulgated in 2003, there was no NACE
standard for SCCDA. Additionally, the requirements pertaining to SCC in
ASME/ANSI B31.8S, Appendix B, only applied to pipe susceptible to high
pH SCC (i.e., pipelines susceptible to near-neutral SCC were not
addressed). Therefore, PHMSA believes that incorporating by reference
the NACE standard and supplementing it with additional requirements to
address issues it has observed related to data gathering and
integration, indirect inspection, direct examinations, remediation and
mitigation, and post-assessments, is an appropriate way to address
SCCDA.
For data gathering and integration, PHMSA is requiring that
operators gather and evaluate data related to SCC at all sites an
operator excavates while conducting its pipeline operations where the
criteria in NACE SP0204-2008 indicate the potential for SCC. Per this
final rule, operators must additionally analyze the effects of a
carbonate-bicarbonate environment, cyclic loading conditions,
variations in applied CP, the effects of coatings that shield CP when
disbonded from the pipe, and other factors that would affect the
mechanics of SCC. For indirect inspections, PHMSA is requiring
operators conduct at least two above-ground surveys using the
measurement tools most appropriate for the pipeline segment based on an
evaluation of the collected data. An operator's plan for direct
examination must include a minimum of three direct examinations within
the SCC segment at the locations where SCC would be most likely to
occur. If an operator finds any indication of SCC in a segment, an
operator must perform specific mitigation measures. Further, in this
final rule, an operator must develop procedures for post-assessments
based on the susceptibility of the pipeline segment to SCC as well as
the mechanical behavior of identified cracking. Regarding EMP's comment
stating that PHMSA should provide guidance to operators on how they
should consider specific factors as a part of the data gathering and
integration process by referring to a standard incorporated by
reference within PHMSA regulations, as well as the comment recommending
that PHMSA incorporate a reference to ASME/ANSI B31.8S, Appendix A3,
for susceptibility criteria, PHMSA declines to incorporate by reference
such standards because it could limit operators from considering all of
the factors that they should.
PHMSA also agrees with commenters that referring to Sec. 192.506,
Transmission lines: Spike hydrostatic pressure test, in Sec. 192.929
is preferred instead of repeating the spike hydrostatic test
requirements and has changed this final rule accordingly. PHMSA
addressed the comment about determining predicted failure pressure when
needed data are not available by referencing Sec. 192.712, which
explicitly provides an operator with conservative assumptions and
alternatives for material toughness values, material strength, and pipe
dimensions and other data, in lieu of documented material properties.
F. Repair Criteria--Sec. Sec. 192.714, 192.933
PHMSA identified several improvements to the IM repair criteria
based on its experience gained since the IM rule became effective in
2004; ongoing research and development, including developments in ASME/
ANSI B31.8S; and investigations into recent incidents. In the NPRM,
PHMSA
[[Page 52245]]
proposed adjustments to the existing repair criteria for anomalies
discovered in HCAs and proposed new repair criteria for anomalies found
outside of HCAs.\30\
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\30\ The GPAC voted on each section of the repair criteria
separately, and each section is discussed in more detail below.
---------------------------------------------------------------------------
F. Repair Criteria--Sec. Sec. 192.714, 192.933
i. Repair Criteria in HCAs--Sec. 192.933
1. Summary of PHMSA's Proposal
In the NPRM, PHMSA proposed to add more immediate repair conditions
and more 1-year repair conditions for HCA pipeline segments in Sec.
192.933. The specific anomalies and repair schedules for cracks, dents,
and corrosion metal loss are discussed in their respective sections
below. In certain cases, like for SCC and selective seam weld corrosion
anomalies that were new to the repair criteria, PHMSA proposed to
require that operators repair ``any indication of '' such anomalies. In
other cases, such as for dents, PHMSA did not make significant changes
to the existing repair criteria at Sec. 192.933, which require the
repair of ``any indication of '' metal loss, cracking, or a stress
riser.
2. Summary of Public Comment
Public advocacy groups, including Pipeline Safety Coalition, the
PST, and Clean Water for North Carolina, supported the proposed
provisions that would strengthen the existing repair criteria at
Sec. Sec. 192.713 (non-HCAs) and 192.933 (HCAs). Additionally, NAPSR
and the NTSB supported PHMSA's proposed repair criteria revisions.
There was common agreement from pipeline operators and the industry
trade associations that the processes for HCA repairs and non-HCA
repairs should be standardized. However, the trade associations and
pipeline operators generally believed that the proposed provisions at
Sec. Sec. 192.713 and 192.933 were too prescriptive and would impede
operators from performing repairs based on risks. They further stated
that the proposed provisions do not take into consideration other
factors that operators currently consider when optimizing plans to
remediate anomalies, such as historical data, geography, and congestion
of the right-of-way.
Some of the commenters representing the industry recommended PHMSA
eliminate all references to the words ``any indication of '' within the
proposed revisions to Sec. Sec. 192.713 and 192.933 when applied to
anomalies needing repair so that it is the confirmed presence of a
condition that requires a repair instead. These commenters stated that
requiring operators to repair an ``indication of '' certain anomalies
would cause needless repairs and misallocate resources. Spectra Energy
stated that PHMSA's annual report data indicates that only one repair
is required for every three anomaly investigations, which demonstrates
that the existing anomaly response criteria operators have implemented
are appropriately conservative.
3. PHMSA Response
Based on PHMSA's annual report data, the number of immediate
repairs have remained relatively constant even though the baseline
assessment period has concluded. PHMSA understands that this is likely
the result of operators deferring repair of non-immediate conditions
until the defect progresses into an immediate repair condition, rather
than immediate conditions arising spontaneously. PHMSA understands that
most defects that become immediate repair conditions are observable by
ILI equipment well in advance of progression to an immediate repair
condition. The repair criteria in this final rule are intended to
assure that anomalies are repaired before they become an immediate
condition and are at or near failure. In this final rule, PHMSA has
included reference to ASME/ANSI B31.8S within each of Sec. Sec.
192.714 and 192.933 to take into consideration other factors that
operators currently consider when establishing remediation plans.
In this final rule, PHMSA has removed the proposed repair criteria
under Sec. Sec. 192.714 (non-HCAs) and 192.933 (HCAs) for SCC and
selective seam weld corrosion, which were new repair criteria that
contained the phrase ``any indication of.'' PHMSA combined SCC and
selective seam weld corrosion repair criteria into a more general
cracking repair criteria because each of these phenomena is, or results
in, cracking. PHMSA included remediation measures for SCC under the
requirements at Sec. 192.929, which are the requirements for using
direct assessment for SCC but did not require the remediation of ``any
indication of '' SCC. PHMSA was not proposing to change any of the
existing repair criteria that referenced ``any indication of,'' such as
that for dents with any indication of metal loss, cracking, or a stress
riser. Those repair criteria remain unchanged in this final rule.
F. Repair Criteria--Sec. Sec. 192.714, 192.933
ii. Repair Criteria in Non-HCAs--Sec. 192.714
1. Summary of PHMSA's Proposal
In the NPRM, PHMSA proposed at Sec. 192.713 repair criteria for
non-HCA areas to assure that operators promptly repair injurious
defects that are discovered outside of HCAs. These proposed repair
criteria for non-HCAs were based on, and were similar, to, the repair
criteria (regarding structure, anomaly types, and the repair
timeframes) for HCA pipeline segments proposed at Sec. 192.933.
For those anomalies for which a 1-year response is required on HCA
pipeline segments, PHMSA proposed that a 2-year response would be
required in non-HCA pipeline segments. This proposal would require
operators to remediate anomalous conditions on gas transmission
pipeline segments promptly and commensurate with the risk they present,
while allowing operators to allocate their resources to those anomalies
in HCAs that present a higher risk.
The specific anomalies and repair schedules for cracks, dents, and
corrosion metal loss are discussed in their respective sections below.
2. Summary of Public Comment
Citizen groups, including Pipeline Safety Coalition, the PST, and
Clean Water for North Carolina, supported the proposed provisions that
would strengthen the repair criteria for HCAs and non-HCAs.
Additionally, NAPSR and the NTSB supported PHMSA's revisions to the
repair criteria.
Generally, the industry trade associations and pipeline operators
supported PHMSA's intention of establishing repair criteria outside of
HCAs but disagreed with some of the specific provisions. There was
common agreement, however, that the processes for HCA repairs and non-
HCA repairs should be standardized.
The trade associations and pipeline operators generally believed
that the proposed provisions were too prescriptive and would impede
operators from performing repairs based on risks. They further stated
that the proposed provisions do not take into consideration other
factors that operators currently consider when optimizing plans to
remediate anomalies, such as historical data, geography, and congestion
of the right-of-way.
AGA recommended that PHMSA create a new subpart to address
assessment requirements outside of
[[Page 52246]]
HCAs and add a section within that subpart to cover repair criteria.
Several other trade associations and pipeline operators echoed AGA's
recommendations.
Several industry commenters also stated that the rulemaking did not
demonstrate that the safety benefit of strengthened repair criteria
outweighs the costs. Multiple operators stated that the proposed repair
provisions in Sec. 192.713 would increase the number of digs operators
would need to perform and asserted that the increased number of digs
may not improve pipeline safety.
Certain commenters suggested that it would not be appropriate for
PHMSA to require operators to repair immediate conditions in non-HCAs
before repairing immediate conditions in HCAs, and that PHMSA should
require operators to prioritize those conditions discovered within HCAs
if operators discover multiple immediate conditions in HCAs and non-
HCAs simultaneously. More specifically, AGA requested that the rule
explicitly prioritize immediate conditions within HCAs over immediate
conditions in other locations when conditions are discovered
simultaneously and recommended that PHMSA adopt different terminology
for ``immediate repair conditions'' inside and outside HCAs. Similarly,
other industry trade organizations expressed concern that the proposed
provisions for non-HCAs would complicate the allocation of resources to
HCAs on a higher-priority basis when confronted with the large number
of new, non-HCA pipelines needing assessments.
Commenters also requested PHMSA make the sections pertaining to
non-HCA repairs and HCA repairs consistent regarding pressure
reductions. Commenters representing the industry noted that, as
proposed, certain notification requirements for long-term pressure
reductions or for those operators unable to respond within the given
timeframe were different depending on whether the pipeline was in an
HCA or a non-HCA. These commenters suggested that those notification
procedures be made consistent, wherever possible, between the HCA and
non-HCA repair criteria. Multiple trade associations and pipeline
industry entities also expressed concerns that the proposed provisions
requiring ``an operator to reduce the operating pressure of its
affected pipeline until it can remediate the immediate repair
conditions'' are unnecessarily conservative. INGAA asserted that the
proposed pressure reduction requirements for non-HCAs are more
stringent than the pressure reductions requirements for HCAs, and
several commenters offered alternative methods for determining
appropriate operating pressure reductions. Specifically, these
commenters requested PHMSA allow operators to take a pressure reduction
other than 80 percent if they documented the analysis performed and
assumptions used. These commenters claimed that, as proposed in the
NPRM, operators were allowed to use a different pressure reduction in
HCAs if an analysis supported it but were not allowed to do so in non-
HCAs.
During its meeting in late March 2018, the GPAC recommended PHMSA
clarify that pressure reductions would be required for immediate
conditions in non-HCAs and in cases where repair schedules could not be
met. As a part of this recommendation, the GPAC also recommended that
operators notify PHMSA when they could not meet the schedule for
anomaly evaluation and remediation or when a temporary pressure
reduction exceeds 365 days. The GPAC also recommended that PHMSA should
allow operators to calculate pressure reductions (following the
discovery of repairable conditions) by using either class location
factors, or 80 percent of the operating pressure, or 1.1 times the
predicted failure pressure. The GPAC also recommended PHMSA require
that operators document and keep records, for 5 years, of the
calculations and decisions used to determine such pressure reductions
and the implementation of the actual reduced operating pressure.
Further, the GPAC recommended PHMSA avoid duplicating language
regarding the need for repairs and pressure reductions found in other
sections of the regulations.
3. PHMSA Response
In the 2019 Gas Transmission Rule, PHMSA promulgated new
requirements for operators to conduct integrity assessments in areas
outside of HCAs, including all Class 3 and Class 4 locations and the
newly defined ``moderate consequence areas'' (MCA) that are piggable.
This new requirement was in response to the congressional mandate in
the 2011 Pipeline Safety Act (Pub. L. 112-90) to expand IM or elements
of IM beyond HCAs. The non-HCA repair criteria PHMSA is issuing in this
final rule are the companion requirements to those assessments and are
necessary to extend the assessment and repair program elements of IM
effectively to areas beyond HCAs. Although PHMSA agrees that this
requirement will likely result in additional repairs, PHMSA believes it
is necessary and important to assure that injurious defects are
remediated before they lead to loss of pipeline integrity.
Commenters requested that the non-HCA repair criteria be split out
from the general non-IM repair provisions that previously existed in
the regulations. PHMSA determined that the non-HCA repair criteria
would be clearer and easier to comply with if they were in a distinct
section, and PHMSA has created a new Sec. 192.714 with all of the non-
HCA repair criteria.
To the comments that suggested that a different schedule be created
for immediate conditions within HCAs and non-HCAs, PHMSA believes that
the existing approach used in subpart O for HCAs is better because the
identification of anomalies based on ILI results is an actionable
indication that there might be an injurious defect in the pipeline.
Establishing repair criteria based on operators discovering these
actionable anomalies assures that the anomaly is investigated promptly
and repaired, if necessary. PHMSA believes it is prudent for an
operator to perform any necessary repairs once the operator has
excavated the pipe and exposed the anomaly for field investigation,
instead of deferring the repairs. Although PHMSA agrees that defects in
HCAs, if they were to fail, could result in higher consequences, PHMSA
reminds readers that ASME/ANSI B31.8S, section 7.2, defines an
immediate condition as an ``indication show[ing] that [a] defect is at
failure point.'' PHMSA believes that any indication of a pipe that is
at the point of failure needs to be addressed immediately, and as such,
for both HCAs and non-HCAs, operators must reduce pressure and
immediately remediate the anomaly.
PHMSA agrees with several commenters and the GPAC recommendations
for consistently addressing pressure reductions for repairs for both
HCA and non-HCA pipeline segments. PHMSA believes that pressure
reductions are needed for immediate conditions and when repair
schedules cannot be met and has incorporated pressure reductions for
non-HCA pipelines that are like the existing requirements for HCAs in
subpart O, which include the operator notifying PHMSA. PHMSA also
agrees that the amount of the pressure reduction should be established
to be 80 percent of the operating pressure at the time of discovery of
the defect, or the predicted failure pressure divided by 1.1, or the
predicted failure pressure times the design factor for the class
location in which the affected pipeline is located, and that records
for such pressure reductions must be kept for a minimum of 5 years.
PHMSA
[[Page 52247]]
incorporated these provisions, as recommended by the GPAC, in Sec.
192.714(e) for non-HCA pipelines. Further, PHMSA followed the GPAC
recommendation for reducing duplicative language regarding repairs and
pressure reductions and has streamlined this final rule accordingly.
PHMSA also notes that AGA suggested creating a new subpart for non-
HCA assessments and repairs. Although PHMSA has not created a new
subpart, PHMSA believes it has accomplished the same purpose by putting
the new non-HCA assessment and repair requirements in separate,
distinct sections.
F. Repair Criteria--Sec. Sec. 192.714, 192.933
iii. Cracking Criteria--Sec. Sec. 192.714(d)(1)(v) & 192.933(d)(1)(v)
1. Summary of PHMSA's Proposal
In the NPRM, PHMSA proposed to add criteria to address cracking and
crack-like defects, including SCC, because the existing regulations
have no explicit repair criteria for those types of critical defects.
The cracking criteria would apply to both HCAs and non-HCAs, but they
would require repair at different size thresholds and at different
timeframes depending on the anomaly location.
Following the Enbridge incident near Marshall, MI, the NTSB
recommended that PHMSA revise the hazardous liquid regulations at Sec.
195.452 to state clearly: (1) when an engineering assessment of crack
defects, including environmentally assisted cracks, must be performed;
(2) the acceptable methods for performing these engineering
assessments, including the assessment of cracks coinciding with
corrosion with a safety factor that considers the uncertainties
associated with sizing of crack defects; (3) criteria for determining
when a probable crack defect in a pipeline segment must be excavated
and time limits for completing those excavations; (4) pressure
restriction limits for crack defects that are not excavated by the
required date; and (5) acceptable methods for determining crack growth
for any cracks allowed to remain in the pipe, including growth caused
by fatigue, corrosion fatigue, or SCC as applicable.\31\ Although the
recommendation was limited to hazardous liquid pipelines, the issue
applies equally to gas transmission pipelines, as SCC can occur on
these pipelines as well.
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\31\ NTSB Recommendation P-12-3, available at <a href="https://www.ntsb.gov/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-12-003">https://www.ntsb.gov/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-12-003</a>.
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Therefore, in the NPRM, PHMSA proposed to allow operators to use an
engineering critical assessment (ECA) to evaluate indications of SCC.
If the SCC was ``significant,'' it would be categorized as an
``immediate'' repair condition. If the SCC was not ``significant,'' it
would be categorized as a ``1-year'' condition. Further, PHMSA proposed
to adopt the definition of significant SCC from the consensus industry
standard NACE SP0204-2008. PHMSA also proposed that an operator could
not use an ECA to justify not remediating any known indications of SCC.
The current regulations also do not have repair criteria for seam
cracks or crack-like flaws. Current regulations also fail to address
corrosion affecting a longitudinal seam and selective seam weld
corrosion, which are time-sensitive integrity threats that behave like
cracks and are categorized as crack-like defects. In the NPRM, PHMSA
proposed to address these gaps by including repair criteria for cracks
and crack-like flaws in Sec. 192.933 and proposed similar criteria in
Sec. 192.713.
2. Summary of Public Comment
INGAA, API, and Piedmont strongly opposed the proposed provisions
in Sec. 192.713(d)(1)(v), that stated ``any indication of significant
SCC'' constitutes an immediate repair condition. Commenters requested
that PHMSA determine the repair condition of cracks and crack-like
defects according to factors that capture the severity of the defect,
such as predicted failure pressures or maximum depth. Many commenters
believed that PHMSA's proposed criteria were too conservative and
suggested the repair criteria be for anomalies with a crack depth of
greater than 70 percent of the pipe wall thickness or with a predicted
failure pressure of less than 1.1 times MAOP. Other commenters
suggested PHMSA delete the definitions of specific significant crack
defects and use the alternative cracking criterion proposed by PHMSA at
the GPAC meeting on March 2, 2018.
INGAA recommended making the repair criteria for cracking
consistent with the repair criteria for metal loss and suggested that
PHMSA consider anomalies with a crack depth of 80 percent wall
thickness as immediate conditions for this reason. INGAA also
recommended that PHMSA adopt a failure pressure ratio approach for
cracking.
Certain commenters noted that the classification of all cracks or
crack-like defects as 2-year repair conditions was overly conservative
and suggested PHMSA relax that requirement. For example, some
commenters suggested requiring repairs at 50 percent crack depth or a
predicted failure pressure of less than 1.25 times MAOP.
At the GPAC meeting, for the proposed repair criteria for cracks,
members representing the industry stated PHMSA's criteria for the
immediate repair of certain crack defects were too conservative and
suggested establishing an immediate repair threshold for cracks up to
70 percent of wall thickness or those with a predicted failure pressure
of less than 1.1 times MAOP rather than those cracks with a predicted
failure pressure of less than 1.25 times MAOP. Members representing the
public noted that public safety would be better served by the threshold
for immediate crack repairs being more conservative but questioned
whether the more stringent threshold would be practical.
Similarly, members representing the industry suggested that PHMSA's
proposed criteria for 1-year and 2-year scheduled conditions were too
conservative as well and suggested setting the relevant criteria as
those cracks with a depth of 50 percent wall thickness or those cracks
with a predicted failure pressure of less than 1.25 times MAOP. Members
representing the industry also suggested that, in addition to relaxing
the criteria for immediate cracks, PHMSA should also add language
requiring operators to consider tool tolerance and other factors when
examining crack growth rates. Further, members representing the
industry suggested that PHMSA base the repair criteria on design
conditions or design factors rather than class location factors.
Committee members also suggested that PHMSA cross-reference specific
regulatory language rather than repeat the text in full in other
sections of the code.
Following the discussion, the committee voted 12-0 that, as
published in the Federal Register, the provisions in the proposed rule
and draft regulatory evaluation for cracking repair criteria were
technically feasible, reasonable, cost-effective, and practicable if
PHMSA: (1) struck the proposed definitions of ``significant seam
cracking'' and ``significant stress corrosion cracking,'' (2) deleted
the phrase ``any indication of'' from the repair criteria related to
cracking, (3) combined the criteria for SCC and seam cracking, (4)
required that operators calculate predicted failure pressures for all
time-dependent cracking anomalies by using the fracture mechanics
[[Page 52248]]
procedure PHMSA developed, (5) revised the definition of ``hard spot''
as discussed,\32\ and (6) considered specific crack repair criteria as
immediate conditions. Those specific crack repair criteria for
immediate conditions would include (1) crack depth plus corrosion
greater than 50 percent of pipe wall thickness; (2) crack depth plus
any corrosion is greater than the inspection tool's maximum measurable
depth; or (3) the crack anomaly is determined to have a predicted
failure pressure that is less than 1.25 times MAOP.
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\32\ This is discussed more under the ``Definitions'' subsection
of this section.
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3. PHMSA Response
In this final rule, PHMSA did not adopt the proposed definitions of
``significant seam cracking'' and ``significant stress corrosion
cracking.'' With the revisions to the cracking repair criteria, these
definitions weren't necessary. Similarly, with the deletion of the
proposed repair criteria using those specific definitions, the
recommendation for deleting the phrase ``any indication of'' from those
criteria, became moot. Further, PHMSA's revisions to the cracking
repair criteria also made the recommendation for PHMSA to combine the
proposed SCC criteria and the seam cracking criteria moot.
PHMSA believes that the repair criteria it proposed in the NPRM for
cracks are consistent with research findings and provides an adequate
safety margin while accounting for the severity of the defects through
the analysis of the predicted failure pressure.\33\ PHMSA believes the
repair criteria for cracks that were suggested by some of the
commenters would not provide an adequate safety margin due to factors
including the accuracy of tool results, varying pipe toughness, and
pressure cycling. This was discussed at length by the GPAC, who
ultimately recommended that anomalies be classified as immediate
conditions where the crack depth plus corrosion is greater than 50
percent of pipe wall thickness, compared to certain commenters who
suggested that cracks with a depth of up to 70 percent pipe wall
thickness be classified as immediate conditions.
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\33\ See ASME, ``STP-PT-0011:Integrity Management of Stress
Corrosion Cracking in Gas Pipeline High Consequence Areas'' (2008).
See also Young, B.A., et al., ``Comprehensive Study to Understand
Longitudinal ERW Seam Failures'' (2017), available at <a href="https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390">https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390</a>. Both papers call
for anomaly evaluation; the knowledge of certain properties,
including the length and depth of the crack, and pipe properties
like wall thickness, grade, and toughness; and a proposed safety
factor based on the time until the next assessment period. The
papers also require that the depth of a crack not be greater than
the depth of the assessment tool's tolerance. See Sec. 192.712(e).
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While the GPAC did not have an explicit recommendation for
scheduled (i.e., non-immediate) crack repair criteria, they recommended
that PHMSA consider a repair schedule for cracks that is less
conservative than what was proposed in the NPRM. Their recommended
schedule is: 1.39 times MAOP for Class 1 and 2 locations and 1.5 times
MAOP for Class 3 and 4 locations. PHMSA considered this recommendation
and determined that the condition should cover Class 1 locations and
Class 2 locations containing Class 1 pipe that has been uprated in
accordance with Sec. 192.611, where the predicted failure pressure is
1.39 times MAOP. For all other Class 2 locations and higher class
locations, the predicted failure pressure would be 1.5 times MAOP.
Section 192.611 allows Class 1 pipe to remain in a Class 2 location if
it has had a subpart J pressure test, for 8 hours, at 1.25 times MAOP.
Also, it allows pipe with a design factor of 0.72, with the reciprocal
of 1 divided by 0.72 being equal to 1.39, which is the predicted
failure pressure. Therefore, PHMSA elected to apply a predicted failure
pressure ratio of 1.39 times MAOP to both Class 1 pipe and uprated
Class 2 pipe.
For immediate conditions, the GPAC asked PHMSA to consider if a
less conservative repair criterion of 1.1 times MAOP (after tool
tolerance had been applied) would be appropriate. PHMSA considered this
suggestion but notes that, after allowing for pressure excursions above
MAOP due to over pressure protection device settings, the actual safety
margin of such an approach would be between 0 and 6 percent. PHMSA has
determined that this safety margin for immediate crack conditions is
inadequate and, for this final rule, has retained the requirement that
operators must immediately repair crack anomalies with a predicted
failure pressure that is less than 1.25 times MAOP.
PHMSA took technical guidance information from several sources into
account regarding significant SCC and significant seam weld corrosion
when creating the repair criteria for these anomalies, including ASME
ST-PT-011 (``Integrity Management of Stress Corrosion Cracking in Gas
Pipeline High Consequence Areas'').\34\
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\34\ ASME, ``STP-PT-011: Integrity Management of Stress
Corrosion Cracking in Gas Pipeline High Consequence Areas'' (2008).
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ASME ST-PT-011 states that stress corrosion cracks are
``Noteworthy'' if the maximum crack depth is greater than 10 percent of
the wall thickness and if the maximum interacting crack length is more
than the critical length of a 50 percent through-wall crack at a stress
level of 110 percent SMYS.\35\ The report provides categories as
follows:
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\35\ PHMSA notes that 110 percent SMYS for a Class 1 pipeline is
roughly equivalent to 1.49 times MAOP.
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Category 1: Predicted Failure Pressure (PFP) is above 110 percent
SMYS (note that 110 percent SMYS is used to delineate Category 1 cracks
because it corresponds to the pressure most commonly prescribed for
hydrostatic testing).
Category 2: PFP is above 125 percent MAOP \36\ and below 110
percent SMYS.
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\36\ PHMSA notes that 125% times MAOP for a pipeline that
operates at 72% SMYS in a Class 1 location would correspond to
roughly 90% SMYS for a Category 2 crack. PHMSA has defined in Sec.
192.506 that a spike test for cracking should be conducted at a
pressure of 100 percent of SMYS (roughly equivalent to 1.39 times
MAOP for a Class 1 location) or 1.5 times MAOP.
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Category 3: PFP is above 110 percent MAOP and below 125 percent
MAOP.
Category 4: PFP is below 110 percent MAOP.
Category Zero: A crack below the threshold for Noteworthy cracks.
These typically fall into two groups: (1) Those that are shallow (i.e.,
less than 10 percent through-wall depth), or (2) Those that are so
short that, even if they were 50 percent through-wall depth, they would
not result in a hydrostatic test failure.
In this final rule, operators can use an engineering analysis on
cracks in Categories 1 through 2 as described above. However, any
Category 3 or 4 cracking defect below 125 percent MAOP would require
immediate remediation. Category 3 cracks would have a 10 percent or
greater safety factor, which is similar to how PHMSA currently treats
corrosion anomalies at Sec. 192.933. PHMSA provides more conservatism
in the cracking criteria because there is more uncertainty with the
accuracy of current ILI technology in its ability to measure crack
length and depth, as well operational factors.
These severity categories allow operators to estimate the minimum
remaining life at operating pressure for each category. The following
estimates from ASME ST-PT-011 are based on the time it would take for
the crack depth to increase to a failure-causing depth at the operating
pressure. For pipelines operating at 72 percent SMYS, the following
minimum operational lives for each category of cracks are as follows:
[[Page 52249]]
Category Zero: Failure life exceeds 15 years (for short cracks) to
25 years (for shallow cracks).
Category 1: Failure life exceeds 10 years.
Category 2: Failure life exceeds 5 years.
Category 3: Failure life exceeds 2 years.
Category 4: Failure may be imminent.
ASME ST-PT-011 further states that mitigating a pipeline segment
with SCC should be commensurate with the severity of the discovered
crack, which would reflect the PFP and the estimated life at the
operating pressure. For example, Category Zero cracks may warrant no
more than ongoing SCC condition monitoring and reassessment after a
period of 7 years. Cracks may be best assessed by direct assessment,
hydrostatic testing, or ILI. The most severe cases would require an
immediate pressure reduction, repair (if the location is known), and
hydrostatic testing or ILI, followed by replacing the pipe or
installing an appropriate sleeve over the crack or known cracking
areas.
F. Repair Criteria--Sec. Sec. 192.714, 192.933
iv. Dent Criteria--Sec. Sec. 192.714 & 192.933
1. Summary of PHMSA's Proposal
In the NPRM, PHMSA proposed that dents in non-HCA segments with any
indication of metal loss, cracking, or a stress riser would be
considered ``immediate'' repair conditions. Additionally, PHMSA
proposed that dents meeting the ``1-year'' repair conditions under
Sec. 192.933 would be required to be repaired in non-HCAs within 2
years.
2. Summary of Public Comment
Multiple commenters, including the industry trade associations and
operators, disagreed that all dents with metal loss should be
considered immediate repair conditions. These commenters requested that
PHMSA's final rule address different kinds of dents separately. Many
pipeline operators stated that dents with metal loss from ``scratches,
gouges, and grooves'' are appropriate as immediate repair conditions,
while dents caused by corrosion are lower risk and should be conditions
scheduled for later repair. Several organizations cited API Publication
1156 \37\ and ASME/ANSI B31.8, ``Gas Transmission and Distribution
Piping Systems,'' to support these claims. Several commenters also
recommended that PHMSA impose different response timelines for dents
depending on the location and the manner of the dents, because dents
with bottom-side metal loss are usually corrosion-related and low-risk,
while dents on the top of the pipeline with metal loss are likely to be
from mechanical damage and are at a higher risk to fail. This
distinction would be consistent with the criteria for smooth dents
(dents with no peaks, buckling, gouging, cracking, or metal loss that
can reduce the operational life of the pipe).
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\37\ API, ``Pub. 1156: Effects of Smooth and Rock Dents on
Liquid Petroleum Pipelines'' (1997).
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With further regard to the repair criteria for dents, commenters
representing the industry believed PHMSA should allow operators to use
an ECA to evaluate dents as an alternative to following the prescribed
repair criteria. Some of this discussion focused on whether PHMSA
should include a finite element analysis (FEA) \38\ as part of the ECA
and whether PHMSA should define critical strain levels as a criterion
in the ECA. Comments from industry additionally suggested that the
criterion related to gouges or grooves greater than 12.5 percent of
wall thickness was duplicative with other criteria. Industry trade
associations noted that gouges and grooves would be evaluated in
accordance with the dent, metal loss, or cracking criteria, and
therefore, a separate anomaly category for gouges and grooves should be
removed. Further, they asserted that current ILI technology can't
determine the specific cause of metal loss, which would make this
criterion unfeasible.
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\38\ FEA is a modeling technique used to find and solve
structural or integrity issues for phenomena such as cracking or
denting. Pipe properties, including the parameters of the damage to
the pipe, planned operating pressure, lifespan until the next
evaluation, and any future operational conditions (max pressure,
pressure cycle, higher temperatures), are needed to perform an FEA.
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At the GPAC meeting on March 26, 2018, the committee recommended
changes to several of the specific repair criteria for cracks,
corrosion metal loss, and dents. Specific to dents, the committee
recommended that PHMSA allow use of an ECA to evaluate certain dent-
related anomalies and incorporate the ECA into the repair criteria.\39\
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\39\ Many of the recommended changes to the proposed repair
criteria were highly technical in nature. For more information,
including transcripts of the discussion and the voting slides,
please visit: <a href="https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=132">https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=132</a>.
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Following the discussion, the committee voted 12-0 that, as
published in the Federal Register, the provisions in the proposed rule
and draft regulatory evaluation for dent repair criteria were
technically feasible, reasonable, cost-effective, and practicable if
PHMSA: (1) allowed operators to use an ECA for specific dent-related
repair criteria and considered language to accommodate alternative ECA
methods (including an FEA), and (2) distinguished between top-side
dents that exceeded critical strain levels and bottom-side dents that
exceeded critical strain levels by making distinct criteria for those
anomalies.
3. PHMSA Response
PHMSA believes that the repair criteria it proposed in the NPRM for
dents provide an adequate safety margin and believes the criteria for
dents that were suggested by some of the commenters would not provide
adequate safety margin. PHMSA based this judgment on R&D programs that
have been sponsored by PHMSA and the Pipeline Research Council
International, and on elements of dent repair criteria that are
contained within API RP 1183.\40\
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\40\ API, Recommended Practice 1183, ``Assessment and Management
of Dents in Pipelines'' (Nov. 2020).
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[…truncated; see source link]Indexed from Federal Register on August 24, 2022.
This is legal information, not legal advice. Laws vary by jurisdiction and change frequently. Always verify current law with official sources and consult a licensed attorney in your jurisdiction for advice on your specific situation.