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Rule2022-07133

Pipeline Safety: Requirement of Valve Installation and Minimum Rupture Detection Standards

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Published

April 8, 2022

Effective

October 5, 2022

Issuing agencies

Transportation DepartmentPipeline and Hazardous Materials Safety Administration

Abstract

PHMSA is revising the Federal Pipeline Safety Regulations applicable to most newly constructed and entirely replaced onshore gas transmission, Type A gas gathering, and hazardous liquid pipelines with diameters of 6 inches or greater. In the revised regulations, PHMSA requires operators of these lines to install rupture-mitigation valves (i.e., remote-control or automatic shut-off valves) or alternative equivalent technologies, and establishes minimum performance standards for those valves' operation to prevent or mitigate the public safety and environmental consequences of pipeline ruptures. This final rule establishes requirements for rupture-mitigation valve spacing, maintenance and inspection, and risk analysis. The final rule also requires operators of gas and hazardous liquid pipelines to contact 9- 1-1 emergency call centers immediately upon notification of a potential rupture and conduct post-rupture investigations and reviews. Operators must also incorporate lessons learned from such investigations and reviews into operators' personnel training and qualifications programs, and in design, construction, testing, maintenance, operations, and emergency procedure manuals and specifications. PHMSA is promulgating these regulations in response to congressional directives following major pipeline incidents where there were significant environmental consequences or losses of human life. The revisions are intended to achieve better rupture identification, response, and mitigation of safety, greenhouse gas, and environmental justice impacts.

Full Text

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[Federal Register Volume 87, Number 68 (Friday, April 8, 2022)]
[Rules and Regulations]
[Pages 20940-20992]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2022-07133]

[[Page 20939]]

Vol. 87

Friday,

No. 68

April 8, 2022

Part II

Department of Transportation

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Pipeline and Hazardous Materials Safety Administration

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49 CFR Parts 192 and 195

Pipeline Safety: Requirement of Valve Installation and Minimum Rupture
Detection Standards; Final Rule

Federal Register / Vol. 87 , No. 68 / Friday, April 8, 2022 / Rules
and Regulations

[[Page 20940]]

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Parts 192 and 195

[Docket No. PHMSA-2013-0255; Amdt. Nos. 192-130; 195-105]
RIN 2137-AF06

Pipeline Safety: Requirement of Valve Installation and Minimum
Rupture Detection Standards

AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
DOT.

ACTION: Final rule.

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SUMMARY: PHMSA is revising the Federal Pipeline Safety Regulations
applicable to most newly constructed and entirely replaced onshore gas
transmission, Type A gas gathering, and hazardous liquid pipelines with
diameters of 6 inches or greater. In the revised regulations, PHMSA
requires operators of these lines to install rupture-mitigation valves
(i.e., remote-control or automatic shut-off valves) or alternative
equivalent technologies, and establishes minimum performance standards
for those valves' operation to prevent or mitigate the public safety
and environmental consequences of pipeline ruptures. This final rule
establishes requirements for rupture-mitigation valve spacing,
maintenance and inspection, and risk analysis. The final rule also
requires operators of gas and hazardous liquid pipelines to contact 9-
1-1 emergency call centers immediately upon notification of a potential
rupture and conduct post-rupture investigations and reviews. Operators
must also incorporate lessons learned from such investigations and
reviews into operators' personnel training and qualifications programs,
and in design, construction, testing, maintenance, operations, and
emergency procedure manuals and specifications. PHMSA is promulgating
these regulations in response to congressional directives following
major pipeline incidents where there were significant environmental
consequences or losses of human life. The revisions are intended to
achieve better rupture identification, response, and mitigation of
safety, greenhouse gas, and environmental justice impacts.

DATES: The effective date of this final rule is October 5, 2022.

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 Regulatory Action
C. Costs and Benefits
II. Background
A. Pipeline Ruptures
B. National Transportation Safety Board Recommendations
C. Advance Notices of Proposed Rulemaking
D. 2011 Pipeline Safety Act and Related Studies
i. Section 4--Automatic and Remote-Controlled Shut-Off Valves
a. GAO Report GAO-13-168
b. Studies for the Requirements of Automatic and Remotely
Controlled Shutoff Valves and Hazardous Liquids and Natural Gas
Pipelines With Respect to Public and Environmental Safety
ii. Section 8--Leak Detection
E. 2020 Valve Rule NPRM
F. Subsequent Legislative Deadlines; Recent Executive Orders and
Actions
III. NPRM Comments, Pipeline Advisory Committee Recommendations, and
PHMSA Responses
A. General Comments, Scope, Applicability, and Cost-Benefit
Issues
B. Rupture Definition
C. Rupture Identification Definition and Timeframe
D. RMV Installation, RMV Closure Timeframe
E. Valve Spacing & Location
F. Valve Status Monitoring
G. Class Location Changes
H. Valve Maintenance
I. Failure Investigations
J. 9-1-1 Notification Requirements
K. Other
IV. Section-by-Section Analysis of Changes to 49 CFR Part 192 for
Gas Pipelines
V. Section-by-Section Analysis of Changes to 49 CFR Part 195 for
Hazardous Liquid Pipelines
VI. Regulatory Analyses and Notices

I. Executive Summary

A. Purpose of the Regulatory Action

This final rule is the culmination of a decade-long PHMSA
rulemaking effort responding to congressional mandates, National
Transportation Safety Board (NTSB) recommendations, and Government
Accountability Office (GAO) recommendations to revise the Federal
Pipeline Safety Regulations at 49 Code of Federal Regulations (CFR)
parts 192 and 195 to prevent the catastrophic loss of life, property
damage, and environmental harm experienced from ruptures on large-
diameter hazardous liquid and natural gas pipelines, such as those that
occurred near Marshall, MI, and San Bruno, CA, in 2010.
This final rule codifies a suite of design and performance
standards prescribing the installation, operation, and spacing of
rupture-mitigation valves (RMV) or alternative equivalent technologies
on most new or entirely replaced, onshore, large-diameter (6 inches or
greater), gas transmission, Type A gas gathering, and hazardous liquid
pipelines.\1\ The final rule also requires operators of all gas and
hazardous liquid pipelines to modify their emergency plans to ensure
immediate and direct contact of 9-1-1 emergency call centers, or
coordinating government officials, on notification of a potential
rupture. PHMSA expects this final rule's regulatory amendments will
ensure operators of pertinent gas and hazardous liquid pipelines take
prompt identification, isolation, and mitigation actions with respect
to unintentional or uncontrolled, large-volume releases of gas or
hazardous liquids during a pipeline rupture. 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 (GHG) emissions released during ruptures of
natural gas pipelines), and promote environmental justice for minority
populations, low-income populations, or other underserved and
disadvantaged communities.
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\1\ For the purposes of this final rule, references to diameter
are to the outside diameter of the pipe. Similarly, subsequent
references in this final rule to gas transmission, Type A gas
gathering, and hazardous liquid pipelines will, for brevity,
generally omit the qualifications (onshore, 6-inch diameter)
appearing in the statement of the final rule's scope above. Lastly,
references within this final rule to ``hazardous liquid pipelines''
will, unless otherwise stipulated, include carbon dioxide pipelines
because both hazardous liquid and carbon dioxide pipelines are
subject to 49 CFR part 195 requirements.
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Recent pipeline ruptures with catastrophic consequences underscore
the importance of prompt identification, isolation, and mitigation
actions in reducing the amount of product released--and by extension,
the loss of life, property damage, and environmental harm--from
ruptures on hazardous liquid and natural gas pipelines. One such
rupture occurred on July 25, 2010, in Marshall, MI, resulting in a
release of approximately 800,000 gallons of crude oil into the
Kalamazoo River and approximately $1 billion in property and
environmental damages.\2\ The operator, Enbridge Energy, LP (Enbridge),
took 18 hours to confirm the

[[Page 20941]]

pipeline rupture following the initial alarms received by the control
room operators. Once Enbridge confirmed the rupture, the failed segment
was immediately isolated using installed remote-control shut-off valves
(RCV).
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\2\ NTSB, Accident Report PAR-12/01, ``Enbridge Incorporated:
Hazardous Liquid Pipeline Rupture and Release; Marshall, MI: July
25, 2010'' (July 10, 2012), <a href="https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1201.pdf">https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1201.pdf</a>.
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Another rupture occurred on September 9, 2010, in San Bruno, CA,
when a gas transmission pipeline ruptured, causing an explosion that
killed 8 people, sent 51 other people to the hospital, destroyed 38
homes and damaged 70 others, and caused the evacuation of approximately
300 homes. According to the NTSB report on that incident,\3\ the
initial 9-1-1 notification call by the public was made within one
minute of the rupture, which occurred at 6:11 p.m. The response crew
assembled to operate valves and isolate the rupture did not reach the
first valve site until 7:20 p.m. According to the California Public
Utilities Commission (CPUC) report on the incident, the operator,
Pacific Gas and Electric (PG&E), did not confirm that the incident was
a pipeline rupture until 7:25 p.m., when PG&E employees in the field,
at dispatch, and in the company's supervisory control and data
acquisition (SCADA) \4\ center confirmed that a PG&E gas transmission
line had failed.\5\ After multiple valve closures, PG&E isolated the
ruptured pipeline segment at 7:46 p.m., 95 minutes after the rupture
initiated.\6\ This delay in closing the valves allowed the fire to burn
unabated and hampered emergency response efforts.
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\3\ NTSB, Accident Report PAR-11/01, ``Pacific Gas and Electric
Company; Natural Gas Transmission Pipeline Rupture and Fire; San
Bruno, CA; September 9, 2010'' (Aug. 30, 2011), <a href="https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1101.pdf">https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1101.pdf</a>.
\4\ Most pipeline operators utilize a SCADA system to run their
operations. These are computer-based systems used by a controller in
a control room that collects and displays information about a
pipeline facility and may have the ability to send commands back to
the pipeline facility. See 49 CFR 192.3 and 195.2.
\5\ CPUC, ``Sept. 9, 2010 PG&E Pipeline Rupture in San Bruno,
CA'' (Jan. 12, 2012), <a href="https://www.cpuc.ca.gov/uploadedFiles/CPUC_Public_website/Content/Safety/Natural_Gas_Pipeline/News/AgendaStaffReportreOIIPGESanBruno">https://www.cpuc.ca.gov/uploadedFiles/CPUC_Public_website/Content/Safety/Natural_Gas_Pipeline/News/AgendaStaffReportreOIIPGESanBruno</a> Explosion.pdf.
\6\ The CPUC also noted that the backfeed to the line and the
gas feeds to a related distribution system were not closed until
7:52 p.m. and 11:32 p.m., respectively.
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These rupture events highlight the need for more robust protections
in the Federal Pipeline Safety Regulations for identifying, isolating,
and mitigating catastrophic pipeline failures. First, there is a need
for better and more timely rupture isolation and mitigation equipment
and methods. PG&E's failure to close isolation valves rapidly after the
rupture at San Bruno diminished its ability to mitigate the
consequences of the failure, allowing the fire to burn unabated for 95
minutes following the initial rupture, with firefighting operations
continuing for an additional 2 days after the rupture occurred. Second,
there is need for operators to identify promptly that a rupture has
occurred and respond quickly to mitigate its consequences. Enbridge had
remote-control isolation valves installed on its ruptured oil pipeline
at the time the spill occurred near Marshall, MI, but its failure to
confirm and respond to the rupture promptly rendered that technology
essentially useless.
After these spill events, the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011 (2011 Pipeline Safety Act; Pub.
L. 112-90) was enacted. The legislation contained several mandates to
improve pipeline safety. In particular, PHMSA is required to issue
regulations requiring the use of automatic shut-off valves (ASV) or
RCVs, or equivalent technology, on newly constructed or replaced gas
transmission and hazardous liquid pipeline facilities. See 49 U.S.C.
60102(n). That statutory mandate was subsequently revisited,
establishing a new deadline for PHMSA to issue a final rule (see 49
U.S.C. 60102 note).
In developing this final rule, PHMSA considered NTSB safety
recommendations following the PG&E incident; GAO recommendations on the
ability of operators to respond to commodity releases in high-
consequence areas (HCA); \7\ technical reports commissioned by PHMSA on
valves and leak detection; <SUP>8 9</SUP> comments received on related
topics through advance notices of proposed rulemaking (ANPRM) and the
notice of proposed rulemaking (NPRM) published in February 2020; \10\
and feedback from members of the public, environmental advocacy
organizations, State pipeline safety regulators, and industry
representatives during Gas Pipeline Advisory Committee and Liquid
Pipeline Advisory Committee meetings.
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\7\ GAO, ``Pipeline Safety: Better Data and Guidance Needed to
Improve Pipeline Operator Incident Response'' (Jan. 2013), <a href="https://www.gao.gov/assets/660/651408.pdf">https://www.gao.gov/assets/660/651408.pdf</a>. An HCA, briefly, is an area with
higher population density or contains an area of cultural
significance or where people would congregate at a certain frequency
(e.g., churches, playgrounds, schools, hospitals, etc.). See Sec.
192.903.
\8\ Oak Ridge National Laboratory (ORNL), ORNL/TM-2012/411,
``Studies for the Requirements of Automatic and Remotely Controlled
Shutoff Valves and Hazardous Liquids and Natural Gas Pipelines with
Respect to Public and Environmental Safety'' (Oct. 31, 2012),
<a href="https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16701/finalvalvestudy.pdf">https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16701/finalvalvestudy.pdf</a>.
\9\ Kiefner and Associates, Inc., Report No. 12-173, ``Leak
Detection Study--DTPH56-11-D-000001'' (Dec. 10, 2012), <a href="https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16691/leak-detection-study.pdf">https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16691/leak-detection-study.pdf</a>.
\10\ 85 FR 7162 (Feb. 6, 2020) (NPRM).
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B. Summary of the Major Provisions of the Regulatory Action

This final rule prescribes installation and spacing requirements
for ASVs and RCVs (collectively, rupture-mitigation valves, or RMVs) as
well as for alternative equivalent technology. The requirements apply
to most newly constructed, or entirely replaced, onshore pipelines with
diameters of 6 inches or greater, including natural gas transmission
pipelines, Type A gas gathering pipelines, and hazardous liquid
pipelines (including certain regulated hazardous liquid gathering
pipelines). In this final rule, PHMSA has defined an ``entirely
replaced'' pipeline as a pipeline that has 2 or more miles being
replaced with new pipe within any stretch of 5 contiguous miles within
any 24-month period.
The rule also defines ASVs and RCVs as RMVs. PHMSA did not identify
specific technologies that operators might use as alternative
equivalent technologies for the purposes of this rulemaking, but PHMSA
is requiring that such alternative technologies meet the performance
standard for RMVs, to include the ability to immediately enable
isolation of a rupture--in 30 minutes or less, measured from an
operator's identification of a rupture after notification of a
potential rupture.
Operators of pipelines subject to the requirements of this final
rule may request to install alternative equivalent technologies if they
can demonstrate within a notification for PHMSA review that site-
specific installation of an alternative equivalent technology would
provide an equivalent level of safety to an RMV. Those notifications
must be submitted in advance of installation of that technology, and
must demonstrate an equivalent level of safety by reference to
technical and safety factors including, but not limited to, the
following: Design, construction, maintenance, and operating procedures;
technology design and operating characteristics such as operation times
(closure times for manual valves); service reliability and life;
accessibility to operator personnel; nearby population density; and
potential consequences to the environment and the public. Further,
should an operator request use of manual valves as an alternative
equivalent technology, the notification submitted to PHMSA must also
demonstrate the economic, technical, or operational infeasibility of
installation of an RMV by reference to

[[Page 20942]]

factors such as access to communications and power; terrain;
prohibitive cost; labor and component availability; ability to secure
required land access rights and permits; and accessibility to operator
personnel for installation and maintenance.
For regulated rural hazardous liquid gathering pipelines,\11\ at
this time, PHMSA is requiring the installation of RMVs or alternative
equivalent technology only where such pipelines cross bodies of water
more than 100 feet in width from high water mark to high water mark.
For hazardous liquid pipelines in general, this final rule establishes
valve spacing thresholds both within and outside of HCAs and provides
valve spacing limits for highly volatile liquid (HVL) pipelines in
populated areas. PHMSA has recently issued a final rule in a separate
rulemaking that will update its regulations that affect all types of
gas gathering pipelines.\12\
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\11\ A regulated rural hazardous liquid gathering pipeline is
defined in Sec. 195.11 as an onshore gathering line in a rural area
that meets all of the following criteria: (1) A nominal diameter
from 6\5/8\ to 8\5/8\ inches; (2) located in or within \1/4\ mile of
an unusually sensitive area, as that term is defined in Sec. 195.6;
and (3) operating at a maximum pressure established under Sec.
195.406 corresponding to a stress level greater than 20 percent of
the specified minimum yield strength (SMYS) of the line pipe or, if
the stress level is unknown or the pipeline is not constructed with
steel pipe, a pressure of more than 125 psig.
\12\ ``Pipeline Safety--Safety of Gas Gathering Pipelines:
Extension of Reporting Requirements, Regulation of Large, High-
Pressure Lines, and Other Related Amendments,'' 86 FR 63266 (Nov.
15, 2021) (``Gas Gathering final rule'').
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For gas transmission and Type A gas gathering pipelines, the RMV or
alternative equivalent technology installation requirements will not
apply if the pipeline segment is in a Class 1 or Class 2 location and
has a potential impact radius (PIR) less than or equal to 150 feet.
PHMSA understands that the lower operating pressures characteristic of
Type B gas gathering pipelines involve risk profiles comparable to the
Type A gas gathering pipelines exempted from the final rule's
installation and operational requirements. Therefore, the final rule
similarly exempts Type B gas gathering pipelines from the RMV or
alternative equivalent technology installation requirements. The final
rule also exempts Type C gas gathering lines from those requirements,
as that designation was established by the Gas Gathering final rule--
which was published well after the publication of the NPRM for this
rulemaking.
Additionally, for each gas pipeline whose operator, in response to
a class location change, chooses to replace 2 or more miles of pipe
within a contiguous 5-miles to meet the maximum allowable operating
pressure (MAOP) requirements of the new class location, the operator
would be required to install or otherwise modify existing valves as
necessary to comply with the valve spacing requirements and rupture
mitigation requirements of this final rule.\13\ The final rule provides
operators replacing smaller pipeline segments following a change in
class location more flexibility: Operators replacing between 1,000 feet
and 2 miles may either install RMVs, or they may automate existing
valves with automatic or remote-control actuators and pressure sensors
(with a maximum spacing of 20 miles). And the final rule's RMV
installation and spacing requirements do not apply to those pipe
replacements that amount to less than 1,000 feet within any single mile
during any 24-month period.
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\13\ Class locations, defined at Sec. 192.5, are determined
depending on the number of dwellings within 220 yards on either side
of a pipeline and reflect the population density around the
pipeline.
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This final rule also establishes Federal minimum safety performance
standards for the identification of ruptures, pipeline segment
isolation, and other mitigative actions, for pipelines on which RMVs or
alternative equivalent technology are installed pursuant to this
rulemaking. Relevant new requirements include: (1) A definition of the
term ``notification of potential rupture'' to identify signs of an
uncontrolled release of a large volume of commodity observed by, or
reported to, the operator; (2) establishing written procedures for
identifying and responding to a rupture; (3) responding to an
identified rupture by closing RMVs or alternative equivalent
technology, to provide complete valve shut-off and segment isolation as
soon as practicable, but no more than 30 minutes after rupture
identification; (4) performing post-event reviews of any incidents/
accidents or other failure events involving the closure of RMVs or
alternative equivalent technologies to ensure the performance
objectives of this rule are met and to apply any lessons learned
system-wide; (5) performing maintenance on RMVs and alternative
equivalent technology, which includes drills for alternative equivalent
technology that is manually or locally operated; and (6) remediation
measures for repair or replacement of inoperable RMVs and alternative
equivalent technologies, including an RMV or alternative equivalent
technology that cannot maintain shut-off, as soon as practicable.
This final rule also requires operators of all gas and hazardous
liquid pipelines subject to the emergency planning requirements at
Sec. Sec. 192.615 and 195.402, respectively, to update their emergency
response plans to provide for immediate and direct notification of
appropriate public safety answering points (9-1-1 emergency call
centers) for the communities and jurisdictions in which a rupture is
located following the notification of a potential rupture. Similarly,
the final rule requires all gas and hazardous liquid pipelines subject
to failure investigation requirements at Sec. Sec. 192.617 and
195.402, respectively, to conduct post-rupture investigations and
reviews, and to incorporate lessons learned from such investigations
and reviews into their personnel training and qualifications programs,
and in design, construction, testing, maintenance, operations, and
emergency procedure manuals and specifications.

C. Costs and Benefits

Consistent with Executive Order 12866 (``Regulatory Planning and
Review''),\14\ PHMSA has prepared an assessment of the benefits and
costs of this final rule, as well as reasonable alternatives. The
Regulatory Impact Analysis (RIA) developed by PHMSA in support of this
final rule, and which is available in the rulemaking docket, estimates
the annual costs of the rule to be approximately $5.9 million,
calculated using a 7 percent discount rate. In the RIA, costs are
aggregated by compliance method to estimate total costs, by year, for
the baseline and the final rule. The incremental effect of this
rulemaking is estimated by taking the difference in total costs
relative to the baseline. Costs are then aggregated across all years in
the analysis period and annualized. The costs reflect the installation
of valves on certain newly constructed and entirely replaced gas and
hazardous liquid pipelines, as well as incremental programmatic changes
that operators will need to make to incorporate the proposed rupture
identification and response procedures.
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\14\ 58 FR 51735 (Oct. 4, 1993).
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PHMSA provides a qualitative discussion of the benefits of this
rulemaking in the RIA.\15\ PHMSA expects this final rule's regulatory
amendments will compel operators of

[[Page 20943]]

pertinent natural gas and hazardous liquid pipelines to take prompt
identification, isolation, and mitigation actions with respect to
unintentional or uncontrolled, large-volume releases of natural gas or
hazardous liquids during a pipeline rupture. 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 ruptures of
natural gas pipelines), and promote environmental justice for minority
populations, low-income populations, or other underserved and
disadvantaged communities. PHMSA has, therefore, determined that these
(unquantified) public safety, environmental, and equity benefits of the
final rule described in this final rule and its supporting RIA and
Environmental Assessment justify the costs of the final rule.
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\15\ PHMSA explains in the RIA that, although the Environmental
Assessment for this rulemaking provides illustrative quantifications
of avoided greenhouse gas emissions from this final rule, PHMSA's
evaluation of the greenhouse gas emissions within its cost-benefit
analysis is on the basis of qualitative assessment of those avoided
emissions.
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II. Background

A. Pipeline Ruptures

Although pipelines are generally considered to be an efficient and
relatively safe means of transporting natural gas and hazardous
liquids,\16\ they can experience large-volume, uncontrolled releases
that can have severe consequences. Such rupture events can be
aggravated by some combination of: Missed opportunities by the operator
to identify that a rupture has occurred; the failure of operating
personnel to take appropriate actions once a rupture has been
identified; delays in accessing and closing available pipeline segment
isolation valves; and an inability quickly to close isolation valves
that would have the most significant impact in mitigating the
consequences of a rupture. Typically, these types of events where a
significant amount of time passes between initiation and isolation of a
rupture have been the most serious in terms of monetary and
environmental damages and safety consequences. The Marshall, MI, and
San Bruno, CA, incidents are examples of rapid failure events with
large-volume releases on high-pressure, large-diameter pipelines with
serious consequences exacerbated by delays in identification and
isolation of the ruptures.
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\16\ See PHMSA, Letter to Congress, Report on Shipping Crude Oil
by Truck, Rail, and Pipeline at 2 (Oct. 2018), <a href="https://www7.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/news/70826/report-congress-shipping-crude-oil-truck-rail-and-pipeline-32019.pdf">https://www7.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/news/70826/report-congress-shipping-crude-oil-truck-rail-and-pipeline-32019.pdf</a>.
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The intent of this final rule is to require design and equipment
elements and improved operational practices for quick and efficient
identification of ruptures, that in turn will improve rupture
mitigation and shorten rupture isolation times for certain gas
transmission, gathering, and hazardous liquid pipelines. Rupture
isolation time, as it is discussed in this final rule, is the time it
takes an operator to identify a rupture after a notification of
potential rupture, implement response procedures, and fully close the
appropriate valves to terminate the uncontrolled flow of commodity from
the ruptured pipeline segment.
PHMSA and NTSB investigations of recent natural gas transmission
and hazardous liquid pipeline ruptures have identified issues relating
to the timeliness of rupture identification and the appropriateness and
timeliness of operators' responses to identified ruptures. Typically,
no single event contributes to the deficiencies in rupture
identification and response. Instead, there are multiple contributing
factors associated with the technology, design, equipment, procedures,
or human elements that result in inadequate rupture identification and
response efforts. In some rupture scenarios, certain aspects of an
operator's rupture identification or response efforts appeared
adequate, but other issues, such as delayed access to isolation valves,
resulted in an inadequate response overall.
For example, in the Enbridge accident near Marshall, MI, the
pipeline operator had installed a leak detection system (LDS) and SCADA
system that notified the operator of a potential rupture within minutes
of the actual event, but issues related to the operator's procedures,
training, and personnel response resulted in an 18-hour lapse before
the operator confirmed the rupture and initiated mitigating actions. In
the PG&E incident in San Bruno, CA, the operator effectively identified
through its LDS or SCADA systems that there was in fact a rupture, but
then took another 95 minutes to isolate it. This delay proved
catastrophic due to the time required for confirming the existence of
the rupture, assembling response personnel, traveling to the valve
site, and closing the valve to isolate the pipeline segment--during
which time a fire resulting from the rupture burned unabated. The
NTSB's report on that incident noted that PG&E lacked a detailed and
comprehensive procedure for responding to large-scale emergencies such
as a transmission pipeline break, and that the use of ASVs or RCVs
would have reduced the amount of time taken to stop the flow of gas.
Prior to those rupture events, the NTSB noted similar issues
related to rupture response in its report on an incident occurring on
March 23, 1994, in Edison Township, NJ.\17\ In the Edison incident, the
operator took nearly 2\1/2\ hours to stop the flow of natural gas from
a ruptured pipeline in a highly-populated area. The fire that followed
the rupture destroyed 8 buildings, caused the evacuation of
approximately 1,500 apartment residents, and resulted in more than $25
million (approximately $40 million in 2020 dollars) worth of property
damage. The NTSB report quotes the operator of that pipeline in saying
that it could typically notify employees to close valves within 5 to 10
minutes after identifying a rupture, and that the time it took to close
a manual valve depended on the employee's travel time to the valve
site: Its employees could usually arrive at a valve site within 15 to
20 minutes, but in some instances it could take more than an hour for
employees to arrive at certain valve locations after being dispatched.
With this in mind, the NTSB concluded that the lack of automatic or
remote-operated valves on the ruptured line prevented the operator from
promptly stopping the flow of gas to the failed pipeline segment, which
exacerbated damage to nearby property. Subsequently, the NTSB
recommended to PHMSA's predecessor, the Research and Special Programs
Administration, that it expedite establishing requirements for
installing automatic or remote-operated valves on high-pressure
pipelines in urban and environmentally sensitive areas to provide for
rapid shutdown of failed pipeline systems.
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\17\ NTSB, PAR-95-01, ``Pipeline Accident Report; Texas Eastern
Transmission Corporation Natural Gas Pipeline Explosion and Fire;
Edison, New Jersey'' (Jan. 18, 1995), <a href="https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR9501.pdf">https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR9501.pdf</a>.
---------------------------------------------------------------------------

B. National Transportation Safety Board Recommendations

In its report on the PG&E gas transmission pipeline incident that
occurred in San Bruno, CA, the NTSB issued safety recommendations P-11-
8 through P-11-20 to PHMSA.\18\ Pertaining to this rulemaking, NTSB
safety recommendation P-11-10 recommended that PHMSA require operators
to equip their SCADA systems with tools, including leak detection
systems and appropriately spaced flow and pressure transmitters along
covered transmission lines, to identify leaks (and ruptures); and NTSB
safety recommendation P-11-11 recommended PHMSA require operators

[[Page 20944]]

install ASVs or RCVs in HCAs and Class 3 and 4 locations, with the
valve spacing based on risk analysis.
---------------------------------------------------------------------------

\18\ See supra note 3.
---------------------------------------------------------------------------

PHMSA determined that, although the NTSB directed these
recommendations to a rupture on a gas transmission pipeline, certain
aspects of these recommendations are also applicable to ruptures on gas
gathering and hazardous liquid pipelines, including the regulated
hazardous liquid gathering pipelines regulated under part 195. PHMSA
took these recommendations into account when developing this final rule
by requiring that RMVs and alternative equivalent technologies be
capable of having their status controlled or monitored (directly, or
indirectly via the upstream pressure, and the downstream pressure)
remotely,\19\ and by requiring the installation of RMVs, or equivalent
alternative technologies, at intervals of no more than 8 miles in Class
4 locations and 15 miles in Class 3 locations.
---------------------------------------------------------------------------

\19\ As discussed later in this document, for ASVs, an operator
does not need to monitor remotely a valve's status if the operator
has the capability to monitor pressures or gas flow rate on the
pipeline to identify and locate a rupture. Pipeline segments that
use an alternative equivalent technology must have the capability to
monitor pressures or gas flow rates on the pipeline to identify and
locate a rupture.
---------------------------------------------------------------------------

C. Advance Notices of Proposed Rulemaking

PHMSA published two ANPRMs seeking comments regarding the revision
of provisions in the Federal Pipeline Safety Regulations governing
safety of hazardous liquid pipelines and natural gas pipelines.\20\
PHMSA responded to pertinent comments received on the ANPRMs in Section
III of the NPRM preceding this final rule. PHMSA addressed other topics
raised in the hazardous liquid and gas transmission ANPRMs within other
rulemakings, as appropriate.
---------------------------------------------------------------------------

\20\ 75 FR 63774 (Oct. 18, 2010) (pertaining to hazardous liquid
pipelines within docket PHMSA-2010-0229), and 76 FR 53086 (Aug. 25,
2011 (pertaining to natural gas pipelines within docket PHMSA-2011-
0023).
---------------------------------------------------------------------------

D. 2011 Pipeline Safety Act and Related Studies

Sections 4 and 8 of the 2011 Pipeline Safety Act established
statutory requirements relating directly to topics addressed in the
ANPRMs discussed previously. This final rule responds to those
statutory mandates. PHMSA also considered the GAO Report No. GAO-13-
168, ``Better Data and Guidance Needed to Improve Pipeline Operator
Incident Response'' and ORNL Report/TM-2012/411, ``Studies for the
Requirements of Automatic and Remotely Controlled Shutoff Valves on
Hazardous Liquids and Natural Gas Pipelines With Respect to Public and
Environmental Safety'' which were performed in response to the 2011
Pipeline Safety Act and are discussed further below.
i. Section 4--Automatic and Remote-Controlled Shut-Off Valves
Section 4 of the 2011 Pipeline Safety Act directs the Secretary of
Transportation (Secretary), if appropriate, to require by regulation
the use of ASVs or RCVs, or equivalent technology, where it is
economically, technically, and operationally feasible, on hazardous
liquid and gas transmission pipeline facilities that are constructed or
entirely replaced after the date on which the Secretary issues the
final rule containing such requirements. This final rule addresses this
mandate by establishing minimum standards for the installation of RMVs
or alternative equivalent technology on specified newly constructed or
entirely replaced, onshore pipelines that have diameters of 6 inches or
greater, including gas transmission pipelines, Type A gas gathering
pipelines, hazardous liquid pipelines, and certain regulated hazardous
liquid gathering lines.
a. GAO Report GAO-13-168
Section 4 of the 2011 Pipeline Safety Act required the development
of a study by the Comptroller General on the ability of pipeline
operators to respond to a hazardous liquid or gas release from a
pipeline segment located in an HCA. In this study, published in January
2013, the GAO recommended PHMSA take the following two actions:
1. Improve the reliability of incident response data to improve
operators' incident response times, and use this data to evaluate
whether to implement a performance-based framework for incident
response times; and
2. Assist operators in determining whether to install automated
valves by using PHMSA's existing information sharing mechanisms to
alert all pipeline operators of inspection and enforcement guidance
that provides additional information on how to interpret regulations on
automated valves, and share approaches used by operators for making
decisions on whether to install automated valves.
The GAO report noted that defined performance-based goals,
established with reliable data and sound agency assessments, could
result in improved operator response to incidents, with ASV and RCV
installation and use being one of the determining factors. The GAO
further noted that PHMSA's then-current regulations for incident
response and installation and use of ASVs and RCVs employed broadly-
stated performance standards, requiring operators to respond to
incidents in a ``prompt and effective manner,'' \21\ and requiring
operators to install ASVs, RCVs, or emergency flow restricting devices
(EFRD) if an operator determines, through risk analysis, such valves
are necessary to protect HCAs.\22\
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\21\ For natural gas and hazardous liquid pipelines, Sec. Sec.
192.615(a)(3) and 195.402(e)(2), respectively.
\22\ Requirements for ASV and RCV installation on gas
transmission pipelines are at Sec. 192.935(c), and requirements for
EFRD installation for hazardous liquid pipelines are at Sec.
195.452(i)(4).
---------------------------------------------------------------------------

More clearly defined goals can help operators identify actions that
could improve their ability to respond to certain types of incidents
consistently and promptly, though identical incident response actions
are not appropriate for all circumstances due to variable locations,
equipment needs, configurations, and operating conditions of pipeline
facilities. PHMSA agrees with the GAO's conclusions that more precise
performance-based standards, in conjunction with carefully selected
requirements, could be more effective in improving incident response
times, particularly when ruptures are involved.
The GAO report also concluded that the primary advantage of
installing and using automated valves is that operators can respond
more quickly to isolate the affected pipeline segment and reduce the
amount of commodity released. Although the report suggested that using
automated valves can have certain disadvantages, including the
potential for accidental closures, which makes it appropriate for
operators to decide whether to install automated valves on a case-by-
case basis, the report recognized that a faster incident response time
could reduce the amount of property damage from secondary fires (after
an initial pipeline rupture) by allowing fire departments to extinguish
the fires sooner. For hazardous liquid pipelines, a faster incident
response time could also result in lower costs for environmental
remediation efforts and less commodity loss.
PHMSA applied these principles and the GAO's findings and
recommendations in developing the standards in this final rule. The
amendments in this final rule also include specific post-event review
requirements in Sec. Sec. 192.617 and 195.402. Operators must make
those post-event reviews available for PHMSA to inspect, and PHMSA
would be able to use those reviews to inform future rulemakings and
guidance documents.

[[Page 20945]]

b. Studies for the Requirements of Automatic and Remotely Controlled
Shutoff Valves and Hazardous Liquids and Natural Gas Pipelines With
Respect to Public and Environmental Safety
In March 2012, PHMSA commissioned a study to assess the
effectiveness of timely operation of automatic and remote-controlled
shut-off valves recommended by the NTSB in its report on the PG&E
incident and mandated by section 4 of the 2011 Pipeline Safety Act for
mitigating the public safety and environmental consequences of natural
gas and hazardous liquid pipeline releases. That study, whose
conclusions were memorialized in the above-captioned report, also
evaluated the economic, technical and operational feasibility and
potential benefits of installing ASVs and RCVs in newly constructed and
entirely replaced pipelines. The study concluded that:
1. In general, installing ASVs and RCVs on newly constructed and
entirely replaced natural gas transmission and hazardous liquid
pipelines is technically feasible, provided sufficient space is
available for the valve body, actuators, power source, sensors and
related electronic equipment, and personnel required to install and
maintain the valve; and is operationally feasible, provided the
communication links between the RCV site and the control room are
continuous and reliable.
2. There is evidence that it is economically feasible to install
ASVs and RCVs on newly constructed and entirely replaced natural gas
transmission and hazardous liquid pipelines, and the benefits would
exceed the costs for the release scenarios (guillotine-type breaks on
gas transmission pipelines with diameters of 12 and 42 inches in HCAs
of all class locations, as well as on hazardous liquid pipelines with
diameters of 8 and 30 inches in HCAs) considered in the study. However,
the study noted that it is necessary to consider site-specific
variables in determining whether installing ASVs or RCVs on newly
constructed or entirely replaced pipelines is economically feasible for
a particular situation and pipeline.
3. Installing ASVs and RCVs on newly constructed and entirely
replaced natural gas and hazardous liquid pipelines can be an effective
strategy for mitigating potential fire consequences resulting from a
release and subsequent ignition. Adding automatic closure capability to
valves on newly constructed or entirely replaced hazardous liquid
pipelines can also be an effective strategy for mitigating potential
socioeconomic and environmental damage resulting from a release that
does not ignite.
4. For hazardous liquid pipelines, installing ASVs and RCVs can be
an effective strategy for mitigating potential fire damage resulting
from a pipe opening-type breaks \23\ and subsequent ignition, provided
the leak is detected and the appropriate ASVs and RCVs close completely
so that the damaged pipeline segment is isolated within 15 minutes
after the break.
---------------------------------------------------------------------------

\23\ A break in the pipeline that involves the opening of the
pipe in either the circumferential or longitudinal direction.
---------------------------------------------------------------------------

PHMSA used the conclusions of that report in developing this
rulemaking and as a basis for implementing standards for valve
installation per section 4 of the 2011 Pipeline Safety Act.
ii. Section 8--Leak Detection
Section 8 of the 2011 Pipeline Safety Act required the Secretary to
submit to Congress a report on LDSs used by operators of hazardous
liquid pipeline facilities, including transportation-related flow
lines, and to establish technically, operationally, and economically
feasible standards for the capability of LDSs to detect leaks.
PHMSA responded to the 2011 Pipeline Safety Act's section 8 mandate
by commissioning a leak detection study.\24\ The study examined LDSs
used by operators of hazardous liquid and natural gas transmission
pipelines and included an analysis of the technical limitations of
current LDSs, the ability of the systems to detect ruptures and small
leaks that are ongoing or intermittent, and what can be done to foster
development of better technologies. It also reviewed the practicality
of establishing technically, operationally, and economically feasible
standards for LDS capabilities. The study addressed five tasks defined
by PHMSA:
---------------------------------------------------------------------------

\24\ See supra note 9.
---------------------------------------------------------------------------

1. Assess past incidents to determine if additional LDSs would have
helped to reduce the consequences of the incident;
2. Review installed and currently available LDS technologies, along
with their benefits, drawbacks, and ability to be retrofitted on
existing pipelines;
3. Study current LDS operational practices used by the pipeline
industry;
4. Perform a cost-benefit analysis of deploying LDSs on existing
and new pipelines; and
5. Study existing LDS industry standards and international
regulations to determine what gaps exist and if additional standards
are needed to cover LDSs over a larger range of pipeline categories.
The authors of the study were tasked only to report data and
technical and cost aspects of LDSs. Although the study did not provide
any specific conclusions or recommendations related to leak detection
system standards, the study acknowledged that pressure/flow monitoring
(leak detection techniques) will consistently and reliably catch large
volume, uncontrolled release events such as ruptures. Consistent with
the study findings, PHMSA has established regulations requiring RMVs
and alternative equivalent technologies to be outfitted with equipment
or other means to monitor valve status, commodity pressures, and flow
rates.
The study also noted that operator procedures may have allowed
ignoring alarms, restarting pumps, or opening valves during large
releases. PHMSA addresses this concern in this rulemaking by requiring
operators to confirm that a rupture is occurring following any one of
the criteria specified in a new regulatory definition for the
``notification of [a] potential rupture.'' The final rule also provides
for post-incident reviews that can help operators determine how best to
implement lessons learned system-wide and assist PHMSA in providing
industry-wide guidance regarding overarching performance issues.

E. 2020 Valve Rule NPRM

On February 6, 2020, PHMSA published the NPRM seeking public
comments on the revision of the Federal Pipeline Safety Regulations
applicable to the safety of certain gas transmission, gas gathering,
and hazardous liquid pipelines. Specifically, the proposed language
created a RMV installation requirement for onshore, newly constructed
and entirely replaced gas and hazardous liquid pipelines, including
gathering pipelines, with diameters of 6 inches or greater.
Additionally, PHMSA proposed to shorten pipeline segment isolation
times in response to rupture events. PHMSA proposed a definition for
``rupture'' and outlined standards related to rupture identification
and pipeline segment isolation, including establishing a 40-minute
maximum RMV closure time and a 10-minute rupture identification
threshold.
In the NPRM, PHMSA also proposed requirements for RMV maintenance
and inspection, spacing, risk analysis, post-incident investigation and
review, and local 9-1-1 notification to help operators achieve better
rupture

[[Page 20946]]

response and mitigation. When developing the proposals in the NPRM,
PHMSA considered the relevant comments it received on the ANPRMs, as
well as the related NTSB recommendations, congressional mandates, and
related studies. A summary of the NPRM proposals and topics, the
comments received on those specific proposals, and PHMSA's response to
the comments received is set forth in Section III.

F. Subsequent Legislative Deadlines; Recent Executive Orders and
Actions

Congress has revisited the rulemaking mandate in the 2011 Pipeline
Safety Act in subsequent legislation. Specifically, Congress directed
PHMSA to issue a final rule no later than December 20, 2020 (see 49
U.S.C. 60102 note). In addition, in the joint explanatory statement
accompanying the Consolidated Appropriations Act for FY 2021 (Pub. L.
116-120; December 27, 2020), the conferees expressed ``disappointment''
that PHMSA had not met the December 20 deadline, and specified that
PHMSA should issue a final rule within 180 days of enactment (i.e., by
June 25, 2021).\25\
---------------------------------------------------------------------------

\25\ 166 Cong. Rec. H8823 (daily ed. Dec. 21, 2020) (joint
explanatory statement on Consolidated Appropriations Act of FY
2021).
---------------------------------------------------------------------------

The President has also issued a series of Executive Orders
emphasizing the importance of public safety, environmental protection,
and GHG reduction in Federal policymaking. Executive Order 13990
(``Protecting Public Health and the Environment and Restoring Science
To Tackle the Climate Crisis'') \26\ announced the Administration's
policy to, among other things, improve public health and protect the
environment, reduce greenhouse gas emissions, and prioritize
environmental justice. Executive Order 14008 (``Tackling the Climate
Crisis at Home and Abroad'') \27\ stated the Administration's policy
that climate considerations will be an essential element of United
States foreign policy and national security. The order also stated the
Administration's policy to organize and deploy the full capacity of
Federal agencies to combat the climate crisis, using a Government-wide
approach. The President also announced a new target for reductions in
national GHG emissions (a 50-52 percent reduction from 2005 levels in
economy-wide net greenhouse gas pollution in 2030) to combat climate
change, highlighting the importance of reducing emissions of greenhouse
gases other than carbon dioxide, including methane, to deliver fast
climate benefits.\28\ Lastly, the Administration touted the GHG
emissions reduction benefits of this rulemaking within the U.S. Methane
Emissions Reduction Action Plan.\29\
---------------------------------------------------------------------------

\26\ 86 FR 7037 (Jan. 20, 2021).
\27\ 86 FR 7619 (Feb. 1, 2021).
\28\ See, e.g., White House, ``Fact Sheet: President Biden Sets
2030 Greenhouse Gas Pollution Reduction Target Aimed at Creating
Good-Paying Union Jobs and Securing U.S. Leadership on Clean Energy
Technologies'' (Apr. 21, 2021), <a href="https://www.whitehouse.gov/briefing-room/statements-releases/2021/04/22/fact-sheet-president-biden-sets-2030-greenhouse-gas-pollution-reduction-target-aimed-at-creating-good-paying-union-jobs-and-securing-u-s-leadership-on-clean-energy-technologies/">https://www.whitehouse.gov/briefing-room/statements-releases/2021/04/22/fact-sheet-president-biden-sets-2030-greenhouse-gas-pollution-reduction-target-aimed-at-creating-good-paying-union-jobs-and-securing-u-s-leadership-on-clean-energy-technologies/</a>.
\29\ White House, ``U.S. Methane Emissions Reduction Action
Plan'' at 7 (Nov. 2021), <a href="https://www.whitehouse.gov/wp-content/uploads/2021/11/US-Methane-Emissions-Reduction-Action-Plan-1.pdf">https://www.whitehouse.gov/wp-content/uploads/2021/11/US-Methane-Emissions-Reduction-Action-Plan-1.pdf</a>.
---------------------------------------------------------------------------

III. NPRM Comments, Pipeline Advisory Committee Recommendations, and
PHMSA Responses

The comment period for the NPRM ended on April 6, 2020. PHMSA
received approximately 30 submissions to the docket commenting on the
NPRM, including comments from major industry trade associations and
others following advisory committee meetings as discussed below. PHMSA
also accepted stakeholders' requests to discuss this rulemaking in
meetings memorialized in the rulemaking docket. Consistent with Sec.
190.323, PHMSA considered all of these comments given their relevance
to the rulemaking and the absence of additional expense or delay
resulting from considering any late-filed comments.
Some of the comments PHMSA received in response to the NPRM were
beyond the scope of the proposed regulations. In this final rule, PHMSA
does not address the comments on pipeline safety issues that were
beyond the scope of the NPRM; 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 Technical Pipeline Safety Standards Committee (commonly known
as the Gas Pipeline Advisory Committee, or the GPAC) and the Liquid
Pipeline Advisory Committee (LPAC) are statutorily mandated (5 U.S.C.
App. 1-16; 49 U.S.C. 60115) advisory committees tasked with advising
and commenting on PHMSA's proposed safety standards, risk assessments,
and safety policies for natural gas and hazardous liquid pipelines,
respectively, prior to their final adoption. Each Committee consists of
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.
On July 22 and 23, 2020, the GPAC and the LPAC (collectively, the
``Committees'') met virtually to discuss this rulemaking. During the
meetings, the Committees considered the specific regulatory proposals
in the NPRM and discussed various comments submitted in the rulemaking
docket on those proposals, including alternative regulatory language,
from the pipeline industry, public interest groups, and government
entities. Interested members of the public and other stakeholders were
permitted to comment on the NPRM's proposals during the open portion of
each meeting prior to the closed Committee discussions and voting. At
the end of their closed discussions of each of the principal elements
of the rulemaking, the Committees voted on whether to recommend PHMSA's
adoption of the language proposed in the NPRM, or a variation thereon,
as technically feasible, reasonable, cost-effective, and practicable.
This section discusses the substantive comments on the NPRM that
were submitted to the docket, the GPAC and LPAC recommendations, as
well as any comments received from stakeholders in writing or during
meetings with PHMSA personnel before issuance of this final rule.\30\
They are organized by topic and include PHMSA's response to, and
resolution of, those comments.
---------------------------------------------------------------------------

\30\ Those written comments, and summaries for the meetings, may
be found in the rulemaking docket. PHMSA notes those comments and
meeting summaries largely recapitulate positions submitted in
written comments on the NPRM or during the GPAC/LPAC meetings.
---------------------------------------------------------------------------

A. General Comments, Scope, Applicability, and Cost-Benefit Issues

1. Summary of Proposal
In the NPRM, PHMSA proposed to make changes to parts 192 and 195
that applied to many regulated gas transmission, gas gathering, and
hazardous liquid pipelines (including regulated rural hazardous liquid
gathering pipelines).

[[Page 20947]]

2. Comments Received
(i) General Support and Criticism
Commenters largely supported the content and intent of the NPRM
while also submitting more specific comments on individual topics and
specific requests for revision, which are summarized in subsequent
sections. Industry organizations were supportive of PHMSA's intent to
enhance pipeline safety by improving rupture mitigation and shorten
rupture isolation times for certain natural gas and hazardous liquid
pipelines. The American Fuel and Petrochemical Manufacturers (AFPM)
indicated that their members rely on an uninterrupted, affordable
supply of crude oil and natural gas as feedstocks to maintain their
competitiveness and economic activity, and that therefore, it is
important to prevent pipeline safety incidents that can disrupt supply.
The Kentucky Oil and Gas Association (KOGA) supported, in
particular, the regulatory certainty provided by the rule, citing the
importance of a clear framework to inform future business decisions.
Additionally, the Clean Air Council and the National Association of
Pipeline Safety Representatives (NAPSR) indicated support for the NPRM,
the clarity it provides, and PHMSA's attention to human health and
safety as well as the environment in regulating the transportation of
gas and hazardous materials via pipeline across the United States.
A broad, general criticism was that the same language, criteria,
and requirements are unnecessarily restated in numerous sections of the
NPRM, and that the NPRM could be improved by consolidating or removing
duplicative language. Other criticisms included the scope of the rule
and its applicability to gathering lines, as discussed in more detail
in this section.
(ii) Scope: General
The NTSB stated that, although Safety Recommendation P-11-10
specifically called for PHMSA to require leak detection equipment on
gas transmission and gas distribution pipelines, that recommendation is
not included in the proposed rule. The NTSB noted that the criteria
proposed for ruptures in the proposed rule do not specifically provide
for leak detection, and the proposed requirements for installing RMVs
exclude gas distribution systems, which are a particular concern of
Safety Recommendation P-11-10.
Other commenters echoed these concerns and stated that the rule
should include leak- and rupture-detection requirements. The Clean Air
Council stated that, because significant time is often lost during a
pipeline incident in determining whether a rupture has occurred, the
final rule should require operators install devices to detect ruptures.
The Clean Air Council also noted that installing extra RMVs might be
fruitless if an operator cannot detect the initial rupture, and went on
to say that, in many rupture events, residents in the vicinity of the
incident are those who discover a pipeline has ruptured, not the
pipeline operators. Additionally, they noted that, in remote locations,
the time between the rupture event occurring and when it is discovered
is often so long that large amounts of product are lost, and the damage
to the surrounding area is extreme.
The Pipeline Safety Trust (PST) stated that it has been nearly 10
years since the NTSB recommended leak detection systems, via
recommendation P-11-10, that meet regulatory performance standards on
all transmission and distribution pipelines, and that PHMSA must do
more to further the development and use of leak detection systems
beyond participating in industry standards development. The PST and the
Clean Air Council also asked that PHMSA consider extending the NPRM's
proposed RMV requirements to existing pipelines consistent with the
NTSB's recommendations.
(iii) Scope: Distribution and Gathering Pipelines
Regarding the scope related to gas distribution pipelines, INGAA et
al.\31\ recommended that PHMSA limit any new gas distribution system
requirements, if they were intended in the proposal, to the 9-1-1
notification requirements and the incorporation of post-incident
lessons learned.
---------------------------------------------------------------------------

\31\ The American Gas Association, American Petroleum Institute,
American Public Gas Association, and Interstate Natural Gas
Association of America (INGAA) jointly submitted comments to this
rulemaking. Throughout this final rule, their joint comment is
referred to as ``INGAA et al.''
---------------------------------------------------------------------------

Several commenters requested clarification regarding the provisions
and their applicability to gathering pipelines, with the American
Petroleum Institute and Association of Oil Pipe Lines (API/AOPL) and
GPA Midstream Association (GPA Midstream), for example, recommending
that PHMSA provide an exception for gathering pipelines from the RMV
installation requirements. These entities stated that section 4 of the
2011 Pipeline Safety Act is limited to transmission pipelines, and also
that requiring gathering pipeline operators to install RMVs is not
economically, technically, or operationally feasible.
KOGA and NAPSR noted that PHMSA initially stated that the NPRM
would be applicable to transmission pipelines, however, both commenters
noted that many of the provisions appeared to apply to gathering
pipelines. NAPSR stated that, per Sec. 192.9, Type A and B gathering
pipelines must follow transmission regulations, and they requested that
PHMSA clarify whether operators of gathering pipelines would have to
install new valves as required by the NPRM for class location changes.
Sander Resources stated that it was unclear whether PHMSA wanted to
make the proposed regulations applicable to gathering pipelines or
whether gathering pipelines were inadvertently included. Therefore,
they noted that PHMSA must consider whether it would be appropriate to
include provisions applicable to gathering pipelines in the final rule.
Similarly, the Texas Pipeline Association (TPA) stated that the
regulations should not be expanded beyond the scope of the
congressional mandate, which applied to transmission pipeline
facilities.
(iv) Cost-Benefit
Industry organizations stated that the NPRM dramatically
understated the potential costs of the proposed valve installation and
rupture detection standards, noting that PHMSA's Preliminary Regulatory
Impact Assessment (PRIA) estimated the annual cost of implementing the
proposed rule would be approximately $3.1 million. These organizations,
however, said that an estimate prepared several decades ago showed that
the cost of complying with similar valve installation standards would
exceed $600 million. They stated the PRIA offered no explanation for
the significant discrepancy between these two cost estimates and failed
to account for the true costs for the changes required, noting that
PHMSA may not propose a standard for adoption without making a
``reasoned determination that the benefits of the intended standard
justify its costs.''
These commenters further stated that the alleged underreporting of
incremental annual regulatory burdens in the PRIA is particularly
impactful given the extraordinary economic conditions currently
confronting the oil and gas industry due to the Covid-19 global
pandemic. Furthermore, GPA Midstream and Sander Resources stated that
the industry expects to add more than 35,000 miles of pipeline during
2020; therefore, they suggested that it may be unrealistic for PHMSA to

[[Page 20948]]

estimate the total annualized cost amounts at $3.1 million. This would
amount to just $88 per mile on an annualized basis. Further, these
commenters noted that PHMSA's estimate did not cover repair or
replacement projects that are ongoing.
TC Energy Corporation commented that the cost estimates for adding
actuators, controls, and telemetry to gas transmission pipelines would
have added $250,000 to $375,000 per valve for a total of $4 to 6
million in additional annual costs. Based on their review of their
class location projects completed in previous years, TC Energy
estimated that the proposed language regarding class location
replacements would add another $5 million in costs annually.
An individual suggested that the cost-benefit analysis should
consider the loss of power when gas transmission or gas distribution
service is interrupted. They stated reductions in serious injuries and
loss of life are the most significant economic consideration, but there
are additional economic factors that PHMSA should consider. Among those
economic costs mentioned were cost to end users associated with
interruption of natural gas supply, as well as the additional delay and
costs associated with recovery efforts (e.g., re-lighting pilot lights)
following a service interruption.
The Clean Air Council commented that the economic feasibility of
the proposed rule should not be a factor in implementing the
regulations. They stated that the installation of the proposed rupture-
detection and automatic-valve technology should be included in pipeline
construction and repair costs and should not be considered ``extra''
infrastructure that would carry an incremental cost. They stated that,
while in some cases, the necessary electricity and connectivity
requirements may make RCVs and ASVs infeasible in very remote
locations, in all other cases, this equipment should be considered
mandatory as part of the cost of constructing or repairing a pipeline.
They argued that the potential loss of life and economic costs from
ruptures is enough to justify this change, and that the implementation
cost is not even 1 percent of the amount of the damages the public and
industry pays annually for pipeline incidents.
3. PHMSA Response
PHMSA considered all the comments regarding the NPRM's readability
and redundant language while drafting this final rule and believes that
this final rule more clearly states the regulations and their intended
effect.
(i) Scope
General. In response to the comments from the PST and the Clean Air
Council that suggested PHMSA consider extending the NPRM's proposed RMV
requirements to existing pipelines consistent with the NTSB's
recommendations, PHMSA first notes that such a change is beyond the
scope of the NPRM. As a result, such an expansion may merit additional
process (e.g., a supplemental notice and solicitation of additional
comments), imposing a substantial delay to a rule that is already ten
years in the making. Further, application of the rule's RMV and
alternative equivalent technology installation requirements to existing
pipeline infrastructure would entail installation activity (e.g.,
blowdowns of existing pipelines prior to replacement, and work in
pipeline rights-of-way) that could involve significant GHG emissions
and other potential environmental harms.\32\
---------------------------------------------------------------------------

\32\ PHMSA notes that the concerns discussed in this paragraph
militate against, at the final rule stage, extending the
rulemaking's scope to offshore gas and hazardous liquid pipelines.
PHMSA is, however, evaluating extension in the future of the
regulatory amendments in this final rule to pipeline facilities
(e.g., offshore pipelines, existing pipelines, additional gathering
lines, and smaller-diameter pipelines) that were not within the
scope of this rulemaking described in the NPRM.
---------------------------------------------------------------------------

PHMSA notes that this does not mean that operators of existing
pipelines do not have to address the risks of leaks or rupture events.
All operators are required under the integrity management (IM)
regulations at Sec. Sec. 192.935 and 195.452 to conduct risk analyses
to identify measures (including installing ASVs, RCVs, or EFRDs) as
appropriate to enhance safety on pipeline segments that are in or which
could affect HCAs. Further, this final rule requires operators of all
gas and hazardous liquid pipelines subject to the emergency planning
requirements at Sec. Sec. 192.615 and 195.402, respectively, to update
their emergency response plans to provide for immediate and direct
notification of appropriate public safety answering points (9-1-1
emergency call centers) following the notification of a potential
rupture. Similarly, the final rule requires all gas and hazardous
liquid pipelines subject to failure investigation requirements at
Sec. Sec. 192.617 and 195.402, respectively, to conduct post-rupture
investigations and reviews, and to incorporate lessons learned from
such investigations and reviews into their training regimes and
procedures.
Regarding the provisions in this rulemaking related to leak
detection, PHMSA is requiring pressure monitoring upstream and
downstream of RMVs and alternative equivalent technology installed
pursuant to this final rule. In doing so, PHMSA believes operators will
be able to better detect and isolate ruptures, and operators can
integrate the pressure monitoring equipment required by this rule into
future, or current, leak detection systems and analyses.
PHMSA also notes that the Federal Pipeline Safety Regulations
reflect PHMSA's commitment to ensuring robust leak detection on PHMSA-
jurisdictional pipelines. Since 2002, operators of hazardous liquid
pipelines have been required to evaluate and install leak detection
systems in HCAs, including on pipeline segments that could affect an
HCA.\33\ PHMSA also issued new regulations in October 2019 \34\
requiring that all hazardous liquid pipelines, even those outside of
HCAs, have an effective system for detecting leaks. Further, hazardous
liquid pipeline operators are required to inspect the surface
conditions of their rights-of-way every 3 weeks.\35\ Similarly, gas
distribution pipeline operators are required by Sec. Sec. 192.722 and
192.723 to conduct periodic patrols and leak surveys of their
distribution systems at intervals. Gas transmission pipeline operators
are obliged by Sec. 192.705 to conduct periodic patrols of their
pipelines, and by Sec. 192.706 to conduct leak surveys twice per year
in Class 3 locations and quarterly for Class 4 locations.
---------------------------------------------------------------------------

\33\ Design regulations for computational pipeline monitoring
(CPM) leak detection systems are at Sec. 195.134, and the
operational requirements for CPM leak detection are at Sec.
195.444. The requirement for operators of pipelines in HCAs and
those that could affect HCAs to have an LDS are at Sec.
195.452(i)(3).
\34\ 84 FR 52260 (Oct. 1, 2019).
\35\ See Sec. 195.412.
---------------------------------------------------------------------------

PHMSA has also, in response to a mandate in section 120 of the
Protecting our Infrastructure of Pipelines and Enhancing Safety Act of
2020 (Pub. L. 116-260; 2020 PIPES Act), initiated a rulemaking (under
RIN 2137-AF51) to require operators of new and existing gas
transmission, gas distribution, and (certain) regulated gas gathering
lines implement leak detection and repair programs to achieve minimum
performance standards reflecting the capabilities of commercially
available advanced technologies. PHMSA will also continue to promote
leak detection technology for pipelines through its research and
development programs.
Application to distribution and gas gathering lines. In the NPRM,
PHMSA intended for the RMV and alternative equivalent technology
installation requirements to apply to new and

[[Page 20949]]

entirely replaced regulated gathering pipelines, both for gas and
hazardous liquid operators. Section 192.9 states that operators of Type
A gas gathering pipelines must comply with the requirements of part 192
applicable to gas transmission pipelines, and new and replaced Type B
gas gathering pipelines must follow part 192 design, construction,
installation, initial inspection, and initial testing requirements
applicable to gas transmission pipelines. Nothing in the NPRM stated or
suggested that the regulatory amendments proposed therein would not
apply to new and entirely replaced gas gathering lines as provided by
the plain meaning of Sec. 192.9. However, in this final rule, PHMSA
has decided to narrow the application of the valve installation
requirements proposed in the NPRM to Type A gas gathering pipelines
only; Type B gas gathering pipelines are explicitly exempted from those
requirements.
PHMSA adopts this limitation on the scope of the RMV and
alternative equivalent technology installation requirements because of
the distinguishable risk profiles associated with ruptures on Type A
and Type B gas gathering pipelines. Type A gas gathering pipelines, per
Sec. 192.8, operate at higher pressures (correlating to hoop stress of
20 percent or more of specified minimum yield strength (SMYS), or
pressures greater than 125 psig) and in areas of higher population
density (specifically Class 2, Class 3, or Class 4 locations). As a
result, ruptures on these pipelines will generally present a higher
risk of public safety consequences, similar to gas transmission
pipelines, warranting the additional protection that RMVs or
alternative equivalent technology would provide. However, as explained
in Section II. E of this final rule, PHMSA provides an exception from
the valve installation requirements if an operator can demonstrate that
a rupture on a new or entirely replaced Type A gas gathering pipelines
in Class 2 locations would yield a PIR of 150 feet or less.
Type B gas gathering pipelines, on the other hand, as defined at
Sec. 192.8, operate at lower pressures (involving hoop stress of less
than 20 percent of SMYS). Ruptures on gas gathering pipelines operating
within that same pressure range are likely to have a PIR comparable to
the Type A gas gathering pipelines that PHMSA exempts from its RMV and
alternative equivalent technology installation requirements. The final
rule therefore exempts Type B gas gathering pipelines from those same
requirements. Going forward, however, PHMSA will gather and consider
additional data to inform application of these requirements to
additional types of gas gathering pipelines.
PHMSA has, in this final rule, further clarified that the Type C
gas gathering lines established in the Gas Gathering final rule are,
like Type B gas gathering lines, not subject to the RMV and alternative
equivalent technology installation requirements. As explained above,
the Type C gas gathering designation is new, created after publication
of the NPRM and the LPAC and GPAC meetings on this rulemaking. PHMSA,
therefore, declines to extend the valve installation requirements to
that newly defined type of gas gathering lines in this final rule;
PHMSA may, however, consider doing so in a subsequent rulemaking.
Section Sec. 195.1 similarly provides that part 195 applies to
onshore hazardous liquid gathering pipelines that are: (1) Located in a
non-rural area, (2) a regulated rural gathering line as that term is
defined in Sec. 195.11, or (3) located within an inlet of the Gulf of
Mexico as provided in Sec. 195.413. Further, operators of regulated
rural gathering lines have to follow specific safety provisions set out
in Sec. 195.11, one of which is that steel regulated rural gathering
lines must be designed, installed, constructed, initially inspected,
and initially tested in compliance with part 195. Therefore, and
similarly to Type A gas gathering pipelines, regulations proposed for
design and construction standards for hazardous liquid pipelines will
apply to regulated rural hazardous liquid gathering pipelines absent a
specific statement that the regulations do not apply to regulated rural
hazardous liquid gathering pipelines.
Accordingly, in this final rule, operators of regulated hazardous
liquid gathering lines must comply with the provisions of this
rulemaking pertaining to hazardous liquid pipelines. Based on comments
received on the NPRM and discussions at the LPAC meeting, however,
PHMSA is requiring that operators of only certain regulated rural
gathering lines--namely, lines that cross bodies of water greater than
100 feet wide, from high water mark to high water mark--install RMVs or
alternative equivalent technologies in accordance with Sec.
195.260(e). PHMSA has required extra valves near such water crossings
for several decades under Sec. 195.260, and similarly applies the
requirements of this final rule to those lines.
As for low-stress, rural hazardous liquid pipelines, as those are
defined at Sec. 195.12, PHMSA acknowledges that a hazardous liquid
pipeline operating below 20 percent of SMYS is less likely to rupture
than the same pipeline operating at higher pressures. However, a
hazardous liquid pipeline can leak, without rupturing, and cause
significant environmental damage; further, PHMSA accident report data
yields that even low-stress hazardous liquid pipelines have failed.
Accordingly, although the LPAC recommended that PHMSA consider an
exception for low-stress, rural hazardous liquid pipelines in the final
rule, PHMSA is instead requiring that all newly constructed and
entirely replaced low-stress, rural hazardous liquid pipelines with
diameter of six inches or greater, including low-stress hazardous
liquid pipelines in rural areas, install RMVs pursuant to this
rulemaking.
PHMSA is also clarifying in this final rule that the requirements
pertaining to RMVs or alternative equivalent technologies as outlined
in the NPRM do not apply to gas distribution pipelines. The only
requirements in this rule intended to apply to gas distribution
pipelines are the requirements at Sec. 192.615 for contacting 9-1-1
call centers and at Sec. 192.617 pertaining to post-incident analysis
and implementation of lessons learned. Although PHMSA acknowledges that
there could be safety and environmental benefits from extending
elements of this final rule to gas distribution pipelines, PHMSA
declines to do so in this final rule as such an extension is beyond the
scope of the NPRM and would require additional notice and public
comment, and thus further delay issuance of this final rule. PHMSA will
conduct further study and analysis evaluating which rupture response
and mitigation measures (including, but not limited, those adopted in
this final rule) are most appropriate for gas distribution pipelines.
(iii) Cost-Benefit
PHMSA analyzed the comments it received on the PRIA and cost-
benefit issues and took them into account when drafting this final
rule. PHMSA addresses those comments within the RIA in the rulemaking
docket.

B. Rupture Definition

1. Summary of Proposal
In the NPRM, PHMSA proposed to introduce a new definition of
``rupture'' for gas pipelines at Sec. 192.3 meaning any of the
following events that involve an uncontrolled release of a large volume
of gas: (1) A release of gas observed or reported to the operator by
its field personnel, nearby pipeline or utility personnel, the public,
local responders,

[[Page 20950]]

or public authorities, and that may be representative of an
unintentional and uncontrolled release event defined in paragraphs (2)
or (3) of this definition; (2) An unanticipated or unplanned pressure
loss of 10 percent or greater, occurring within a time interval of 15
minutes or less, unless the operator has documented in advance of the
pressure loss the need for a higher pressure-change threshold due to
pipeline flow dynamics that cause fluctuations in gas demand that are
typically higher than a pressure loss of 10 percent in a time interval
of 15 minutes or less; or (3) An unexplained flow rate change, pressure
change, instrumentation indication, or equipment function that may be
representative of an event defined in paragraph (2) of this definition.
Similarly, for hazardous liquid pipelines, PHMSA proposed to
introduce at Sec. 195.2 a definition of ``rupture'' for hazardous
liquid pipelines as any of the following events that involve an
uncontrolled release of a large volume of hazardous liquid or carbon
dioxide: (1) A release of hazardous liquid or carbon dioxide observed
and reported to the operator by its field personnel, nearby pipeline or
utility personnel, the public, local responders, or public authorities,
and that may be representative of an unintentional and uncontrolled
release event defined in paragraphs (2) or (3) of this definition; (2)
An unanticipated or unplanned flow rate change of 10 percent or greater
or a pressure loss of 10 percent or greater, occurring within a time
interval of 15 minutes or less, unless the operator has documented in
advance of the flow rate change or pressure loss the need for a higher
flow rate change or higher pressure-change threshold due to pipeline
flow dynamics and terrain elevation changes that cause fluctuations in
hazardous liquid or carbon dioxide flow that are typically higher than
a flow rate change or pressure loss of 10 percent in a time interval of
15 minutes or less; or (3) An unexplained flow rate change, pressure
change, instrumentation indication or equipment function that may be
representative of an event defined in paragraph (2) of this definition.
For both definitions, PHMSA added a note stating that ``rupture
identification'' was to occur when a rupture, as defined above, was
first observed by, or reported to, pipeline operating personnel or a
controller.
2. Comments Received
For both gas and hazardous liquid pipelines, commenters stated that
the proposed definitions are unclear in many respects and that the
proposed definition of rupture emphasized the sources of information an
operator might use to identify a rupture, like notifications to an
operator, as opposed to establishing workable criteria for determining
what qualifies as a rupture.
Some commenters suggested that the release criteria PHMSA used to
define a rupture were impractical and do not account for differences in
pipeline system operation and monitoring capabilities. Some commenters
further suggested that PHMSA proposed technically infeasible detection
sensitivities.
Individual operators and trade associations provided alternative
definitions for ``rupture'' and ``rupture identification'' or provided
editorial changes to the definitions. Other commenters, such as the
NTSB, noted that elements of the definition, including the terms
``large-volume'' and ``uncontrolled release,'' could be interpreted in
several ways and could benefit from clarification.
Northern Natural Gas Company stated that the proposed definition of
a rupture is too restrictive, noting that their pipeline system
consists of pipelines with a series of branch or lateral lines which
serve power plant or industrial customers that may change operating
status several times per day with subsequent start-ups and shutdowns.
They added that many of these start-ups and shutdowns would meet the
proposed threshold defining a rupture, and for them to develop and
maintain documentation in advance for all of these scenarios would be
burdensome, extensive, time consuming, expensive, and would not result
in improved pipeline safety. Therefore, they recommended that the
language defining a rupture be changed to an unanticipated or unplanned
flow rate change or pressure loss of 25 percent occurring within 30
minutes, or that the operator should be allowed to establish specific
rupture criteria for each pipeline and maintain technical
justification.
TPA stated that there should be some recognition of the difficulty
of determining a 30 percent pressure drop on certain transmission
pipelines, such as where a natural gas-fueled electric generation plant
is located on a segment. On pipeline segments such as these, they
stated, significant swings in pressure are not uncommon as the
generation plant starts up, and these swings in pressure can occur with
little notice.
Emerson Process Management Actuation Technologies, a manufacturer
of pipeline valve operating systems and controls (including ASVs),
noted that their clients typically use an actuation set point of a 20
to 30 psi pressure drop per minute with the goal of sensing a rupture
but not being too sensitive to ``risk a false valve closure.'' This
commenter proceeded to assert that the proposed definition could
require ASV set points that are more sensitive to pressure changes than
currently used within industry.
Pertaining to hazardous liquid pipelines, AFPM stated that defining
a rupture as a 10 percent pressure loss is not feasible for all
locations, stating that the proposed language would force operators to
consider pressure drops as ruptures when such pressure drops would
likely not constitute an actual rupture event. They stated further that
such a measure could lead to unnecessary incident reports, even in
instances when no product is released, and suggested that a rupture is
better defined as a percentage of flow leaving the pipeline, typically
defined as 50 percent of receipt flows or higher.
Magellan Midstream Partner, L.P. stated that the proposed rule is
not clear regarding the impact of alarm persistence on determining
whether a rupture is occurring and whether any momentary pressure
change of 10 percent constitutes a rupture, or if the 10 percent drop
would be sustained continuously over 15 minutes. Magellan also
suggested that, since there are several scenarios in any given pipeline
operation that could contribute to pressure drops and flow rates, a
rupture should not be defined by a single variable, such as pressure or
flow, but be inclusive of multiple indications that, evaluated
collectively, would provide for a rupture signature.\36\
---------------------------------------------------------------------------

\36\ Including pressure, temperature, meter flow, product
characteristics, and geometry of the pipeline.
---------------------------------------------------------------------------

OptaSense stated that operators should rely on monitoring systems
that alert them of significant events with immediacy and actionable
detail to mitigate the harmful consequences of a rupture rather than
relying on third-party notification. On the other hand, TPA stated that
the differences in the sophistication of various operators' pressure
monitoring capabilities and differing granularity of monitored pressure
points, combined with the short response times in the proposed rule,
support some broadening of the definition of rupture to include
notifications from first responders and the public. TPA added that
these notifications would need some provision for operator
confirmation. Magellan Midstream Partner, L.P. suggested that the
proposed rule, as

[[Page 20951]]

written, creates the potential for numerous false rupture alarms that
could impact an operator's safety culture and desensitize an
organization to the heightened awareness and urgent response that a
rupture alarm should create.
Commenters also suggested PHMSA consider allowing operators to
establish specific rupture notification criteria for individual
pipelines based on a pipeline's unique operating environment and
parameters rather than establishing one-size-fits-all criteria.
INGAA et al. stated that the proposed definition of rupture does
not take into account that operators' natural gas systems and their
customers' needs are unique and dynamic. INGAA et al. stated that the
proposed definition arbitrarily establishes set points which require
response and that PHMSA did not provide a technical basis for the 10-
percent-over-15-minutes threshold in the proposed rule. INGAA et al.
added that by unnecessarily triggering rupture response, PHMSA's
proposed 10 percent over 15 minutes criteria may potentially compromise
the reliability of service to customers. INGAA et al. stated that
rather than prescribe a one-size-fits-all rupture criteria, they
recommended that PHMSA direct operators to establish rupture-
notification criteria for individual operating systems and to outline
these criteria clearly within each operator's procedures.
TC Energy recommended that if PHMSA includes a rate of pressure
drop (ROPD) in the definition of a rupture, that operators should be
allowed to establish their own ROPD that would indicate a rupture. They
stated that the proposed definition of a rupture does not consider that
operators' natural gas systems are unique and dynamic.
Similarly, API/AOPL and GPA Midstream stated that the proposed
definition of rupture relies on one-size-fits-all numerical thresholds
for pressure loss and flow rates that would encompass many scenarios
that are not in fact ruptures (e.g., a power loss at a pump station).
These entities added that PHMSA does not provide any technical
justification for the proposed numeric thresholds and rigid application
of the criteria that could lead to numerous false alarms and
unnecessary valve closures.
Commenters requested PHMSA clarify and distinguish between the
meanings of the terms ``rupture identification'' and ``notification of
potential rupture'' for both gas and hazardous liquid pipelines. INGAA
et al. stated that the proposed definition of rupture does not address
actual ruptures but rather the notification of potential ruptures, and
PHMSA should therefore re-label this definition as the ``notification
of potential rupture,'' which will also provide clarity in other
sections of the rule. INGAA et al. and NAPSR also stated that PHMSA
should limit the definition of ``rupture'' or ``notification of
potential rupture'' to gas transmission pipelines, enabling PHMSA to
use the terms ``rupture'' and ``notification'' as intended throughout
the rulemaking without continuously qualifying whether the requirements
are applicable to only potential ruptures on gas transmission lines or
to both transmission line ruptures and rupture-like events on gas
distribution lines, such as excavation damages.
As noted previously, commenters, including API/AOPL and GPA
Midstream, also suggested that PHMSA align the definition of rupture in
this rulemaking with the definition of rupture used in PHMSA's incident
report, noting the existing guidance currently used in the instructions
for the part 195 accident reports state that a rupture occurs when a
pipeline has ``burst, split, or broken and the operation of the
pipeline facility is immediately impaired,'' resulting in an
uncontrolled, large volume release of hazardous liquid or carbon
dioxide. These industry commenters suggested that matching the
definition in the reporting instructions would promote consistency,
make the regulations easier to understand, and avoid unnecessary
compliance burdens. The PST added that if the definition of rupture in
the proposed rule is not the same as the definition of a rupture for
incident and accident reporting purposes, it will make it impossible to
track the effectiveness of this rule over time and to know whether this
rule is driving safety.
In response to these comments, PHMSA provided the Committees in
advance of their July 22-23, 2020 meetings alternative language for
consideration that would substitute the term ``notification of
potential rupture'' for the definition of ``rupture'' proposed in the
NPRM.
The Committees unanimously recommended that PHMSA adopt this
substitute language as presented and recommended by PHMSA staff at the
meeting. However, the LPAC also recommended PHMSA remove from the
second criterion under the part 195 definition of ``notification of
potential rupture'' any reference to a specific pressure loss-rate
threshold, instead recommending that this criterion refer only to
operator observation of an unanticipated or unplanned pressure loss
outside of a pipeline's normal operating parameters as defined in the
operator's procedures.
3. PHMSA Response
PHMSA acknowledges that having a clear definition is essential for
successful implementation of the rule and considered the varying
suggestions provided by commenters to clarify terms and improve
understanding of, and compliance with, the final rule. Therefore, PHMSA
has changed the proposed definition of ``rupture'' to a definition of
``notification of potential rupture'' as proposed to and recommended by
the Committees. PHMSA intended for the definition of a ``rupture'' to
provide operators with a standard to initiate rupture-mitigation
measures consistently and promptly and notify emergency responders of a
rupture event. PHMSA acknowledges, however, that operator response
actions are more appropriately initiated on ``notification of potential
rupture'' than on ``rupture'' as suggested by the NPRM. Indeed, the
experience of the rupture events in San Bruno, CA, and Marshall, MI,
underscore there can be a significant time lag between notification of
indicia of a potential rupture and verification of a rupture. PHMSA has
consequently, in this final rule, recharacterized the NPRM definition
of ``rupture'' as a ``notification of potential rupture.''
PHMSA declines, however, to further modify the second criterion of
the definition of ``notification of potential rupture'' to remove the
NPRM's reference to a 10-percent-pressure-loss-within-15-minutes
threshold as recommended by the LPAC. PHMSA's Accident Investigation
Division has reviewed ruptures that have occurred the past several
years that PHMSA has investigated and finds this to be an appropriate
requirement. In certain cases, for example, operator pressure charts
provided to PHMSA following pipeline ruptures showed pipelines
operating at approximately 850 psig rapidly fall to approximately 100
psig. Another pipeline went from operating at 1,160 psig to 0 psig. In
PHMSA's experience, unexpected pressure-loss events that are greater
than 10 percent within 15 minutes are not routine events and are often
indications a rupture has occurred. However, because PHMSA acknowledges
that operators may have conditions or considerations that would cause
pressure swings in excess of 10 percent within 15 minutes, PHMSA has
introduced language permitting operators to document in their written
procedures the need for alternative pressure-loss-rate thresholds due
to the unique pipeline flow

[[Page 20952]]

dynamics resulting from changes in demand. This final rule does not
contemplate that operators must submit those written operating
procedures to PHMSA in advance for notification or approval. PHMSA
furthermore submits that operator concerns regarding the ``one-size-
fits-all'' approach of this numerical threshold or the difficulty in
predicting pressure drops given the diverse and variable demands on
their systems may also be addressed by the qualifying language that any
such pressure loss must be ``unanticipated or unexplained.''
PHMSA initially considered including the criteria for a
``notification of potential rupture'' within the definition sections of
parts 192 and 195 (Sec. Sec. 192.3 and 195.2, respectively) but found
such an approach challenging. First, PHMSA found it unwieldy to include
such detailed criteria in a definition section that has no enumerated
paragraphs. Second, because the criteria also include requirements,
PHMSA determined that the definition, including the criteria, would be
more appropriately located in an operative section of the regulations.
PHMSA understands the approach taken in this final rule provides
improved clarity and enforceability. PHMSA used a similar approach when
developing the definition of an ``unusually sensitive area'' in part
195. Therefore, in this final rule, PHMSA has established a definition
for the term ``notification of potential rupture'' and has promulgated
the criteria for that definition in Sec. Sec. 192.635 and 195.417 for
gas pipelines and hazardous liquid pipelines, respectively. PHMSA has
also made editorial corrections clarifying the definitional criteria
and identifying indicia--including explosions and fires in the
immediate vicinity of a pipeline--discussed in the NPRM and during the
Committee meetings as potential consequences (and therefore indicia) of
a rupture.
PHMSA acknowledges the value in aligning any regulatory definition
of the term ``rupture'' with the definitions in its parts 192 and 195
incident/accident reporting forms. However, PHMSA has decided against
codifying any regulatory definition of ``rupture'' in this final rule.
Should PHMSA consider introducing a regulatory definition of
``rupture'' in a future rulemaking, it will endeavor to ensure
consistency between any definition in the Federal Pipeline Safety
Regulations and the incident and accident reporting forms.

C. Rupture Identification Definition and Timeframe

1. Summary of Proposal
In the NPRM, PHMSA proposed new provisions (Sec. Sec.
192.634(c)(1) and 195.418(c)(1)) requiring operators installing RMVs or
alternative equivalent technology to isolate a ruptured pipeline
segment as soon as practicable, but within 40 minutes of rupture
identification--defined in the NPRM (Sec. Sec. 192.3 and 195.2) as the
initial report to pipeline operators, or their initial observation, of
a rupture. PHMSA also solicited comments on whether to oblige operators
to have procedures to identify a rupture event within 10 minutes of the
initial notification to the operator. These requirements would apply to
both gas and hazardous liquid pipelines.
2. Summary of Comments Received
API/AOPL, GPA Midstream, KOGA, Magellan Midstream Partner, L.P.,
and TC Energy Corporation stated that PHMSA should add a separate
definition for the term ``rupture identification'' to specify that
rupture identification occurs when a pipeline operator has sufficient
information reasonably to determine that a rupture occurred. Some of
these industry commenters provided alternative definitions or editorial
suggestions to that end.
API/AOPL stated that the rupture identification concept is highly
important in establishing the extent of an operator's obligations under
the new regulations. They suggested, along with GPA Midstream, that
adding a separate definition for ``rupture identification'' that is
based on a reasonableness standard is preferable to the NPRM's approach
of defining a ``rupture'' by reference to a list of information that
may be indicative, but not conclusive, of whether there is indeed a
rupture.
Northern Natural Gas Company stated that a 10-minute time limit for
determining whether there is a rupture can create uncertainty in the
initial actions that must be undertaken by natural gas transmission
pipeline operators upon initial notification, and should be eliminated;
Northern Natural Gas Company suggested that the final rule would be
better focused on the time to commence shut-off of RMVs or alternative
equivalent technology. Similarly, TC Energy Corporation called on PHMSA
to remove the 10-minute rupture identification requirement entirely,
and instead revise the regulatory text to mirror language in the NPRM
preamble requiring operators to respond to a rupture as soon as
practicable by closing rupture-mitigation valves, with complete valve
shut-off and segment isolation within 40 minutes after rupture
identification.
INGAA et al. and TC Energy Corporation stated that PHMSA should
eliminate the 10-minute identification requirement because the 40-
minute response standard is sufficient to ensure safety in HCAs and
Class 3 and Class 4 locations. INGAA et al. further stated that the
decision to shut down a pipeline should not be rushed to meet an
arbitrary 10-minute threshold because it risks significant service
disruptions for natural gas customers. They added that operators should
be provided the necessary time to determine whether a pipeline needs to
be shut down.
For hazardous liquid pipelines, API/AOPL stated that the
feasibility of a 10-minute rupture identification requirement is highly
dependent on the location of the pipeline. They further stated that
imposing a 10-minute rupture identification requirement for pipelines
in remote or difficult-to-access areas will effectively force operators
of such pipelines to err on the side of being overly-conservative in
responding to events as ruptures. Both API/AOPL and GPA Midstream
stated that this requirement would disrupt operations, is too
restrictive, and could lead to adverse consequences. API/AOPL requested
that PHMSA eliminate the rupture identification timeframe or provide a
longer period for rupture identification. Similar to comments made for
gas transmission pipelines, GPA Midstream stated that, rather than
providing a 10-minute deadline for rupture identification, PHMSA should
provide operators with a 40-minute total response time for closing
RMVs, manual valves, or equivalent technology following a rupture.
TPA stated that the 10-minute requirement for identifying a rupture
and contacting first responders is not feasible because of the need to
determine the existence of a rupture as the trigger for the
determination of the start of the response time. TPA stated that
existing emergency procedures and damage prevention procedures at
Sec. Sec. 192.615 and 195.402 already contain requirements for the
timely contact of emergency responders and calls to 9-1-1 numbers, so
the 10-minute notification requirement in these provisions is
duplicative and unnecessary, and recommended that this requirement be
deleted from the proposed rule. An individual, on the other hand,
agreed that the time to identify a rupture should be no more

[[Page 20953]]

than 10 minutes, and that emergency services must be notified right
away.
At the Committee meetings on July 22 and 23, 2020, both the GPAC
and the LPAC unanimously recommended that PHMSA eliminate the 10-minute
rupture identification requirement because of the practical
difficulties of prescribing a universal 10-minute rupture
identification timeline notwithstanding the variety of pipeline
locations and operational environments. In conjunction with this
recommendation, the Committees also recommended that PHMSA require RMVs
to be closed ``as soon as practicable'' within 30 minutes of ``operator
identification of a rupture'' and that PHMSA require operators to
document a method for rupture identification in their written
procedures.
3. PHMSA Response
PHMSA is adopting in this final rule at Sec. Sec. 192.3 and 195.2
effectively identical regulatory definitions for ``notification of
potential rupture'' that reflect editorial revisions to the definitions
endorsed by the GPAC and LPAC. PHMSA notes that its decision to re-cast
the NPRM definition of ``rupture'' as the term ``notification of
potential rupture'' reflects that timely and effective rupture
mitigation demands operators undertake certain actions on notification
of common indicia of a rupture. Effective and timely rupture mitigation
also demands operators take action on confirming, or identifying, that
a rupture is in progress.
The definition for ``notification of potential rupture'' allows an
operator to consider the different pipeline operating characteristics,
diverse potential rupture mechanisms, and information of varying
quantity and quality in evaluating whether a rupture is, in fact, in
progress, and whether additional mitigation measures are necessary.
PHMSA believes this definition is flexible enough to help ensure
operators reach an informed determination on whether a rupture is in
progress. However, PHMSA has backstopped this flexibility by requiring
within revisions to each of Sec. Sec. 192.615 and 195.402 that each
operator have written procedures specifying its methodology for
identifying a rupture on receipt of a notification of a potential
rupture. The communication of ruptures to 9-1-1 or other public safety
officials was always meant to be broadly applicable to all pipeline
operators--the provisions were placed in the emergency response section
of the regulations applicable to all operators, and the GPAC and LPAC
each recognized this intent when recommending that the proposed
provisions for communicating with 9-1-1 applied to all ruptures,
without exception. An operator cannot properly and promptly coordinate
and share information with the appropriate public safety authorities
regarding event location and planned and actual responses to an
emergency if they do not have a procedure for identifying a rupture
upon the notification of a potential rupture.
Consistent with the Committees' recommendations, PHMSA has decided
against including within this final rule the 10-minute global rupture
identification time interval proposed in the NPRM. Although PHMSA
understands that a 10-minute rupture identification timeline is
achievable based on currently available technology, after reviewing the
written comments submitted in this proceeding, and the discussions
during the Committee meetings, PHMSA has concluded that the NPRM's one-
size-fits-all approach to rupture identification could be challenging
in light of the diversity of pipeline operational conditions and
customer requirements.
However, PHMSA remains concerned that, in the absence of a minimum
rupture identification time interval, a scenario similar to those that
played out during the Marshall, MI, and San Bruno, CA rupture events--
in which there were extended delays in rupture identification and
response despite multiple indicia of a potential rupture--could happen
again. With that in mind, PHMSA had considered triggering this final
rule's RMV operation response actions set forth in Sec. Sec. 192.636
and 195.419 on notification of potential rupture rather than rupture
identification. PHMSA has, however, declined to adopt such an approach
in this final rule to avoid further procedural delays in realizing the
safety benefits of a rulemaking that has been over a decade in the
making here at PHMSA--which effort commenced over 40 years after the
NTSB highlighted the public safety benefits from operators'
installation of readily-available technologies such as RMVs on
pipelines.\37\
---------------------------------------------------------------------------

\37\ See Homendy, ``San Bruno Victims and Their Families Deserve
Long-Overdue Action'' (Sept. 9, 2020), <a href="https://safetycompass.wordpress.com/category/infrastructure/">https://safetycompass.wordpress.com/category/infrastructure/</a> (last visited
Nov. 8, 2021) (referencing NTSB, PSS-71-1, Special Study of Effects
of Delay in Shutting Down Failed Pipeline Systems and Methods of
Providing Rapid Shutdown (Dec. 31, 1970), <a href="https://www.ntsb.gov/safety/safety-studies/Documents/PSS7101.pdf">https://www.ntsb.gov/safety/safety-studies/Documents/PSS7101.pdf</a>).
---------------------------------------------------------------------------

As a result, PHMSA may, in future rulemakings, consider whether it
is appropriate to key operator RMV operation response actions to
notification of potential rupture. In the interim, PHMSA has in this
final rule codified at Sec. Sec. 192.615(a)(12) and 195.402(e)(4)
language within the NPRM expressing its expectation that operators
will, upon notification of a potential rupture, identify whether there
is indeed a rupture by reference to written procedures. Operators
implementing this final rule should ensure those written procedures
incorporate common-sense elements including, but not limited to, waiver
of any requirements for specific pipeline personnel to conduct on-scene
investigation of a potential rupture if an operator receives one or
more of the following: Multiple or recurring instrument indications
(pressure readings, alarms, etc.) of potential ruptures; pressure drops
significantly in excess of the minimum thresholds in Sec. Sec.
192.635(a)(1) and 195.417(a)(1); \38\ and reports of rupture indicia
from on-scene, credible sources (e.g., on or off-duty pipeline operator
personnel, sheriff or police officers, fire department personnel, or
other emergency response personnel). PHMSA understands this reading of
its revisions at Sec. Sec. 192.615(a)(12) and 195.402(e)(4) to be
consistent with operators' obligations elsewhere in Sec. Sec.
192.615(a) and 195.402(e) (as revised) to take ``necessary actions to
minimize hazards of released [commodity] to life, property, or the
environment.'' PHMSA further notes that any risks to the public and the
environment arising from delays in rupture identification for operators
installing RMVs under this final rule would be further reduced by each
of (1) language in Sec. Sec. 192.615 and 195.402 requiring operators
to ensure that their protocols identify ruptures ``as soon as
practicable'' and (2) language at Sec. Sec. 192.636 and 195.419
imposing demanding timelines--``as soon as practicable,'' but not to
exceed 30 minutes from rupture identification--for operation of RMVs
following rupture identification.
---------------------------------------------------------------------------

\38\ PHMSA submits that operators may be able to leverage other
provisions in this final rule (Sec. Sec. 192.636(d)-(e) and
195.419(d)-(e)) pertaining to upstream/downstream pressure
monitoring to support timely rupture identification without the need
for on-scene investigation of a potential rupture.
---------------------------------------------------------------------------

D. RMV Installation; RMV Closure Timeframe

1. Summary of Proposal
In the NPRM, PHMSA proposed to require that all valves on newly
constructed or entirely replaced onshore gas transmission and gathering

[[Page 20954]]

pipelines that have diameters greater than or equal to 6 inches be RMVs
or an alternative equivalent technology. Operators seeking to use an
alternative equivalent technology in lieu of an RMV would have needed
to submit a notification to PHMSA demonstrating that their preferred
technology would provide an equivalent level of safety to an RMV. And
should an operator seek to use a manual valve as an alternative
equivalent technology, the operator would also have had to demonstrate
that installation of an RMV would not be economically, technically, or
operationally feasible. All valves installed per this proposal would
meet the new rupture-mitigation standards proposed in Sec. 192.634 and
isolate a ruptured pipeline segment within 40 minutes of rupture
identification.
Similarly, for hazardous liquid pipelines, PHMSA similarly proposed
to require that all valves on newly constructed and entirely replaced
onshore hazardous liquid pipelines that have diameters greater than or
equal to 6 inches be RMVs or alternative equivalent technology.
Operators seeking to use an alternative equivalent technology in lieu
of an RMV would have needed to submit a notification to PHMSA
demonstrating that their preferred technology would provide an
equivalent level of safety to an RMV. And should an operator seek to
use a manual valve as an alternative equivalent technology, the
operator would also have had to demonstrate that installation of an RMV
would not be economically, technically, or operationally feasible. All
valves installed under this proposal would meet the new rupture-
mitigation standards proposed in Sec. 195.418 and isolate a ruptured
pipeline segment as soon as practicable, but within 40 minutes of
rupture identification.
2. Comments Received
The PST stated that the proposed rule did not provide sufficient
rationale regarding how PHMSA arrived at a 40-minute shutdown
requirement, other than a suggestion that it is ``reasonable.'' They
stated that they have seen spill response plans for hazardous liquid
pipelines claiming that failures isolated within 15 minutes constitute
an operator's worst-case discharge. If those are accurately identified
as the worst-case discharges, the PST noted, then valves must be able
to close that fast or even more quickly. They stated that PHMSA's
determination of the maximum allowable shut-off period should be
justified by data relating to the speed with which automatic valves can
shut, and if they can shut more quickly, then the maximum allowable
valve closure period should be shortened to that length of time.
Similarly, the NTSB suggested that the 40-minute valve closure time
period is longer than expected for remote or automatic valves. The NTSB
suggested that, if PHMSA determined that shut-off valves are not
capable of isolating pipeline segments in less than 40 minutes, every
facility response plan calculating the worst-case discharge based on a
valve closure of less than 40 minutes after rupture identification
should be re-evaluated.
Conversely, Northern Natural Gas Company asserted that the
requirement for closing a valve to isolate a rupture within 40 minutes
does not allow adequate time for the pipeline controller to evaluate
the nature of the pressure change, determine if there is an emergency,
or identify the actions needed to mitigate the emergency. Therefore,
Northern Natural Gas Company recommended PHMSA change the rupture
identification and valve shut-off period to 60 minutes total. It stated
that a 40-minute valve closure requirement could result in too-rapid
decisions to shut-in pipeline segments, causing unnecessary outages,
unanticipated pressure changes, and potential damage to the pipeline
system. It also stated that, within the States where it operates,
unplanned, sudden outages could cause major problems with prolonged
loss of heat to residences, businesses, and government facilities as
well as an interruption of electric power generation and industrial
processes.
INGAA et al. recommended that PHMSA apply the 40-minute valve
closure time only to pipelines in HCAs and Class 3 and Class 4
locations to allow more flexibility in remote areas, noting
specifically that achieving valve closure within 40 minutes is
typically more challenging in remote areas. They noted that operators
are likely to consider the use of manual valves in remote areas because
an ASV, RCV, or equivalent technology would be economically,
technically, or operationally infeasible, as it can be difficult to
provide power or communications to automated valves in remote areas.
INGAA et al., further noted that pipelines traverse a multitude of
geographies, including locations that cannot safely be reached within
40 minutes, particularly during winter months.
Similarly, AFPM and other commenters representing hazardous liquid
pipeline operators also requested that PHMSA consider flexibility for
response time in remote areas where manual valves are located, stating
that, according to information submitted by AFPM members after a review
of their respective systems, manual valve response times in certain
scenarios would potentially exceed 40 or 60 minutes. AFPM stated that
the increased response time is due to the location of field employees
and their ability to reach remote locations, and that some valves may
take up to 10 to 20 minutes to close once personnel are at the valve
site. Therefore, these commenters stated that manual valves installed
in accordance with the RMV installation requirements should not need to
meet the proposed 40-minute valve closure standard.
GPA Midstream, like other commenters, provided specific regulatory
text for streamlining the requirements related to the valve closure
period. GPA Midstream also recommended that operators be allowed to
seek authorization from the Associate Administrator for Pipeline Safety
to use an alternative shut-off time in appropriate cases, stating that
there may be circumstances where an operator cannot meet the 40-minute
shut-off time.
INGAA et al. asserted that the 40-minute response time would not be
practicable or appropriate to apply to existing pipelines, should PHMSA
consider such a proposal in a future rulemaking. INGAA et al. claimed a
40-minute closure time is on the leading edge of what is practicable
under currently-available technologies that could be applied to new and
replaced pipelines. They noted that multiple PHMSA special permits
contain a 60-minute valve closure time requirement, and operators have
proactively taken steps to attain the 60-minute response target while
the current rulemaking has been pending for almost a decade.
Further, INGAA et al. stated that, even for new and replaced
pipelines, attaining the 40-minute valve closure time will push the
limit of what is currently technologically and operationally possible.
They noted that for almost 60 percent of PHMSA-reportable ruptures from
2010 to 2019, the response time was greater than 40 minutes, which,
they claimed, would indicate any response time shorter than 40 minutes
for new and replaced pipelines would be infeasible. Similarly, Magellan
Midstream Partners L.P. stated that 40 minutes is not a practical
travel time to manual valves that have been installed in accordance
with the RMV installation requirements.
Commenters also suggested PHMSA should provide an allowance for
scenarios where the operator and

[[Page 20955]]

emergency responders agree not to shut an RMV following a rupture.
At the Committee meetings on July 22 and 23, 2020, the Committees
unanimously endorsed the NPRM's RMV closure requirements as
``technically feasible, reasonable, cost effective and practicable''
provided that PHMSA reduce the RMV closure time to 30 minutes in
combination with eliminating the proposed 10-minute rupture
identification standard. PHMSA understands that endorsement to reflect
Committee discussions in which industry representatives focused their
objections to the NPRM on the difficulty of meeting the 10-minute
rupture identification timeline given differences in environmental
conditions and operational requirements within their systems.
Further, the GPAC recommended PHMSA review the issue of allowing
certain valves to remain open during emergency situations based on the
Committee discussion and public comments and ensure that the integrity
of the rule was not compromised and would minimize environmental
damage.
The GPAC also recommended PHMSA allow, for natural gas pipelines,
manual valves installed as alternative equivalent technology in non-HCA
Class 1 locations to exceed the 30-minute closure time requirement only
if the operator submits within its notification to install such valves
as alternative equivalent technology a specific closure time for those
manual valves. For hazardous liquid pipelines, the LPAC recommended a
similar limitation apply to manual valves used as alternative
equivalent technology in remote, non-HCA locations.
3. PHMSA Response
As a part of developing the NPRM, PHMSA considered what would make
it economically, technically, or operationally infeasible to install or
use an ASV, RCV, or equivalent technology. For instance, PHMSA proposed
to limit the installation of ASVs, RCVs, equivalent technologies
(including, potentially manual valves) to pipelines of 6 inches and
greater because, while rupture-mitigating technologies are commercially
available for pipelines as small as 2 inches in diameter, PHMSA
determined at the time that it is unlikely the safety and environmental
benefits on those pipelines would justify the costs of installing the
technology. While PHMSA applies these requirements to pipelines of 6
inches in this final rule, PHMSA may consider expansion of this
application for smaller pipeline diameters in a future rulemaking.
PHMSA would analyze the costs and potential safety and environmental
benefits of an expansion in any such rulemaking.
PHMSA also noted in the NPRM that examples of where it might be
infeasible to install ASVs or RCVs included locations that may have
issues with communication signals, power sources, space for actuators,
or physical security. These locations can vary and are not limited to
certain types of terrain. Certain urban areas, for example, might have
access to power sources but might not have adequate physical space for
the necessary valve actuators. Certain rural areas, on the other hand,
might have issues with maintaining continuous communication signals or
might have difficult-to-access valves. Other reasons that installation
of RMV may be infeasible identified in written comments and during
GPAC/LPAC meetings include difficulties in obtaining required access
rights or permits. The COVID-19 global health emergency has also
exacerbated labor and component constraints, drawing out procurement
timelines and increasing costs.
However, given that these valve installation requirements apply to
new construction and replacement projects whose routes and components
are planned out years in advance, PHMSA does not believe that there
should be major economic, technical, or operational constraints
impacting valve installation. Final Environmental Impact Statements for
pipeline projects proposed after the passage of the Pipeline Safety Act
of 2011 have shown that operators are committing to installing a
substantial number of remotely operated and monitored valves. However,
PHMSA does not want to preclude unforeseen challenges or conditions
operators may face in installing valves pursuant to this rulemaking,
and so developed an advance notification process at Sec. Sec. 192.18
and 195.18, by which operators can (subject to PHMSA's review) make a
site-specific case before installation of an alternative equivalent
technology that (1) the technology would provide an equivalent level of
safety to an RMV, and (2) if that proposed alternative equivalent
technology is a manual valve, installation of an RMV would be
economically, technically, or operationally infeasible. Similarly,
PHMSA has in this final rule established procedural machinery allowing
operators to request extensions of compliance timelines for
installation of RMVs and alternative equivalent technology is such
timelines are economically, technically, or operationally infeasible
for near-term construction and replacement projects.
PHMSA also considered what would make a technology ``alternatively
equivalent'' to the ASVs and RCVs that the statute specifically listed.
In developing the NPRM, and given the circumstances noted above, PHMSA
wanted to provide operators with flexibility to install the appropriate
valve or technology based on the unique circumstances at each site
while still ensuring that such valves or technologies would close as
soon as practicable.\39\ In the NPRM, PHMSA also noted that, in the
Marshall, MI incident, the rupture-mitigating valves the operator had
equipped on the line were functionally useless until the operator was
able to identify the rupture. Therefore, PHMSA believed that any
proposed regulation would need to pair a valve installation requirement
with a standard delineating when an operator must identify a rupture
and actuate those valves. PHMSA did not consider it appropriate to
assign different valve closure times to different rupture-mitigating
valves or technologies, because doing so would have made compliance and
enforcement difficult.
---------------------------------------------------------------------------

\39\ PHMSA notes that, as contemplated by the NPRM, such
alternative technologies can include manual valves if an operator
makes the requisite showings of safety equivalence and technical,
operational, or economic infeasibility of RMV installation. See,
e.g., 85 FR at 7178.
---------------------------------------------------------------------------

PHMSA believed that, by setting a valve and technology closure
standard for operators to meet, it would contribute to PHMSA's review
of notifications contending that an alternative technology would
provide an equivalent level of safety to an RMV. This approach allows
operators to install the most appropriate valve or technology given
site specifics, and it also prevents PHMSA from inadvertently
restricting the development or use of promising rupture-mitigating
technologies by imposing prescriptive requirements on the use of
``equivalent technology,'' which was not defined by the statute. As
discussed throughout the NPRM and this final rule, PHMSA does expect
operators to be able to close certain valves or technologies faster
than others, and has included requirements for operators to close RMVs
or alternative equivalent technologies ``as soon as practicable'' but
within the required timeframe.
PHMSA maintains that the proposed 40-minute RMV closure standard is
achievable with current technology, and it would be a significant
improvement over the 95 minutes it took PG&E to

[[Page 20956]]

close the necessary valves during the incident at San Bruno, CA. As
discussed in the NPRM, recent PHMSA-issued special permits for non-
looped pipelines contemplate those lines will be equipped with
isolation valves that can be closed in 30 minutes or less. PHMSA
proposed a higher ceiling (40 minutes) in the NPRM because many gas and
hazardous liquid systems have several incoming and outgoing product
receipts and deliveries or tie-ins and, in some situations, multiple
loop lines; establishing a one-size-fits-all requirement for valve
closure times on all gas and hazardous liquid pipeline systems can be
challenging based on the configuration of those systems. In the NPRM,
PHMSA also noted that it considered valve closure times between 30 and
60 minutes based on comments on the ANPRMs and work on the
``Alternative MAOP'' rulemaking.\40\
---------------------------------------------------------------------------

\40\ 73 FR 62147 (Oct. 17, 2008).
---------------------------------------------------------------------------

PHMSA notes that it developed the 40-minute RMV closure standard in
the NPRM accounting for the potential need to include manual valves as
alternative equivalent technology due to site-specific concerns; PHMSA
assumed and expects ASVs and RCVs will be closed much faster. In the
NPRM, PHMSA proposed to allow operators to use manual valves as an
alternative equivalent technology, with a notification to PHMSA
demonstrating that installing an ASV or RCV would be economically,
technically, or operationally infeasible, and that a manual valve would
provide an equivalent level of safety to an RMV. The NPRM's proposal
reflected PHMSA's belief it would be reasonable to apply a 40-minute
valve closure standard to provide time (if needed) for operators to get
personnel on-site to close any necessary manual valves.
As discussed elsewhere in this document, both the GPAC and the LPAC
each unanimously voted to characterize a shortened valve closure time
as ``technically feasible, reasonable, cost-effective, and
practicable'' provided that the NPRM's prescriptive timeframe for
rupture identification was eliminated. PHMSA acknowledges that a faster
valve-closure standard would provide additional environmental and
public safety benefits and has revised this final rule to require a 30-
minute maximum valve-closure time, measured from rupture
identification--with an emphasis that this is a ceiling whereas the
actual requirement is ``as soon as is practicable.'' As noted by some
of the commenters, many operators indicate ``worst case scenarios'' of
15 minutes.
Accordingly, PHMSA is requiring any RMVs and alternative equivalent
technology installed pursuant to this final rule be closed ``as soon as
practicable'' but no later than 30 minutes following the identification
of a rupture. In addition, as suggested in comments from PST, those
operators that have indicated in their spill response plans a valve
closure time of less than 30 minutes during a worst-case discharge
would still have to operate such valves in the time indicated in their
spill response plan (see Sec. 194.105(b)(1)). If an operator chooses
to install ASVs as RMVs, they must conduct flow modeling for the
applicable pipeline segments and any laterals that feed the pipeline
segment to ensure that the ASV will close within 30 minutes or less
following rupture identification. The flow modeling must include the
anticipated maximum, normal, or any other flow volumes, pressures, or
other operating conditions (including extreme fluctuations in weather
that might affect operating pressures) that may be, or are anticipated
to be, encountered during the year, not to exceed a period of 15
months, and it must be modeled for the flow between the RMVs or
alternative equivalent technologies, and any looped pipelines or gas
receipt tie-ins. If operating conditions change in a way that could
affect the ASV set pressures and the valve closure time after rupture
identification, an operator must conduct a new flow model and reset the
ASV set pressures prior to the next review for ASV set pressures in
accordance with Sec. 192.745. The flow model must include a pressure
drop/time chart or graph for the segment containing the ASV if a
rupture event occurs and must show rupture segment isolation as soon as
is practicable and within 30 minutes of rupture identification. An
operator must conduct this flow modeling prior to making flow condition
changes in a manner that could assure that the 30-minute valve closure
time is achievable. If an operator does not perform this flow modeling
correctly, the set pressure could be too low, thus rendering a 30-
minute closure time unachievable.
When conducting flow modeling for ASVs, operators should also
consider what type of rupture may occur on their system, especially
whether the rupture may be a pipe-body type or a seam-type failure. The
flow model detection for a rupture should be based on 0.5 times the
pipe diameter (or less) pipe area when sizing the pressure drop for a
rupture.
Operators also have the option, in lieu of installing RMVs, to
install alternative equivalent technology with an advance notification
to PHMSA in accordance with Sec. Sec. 192.18 and 195.18. An operator
must include, for PHMSA's review, a site-specific technical and safety
evaluation in its notice consisting of the following information, as
well as any other information requested by PHMSA in its review of the
notification: Design, construction, maintenance, and operating
procedures; technology design and operating characteristics such as
operation times (closure times for manual valves); service reliability
and life; accessibility to operator personnel; nearby population
density; and potential consequences to the environment and the public.
Where the operator proposes to use manual valves as alternative
equivalent technology, its notification to PHMSA must also demonstrate
that installation of an RMV would be economically, technically, or
operationally infeasible by reference to factors such as access to
communications and power; terrain; prohibitive cost; component and
labor availability; ability to secure required access rights and
permits; and accessibility to operator personnel for installation and
maintenance.
As discussed above, PHMSA is requiring an ``as soon as is
practicable'' valve closure time (with an absolute ceiling of 30
minutes), measured from rupture identification pursuant to an
operator's written procedures, in conjunction with eliminating the 10-
minute rupture identification timeframe. Shortening the time it takes
for an operator to close a RMV or alternative equivalent technology
provides a better mitigation standard to protect the public and the
environment from the consequences of a rupture. PHMSA notes that it has
seen evidence of operators being able to isolate looped pipeline
systems in less than 10 minutes--this rule should help ensure this
timeframe is widely achievable. Operators of hazardous liquid pipelines
must also consider the shut-down times they use when calculating worst-
case discharges in accordance with Sec. 194.105 and be able to close
RMVs within that timeframe if it is less than 30 minutes.
For gas pipelines, some commenters suggested allowing operators to
exceed the 30-minute closure standard if using manual valves as
alternative equivalent technology in non-HCA, Class 1 locations, if the
operator submits a notification demonstrating that installing an RMV
would be economically, technically, or operationally infeasible. Given
that non-HCA Class 1 locations are largely rural areas, PHMSA believes
such a provision would be warranted if the operator could demonstrate
they could not install

[[Page 20957]]

a compliant valve or technology in those locations. In this final rule
at Sec. 192.636(g), PHMSA specifies that an operator seeking an
exemption from the rule's RMV and alternative equivalent technology 30-
minute operation requirement would, within its request submitted under
Sec. 192.18, have to provide PHMSA for its review, inter alia, with an
estimated closure time of any manual valve employed as an alternative
equivalent technology. PHMSA has not included procedural machinery for
such an exemption from that operation requirement for manual valves
used as alternative equivalent technology in non-HCA Class 2 locations
in this final rule, however, because those locations would pose a
greater risk to public safety: By definition, Class 2 locations have a
minimum of 10 houses and up to 45 houses in the class location unit
near the pipeline. The final rule incorporates at Sec. 195.419(g) an
analogous procedure for certain hazardous liquid pipelines
(specifically, those that are neither in, nor could affect, an HCA)
whereby an operator can request an exemption from the 30-minute
operation requirement at Sec. 195.419(b) when employing a manual valve
as an alternative equivalent technology; those pipelines, too, pose a
lower risk to public safety and environment from hazardous liquid
pipeline segments which are located in, or could affect, an HCA.
In this final rule, PHMSA does not authorize operators, in
conjunction with emergency responders, to leave RMVs or alternative
equivalent technologies open for rupture mitigation or safety during
emergency response, without first forwarding to PHMSA pursuant to
Sec. Sec. 192.18 or 195.18 such a request and developing appropriate
written procedures. PHMSA believes that the need to isolate ruptures is
paramount--precisely to be able to afford maximum safety for an
emergency response as well as for mitigation purposes--and that RMVs
and alternative equivalent technologies should be closed as soon as
practicable. Any discussions occurring with emergency responders while
an incident is occurring could lead to unjustified delays in isolating
ruptures. If an operator has not established the need in their
operating procedures for not closing valves prior to a rupture, the
emergency responder(s) would probably not have the appropriate
information to make such a decision promptly. Commenters at the GPAC
meeting noted that there might be instances where leaving RMVs or
alternative equivalent technologies open during emergencies was
warranted, such as when the pipeline was the sole product source for a
power plant or a hospital, or where closing a RMV or alternative
equivalent technology would then have an adverse economic impact on
other customers downstream. PHMSA has determined that, in situations
such as these, the potential risks associated with interruption of gas
supply to particular end users will generally outweigh the value of
more quickly mitigating the nearly certain catastrophic consequences of
a pipeline rupture. PHMSA notes that a rupture may itself result in
interruption of service to critical facilities and electric generators,
regardless of response actions taken by operators. Further, PHMSA notes
that bi-directional product flow or the residual volume of product
downstream of a ruptured pipeline segment can provide operators with
time to isolate the ruptured pipeline segment while also redirecting
product flow as necessary to ensure that any disruption to downstream
facilities would be minimized. PHMSA also contemplates operators will
appropriately plan for the aforementioned contingencies.
Based on the GPAC discussion, however, PHMSA has provided in this
final rule a mechanism for an operator to forward to PHMSA such a
request. Accordingly, an operator of a gas pipeline may request
pursuant to Sec. 192.18 to plan to leave an RMV or alternative
equivalent technology open for more than 30 minutes following rupture
identification if the operator can demonstrate to PHMSA that closing
that RMV or alternative equivalent technology would be detrimental to
public safety. Such a request must be coordinated in advance with
appropriate local emergency responders, and the operator and applicable
emergency responders must agree that it would be safe to leave the
valve open. If PHMSA grants such a request to an operator, that
operator would be required to have written procedures for determining
when to leave a RMV or alternative equivalent technology open,
including all plans for communicating with local emergency responders
during a rupture event during which the RMV or alternative equivalent
technology would be left open, and including measures by which the
operator would minimize environmental impacts.
Regarding the comments requesting clarification on the meaning of
``other mitigative actions,'' PHMSA intended this phrase to require
that operators take whatever action is appropriate to mitigate the
event, in addition to closing the appropriate RMVs or alternative
mitigative technologies. The specific actions PHMSA would expect an
operator to take would be dependent on each unique rupture scenario and
may include, but are not limited to, the closure of valves on laterals
used for receipt or delivery and communication with product receipt and
delivery customers.

E. RMVs

1. Summary of Proposal
In the NPRM, for gas pipelines, PHMSA proposed to require that all
valves on newly constructed or entirely replaced onshore gas
transmission and gathering pipelines that have diameters greater than
or equal to 6 inches be ASVs, RCVs or an alternative equivalent
technology. Operators seeking to use manual valves as an alternative
equivalent technology would also need to demonstrate to PHMSA's
satisfaction that installing an ASV or RCV was economically,
technically, or operationally infeasible. PHMSA proposed to define the
statutory phrase ``entirely replaced'' as being where an operator
replaces 2 or more contiguous miles of pipeline with new pipe. All
valves installed per this proposal would meet the new rupture-
mitigation standards proposed and isolate a ruptured pipeline segment
within 40 minutes of rupture identification. PHMSA also proposed that
new or entirely replaced laterals contributing 5 percent of the total
volume of the applicable gas line shut-off segment would also require
RMVs.
For hazardous liquid pipelines, PHMSA similarly proposed to require
that all valves on newly constructed and entirely replaced onshore
hazardous liquid pipelines that have diameters greater than or equal to
6 inches be RCVs, ASVs, or an alternative equivalent technology. PHMSA
proposed to permit operators to install manually or locally operated
valves as alternative equivalent technology only when there were
economic, technical, or operational feasibility issues precluding the
installation of ASVs or RCVs and proposed to require operators to
notify PHMSA as well. All valves installed under this proposal would
meet the new rupture-mitigation standards proposed in Sec. 195.418 and
isolate a ruptured pipeline segment as soon as practicable, but within
40 minutes of rupture identification. Similar to gas transmission
lines, new or entirely replaced laterals contributing 5 percent of
hazardous liquid volume would also be required to install RMVs.
PHMSA also defined the term ``shut-off segment'' in the NPRM as the
segment of applicable pipe between the RMVs closest to the upstream and

[[Page 20958]]

downstream endpoints of an HCA, a Class 3 location, or a Class 4
location so that the entirety of these areas is between RMVs. Multiple
HCAs, Class 3 locations, or Class 4 locations can be contained in a
single shut-off segment, and all valves installed on a shut-off segment
are RMVs. While PHMSA did not specifically define the term ``rupture-
mitigation valve'' in the NPRM, it used that term in the NPRM to
describe the ASVs, RCVs, or alternative equivalent technology installed
to mitigate ruptures.
For the proposed construction and replacement requirements, PHMSA
proposed an implementation timeframe of 12 months following the
effective date of the rule.
2. Comments Received
(i) ``Rupture-Mitigation Valve'' and Related Definitions
API/AOPL, GPA Midstream, Magellan Midstream Partner, L.P., and TC
Energy Corporation recommended that PHMSA add a definition of an RMV
for clarity. These industry commenters stated that the definition of an
RMV should explicitly include check valves within its scope and also
specify the purpose served by these valves, which is to minimize the
volume of product released following a rupture and mitigate the safety
and environmental consequences of a rupture. API/AOPL and GPA Midstream
added that the definition of an RMV should include automated valves,
alongside ASVs and RCVs, per the GAO report. Other commenters,
representing hazardous liquid pipelines operators, noted that the
definition should also contain EFRDs for hazardous liquid pipelines.
PHMSA also received several comments regarding the use of
additional technologies and practices. Regarding valve types, industry
commenters suggested PHMSA should allow operators to use a ``locked-
out'' or ``tagged-out'' manual valve as an alternative equivalent
technology at crossovers, and allow operators to use a check valve as
an RMV for laterals used for receipt or delivery, provided that the
check valve is positioned to stop product flow into the shut-off
segment. Further, industry commenters suggested that PHMSA should add
language to the final rule to confirm that locally actuated ASVs would
be an acceptable alternative for RMVs and that operators could select
any pipeline (mainline or lateral) or station valve as an RMV as long
as it complied with the RMV spacing requirements.
Commenters also had suggestions for definitions related to RMVs,
including ``shut-off segment'' and ``entirely replaced.'' For ``shut-
off segment,'' commenters recommended defining that term and provided
assorted editorial suggestions for the definition. Similar comments
were made for the term ``entirely replaced.''
Additionally, for the term ``entirely replaced,'' industry
commenters noted that PHMSA discussed the definition for the term in
the preamble text but did not include it in the regulatory text. They
asserted that the definition that PHMSA uses for ``entirely replaced''
in the NPRM is not consistent with the plain meaning of that term, as
meaning ``in every way possible; completely.'' Based on that
interpretation of the definition of ``entirely replaced,'' these
commenters stated that replacing a portion of a pipeline would not
constitute an ``entirely replaced'' pipeline and suggested that, based
on PHMSA's definition, ``entirely replaced'' could create an incentive
to make poor engineering decisions based on the potential consequences
of a segment being ``completely'' replaced.
The PST stated that PHMSA provided no explanation for how it
arrived at the 2-mile threshold or whether recent replacement projects
were tallied to see how many recent projects that distance would
include or exclude. The PST asserted that choosing a shorter distance
would include more replacement projects and would therefore result in
more of the Nation's pipeline systems having the additional protection
of ASVs or RCVs. The PST also stated that because 2 miles is a long
distance, it seems an easier distance to design around to avoid
application of this rule. Therefore, the PST suggested PHMSA establish
the definition of ``entirely replaced'' based on a replacement length
of 600 contiguous feet or a length of more than 600 feet of any
contiguous 1,000 feet, which would be a distance longer than a single
integrity repair might require but short enough to capture smaller
replacement projects. The PST stressed the importance of this
definition due to limitations on changing design and construction
requirements on existing pipeline systems. Similarly, other commenters
from the general public suggested that PHMSA should reduce the distance
for replacement that triggers valve installation to 1 mile of
contiguous pipeline.
At the Committee meetings on July 22 and 23, 2020, discussions
focused on the practicability of NPRM's proposed definition of
``entirely replaced.'' Pipeline operators generally supported the 2-
mile element of the definition as striking an appropriate balance
between safety benefits and practical difficulties (e.g., obtaining
land access rights and permits) associated with installing new RMVs on
replacement pipelines--provided PHMSA clarify (1) the length of the
pipeline from which the 2 miles of replaced pipe would be calculated
was less than each operator's entire system, and (2) the timeframe over
which those pipeline replacements would be conducted so as to
accommodate pipeline maintenance planning cycles. The Committees
unanimously recommended that PHMSA revise the final rule so that the
``entirely replaced'' standard applies to multiple replacements that,
in the aggregate, exceed 2 miles of pipeline within a 5-contiguous-mile
length within a 24-month period. The Committees also unanimously
recommended PHMSA allow check valves and valves on crossover piping
that are locked and tagged closed in accordance with operating
procedures to be used as RMVs. Committee members noted that check
valves could already be considered an ASV based on their design, and
that check valves have been used effectively in hazardous liquid
pipeline systems.
(ii) RMV Applicability
NAPSR and other commenters requested PHMSA clarify whether the
proposed requirements would be applicable to low-stress systems, noting
that rupture risk is greatly reduced for systems that operate at less
than 20 or 30 percent of SMYS.
Similarly, the industry associations requested that PHMSA except
pipelines from the RMV installation requirements where the PIR of those
pipelines is less than 150 feet. They stated that pipeline diameter
alone is not an accurate indicator of the potential consequences of a
rupture, as many pipelines with diameters ranging from 6 inches to 12
inches operate at pressures low enough that the impact of a rupture
would be minimal. The industry associations noted that a pipeline's PIR
reflects both the pipeline size and the operating pressure, and it is
therefore a better measure of potential consequence than diameter
alone. Further, the industry associations noted that the 2019 Gas
Transmission Final Rule \41\ used a PIR of less than or equal to 150
feet to establish less-stringent requirements for aspects of MAOP
reconfirmation and pressure reductions.
---------------------------------------------------------------------------

\41\ 84 FR 52180 (Oct. 1, 2019).
---------------------------------------------------------------------------

Commenters representing hazardous liquid pipeline operators
similarly requested that PHMSA exempt pipeline segments that could not
affect HCAs

[[Page 20959]]

from the requirement for installing RMVs to create the greatest benefit
for the rule using an HCA-focused approach consistent with the risk-
based philosophy of the Federal Pipeline Safety Regulations.
For both gas and hazardous liquid pipelines, industry commenters
requested that PHMSA clarify whether the 5 percent volume contribution
for determining the need for RMVs on laterals is based on flow rate or
total volume.
At the Committee meetings on July 22 and 23, 2020, the Committees
recommended that PHMSA consider exceptions from the RMV installation
requirement for pipelines with SMYS of 30 percent or less and for all
gas transmission and gas gathering pipelines with a PIR equal to or
less than 150 feet (not for pipeline segments in Class 4 locations)
considering cost-benefit issues and while maintaining the integrity of
the rule. For hazardous liquid pipelines, the Committees recommended
that PHMSA consider exceptions for pipelines 30 percent of SMYS or
less.
Further, the GPAC recommended PHMSA consider an exception for Type
A gas gathering pipelines of 12 inches or less and Type B gas gathering
pipelines. Both the GPAC and the LPAC recommended that PHMSA consider
the appropriateness of applying this rulemaking, or a separate
rulemaking, to gathering lines.
(iii) Timeframe for RMVs To Be Operational and Implementation Period
With regard to the timeframe for making RMVs operational following
operators placing pipelines into service, INGAA et al. requested that
PHMSA provide operators with 14 days rather than the 7-day period
proposed. They stated that several safety and operational activities
must take place following the introduction of gas into a new pipeline
segment, including the testing of control and communication systems,
evaluating system constraints, and conducting management of change
processes, which could require more than 7 days to conduct. Some
commenters from industry also suggested that PHMSA change the
implementation period for new construction from 12 months after the
effective date to 24 months.
At the GPAC and LPAC meetings on July 22 and 23, 2020, the
Committees unanimously recommended that PHMSA change the implementation
period of the rule to 24 months after publication date for gas
transmission and gas gathering pipelines, and consider reducing the
implementation of the rule to be between 12 and 18 months for hazardous
liquid pipelines. On both Committees, members representing the public
(including PST) were initially reluctant to provide longer periods of
time for the implementation of the rule. However, PHMSA noted during
the meeting that the NPRM already provided a compliance period of 12
months after the 6-month effective date of the rule, which would have
provided a compliance date of 18 months after the rule's publication.
Members of the Committees representing industry (including Enbridge,
National Grid, Marathon Pipeline, Colonial Pipeline, DCP Midstream, and
PECO) noted that there could be significant lead time required for
obtaining actuators for valves for larger-diameter pipelines, and
recommended longer implementation times for the rule. As a result of
this discussion, the committee ultimately recommended the 24-month
implementation period. Additionally, for hazardous liquid pipelines,
the LPAC also unanimously recommended PHMSA change the timeframe to
activate RMVs after construction from 7 days to 14 days because of
practicability concerns.
(iv) Notifications
Commenters representing hazardous liquid pipeline operators stated
that PHMSA should align the various notification requirements
throughout the rulemaking, including those for ``other [alternative
equivalent] technology'' requests, with other part 195 notification
requirements. Regarding such notifications, the PST requested that
PHMSA clarify what criteria or standards are needed to justify the
determination and provide for an equivalent level of safety. Commenters
also requested that this notification period operate similarly to how
PHMSA has created notifications for gas pipeline operators; namely,
that unless an operator receives a specific objection from PHMSA or a
request for more review time before the 90-day period has passed, the
operator can install the technology under the assumption that PHMSA has
no objection.
INGAA et al. also recommended PHMSA revise the rule so that the
notification process for alternative technology such as manual valves
applies to all locations, asserting that operators installing new or
replaced pipelines in remote areas are likely to use this process.
At the Committee meetings on July 22 and 23, 2020, the LPAC and
GPAC each unanimously recommended that PHMSA add specificity on
standards for PHMSA review of ``other technology'' and manual valve
notifications. The LPAC also unanimously recommended PHMSA incorporate
the notification requirements of Sec. 192.18 into the final rule and
make a similar provision for hazardous liquid pipelines.
3. PHMSA Response
(i) ``Rupture-Mitigation Valve'' and Related Definitions
PHMSA notes that there was concern regarding the clarity of the
terms RMV, ``shut-off segment,'' and ``entirely replaced,'' and PHMSA
has revised those terms in this final rule.
For the definition of an RMV, PHMSA has made it explicit that such
a valve is an ASV or an RCV. Commenters from industry requested PHMSA
allow the use of certain valve technologies to satisfy the proposed RMV
or alternative equivalent technology installation requirement. In this
final rule, PHMSA is clarifying that a valve on crossover piping that
is locked and tagged closed in accordance with operating procedures
would qualify as an alternative equivalent technology. PHMSA notes
that, for other technologies (such as check valves) that commenters
from industry had suggested should be generally considered alternative
equivalent technologies, PHMSA included a pre-installation notification
procedure for alternative equivalent technologies and will consider
requests to use such technologies on a case-by-case, site-specific
basis. When determining the appropriateness of alternative equivalent
technologies for a particular site, PHMSA will consider technical and
safety information submitted by an operator including, but not limited
to, design, construction, maintenance, and operating procedures;
technology design and operating characteristics such as operation times
(closure times for manual valves); service reliability and life;
accessibility to operator personnel; nearby population density; and
potential consequences to the environment and the public.
The definition of a ``shut-off segment,'' as it pertains to RMVs
and alternative equivalent technologies, has been clarified in this
final rule as well. These segments are only relevant when RMVs or
alternative equivalent technologies are installed pursuant to this
final rule for Class 3 and Class 4 locations for gas pipelines, as well
as HCAs (or on pipeline segments that could affect HCAs, in the case of
hazardous liquid pipelines) for gas and hazardous liquid pipelines.
Shut-off

[[Page 20960]]

segments are defined as segments of pipe located between the upstream
mainline valve closest to the upstream endpoint of the new or entirely
replaced Class 3, Class 4, or HCA segment, and the downstream mainline
valve closest to the downstream endpoint of the new or entirely
replaced Class 3, Class 4, or HCA segment. Shut-off segments can
include crossover or lateral pipe depending on where that pipe connects
to the specific shut-off segment. Single shut-off segments can include
multiple Class 3, Class 4, or HCA pipeline segments.
Pertaining to the definition of ``entirely replaced,'' it was not
PHMSA's intent to require the addition of RMVs or alternative
equivalent technologies for small maintenance replacements, such as at
road crossings or anomaly repairs where the pipe is replaced. PHMSA did
note throughout the NPRM that it was considering ``entirely replaced''
to mean the replacement of 2 contiguous miles of pipe. Some commenters
representing the public noted that pipeline operators may try to
schedule replacement activities and pipeline segment lengths to
circumvent the replacement mileage threshold. PHMSA determined that
this concern is mitigated by the recommendations of the Committees to
clarify that the RMV and alternative equivalent technology installation
requirements would apply to those replacement projects where 2 or more
miles of pipeline, in the aggregate, are replaced within any 5
contiguous miles within any 24-month period. PHMSA is aware that
sourcing valves might take a long lead time, and that waiting to
install a valve, at any location, could be deleterious to safety.
Requiring the installation, or automation, where applicable, of valves
where relatively larger construction projects are taking place will
facilitate operators obtaining and installing the RMVs or alternative
equivalent technologies required by this final rule. Accordingly, in
this final rule, PHMSA has introduced specific definitions for
``entirely replaced onshore transmission pipeline segments'' and
``entirely replaced onshore hazardous liquid or carbon dioxide pipeline
segments'' meaning those gas and hazardous liquid pipeline replacement
projects where 2 or more miles of pipe have been replaced within any 5
contiguous miles of pipe within any 24-month period.
(ii) RMV Applicability
Certain commenters from the industry and the industry associations
requested various exemptions for the RMV and alternative equivalent
technology installation requirements, including pipelines that operated
at pressures below 30 percent of SMYS. Pipelines operating at pressures
below 30 percent of SMYS have ruptured in the past, and low operating
pressure is not a guarantee that the pipe will not rupture. However,
PHMSA is aware of data that would indicate that pipelines operating at
pressures lower than 20 percent of SMYS are at less risk of rupturing.
A study on pipelines that ruptured while operating at low hoop stresses
that was published in 2013 noted that, within the 5-year window of the
study, there were seven pipeline ruptures occurring on pipelines
operating at a pressure below 20 percent SMYS.\42\ The authors of the
study noted that, while these are not highly likely events, the
likelihood is not so low where certain conditions could be present that
they do not need to be considered in an operator's IM plans.
---------------------------------------------------------------------------

\42\ Rosenfeld & Fassett ``Study of Pipelines that Ruptured
While Operating at a Hoop Stress Below 30% SMYS;'' Pipeline Pigging
and Integrity Management Conference (Feb. 13-14, 2013).
---------------------------------------------------------------------------

Additionally, according to PHMSA's 2019 annual report data, the
population of natural gas and hazardous liquid pipelines that operate
at these pressures are a small portion of the aggregate mileage of
those types of pipelines across the United States.\43\ Consistent with
other, current regulatory requirements, PHMSA believes it is reasonable
to add certain exemptions for pipeline segments operating at lower
stress levels. For natural gas pipelines, PHMSA presented data during
the GPAC meeting showing a correlation between pipelines operating at
lower stresses and pipelines with smaller PIRs. Given that natural gas
pipelines that would have a PIR of less than 150 feet would typically
be either pipelines of smaller diameter that would not be subject to
the requirements of this rulemaking, or larger pipelines operating at
lower stresses, PHMSA believes it would be feasible to exempt such
pipelines from the RMV and alternative equivalent technology
installation requirements if those pipelines are in Class 1 or Class 2
locations. PHMSA did not accept the GPAC's recommendation to provide an
exception, based on the pipeline's PIR, for gas transmission and
gathering pipelines in Class 3 locations. Pipelines in Class 3
locations are by definition adjacent to population centers: A Class 3
location is where there are 46 or more buildings for human occupancy
within the class location unit, or where there is a building or area
that is occupied by 20 or more persons on at least 5 days a week for 10
weeks in any 12-month period. PHMSA has determined that, while it might
be less likely that a gas pipeline operating at lower stresses in a
Class 3 location would rupture, the potential consequences to public
safety and the environment are still unacceptable.
---------------------------------------------------------------------------

\43\ Seven percent of the gas transmission mileage operates at
pressures below 20 percent of SMYS, which equates to approximately
21,000 miles out of 302,000 miles. For hazardous liquid pipelines, 3
percent of the total mileage operates as pressures less than 20
percent of SMYS, which equals 6,750 miles out of a total of 225,000
miles.
---------------------------------------------------------------------------

For hazardous liquid pipelines, PHMSA notes that there are
currently regulatory requirements for low-stress pipelines in rural
areas. By definition (at Sec. 195.12), these pipelines operate at
stress levels equal to or less than 20 percent of SMYS. The
environmental consequences of a hazardous liquid spill can linger for
many years, and hazardous liquids can travel far from the initial
accident site to affect other areas as well. Therefore, counter to the
LPAC recommendation, PHMSA is not providing hazardous liquid pipelines
that operate at lower stresses an exemption from the RMV installation
and usage requirements of this rulemaking.
Some commenters (including TC Energy and the industry associations)
requested PHMSA provide exemptions from RMV installation requirements
for, or otherwise exclude, gas pipelines in Class 1 and Class 2
locations, and for hazardous liquid pipelines that are outside of HCAs.
PHMSA notes that, for hazardous liquid pipelines, there are many
locations, such as non-navigable waterway crossings, that could
experience significant consequences from an accident even though they
are not defined as HCAs. For gas pipelines, there have been many
instances where a Class 1 location in which a pipeline has been
installed has later experienced so much population growth that it has
grown into a Class 3 location. Requiring operators to install RMVs and
alternative equivalent technology on Class 1, Class 2, and non-HCA
infrastructure is prudent and provides future generations with a
baseline level of public and environmental safety that can accommodate
changes in population density.
As discussed earlier in this rulemaking, PHMSA considered the
recommendations the Committees made regarding the applicability of this
rulemaking to gathering pipelines. For gas pipelines, PHMSA determined
that the risk profile of Type A gas gathering pipelines was
considerable enough not to impose a broad exception to the rule's
requirements, as these pipelines tend to operate at higher pressures
and are in Class 2, Class 3, or Class 4 locations,

[[Page 20961]]

where there are more concentrated populations. However, based on risk
profile, PHMSA did create a general exemption from the RMV and
alternative equivalent technology installation requirements in this
rulemaking for Type A gas gathering pipelines in Class 2 locations with
a PIR of 150 feet or less. Operators of Type A gas gathering pipelines
that have a PIR of 150 feet or less in a Class 2 location are not
required to install RMVs or alternative equivalent technology in
accordance with this rulemaking. PHMSA considered the GPAC's
recommendation applicable to Type B gathering lines and determined that
a broad exemption from the RMV and alternative equivalent technology
requirements would be warranted, given the fact that Type B gas
gathering pipelines, by definition, operate at hoop stresses less than
20 percent of SMYS. Pipelines operating at pressures that low are less
likely to rupture. As noted above, PHMSA will carefully monitor data
from these lines to inform future rulemaking.
For hazardous liquid pipelines, PHMSA noted earlier that regulated
hazardous liquid gathering pipelines would be required to install and
use RMVs and alternative equivalent technologies in accordance with
this rulemaking, as hazardous liquid gathering pipelines that are in
non-rural areas are required to comply with the entirety of part 195.
However, PHMSA is exempting regulated rural gathering pipelines from
the RMV and alternative equivalent technology requirements of this
rulemaking unless they cross bodies of water greater than 100 feet
wide, as ruptures on regulated rural gathering pipelines would
generally involve less risk to public safety and property than non-
rural gathering lines, and ruptures on regulated rural gathering lines
that cross large bodies of water have the potential to cause more
significant environmental damage. Regarding the comment that PHMSA
should clarify whether the 5 percent volume contribution for
determining the need for RMVs on laterals is based on flow rate or
total volume, Sec. 192.634(b)(3) states that the 5 percent volume
contribution is based on total volume.
(iii) Timeframe for RMVs To Be Operational and Implementation Period
Regarding the timeframe for making RMVs and alternative equivalent
technologies operational, PHMSA has determined that 14 days is more
appropriate than the proposed 7 days given that (as noted in the
comment submitted by INGAA et al.) a number of activities must take
place after a pipeline has been placed into service but before an RMV
is fully operational--PHMSA understands the scale and number of those
activities make completion within the proposed 7-day timeline
impracticable. Accordingly, PHMSA has adjusted that timeframe in this
final rule. PHMSA has also provided a procedural machinery for
operators to request an extension beyond 14 days if completion of
necessary activities for a valve to become operational is not
economically, technically, or operationally feasible (e.g., due to
prohibitive costs, labor or component shortages, or required permitting
or access rights).
Regarding the implementation date for RMV and alternative
equivalent technology installation, PHMSA notes the confusion several
commenters had regarding the implementation date and the effective date
of the rule. In this final rule, PHMSA is clarifying the implementation
date for RMV and alternative equivalent technology installation by
stating that pipelines and pipeline segments installed or entirely
replaced beginning 12 months after the publication date of the final
rule will be required to have RMVs or alternative equivalent
technologies. PHMSA believes 12 months is a reasonable implementation
period for RMV and alternative equivalent technology installation
rather than the 24 months recommended by the Committees as it should
provide operators with sufficient lead time to source RMV or
alternative equivalent technology for planning construction and
replacement projects without causing substantial implementation delay.
Further, as shown in the RIA, PHMSA has found that much new pipeline
construction is already obtaining and installing RMVs. If a gas or
hazardous liquid pipeline operator anticipates it will not be able to
meet this compliance timeframe, it may request from PHMSA, in
accordance with Sec. Sec. 192.18 and 195.18, respectively, additional
time to comply because of economic, technical, or operational
feasibility constraints (e.g., labor or component availability
constraints and lead times, prohibitive cost, permitting requirements,
or obtaining requisite access rights) with respect to its near-term
construction and replacement projects. Per the procedures at Sec. Sec.
192.18 and 195.18, PHMSA has discretion to grant or deny an operator's
request based on the information that the operator provides.
(iv) Notifications
Regarding the notification requirements for RMV and alternative
equivalent technology installation, PHMSA acknowledges that aligning
the notification process with the recently finalized Sec. 192.18 would
be beneficial. Accordingly, PHMSA has done so in this final rule for
both hazardous liquid and gas pipelines. For gas pipelines, this means
that PHMSA has cross-referenced the notification requirements in this
final rule to Sec. 192.18 to provide for, and build upon, the
notification process that is in that section. For hazardous liquid
pipelines, because there was no corresponding notification section,
PHMSA has created a new Sec. 195.18 in this final rule that functions
similarly to Sec. 192.18. For any notifications related to the RMV and
alternative equivalent technology requirements of this rulemaking,
Sec. 195.18 provides a consistent process where operators submit in
advance of installation the pertinent, requested information to PHMSA,
and PHMSA has 90 days in which to review and respond to the request. If
an operator does not receive a letter of objection or a request from
PHMSA for more time or information for PHMSA to complete its review of
the request within 90 days of the notification, then the operator may
use the alternative technology, method, compliance timeline, or valve
spacing that is being requested. Similar to the notification response
process for part 192, PHMSA's objection will specify the reasons PHMSA
does not approve of the proposed alternative technology, method,
compliance timeline, or valve spacing, while a request from PHMSA for
more time to review the request will extend the notification review
period beyond 90 days. Further, to establish a verifiable record, it is
PHMSA's policy to send a formal ``no objection'' letter or email,
either before or after the 90-day review period, when PHMSA does not
object to an operator's request in the notification.

F. Valve Spacing & Location

1. Summary of Proposal
In the NPRM, PHMSA proposed to require RMVs or alternative
equivalent technologies installed on newly constructed or entirely
replaced gas and hazardous liquid pipelines to be spaced at certain
intervals. For gas pipelines, PHMSA proposed that the distance between
RMVs or alternative equivalent technologies must not exceed 8 miles for
Class 4 locations, 15 miles for Class 3 locations, and 20 miles for
Class 1 and Class 2 locations in HCAs. For hazardous liquid pipelines,
PHMSA proposed RMV and alternative equivalent technology spacing of 15
miles for HCAs and 7\1/2\ miles for HVL lines in populated HCAs. PHMSA
also

[[Page 20962]]

proposed valve spacing of 20 miles for hazardous liquid pipelines not
in HCAs and spacing of a maximum of 1 mile for pipelines at water
crossings of greater than 100 feet in width so that the valve is
located outside of the flood plain, or the actuators and controls were
otherwise unaffected by floodwaters.
In Sec. Sec. 192.634 and 195.418, PHMSA also proposed that
operators would, in HCAs and Class 3 and Class 4 locations for gas
pipelines, install RMVs or alternative equivalent technologies upstream
and downstream of new construction and replacements longer than 2
contiguous miles regardless of whether the project involved a valve
installation.
PHMSA also proposed to modify the IM requirements for both gas and
hazardous liquid pipelines to specify that RMVs or alternative
equivalent technologies installed to protect HCAs must meet the design,
operation, testing, maintenance, and rupture mitigation requirements
proposed elsewhere in the NPRM.
2. Comments Received
(i) Spacing
The PST and the NTSB stated the maximum RMV and alternative
equivalent technology spacing intervals proposed in the NPRM might not
be sufficient to mitigate the consequences of a ruptured pipeline, with
the PST expressing concern that 15- and 20-mile spacing is too far,
especially for large-diameter pipelines.
For hazardous liquid pipelines, commenters representing the
pipeline industry generally did not support a universal mileage
threshold for maximum valve spacing without considering the
feasibility, practicability, and public safety benefits associated with
installing a valve at a particular location. Magellan Midstream
Partners L.P. specifically requested PHMSA consider valve spacing that
relies on operator programs providing for pipeline-specific evaluations
on optimization of valve spacing to reduce the magnitude of potential
releases within HCAs. Similarly, commenters representing the hazardous
liquid pipeline industry requested PHMSA provide a process for
operators to request alternative valve spacing distances for situations
where an operator determines the installation of additional valves
would not provide additional public safety or where installation is
otherwise infeasible.
API, AOPL, and GPA Midstream also suggested that PHMSA's proposal
for the maximum valve spacing for HVL pipelines was too stringent at 7
\1/2\ miles and that a 10-mile distance for valves on HVL pipelines
would better align PHMSA requirements with standards established in
Canada that would be more appropriate for pipelines in the United
States. API, AOPL, and GPA Midstream suggested that a 7 \1/2\-mile
spacing for HVL pipelines was appropriate only for those pipelines in
HCAs. Commenters also noted that the Canadian standard provides
operators with a 25 percent spacing flexibility when determining valve
locations, and the commenters recommended PHMSA provide a similar
allowance.
The PST expressed confusion regarding the NPRM language related to
RMV and alternative equivalent technology spacing, suggesting that
their interpretation of the proposed regulatory text would allow RMVs
and alternative equivalent technology to be spaced at distances greater
than the current valve spacing requirements at Sec. 192.179. By
contrast, their expectation is that PHMSA's intent is to require more
valves at closer spacing intervals than the current rules, or at most,
at the same spacing. The PST requested PHMSA clarify whether new valve
spacing requirements would be equal to or more stringent than currently
required.
At the GPAC meeting on July 22, 2020, the Committee unanimously
recommended that PHMSA specify that the spacing requirements in Sec.
192.634 apply to replacement projects covered by Sec. 192.179. At the
LPAC meeting on July 23, 2020, the Committee unanimously recommended
that PHMSA add a 25 percent tolerance to the spacing of HVL pipelines
and add a notification procedure to allow operators of hazardous liquid
pipelines to obtain relief from the valve spacing requirements on a
case-by-case basis.
(ii) Location
INGAA et al. noted that using an automated valve in a remote area
may create a comparatively higher reliability risk than using an
automated valve in a more populated area, noting that if a
communications failure, power loss, or other malfunction causes an
automated valve in a remote area to close unnecessarily, it may take
the operator hours to arrive at the valve and restore service, leading
to an extended loss of gas supply. They also stated that, in locations
where an operator employs an RCV to meet the proposed installation
requirement in a Class 1 or Class 2 location, it will take more time
for the operator to acquire information about a potential rupture event
in remote areas. Further, INGAA et al. stated that operators require
significant information about a potential rupture event before making
the critical decision to close an RCV, as closing a valve prematurely
can have the same disruptive impacts to customers as a rupture.
INGAA et al. also noted that limiting the RMV and alternative
equivalent technology installation requirements to pipelines in HCAs
and Class 3 and Class 4 locations would also improve the clarity of the
rulemaking, stating that the rule, as written, is confusing. INGAA et
al. suggested PHMSA revise Sec. 192.179 to clarify that Class 1 and
Class 2 locations outside of HCAs do not require RMVs or alternative
equivalent technologies to be installed unless the replacement project
involves a valve. INGAA et al. noted that this ``opportunistic
approach'' appears to have been PHMSA's intent in the proposal, and it
differed from their understanding of the rule's application to
replacement projects in HCAs and Class 3 and Class 4 locations. Other
commenters had similar suggestions and requested PHMSA revise cross-
references throughout the rule for clarity. Commenters representing
hazardous liquid pipeline operators made a similar comment pertaining
to the proposals for hazardous liquid pipelines.
API and AOPL also requested that PHMSA clarify the requirements for
the placement of valves near water crossings, recommending that PHMSA
base the valve spacing requirements on the size of a 100-year flood
plain.
Operators of both gas and hazardous liquid pipelines recommended
that PHMSA explicitly state that a shut-off segment must contain the
new or replaced HCA segment or Class 3 or Class 4 segment where RMVs or
alternative equivalent technologies are installed. Related to shut-off
segments, these operators also asked PHMSA to clarify whether
operational block valves would be permitted within a shut-off segment,
and if an RMV or alternative equivalent technology would need to be the
nearest valve to the shut-off segment. Some commenters noted that
requiring valves within the endpoints of certain segments might create
valve spacing more stringent than the current valve spacing
requirement. Further, INGAA et al. questioned if an RMV or alternative
equivalent technology is needed at the termination of a pipeline.
For hazardous liquid pipelines, several commenters requested PHMSA
clarify what a ``flood plain'' is for the purposes of valve spacing at
water crossings, with some commenters suggesting PHMSA specify
operators must use the 100-year flood plain. The PST requested PHMSA
clarify what

[[Page 20963]]

``flood conditions'' meant. Similarly, certain commenters, including
Magellan, requested that PHMSA remove the 1-mile limitation on water
crossings or provide for alternative spacing if that mile is within the
flood plain.
PHMSA also received comments requesting that it remove the proposed
requirement to locate valves within 7\1/2\ miles of the endpoint of an
HCA segment.
At the Committee meetings on July 22 and 23, 2020, the Committees
unanimously recommended that PHMSA:

(1) Clarify that replacement projects in non-HCA Class 1 and
Class 2 locations do not require RMVs or alternative equivalent
technology unless the replacement project involves a valve.
Throughout industry public comments, this was what was referred to
as the ``opportunistic approach.'' For hazardous liquid pipelines,
the LPAC recommended PHMSA revise the rule to clarify the same
concept for pipelines in non-HCA locations.
(2) Specify that proposed valve spacing requirements related to
pipeline replacements and RMV and alternative equivalent technology
installation requirements do not apply to pipelines in non-HCA Class
1 and Class 2 locations.
(3) Specify that a ``shut-off segment'' must contain the newly
constructed or replaced HCA or Class 3 or Class 4 pipeline segment.
(4) Specify that RMVs or alternative equivalent technology would
not be required at the downstream termination of a pipeline.
Further, specify that operational block valves are allowed within a
shut-off segment and RMVs and alternative equivalent technology need
not be the nearest valve to a shut-off segment.
(5) For hazardous liquid pipelines, specify the 100-year flood
plain at hazardous liquid pipeline water crossings.
3. PHMSA Response
(i) Spacing
PHMSA believes the valve spacing it proposed in the NPRM for both
gas and hazardous liquid pipelines is appropriate. For new gas pipeline
construction, spacing of RMVs and alternative equivalent technology
will follow existing requirements at Sec. 192.179(a) determining
distance by reference to class location: 2.5-mile intervals in Class 4
locations, 4-mile intervals in Class 3 locations, 7.5-mile intervals in
Class 2 locations, and 10-mile intervals in Class 1 locations. For
replacement projects on gas pipelines, PHMSA's experience with how
operators implement a ``one-class bump'' when a pipeline's class
location changes support the final rule's spacing approach. Per the
current requirements following a class location change, an operator can
base a pipeline's MAOP on a specified design factor multiplied by the
test pressure for the new class location as long as the corresponding
hoop stress does not exceed certain percentages of the SMYS of the pipe
and as long as the pipeline has been tested for a period of 8 hours or
longer in accordance with Sec. 192.611(a)(1). This approach has been
practical for operators where single-step class location changes occur.
Operators performing one-class bumps leave the existing infrastructure
in place, which means that, even though the class location has changed,
the design standards of the original pipeline are still being used. In
addition to wall thickness and steel strength, this applies to the
spacing of the valves along the segment as well. For example, operators
have been able to use Class 1 spacing standards for valves on a
pipeline segment that has changed from a Class 1 to a Class 2 if the
operator has followed the appropriate procedures in Sec. 192.611.
PHMSA is extending this same methodology to replacement RMV and
alternative equivalent technology spacing for gas pipelines by allowing
operators to use the maximum valve spacing of a class below the class
location of the replacement project. In practice, this means that
replacement projects requiring RMVs or alternative equivalent
technology in Class 4 locations can have RMVs or alternative equivalent
technology spaced at a maximum of 8 miles, replacement projects
requiring RMVs or alternative equivalent technology in Class 3
locations can have RMVs or alternative equivalent technology spaced at
a maximum of 15 miles, and replacement projects in Class 1 and Class 2
locations can have RMVs or alternative equivalent technology spaced at
a maximum of 20 miles. If the RMV or alternative equivalent technology
spacing is greater than the spacing for the next class location, a new
RMV or alternative equivalent technology is required. Going forward,
PHMSA will monitor data in these locations to ensure such spacing does
not create an undue risk to people or the environment.
According to PHMSA's data from 2015 to 2019, hazardous liquid
pipeline operators have constructed or replaced 4,708 miles of pipeline
that is 6 inches or greater in diameter, and they have installed a
total of 673 valves on that pipeline mileage for an average of 1 valve
for every 7 miles. Therefore, PHMSA does not believe it is onerous to
finalize minimum valve spacing standards at every 15 miles for pipeline
segments in, or which could affect, HCAs and at every 20 miles for
pipeline segments that could not affect HCAs. However, a hazardous
liquid pipeline operator may request an exemption from these
requirements if it can demonstrate to PHMSA in accordance with the
notification procedures in Sec. 195.18, that installing an RMV or
alternative equivalent technology as otherwise required by Sec.
195.260 would be economically, technically, or operationally infeasible
by reference to factors such as access to communications and power;
terrain; prohibitive cost; component and labor availability; ability to
secure access rights and necessary permits; and lack of accessibility
to operator personnel for installation and maintenance. That notice
must also include a safety evaluation of deviation from this final
rule's spacing requirements that references technical and safety
factors including, but not limited to, the following: Design,
construction, maintenance, and operating procedures for pertinent
pipeline segments; potential consequences to the environment and the
public from a rupture on the pertinent pipeline segments; and
mitigation measures (e.g., operating times for isolation valves) in the
event of a rupture.
Concerning the proposed spacing for HVL pipeline segments, PHMSA
based the valve spacing requirements on the recommended spacing in
American Society of Mechanical Engineers (ASME) B31.4, ``Pipeline
Transportation Systems for Liquids and Slurries,'' an industry standard
that has existed for many decades. PHMSA does not believe that
permitting broad tolerance from the HVL valve spacing requirements in a
manner similar to the Canadian standard commenters referenced is
appropriate, as PHMSA prescribed this valve spacing standard only in
high-population areas or other populated areas as defined by Sec.
195.450 where there would be significant populations in need of
additional protection. However, in accordance with the LPAC
recommendation, PHMSA has provided in this final rule a method for
operators to request (in accordance with Sec. 195.18 and subject to
PHMSA review) an increase, by 25 percent, of the maximum valve spacing
intervals for HVL pipeline segments in high-population areas or other
populated areas should the installation of a valve at a particular
location not be economically, technically or operationally feasible.
Operators would, in connection with that notice, submit a safety
evaluation referencing technical and safety factors including, but not
limited to, the following: Design, construction, maintenance, and
operating procedures

[[Page 20964]]

for pertinent pipeline segments; potential consequences to the
environment and the public from a rupture on the pertinent pipeline
segments; and mitigation measures in the event of a rupture. If PHMSA
grants the request, the operator is required to keep the records
necessary to support such a determination for the useful life of the
pipeline.
PHMSA considered the comments regarding the clarity of the proposed
valve spacing regulations and the interplay of the various sections of
the NPRM when drafting this final rule. PHMSA attempted to simplify the
regulatory text by dividing the RMV sections into installation
requirements and performance requirements. PHMSA also attempted to
consolidate notification requirements broadly by establishing a
notification section in part 195, similar to that established in part
192 in the 2019 Gas Transmission Final Rule, and cross-referencing to
these sections whenever a notification might be required in the
regulations. In addition to reducing the amount of regulatory text,
these sections also provide for a more consistent notification process
across the regulated community.
(ii) Location
PHMSA notes that the proposed RMV and alternative equivalent
technology requirements for gas pipelines in Class 1 and Class 2
locations were intended to apply only to new construction and those
replacement projects where 2 or more miles were being replaced and
which involved a valve. This was unlike the proposed requirements for
gas pipe replacements in excess of 2 miles in HCAs and Class 3 and
Class 4 locations, which, as proposed, would have needed upstream and
downstream RMVs or alternative equivalent technology regardless of
whether the project impacted an existing valve. Therefore, PHMSA is
clarifying in this final rule that operators are to take the
``opportunistic'' approach suggested in the comments and are required
to install RMVs or alternative equivalent technology during pipe
replacement projects in non-HCA Class 1 or Class 2 areas only if the
replacement project involves the addition, replacement, or removal of a
valve. As previously discussed, this requirement does not apply to
those Class 1 or Class 2 locations that have a PIR of 150 feet or less.
For hazardous liquid pipelines, the same approach applies to those
replacements in non-HCA locations.
Commenters questioned whether a newly constructed or entirely
replaced pipeline segment in an HCA was supposed to be included within
a shut-off segment for the purposes of the NPRM. PHMSA intended the
shut-off segment to include the entire new or replaced pipeline segment
in (or, for hazardous liquid lines, which could affect) an HCA and has
clarified that intent in the regulatory text of this final rule by
stating so explicitly in Sec. Sec. 192.634 and 195.418. Similarly,
some commenters from the hazardous liquid pipeline industry also
questioned whether requiring an RMV or alternative equivalent
technology within 7\1/2\ miles of the endpoint of a hazardous liquid
pipeline segment in or which could affect an HCA would ultimately
reduce the existing valve spacing. PHMSA did not intend for such a
measure to reduce valve spacing and determined that the requirement is
duplicative of similar preventative and mitigative requirements set
forth in Sec. 195.452. As such, PHMSA has determined that the proposed
requirement may have been unnecessary and has deleted it from this
final rule.
INGAA et al. also requested PHMSA clarify whether an RMV or
alternative equivalent technology is needed at the termination of a
pipeline. Per this final rule, an RMV or alternative equivalent
technology is needed at the termination of a pipeline, and PHMSA is
clarifying that an operator may use a manual compressor station valve
at a continuously manned station as an alternative equivalent
technology; PHMSA understands that the logical termination of a
pipeline might be within a station, and a valve there could also be
used as an RMV or alternative equivalent technology to help isolate a
rupture on the pipeline system. Such a valve used as an alternative
equivalent technology would not require an advance notification to
PHMSA pursuant to Sec. Sec. 192.18 or 195.18, but, as with any
alternative equivalent technology, it must be able to be closed as soon
as is practicable and absolutely within 30 minutes after the rupture
identification and comply with the applicable provisions of this final
rule.
Further, PHMSA also received questions regarding whether
operational block valves are permitted within a shut-off segment and
whether an RMV or alternative equivalent technology needs to be the
nearest valve to the shut-off segment. In the NPRM, PHMSA stated that
``all valves in a shut-off segment'' needed to be RMVs or alternative
equivalent technology. However, it was PHMSA's intent that operational
block valves be allowed within a shut-off segment as long as the RMV or
alternative equivalent technology is within the valve spacing
requirements. As such, PHMSA has removed that phrase from this final
rule; the section now states the requirements for installing RMVs or
alternative equivalent technologies, and it leaves open the possibility
that an operator can install additional block valves on a shut-off
segment between compliant and appropriately spaced RMVs or alternative
equivalent technologies. PHMSA is also clarifying in this final rule
that RMVs or alternative equivalent technologies do not need to be the
nearest valve to the shut-off segment, and has specifically stated this
in the RMV and alternative equivalent technology installation sections
at Sec. Sec. 192.634 and 195.418.
Regarding comments about the installation of RMVs or alternative
equivalent technologies near river crossings and flood plains, PHMSA
notes that, based on the comments it received, it has made explicit in
this final rule that such valves must be installed outside of the 100-
year flood plain of the body or bodies of water, or the valves must
have actuators and other control equipment installed so as to not be
impacted by flood conditions, or the equipment might be elevated to a
level where they will not be impacted by flood conditions. PHMSA
considers ``flood conditions'' to be where water is at a high enough
level near the valve so that it, or the related electronics, would not
operate. Flood conditions also can include debris carried by
floodwaters that could affect the equipment. For multiple water
crossings, PHMSA structured the proposed requirements to provide
operators the flexibility to install valves near sites where there are
multiple water crossings and where there might be potential access
issues between water crossings. This mechanism is consistent with
approvals PHMSA has granted operators under the existing authority and
process at Sec. 195.260. In this final rule, PHMSA is requiring
operators to locate valves upstream and downstream of the first and
last of multiple water crossings so that the total distance between the
upstream-most valve and the downstream-most valve does not exceed 1
mile, rather than requiring an operator to install RMVs or alternative
equivalent technologies on either side of each water crossing where
there are multiple water crossings.

G. Valve Status Monitoring

1. Summary of Proposal
In the NPRM, PHMSA proposed to require operators to monitor or
otherwise control RMVs or alternative equivalent technologies using
remote or

[[Page 20965]]

on-site personnel. This monitoring or control would include the valve
status, the upstream and downstream product pressures, and product flow
rates during normal, abnormal, and emergency operations. PHMSA also
proposed to require operators be able to monitor the status of valves
during rupture events.
2. Comments Received
Several commenters, including INGAA et al., questioned whether
remote monitoring of ASVs was required, as those valves would be set to
respond automatically to rupture events and not require additional
input.
INGAA et al. also requested that PHMSA allow operators to monitor
pressure or flow rates in lieu of valve status if they were unable to
monitor valve status. PHMSA was also asked to clarify whether operators
would need to monitor remotely the flows and pressures through manually
operated RMVs after they close. Further, PHMSA was also asked to
remove, on efficiency grounds, the proposed requirement for operators
to station personnel at a manually operated RMV site for continuous
monitoring.
At the Committee meetings on July 22 and 23, 2020, the Committees
unanimously recommended that PHMSA specify that an operator does not
need to monitor ASV status if the operator can monitor pressures or
flows in the pipeline segment to be able to identify and locate a
rupture. This differed from the proposed language in that, as worded,
an operator would have been required to monitor ASV status in addition
to pressures and flows. The Committees also unanimously recommended
PHMSA provide a similar allowance for manual valves.
3. PHMSA Response
PHMSA maintains that an operator's ability to monitor the upstream
and downstream pressures around RMVs and alternative equivalent
technologies is important to identify ruptures effectively and mitigate
incidents. As such, PHMSA expects all valves installed as RMVs and as
alternative equivalent technologies to monitor pressures upstream and
downstream of those valves at all times. However, if operators can
monitor upstream and downstream pressures around manual valves that are
being used as alternative equivalent technologies or ASVs in real-time
so that they can identify and locate a rupture, operators do not need
to station personnel at a site where a manually operated alternative
equivalent technology has been installed or continually monitor ASV
status. In accordance with the Committee recommendations on this issue,
PHMSA has specified in this final rule that, if an operator can
remotely monitor either pressures or flows in real-time at an ASV or a
manual shut-off valve such that they can identify and locate a rupture,
the operator does not need to monitor valve status continually, nor are
operators required to monitor the pressures on manual valves being used
as alternative equivalent technology once those valves are closed in
response to a rupture.

H. Class Location Changes

1. Summary of Proposal

[…truncated; see source link]

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