[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 [www.gpo.gov]
[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
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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), https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1201.pdf.
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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), https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1101.pdf.
\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), https://www.cpuc.ca.gov/uploadedFiles/CPUC_Public_website/Content/Safety/Natural_Gas_Pipeline/News/AgendaStaffReportreOIIPGESanBruno 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; 8 9 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), https://www.gao.gov/assets/660/651408.pdf. 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),
https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16701/finalvalvestudy.pdf.
\9\ Kiefner and Associates, Inc., Report No. 12-173, ``Leak
Detection Study--DTPH56-11-D-000001'' (Dec. 10, 2012), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16691/leak-detection-study.pdf.
\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
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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
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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), https://www7.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/news/70826/report-congress-shipping-crude-oil-truck-rail-and-pipeline-32019.pdf.
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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), https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR9501.pdf.
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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
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install ASVs or RCVs in HCAs and Class 3 and 4 locations, with the
valve spacing based on risk analysis.
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\18\ See supra note 3.
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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.
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\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.
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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.
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\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).
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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.
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\23\ A break in the pipeline that involves the opening of the
pipe in either the circumferential or longitudinal direction.
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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\
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\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), 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/.
\29\ White House, ``U.S. Methane Emissions Reduction Action
Plan'' at 7 (Nov. 2021), https://www.whitehouse.gov/wp-content/uploads/2021/11/US-Methane-Emissions-Reduction-Action-Plan-1.pdf.
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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.
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\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.
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\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\
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\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.
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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.
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\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.
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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\
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\36\ Including pressure, temperature, meter flow, product
characteristics, and geometry of the pipeline.
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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\
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\37\ See Homendy, ``San Bruno Victims and Their Families Deserve
Long-Overdue Action'' (Sept. 9, 2020), https://safetycompass.wordpress.com/category/infrastructure/ (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), https://www.ntsb.gov/safety/safety-studies/Documents/PSS7101.pdf).
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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.
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\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.
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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\
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\40\ 73 FR 62147 (Oct. 17, 2008).
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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
In the NPRM, PHMSA proposed to clarify the valve spacing
requirements of Sec. 192.179 and to apply the RMV and alternative
equivalent technology installation requirement and rupture-mitigation
requirements to pipelines where segments of pipe (of any length) were
replaced to meet MAOP requirements following a class location change.
As proposed, operators would need to install necessary RMVs or
alternative equivalent technology within 24 months of the class
location change.
2. Comments Received
INGAA et al., GPA Midstream, and the KOGA, expressed concern over
the proposed Sec. 192.610 requirements and recommended revisions to
the rule language. INGAA et al. indicated that class location change
pipe replacements produce minimal pipeline safety benefits because they
involve less than 75 miles of transmission pipe per year, and the
replaced pipe is often in safe, operable condition.
GPA Midstream called for PHMSA to establish specific valve
installation requirements for class-location-related pipeline
replacements. They claimed that under PHMSA's interpretation of the
current regulations at Sec. Sec. 192.13(b) and 192.179, operators must
comply with valve installation requirements for new pipelines if a
segment is replaced in response to a class location change; but that
this is contrary to the original intent of the regulations, imposes
unreasonable compliance burdens, and discourages pipeline replacements.
INGAA et al. noted that, because the vast majority of class change
pipe replacements are less than 2 miles in length, the proposed Sec.
192.610 would require the installation of at least one manual valve for
many pipe replacements where the class location changes from a Class 1
to a Class 3. INGAA et al. estimated that it costs $600,000 to $800,000
for an operator to install a new manual valve on an existing pipeline
ranging from 24 to 36 inches in diameter, and therefore, the annual
cost for installing manual valves under this proposed provision could
exceed $100 million per year. Therefore, INGAA et al. suggested that,
for class location change pipe replacements that involve less than 2
contiguous miles of pipe but more than 2,000 feet of pipe, PHMSA should
provide operators the option to automate an existing upstream and
downstream valve so that the distance between such automated valves
would not exceed 20 miles, which is the current spacing requirements
for valves on pipelines in Class 1 locations. INGAA et al. stated that
this would be consistent with the approach that PHMSA has proposed for
replacements greater than or equal to 2 contiguous miles in Class 1 and
Class 2 locations that are also HCAs. They further stated that
retaining the valve spacing requirements for Class 1 locations is
appropriate for class location change pipe replacements that do not
meet the 2-mile ``entirely replaced'' definition and will mitigate the
need to install a new valve for most class location change pipe
replacements.
Similarly, other industry commenters, including GPA Midstream and
TC Energy Corporation, stated that PHMSA should exclude short pipe
replacements from proposed Sec. 192.610, noting that when an operator
is removing a short section of pipe, there may not be an appropriate
location in that short area to install a new valve, which can make
complying with the valve spacing provisions impractical. Further, these
commenters suggested that operators frequently replace short sections
of existing pipe to repair potentially injurious conditions found to be
affecting that pipe. They stated that many of these maintenance
replacements are not ``pipe replacement projects,'' generally only
affect small sections of the pipeline, and in some cases, must be
conducted immediately to ensure public safety. They argue that
operators must be reasonably able to repair such pipeline defects
without installing additional valves, stating that requiring all pipe
replacements, no matter how small, to comply with valve spacing
requirements applicable to new pipe construction would increase cost
and regulatory complexity and may reduce an operator's incentive or
ability to complete voluntary assessments and remediation. As such,
PHMSA was asked to exclude pipe replacements that were less than 2,000
feet from the RMV and alternative equivalent technology installation
requirements.
AFPM stated that the requirement to update and install the required
valves to match the class location requirements
[[Page 20966]]
within 24 months of the class location change may not be feasible in
all circumstances due to factors outside the control of the operator,
such as local permitting. AFPM also suggested that PHMSA should
incorporate a process to account for such uncontrollable delays.
At the GPAC meeting on July 22, 2020, the GPAC unanimously
recommended that PHMSA specify that the valve spacing in Sec. 192.634
would, pursuant to Sec. 192.610, be applicable to class location
changes resulting in the replacement of an aggregate of 2 or more miles
of pipe within any 5 contiguous miles, and consider implementing a
timeframe of 24 months for compliance from the change in class
location. Following discussion of the potential that high installation
costs from application of valve spacing requirements to replacement of
smaller pipeline segments may discourage pipeline replacement projects,
the GPAC also unanimously recommended PHMSA exclude pipeline
replacements less than 1,000 feet within 1 contiguous mile from the
valve installation requirements. Finally, the Committee unanimously
recommended (after discussion of the costs and practical difficulties
associated with obtaining land rights necessary to install RMVs on
pipelines on segments less than 2 miles in length) that, for pipeline
replacements due to class location changes that are between 1,000 feet
and 2 miles, PHMSA should allow operators to automate the existing
valves with automatic or remote-control actuators and pressure sensors,
with a maximum spacing of 20 miles, which they asserted would be
consistent with the operational capability proposed in Sec. 192.634.
3. PHMSA Response
PHMSA intended for the RMV and alternative equivalent technology
requirements, including those for valve spacing proposed in Sec.
192.634, to be applicable to class location changes for cases where the
operator chose to replace pipe to meet the MAOP requirements of the new
class location. The proposal was attempting to clarify that, in the
event of pipe replacement due to a class location change, operators
must install valves that comply with the existing valve spacing
requirements at Sec. 192.179(a) for the new class location.\44\
---------------------------------------------------------------------------
\44\ In the Matter of Viking Gas Transmission, Final Order,
C.P.F. No. 32102 (May 1, 1998).
---------------------------------------------------------------------------
In addition to finalizing that proposal in this final rule for
class location-based pipeline replacements of 2 or more miles within
any 5 contiguous miles over a 24-month period, PHMSA is also allowing
operators to comply with this section by installing or using existing
RMVs when a class location changes (i.e., from Class 1 to a Class 2 or
a Class 2 to a Class 3) so that the distance between RMVs does not
exceed 20 miles. This allowance considers several public comments in
addition to a corresponding discussion and recommendation from the
GPAC. INGAA et al. noted that the NPRM seemed to require the
installation of manual valves on pipelines where the class location had
changed. However, this was not PHMSA's intent. The automation of
existing valves to protect a pipeline segment where the class location
has changed is to provide a higher measure of public and environmental
safety than the installation of additional manual valves, given that
automated valves will be able to be closed more quickly than manual
valves in the event of an emergency.
PHMSA acknowledges that there may be instances where the RMV and
alternative equivalent technology installation requirements might not
be appropriate for very short sections of pipe that are being replaced
under Sec. 192.610. As such, PHMSA is providing in this final rule an
exception from the RMV and alternative equivalent technology
installation requirements for short pipeline replacements that are less
than 1,000 feet in length within 1 contiguous mile. For pipe
replacements that occur when class locations change and that range from
1,000 feet to 2 miles in length, PHMSA believes that operators could
automate existing valves with RCV or ASV technologies and corresponding
pressure sensors that would be consistent with the operational
requirements and valve spacing requirements of proposed Sec. 192.634.
As discussed in the paragraph above, PHMSA has modified this final rule
accordingly.
I. Valve Maintenance
1. Summary of Proposal
In the NPRM, PHMSA proposed to revise Sec. Sec. 192.745 and
195.420 to require operators perform inspections, maintenance, and
drills on RMVs to ensure that they can be closed as soon as practicable
but within 40 minutes of identifying a rupture. Among other
requirements, PHMSA proposed operators perform point-to-point
verification tests for RMVs that are ASVs or RCVs and perform initial
validation drills and periodic confirmation drills for manual or
locally operated valves an operator identified as RMVs. PHMSA also
proposed that operators would be required to identify corrective
actions and lessons learned from the validation and confirmation drills
and share and implement those lessons learned throughout their pipeline
systems. As proposed, operators would be required to repair or
remediate inoperable valves within 6 months following a failed drill,
with the operator designating a temporary alternate compliant valve
within 7 days of a failed drill.
2. Comments Received
Some commenters, including INGAA et al., stated PHMSA should remove
the proposed requirement for point-to-point testing because it is
already required under the control room management requirements in
Sec. Sec. 192.631 and 195.446. This comment applied to the proposed
regulations for both gas and hazardous liquid pipelines.
Operators requested that PHMSA clarify that annual drills are not
required for every manual valve and that the drills for ``locally-
actuated'' valves would exclude ASVs and RCVs. Further, commenters
indicated that PHMSA should provide more specificity regarding the
random drill selection process.
INGAA et al. commented that PHMSA should clarify that operators are
not required to fully close manual or locally actuated valves during
drills. TPA and AFPM expressed this same concern, with AFPM stating
that such a requirement might cause significant disruptions when the
applicable pipeline is the primary source of feedstock for a major
manufacturing facility. INGAA et al. suggested PHMSA allow operators to
perform tabletop drills to meet the drill response time requirement.
The Clean Air Council stated that the final rule should include
provisions for pipeline operators to perform regular drills to ensure
they can comply with the rupture response regulations, test the
performance of their equipment, and ensure that pipeline personnel will
be trained and skilled in responding to an emergency properly. They
noted that while ASVs and RCVs will cut the response time down in a
rupture event, having trained operating personnel is also important,
stating that PHMSA should include provisions wherein a key responsible
individual within the company is identified whose responsibility it is
to train new personnel on the rupture response procedures within a
certain period of new personnel being hired. They stated that PHMSA
should require operators to report on how such training would be
conducted and in what period the new individuals are trained, noting
that this
[[Page 20967]]
would create accountability for an otherwise unknown factor in pipeline
management that would decrease the likelihood that operators may fail
in carrying out rupture response procedures in a timely manner. They
also noted that with adding in electrical connections and cellular
communications with new valves, additional maintenance schedules and
procedures will need to be developed for this added complexity.
Similarly, the PST supported the proposed requirements for testing,
maintenance, drills, and the incorporation of lessons learned into
operator procedures.
INGAA et al. stated that PHMSA should reconsider the proposed
maintenance requirements for when an RMV or alternative equivalent
technology installed under the final rule is unable to achieve the
proposed performance standard. Specifically, they suggested PHMSA
should revise the NPRM by providing operators 12 months to repair,
replace, or install new RMVs when an RMV or alternative equivalent
technology is not operating correctly or otherwise cannot achieve the
40-minute response time requirements. This concern was echoed by other
industry commenters, who suggested various compliance timeframes. INGAA
et al. also stated that PHMSA should allow a notification process when
it would not be practicable for an operator to repair or replace an RMV
or alternative equivalent technology within 12 months.
GPA Midstream noted that operators should be required to make
repairs or replacements as soon as practicable but no later than the
time provided in their procedures for conducting operations,
maintenance, and emergency activities. GPA Midstream also stated that a
7-day timeframe may not be sufficient to locate and designate an
alternative valve to serve as a substitute for a damaged or otherwise
inoperable RMV or alternative equivalent technology. They requested
that PHMSA revise the provision to allow 14 days for designating an
alternative compliant valve. This concern was echoed by individual
operators, who suggested different compliance periods for implementing
alternative valve measures.
Other commenters also noted that the proposed 6 months for
implementing alternate shut-off valve measures is inadequate because it
fails to account for right-of-way acquisition, the time needed to
obtain necessary environmental clearance and permits, and extended lead
times for the procurement of transmission valves. More specifically, TC
Energy requested that PHMSA clarify what is meant by ``alternative
compliant valve,'' noting that, because of the proposed 6-month
compliance deadline for completing maintenance or replacing a RMV or
alternative equivalent technology, it is apparent that ``compliant'' is
not intended to refer to proximity or spacing or whether a designated
``alternative valve'' is automated or is manual. TC Energy suggested
that PHMSA should direct operators to designate an alternative shut-off
valve and document an interim response plan until the primary RMV or
alternative equivalent technology is repaired or replaced.
API/AOPL and GPA Midstream also suggested that PHMSA should revise
the maintenance procedures to allow operators to obtain an authorized
alternative response time.
At the Committee meetings on July 22 and 23, 2020, the Committees
unanimously recommended that PHMSA delete the requirement for point-to-
point testing because it duplicates requirements in the existing
control room management regulations in both parts 192 and 195.
Regarding the drill requirements, the Committees unanimously
recommended that PHMSA clarify that annual drills apply only to
manually operated valves and involve the manual operation of a local
actuator or by hand, and not to ASVs or RCVs. Further, the Committees
unanimously recommended specifying that a 25 percent valve closure is
sufficient to demonstrate the successful completion of the response
time validation drill for manually operated valves.
The Committees also unanimously recommended PHMSA provide operators
with a notification process to justify a need to extend the timeframes
for repair and establishing alternate RMVs, if necessary. Further, the
Committees unanimously recommended PHMSA consider adjusting the
timeframe for repairs to 12 months but as soon as practicable, rather
than the proposed 6 months. Certain members of the Committees
representing the public (including Pipeline Safety Trust) expressed a
preference to keep the timeframe for repairs at 6 months. However,
other members of the Committees representing industry (including
Enbridge, Williams, Consumers Energy, Marathon Pipeline, and PECO)
noted that 12 months might be more appropriate given difficulties with
supplier access to inventory and procurement issues. Additionally, the
Committees unanimously recommended that PHMSA specify that alternative
compliant valves identified through this process would not be required
to comply with the valve spacing requirements for RMVs.
3. PHMSA Response
PHMSA acknowledges that the proposed point-to-point testing
requirements were already a part of the control room management
regulations at Sec. Sec. 192.631 and 195.446. However, PHMSA believes
restating the provision in the valve maintenance requirements will
provide additional clarity and will improve compliance and
enforceability. Therefore, PHMSA has chosen to retain the language in
this final rule.
Regarding the proposed manual valve drill requirements, PHMSA
intended the annual drills to apply to manually operated valves used as
alternative equivalent technology only, and not ASVs or RCVs. PHMSA
expects such a drill would include the manual operation of a local
actuator or closing the valve via a hand-wheel. PHMSA confirms that
annual drills are not required for every manual valve. Rather, an
annual drill is required for one randomly selected manual valve in each
of the operator's field work units. The way that an operator determines
which manual valves would be randomly selected is at the discretion of
the operator, but the selection method must be included in an
operator's written procedures so it can be subject to inspection.
PHMSA has determined that full closure of valves is not necessary
for the purposes of the valve maintenance requirements of this final
rule. Accordingly, PHMSA has revised the provision to require, at a
minimum, a 25 percent closure of the valve. PHMSA recognizes that
overcoming inertia is likely to be the most difficult work in getting a
valve to operate. Therefore, PHMSA has determined that a 25 percent or
more closure is sufficient to demonstrate the valve's operability and
functionality while allowing pipeline operators to maintain service
without major interruptions.
Additionally, in this final rule, PHMSA is not allowing operators
to perform tabletop drills to verify response times for manually
operated valves. PHMSA believes that a tabletop drill would not be
sufficient for ensuring that the valve is working, which is the intent
of the provision. Operators need to ensure that manual valves being
used as an alternative equivalent technology for the purposes of this
rulemaking can be arrived at and physically operated so that they
function as intended, achieving full closure within the maximum valve-
closure time of this rulemaking. A paper exercise cannot effectively
confirm real-
[[Page 20968]]
time travel time to a valve location or the time it will take operator
personnel to close a particular valve manually, given conditions that
could occur during a rupture.
Regarding the measures operators must take after a failed drill,
PHMSA believes that a 7-day timeframe for identifying alternative shut-
off measures and a 6-month timeframe for valve repair are appropriate.
Because the purpose of an RMV or alternative equivalent technology is
to mitigate the consequences of a rupture, should one occur, the longer
a valve stays non-functional or the longer it takes an operator to
identify alternative measures increases the potential rupture
consequences to the area near the impacted pipeline segment. In light
of the comments and Committee recommendations for extending the repair
period to 12 months given the likely delays involved in scoping and
executing required repairs, PHMSA understands that there operators may
need repair timeframes longer those identified in the NPRM; PHMSA has,
therefore, extended the repair period to 12 months. PHMSA has also
provided an advance notification process in this final rule for
operators to request (before the repair is undertaken) an extension of
that 12-month repair period by demonstrating to PHMSA that repair
according to the final rule's timeline will be economically,
technically, or operationally infeasible (e.g., by reference to
prohibitive costs, difficulty in securing required access rights and
permits, long procurement lead times, and component/labor
availability). However, PHMSA declines to offer a similar notification
process in connection with identification of alternative shut-off
measures following a failed drill, as prompt identification of those
alternatives are essential for ensuring that the public and the
environment are not unprotected from a rupture for extended periods of
time.
PHMSA did not intend that any valves operators would identify as an
alternative compliant RMV or equivalent technology based on a failed
drill would need to comply with the valve spacing requirements of the
rulemaking, and PHMSA is not requiring that in this final rule. PHMSA
is requiring, however, that any alternative compliant RMV or equivalent
technology would contain the entire shut-off segment and comply with
the 30-minute valve closure standard of this rulemaking.
Some commenters requested PHMSA enhance the proposed maintenance
and drill requirements to cover valve-related specialized equipment and
periodic personnel training and management programs. PHMSA notes that
these requirements are already included in the Federal Pipeline Safety
Regulations, including under the operator qualification and control
room management regulations.
J. Failure Investigations
1. Summary of Proposal
In the NPRM, PHMSA proposed to revise the regulations applicable to
gas and hazardous liquid pipelines to define the elements that an
operator must incorporate when conducting analyses of incidents and
other releases and failures involving the activation of RMVs and
alternative equivalent technologies, namely ruptures.
The proposed revisions would require the operator to identify
potential P&M measures that could be taken to reduce or limit the
release volume and damage from similar events in the future. The post-
incident or -failure review would address factors associated with this
rulemaking, including but not limited to detection and mitigation
actions, response time, valve location, valve actuation, and SCADA
system performance. Upon completing the post-incident or -failure
analysis, the operator would be required to develop and implement the
lessons learned throughout its suite of procedures, including in
pertinent operator personnel training and qualification programs, and
in design, construction, testing, maintenance, operations, and
emergency procedure manuals and specifications.
2. Comments Received
INGAA et al. stated that PHMSA should remove the references to
``failures'' in Sec. 192.617, as ``failure'' is not defined in parts
191 or 192, and it is unclear if the section accounts for abnormal
operations that do not result in a rupture. Similar comments were made
by representatives of hazardous liquid pipeline operators, requesting
that ``failure'' be changed to ``accident'' to be more consistent with
the part 195 regulations.
INGAA et al. added that the prescriptive post-incident requirements
proposed in Sec. 192.617 are fit-for-purpose following a rupture but
are unnecessary and overly burdensome following an abnormal operation.
Other commenters from industry noted that the investigation
requirements seemed to be duplicative of existing accident and incident
reporting requirements and suggested that PHMSA remove the proposed
investigation requirements from the final rule.
GPA Midstream stated that the proposal for operators to prepare and
follow procedures for conducting failure and incident investigations
should be stated in a new, separate paragraph, and the proposed
requirement to incorporate any lessons learned into appropriate part
192 procedures can be consolidated in another paragraph. They further
stated that PHMSA could eliminate the other additional language
proposed in the section (including sending the failed pipe, component,
or equipment to a laboratory for testing), because it is unnecessary.
Similarly, Magellan Midstream Partners, L.P., as well as other industry
commenters, suggested that PHMSA should remove the proposed
requirements for failure analysis because it is not appropriate or
effective for an operator to send all failed pipe, components, or
equipment for laboratory testing and examination. Further, several of
these industry commenters requested PHMSA specify that the
implementation of any lessons learned and any additional P&M measures
following an incident would be required only if they are reasonable and
practicable.
INGAA et al. and GPA Midstream stated that the proposed
documentation and recordkeeping requirements for failure investigations
are unnecessary, with INGAA et al. stating that the requirements appear
to be duplicative of requirements currently under PHMSA's incident
reporting requirements. GPA Midstream stated that, to avoid imposing
undue burdens on pipeline operators, the senior executive review and
lifetime recordkeeping requirements PHMSA proposed should only apply to
the final analysis prepared at the conclusion of the investigation
rather than preliminary analyses. GPA Midstream and API/AOPL commented
that such a requirement would create an additional recordkeeping burden
without improving safety, with API requesting PHMSA delete the proposed
requirement. AFPM provided similar comments.
The PST stated that PHMSA should amend Sec. 192.617(c) to require
that the results of an operator's post-incident review be incorporated
into operators' procedures, not just read and kept, as it appears to be
proposed. INGAA et al. stated that they support the incorporation of
post-incident lessons learned as an important aspect of pipeline safety
management systems. However, INGAA et al. added there may be some
circumstances where an incident investigation would not yield a change
to procedures, for example, some third-party damage incidents, and
PHMSA should require operators to
[[Page 20969]]
incorporate lessons learned and P&M measures only if appropriate and
practicable following an incident investigation. TPA generally echoed
these remarks.
Further, INGAA et al. stated that they support distribution
operators incorporating post-incident lessons learned into their
procedures even though the rule stated it only applies to gas
transmission and hazardous liquid pipelines, but they recommended PHMSA
clarify that the requirements in Sec. 192.617(c) only apply to
transmission lines, since the broad definition of ``rupture'' in Sec.
192.3 could lead to Sec. 192.617(c) being interpreted to apply to both
gas distribution and gas transmission pipeline incidents.
PST stated that, although the NPRM proposes operators incorporate
post-incident lessons into their procedures, the paragraph relating to
rupture and valve shut-off incident reviews does not include that same
requirement. They added that the section should be amended to include a
requirement that the results of the post-incident reviews be
incorporated into operator's procedures, not just read and kept.
At the Committee meetings on July 22 and 23, 2020, the Committees
unanimously recommended that PHMSA clarify that the implementation of
lessons learned and additional P&M measures after incidents are
required only where they are found to be reasonable and practicable.
Additionally, the GPAC unanimously recommended that PHMSA specify that
general failure investigations under these sections would apply to gas
distribution pipelines; however, failure investigations specific to
RMVs would not apply to gas distribution pipelines.
3. PHMSA Response
PHMSA acknowledges the comments stating that it should clarify the
terminology of its proposed regulatory amendments by using defined
terms, such as removing the use of the term ``failure'' in favor of
``incident'' or ``accident.'' However, PHMSA notes that existing
regulations at Sec. 192.617 address the investigation of failures on
gas lines, which is broader than reportable incidents. Similarly, the
term ``failure'' is used throughout parts 192 and 195 of the Federal
Pipeline Safety Regulations. Therefore, PHMSA has made no changes in
this final rule to the phrasing as it was originally proposed in the
NPRM, since the term ``failure'' is currently used throughout its
regulations.
Other commenters suggested that the failure investigation
requirements would duplicate existing incident/accident reporting
requirements. PHMSA does not consider the failure investigation
requirements that were proposed and the existing incident/accident
reporting requirements to be duplicative, as the proposed failure
investigation requirements were intended to build on existing failure/
accident investigation requirements for gas and hazardous liquid
pipelines, and provide more thorough technical evaluation of valve
functionality and performance during the mitigation of an incident or
accident. PHMSA intended for operators to investigate ``failures,'' as
that term is used throughout parts 192 and 195 of its regulations, and
as it is defined in ASME B31.8S and ASME B31.4. PHMSA has, however,
revised the regulatory text in in this final rule to better convey that
intent.
Similarly, some industry commenters, including Magellan, opposed
certain requirements in this section, especially with respect to
operators sending failed pipe, components, or equipment for laboratory
testing and examination. With respect to gas pipelines in particular,
PHMSA provides in this final rule additional specificity to the
existing regulation at Sec. 192.617, which states that ``each operator
shall establish procedures for analyzing accidents and failures,
including the selection of samples of the failed facility or equipment
for laboratory examination, where appropriate [. . .].'' The underlying
requirement remained unchanged, and PHMSA has finalized the clarifying
changes proposed in the NPRM in a way that will improve the ability to
identify and respond to safety issues that could be revealed in such
testing and examinations. PHMSA believes that regulatory language in
this final rule providing for parallel obligations for hazardous liquid
pipelines are similarly essential to its continuing regulatory
oversight of the safety of those pipelines.
As for the scope of the proposed failure investigation requirements
for gas pipelines, because PHMSA included the amendments in the
existing regulations at Sec. 192.617(a) and (b), PHMSA intended those
proposed requirements to apply to distribution pipelines, which were
already subject to the existing requirements of that section. Because
proposed paragraphs (c) and (d) of that section addressed failure
investigations specific to the closure of RMVs or alternative
equivalent technologies, however, and RMVs or alternative equivalent
technologies were and are not required for gas distribution systems in
this rulemaking, operators of gas distribution pipelines are not
required to comply with those paragraphs as a result of this rule.
INGAA et al. requested PHMSA clarify that the implementation of any
post-incident lessons-learned and any additional P&M measures be
required only where they are reasonable and practical. PHMSA would not
expect operators to implement P&M measures that were clearly
unreasonable or impractical. Regarding those measures, PHMSA did not
intend to cause any confusion with similar IM requirements by
referencing a term that is primarily used in the IM regulations.
Subsequently, in this final rule, PHMSA has changed this phrase from
``P&M measures'' to a more general phrase of ``operations and
maintenance'' measures to avoid confusion with separate IM-related
requirements.
Several comments were submitted regarding senior executive
involvement for the certification of failure investigations. PHMSA
believes that senior executive certification is essential to ensuring a
failure investigation's quality and highlighting the importance of the
investigation results and their implementation into operations.
K. 9-1-1 Notification Requirements
1. Summary of Proposal
In the NPRM, PHMSA proposed requirements related to operators
responding to pipeline ``emergencies'' that built on existing
regulations at Sec. Sec. 192.615 and 195.402. Specifically, PHMSA
proposed to require that an operator's emergency procedures provide for
rupture mitigation in response to a rupture event, and that operators
contact and maintain liaison with the appropriate public safety
answering point (9-1-1 emergency call center) in the event an
operator's pipeline ruptures.
2. Comments Received
NAPSR stated that the term ``emergency'' is not defined within part
192, noting that, without a definition for ``emergency,'' operators may
make unnecessary notifications to the appropriate fire, police, and
public officials, and force responses to minor events instead of real
emergencies. NAPSR suggested that if PHMSA is changing this
specifically to address ruptures on gas transmission lines, then it may
be appropriate for PHMSA to reference ``rupture'' in the final rule
language instead of ``emergency.''
TPA stated that the 10-minute requirement for contacting first
responders is duplicative and unnecessary, as existing emergency
procedures and damage prevention
[[Page 20970]]
procedures already contain requirements for the timely contact of
emergency responders and calls to 9-1-1 numbers. They recommended that
PHMSA remove this requirement from the rule. A member of the public
agreed that the time to declare a rupture following the first sign of a
problem should be no more than 10 minutes, and that emergency services
must be notified right away.
The NTSB stated that the proposed changes to the emergency planning
regulations do not require immediate and direct notification to local
jurisdictions of possible ruptures as recommended by Safety
Recommendation P-11-9. They stated that the NPRM's clarifications for
when notification is required could unnecessarily delay operators
notifying local authorities and possibly exclude some ruptures from the
notification requirement, such as distribution systems or portions of
transmission systems that do not contain RMVs.
AFPM stated that the language in the proposed sections is
unnecessarily prescriptive and the language should be simplified, as
the position title or function of the operator personnel that is
responsible for contacting the appropriate public safety answering
point is immaterial.
AFPM stated that the use of ``may'' in the proposed revision to
require notification of ``each government organization that may respond
to a pipeline emergency'' vastly expands the universe of events for
which operators would have to provide notice and is an unrealistic
request. AFPM stated that the operator may not reasonably be able to
identify all the possible jurisdictions or agencies that may need to be
called upon. As such, AFPM recommended PHMSA allow an operator to
identify and coordinate with the agency identified by local or State
law as the lead agency in a pipeline emergency, or allow communication
with a regional coordinating agency (e.g., Office of Emergency
Management) to meet this requirement.
AFPM stated that they support PHMSA's intent to require operators
to establish and maintain adequate means of communication with the
appropriate public safety officials, as previously established
relationships between operators and safety officials could help
mitigate the consequences of an incident.
AFPM stated that they believe the use of ``and other public
officials'' in the proposed requirements is too vague and potentially
expansive. AFPM and INGAA et al. recommended that PHMSA should
explicitly note with whom operators should liaise, such as county
emergency managers, local emergency planning committees, or 9-1-1
agencies, and limit the requirement to those emergency response
agencies with primary jurisdiction for response to a pipeline incident.
INGAA et al. stated that this approach would be consistent with the
Pipeline Emergency Responder Initiatives that have been developed in
several States with the support of PHMSA.
AFPM added that ``notifying the appropriate public safety answering
point (9-1-1 emergency call center), as well as fire, police, and other
public officials'' is redundant and possibly confusing in jurisdictions
where the 9-1-1 center is designated as the single point of emergency
services contact. AFPM recommended PHMSA allow 9-1-1 to be the single
point of contact for all jurisdictions for which the 9-1-1 center
serves as such.
At the Committee meetings on July 22 and 23, 2020, the Committees
unanimously recommended that PHMSA state that communication with 9-1-1
applies to all ruptures without exception. For operators of pipelines
not located within 9-1-1 service areas or that otherwise have no public
safety answering points, the Committees unanimously recommended PHMSA
promulgate similar requirements. Further, the Committees unanimously
recommended that PHMSA allow operators to establish liaison with the
appropriate local emergency response coordinating agencies, such as 9-
1-1 emergency call centers or county emergency managers, in lieu of
communicating individually with each fire, police, or other public
entity, as was proposed in the NPRM.
The Committees also unanimously recommended that PHMSA limit
certain sections of the regulations to emergency preparedness
activities and other sections to emergency response activities, rather
than combining the two as PHMSA did in the NPRM.
3. PHMSA Response
The NTSB and the PST were concerned that the NPRM, as proposed,
could exclude certain ruptures from the notification requirements of
this section. PHMSA did not intend to include any exceptions from the
9-1-1 notification requirements of this rulemaking, including for those
pipelines where RMV or alternative equivalent technology closure is not
required, and does not believe the NPRM was worded as such. Further,
PHMSA has modified the language in the NPRM regarding when the 9-1-1
notification obligation has been triggered to reflect the substitution
in this final rule of the term ``notification of potential rupture''
for the NPRM's definition of ``rupture''; PHMSA expects this
substitution will reduce the time before response and mitigation
actions are taken. Ultimately, the requirement in this final rule for
9-1-1 notification applies to all notifications of potential ruptures
on all gas and hazardous liquid pipeline systems governed by the
emergency planning and procedure requirements at Sec. Sec. 192.615 and
195.402, respectively.
Industry commenters requested that PHMSA include in the final rule
9-1-1 communication provisions for pipelines that are not located in
areas served by 9-1-1 call centers or that have no public safety
answering points. The emergency notification requirements in this final
rule require operators to establish adequate means of communication
with fire, police, and other public officials as needed, regardless of
whether they are affiliated with public safety answering points.
Operators must determine the jurisdictional areas, responsibilities,
resources, and emergency contact numbers for those government
organizations that may respond to pipeline emergencies involving their
pipeline facilities.
To the points commenters made on liaising with the appropriate
local emergency coordinating entities and allowing coordination with a
lead agency if recognized by State and local law, PHMSA will note that
it did not propose to amend the long-standing requirements about
coordinating with local officials, including fire and police officials.
The NPRM intended to add the explicit requirement, when applicable, for
operators to call 9-1-1 after the notification of a potential rupture.
Per this final rule, to meet these requirements of this section,
operators may liaise with the appropriate emergency response
coordinating agencies, such as 9-1-1 emergency call centers or county
emergency managers, in lieu of communicating individually with each
fire, police, or other public entity. PHMSA believes that the
requirement to liaise with appropriate emergency response coordinating
agencies responds to the Committee recommendation for including
provisions for operators of pipeline segments outside of 9-1-1 or
public safety access point service areas.
L. Other
1. Summary of Proposal
In the NPRM, PHMSA proposed to revise Sec. Sec. 192.935 and
195.452 to clarify the requirements for conducting ASV
[[Page 20971]]
and RCV evaluations for HCAs, particularly when RCVs and ASVs are
installed as P&M measures associated with improved response times for
pipeline ruptures. The proposed amendments would have required that
operators be able to evaluate and demonstrate that they could identify
a rupture within 10 minutes in accordance with the proposed rupture
identification regulations, meet the proposed RMV or alternative
equivalent technology closure standard of 40 minutes, and demonstrate
compliance with the proposed valve maintenance requirements.
2. Comments Received
Regarding the installation of RMV technology in HCAs under Sec.
192.935, INGAA et al. recommended that PHMSA clarify the decisions
operators would be required to make, stating PHMSA proposed in the NPRM
that these decisions should consider the swiftness of rupture detection
capabilities, not leak detection capabilities. INGAA et al. and other
industry commenters also recommended that PHMSA remove the proposed
requirements in Sec. 192.935(c) because they appear to be duplicative
with the proposed requirements for RMV installation under Sec.
192.634. Similarly, Northern Natural Gas Company recommended that PHMSA
remove the proposed requirements at Sec. 192.935 because they are
already partially addressed by the investigation of failures and
incidents at Sec. 192.617.
The PST supported PHMSA's proposed addition of performance measures
for the installation of EFRDs and their use as RMVs under Sec.
195.452. API/AOPL and GPA Midstream suggested that PHMSA should restate
that EFRDs installed under the IM regulations must meet the applicable
requirements in part 195 for RMVs, as this would simplify the
regulatory language.
Northern Natural Gas Company noted that the use of automatic valves
may create cybersecurity vulnerabilities. A private citizen echoed this
sentiment, stating that PHMSA needs to address cybersecurity issues
related to sensors and control systems associated with RMVs, as such
issues could reduce the effectiveness of those valves. However, the
private citizen noted that Congress has not provided PHMSA, or the U.S.
DOT in general, with specific authority to regulate the cybersecurity
of pipeline infrastructure. That private citizen suggested that these
technologies should be protected from cyber-threats, and the failure of
cybersecurity protections should trigger the same reporting
requirements that accompany the failure of physical controls.
The Clean Air Council suggested that PHMSA adjust the definition of
HCAs to be broader than areas with higher population density, stating
they believe that the environmental and historical value of certain
locations should be included in an evaluation whether a location is an
HCA.
3. PHMSA Response
PHMSA was attempting to update the existing requirements for ASV
and RCV analysis in HCAs with the terminology and specific requirements
related to RMVs and alternative equivalent technology that were
proposed in the NPRM. PHMSA was proposing no new requirements other
than that, if operators performed a risk analysis indicating that an
ASV or an RCV would provide protection to an HCA or a could-affect HCA
pipeline segment, those valves that the operators installed would
essentially be RMVs and would need to comply with the 10-minute rupture
identification standard, the valve closure time, and the associated
maintenance requirements. PHMSA believes that the wording of the
section and duplication of those requirements, rather than cross-
references, may have confused readers. As such, in this final rule,
PHMSA has retained those same requirements while simplifying the
language to state that an RMV installed in accordance with Sec. Sec.
192.935 and 195.452 must comply with all of the other RMV requirements
in the respective parts of the regulations.\45\
---------------------------------------------------------------------------
\45\ See Sec. Sec. 192.3, 192.9, 192.18, 192.179, 192.610,
192.615, 192.617, 192.634, 192.636, 192.745, and 192.935, as
appropriate, for gas transmission and gathering pipelines, and
Sec. Sec. 195.2, 195.11, 195.18, 195.258, 195.260, 195.402,
195.418, 195.419, 195.420, and 195.452, as appropriate, for
hazardous liquid pipelines.
---------------------------------------------------------------------------
Regarding cybersecurity issues, PHMSA notes that the recent
cyberattack on the Colonial Pipeline underscores the urgency of public-
private collaboration to address international cybersecurity threats.
PHMSA is working with a coalition of its Federal partners, including
the Transportation Security Administration (TSA), to ensure that
pertinent regulatory regimes adequately address cybersecurity risks on
pipeline infrastructure. PHMSA notes that the TSA recently issued
security directives that will enable the Department of Homeland
Security (DHS) to better identify, protect against, and respond to
threats to critical operators in the pipeline sector. The TSA's initial
directive requires critical pipeline owners and operators to report
confirmed and potential cybersecurity incidents to the DHS
Cybersecurity and Infrastructure Security Agency (CISA) and to
designate a Cybersecurity Coordinator, to be available 24 hours a day,
7 days a week. It also requires critical pipeline owners and operators
to review their current practices as well as to identify any gaps and
related remediation measures to address cyber-related risks and report
the results to TSA and CISA within 30 days.\46\ A second Security
Directive requires owners and operators of TSA-designated critical
pipelines to implement specific mitigation measures to protect against
ransomware attacks and other known threats to information technology
and operational technology systems, develop and implement a
cybersecurity contingency and recovery plan, and conduct a
cybersecurity architecture design review.
---------------------------------------------------------------------------
\46\ https://www.dhs.gov/news/2021/05/27/dhs-announces-new-cybersecurity-requirements-critical-pipeline-owners-and-operators.
---------------------------------------------------------------------------
Changing the HCA definition is outside the scope of the rulemaking
and would require substantial technical analysis. However, in response
to congressional mandates in the ``Protecting Our Infrastructure of
Pipelines and Enhancing Safety Act of 2016'' (Pub. L. 114-183) and the
2020 PIPES Act, PHMSA has promulgated an Interim Final Rule (under RIN
2137-AF31) titled ``Pipeline Safety: Coastal Ecological Unusually
Sensitive Areas,'' to amend the definition of an ``unusually sensitive
area'' in part 195 for hazardous liquid pipelines to include the Great
Lakes, coastal beaches, and certain coastal waters explicitly as
ecological resources for the purposes of determining whether a pipeline
is in, or could affect, an HCA.\47\ Further, section 119 of the 2020
PIPES Act requires PHMSA to contract with the National Academy of
Sciences (NAS) for development of a study evaluating potential
regulatory amendments that would build on this final rule by requiring
installation of RMVs on existing natural gas pipelines in HCAs,
hazardous liquid pipelines in unusually sensitive areas, and hazardous
liquid pipelines in commercially navigable waterways. The NAS committee
has been formed and that committee is in the process of planning its
activities.\48\
---------------------------------------------------------------------------
\47\ 86 FR 73173 (Dec. 27, 2021).
\48\ NAS, ``Criteria for Installing Automatic and Remote-
Controlled Shutoff Valves on Existing Gas and Hazardous Liquid
Transmission Pipelines'' (last visited Nov. 23, 2021).
---------------------------------------------------------------------------
[[Page 20972]]
IV. Section-by-Section Analysis of Changes to 49 CFR Part 192 for Gas
Pipelines
Sec. 192.3 Definitions
Section 192.3 provides definitions for various terms used
throughout part 192. Most of the requirements of this final rule would
be triggered by an operator identifying a rupture following the
notification of a potential rupture. Therefore, PHMSA is amending Sec.
192.3 to define the ``notification of potential rupture'' in terms of
notification of, or observation by, an operator of indicia specified in
Sec. 192.635 of an unintentional or uncontrolled release of a large
volume of gas from a pipeline.
Once an operator is notified of a potential rupture, they must
identify a rupture, if one exists. Therefore, PHMSA has established a
concept of ``rupture identification'' to mean the point when a pipeline
operator has sufficient information reasonably to determine that a
rupture occurred. PHMSA believes this would occur following a
``notification of potential rupture,'' as that term has been defined in
this rulemaking, given that the operator would have been notified or
would have had notice of some indicia of a potential rupture per Sec.
192.635. The final rule at Sec. 192.615 requires that operators must
document, in their operations manual or written procedures, their
method for rupture identification. An operator, after identifying a
rupture, would be required to close the RMVs or alternative equivalent
technologies necessary to isolate the ruptured pipeline segment.
As a part of this rulemaking, operators are required to install
RMVs or alternative equivalent technology on certain pipeline segments,
including those that are ``entirely replaced onshore pipeline
segments.'' RMVs are defined in this rulemaking to mean ASVs or RCVs
that a pipeline operator uses to minimize the volume of gas released
from the pipeline and to minimize the consequences of a rupture. PHMSA
has defined entirely replaced onshore transmission pipeline segments to
mean those pipeline replacement projects where 2 or more miles of
pipeline have been replaced within any length of 5 contiguous miles of
pipeline during any 24-month period.
Sec. 192.9 What requirements apply to gathering lines?
In this final rule, PHMSA has clarified that the RMV and
alternative equivalent technology requirements being promulgated apply
to Type A gas gathering pipelines (not Types B or C gathering lines),
as these pipelines typically have risk profiles similar to transmission
pipelines.
Sec. 192.18 How To Notify PHMSA
In this final rule, operators can notify PHMSA in advance of their
intent to use a technology, method, or compliance timeline that differs
from that listed in the regulations, when the option for notification
is specifically provided. PHMSA retains discretion under Sec. 192.18
to reject, as appropriate, such requests. Accordingly, PHMSA has
revised this section to provide for a consistent notification procedure
across part 192 whenever an operator is required to notify PHMSA as a
part of a requirement.
Sec. 192.179 Transmission Line Valves
In this final rule, PHMSA is requiring the installation of RMVs or
alternative equivalent technologies on certain gas pipelines. This
section specifies that operators must install RMVs, or alternative
equivalent technologies, on onshore gas pipeline segments with
diameters greater than or equal to 6 inches that are newly constructed,
or meet the definition of entirely replaced onshore transmission
pipeline segments, after April 10, 2023. RMVs and alternative
equivalent technologies installed in accordance with this section must
meet the existing valve spacing requirements of this section, and all
RMVs and alternative equivalent technologies installed in accordance
with this section must meet the operational requirements outlined in
Sec. 192.636.
These installation requirements do not apply to those pipeline
segments that are in Class 1 or Class 2 locations and that have a PIR
of less than or equal to 150 feet. Further, the installation
requirements for entirely replaced onshore pipeline segments only apply
to those pipeline replacement projects that involve the addition,
replacement, or removal of a valve.
If an operator seeks to install alternative equivalent technology
pursuant to this section, the operator must, in advance of such
installation, submit a notification making such a request to PHMSA in
accordance with Sec. 192.18. The operator must include in that
notification a site-specific technical and safety evaluation
demonstrating that technology provides an equivalent level of safety to
an RMV by reference to factors including, but not limited to, the
following: Design, construction, maintenance, and operating procedures;
technology design and operational 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.
If an operator requests use of manual valves as an alternative
equivalent technology, the notification submitted to PHMSA must also
demonstrate the site-specific economic, technical, or operational
infeasibility of installing an RMV (e.g., by reference to 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).
An operator may also submit for PHMSA review, in accordance with
the notification procedures in Sec. 192.18, a project-specific request
for extension of the compliance deadline in this section. That
notification must demonstrate installation of an RMV or alternative
equivalent technology in connection with near-term construction and
replacement projects would be economically, technically, or
operationally infeasible (e.g., by reference to prohibitive economic
costs, difficulty in securing access rights, component/labor
availability and procurement lead times, or permitting requirements).
An operator that replaces pipeline segments is not required to meet
the valve spacing requirements of this section if the distance between
each point on the pipeline and the nearest valve does not exceed 4
miles in Class 4 locations, 7\1/2\ miles in Class 3 locations, and 10
miles in all other locations.
Sec. 192.610 Change in Class Location: Change in Valve Spacing
This section specifies RMV and alternative equivalent technology
requirements when a class location changes. In cases where pipeline
segments are entirely replaced, as that term is defined in Sec. 192.3,
to meet the maximum allowable operating pressure in accordance with
requirements for class location changes under Sec. Sec. 192.611,
192.619(a), and 192.620, then an operator must install valves,
including RMVs or alternative equivalent technology, as necessary to
comply with this part. An operator must install such valves within 24
months of the class location change.
If an operator replaces less than 2 miles of pipe in a length of 5
contiguous miles of pipe during a 24-month period to comply with the
maximum allowable operating pressure requirements after a class
location changes, the operator must either: (1) Comply with the valve
[[Page 20973]]
spacing requirements at Sec. 192.179(a), or (2) install or use RMVs or
alternative equivalent technology so that the entirety of the replaced
pipeline segment is between 2 RMVs or alternative equivalent technology
and so that the distance between those valves does not exceed 20 miles.
Operators are not required to comply with this section if they replace
less than 1,000 feet of pipe within any single contiguous mile within
any 24-month period to comply with a class location change.
Sec. 192.615 Emergency Plans
In this final rule, PHMSA revised paragraphs (a)(2), (a)(6),
(a)(8), (a)(11), and (a)(12) and the introductory text of (c) in Sec.
192.615 to require that emergency procedures provide for rupture
mitigation in response to a rupture event. PHMSA is also requiring that
operators maintain liaison with and contact the appropriate public
safety answering point (i.e., 9-1-1 emergency call center), if such a
service is available, in the event of pipeline emergencies. In lieu of
communicating with individual fire, police, or other public entities,
operators may instead establish liaison with appropriate local
emergency coordinating agencies, such as 9-1-1 emergency call centers
or county emergency managers, as appropriate.
PHMSA is requiring, through this final rule, that operators learn
the responsibilities, resources, jurisdictional areas, and emergency
contact telephone numbers for each Federal, State, and local government
organization that may respond to a pipeline emergency involving their
pipeline facilities, and inform such officials of the operator's
ability to respond to and communicate during pipeline emergencies.
PHMSA has not changed the existing requirements for operators to
maintain liaison with fire, police, and other public officials, as
appropriate.
In conjunction with the definition of the ``notification of
potential rupture,'' PHMSA has in this final rule codified at Sec.
192.615(a)(12) 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 their written
procedures. At a minimum, the procedures must specify the sources of
information, operational factors, and other criteria that the operator
will use to evaluate a notification of a potential rupture as an actual
rupture. Those written procedures should also incorporate procedures
for 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. 192.635(a)(1); or 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).
Sec. 192.617 Investigation of Failures and Incidents
In this final rule, PHMSA has revised Sec. 192.617 to define the
elements that an operator must incorporate when conducting a post-event
analysis of ruptures and other failure events involving the activation
of RMVs or alternative equivalent technology.
The revision requires the operator to identify potential preventive
and mitigative measures that could be taken to reduce or limit the
release volume and damage from similar events in the future. The post-
incident or -failure review would include, but not be limited to,
detection and mitigation actions, response time, valve location, valve
actuation, and SCADA system performance. Upon completing the post-event
analysis, the operator must develop and implement the lessons learned
throughout its suite of procedures, including in pertinent operator
personnel training and qualification programs, and in design,
construction, testing, maintenance, operations, and emergency procedure
manuals and specifications. In accordance with this section, an
operator must also complete a summary of the post-incident or -failure
review within 90 days of the incident. The operator must conduct
quarterly status reviews until the investigation is complete and a
final post-incident summary is prepared. The final post-incident
summary and all other reviews and analyses produced under the
requirements of this section must be reviewed, dated, and signed by the
operator's appropriate senior executive officer. Further, an operator
must keep the final post-incident summary, all investigation and
analysis documents used to prepare it, and records of lessons learned
for the useful life of the pipeline. The requirements to produce a
summary report are not applicable to gas distribution and Types B and C
gathering pipelines.
PHMSA has also modified the existing failure and incident
investigation requirements at Sec. 192.617 to require operators
subject to that provision to incorporate lessons learned from those
investigations into their written procedures, including personnel
training and qualification programs, and design, construction, testing,
maintenance, operations, and emergency procedure manuals and
specifications. PHMSA has otherwise not made changes to the existing
requirements in this section for operators of gas pipelines to
establish procedures for analyzing incidents and failures.
Sec. 192.634 Transmission Lines: Onshore Valve Shut-Off for Rupture
Mitigation
This section requires operators to install and use RMVs or
alternative equivalent technology on newly constructed and entirely
replaced onshore gas pipeline segments with diameters of 6 inches or
greater. Such valves would be required to be operational within 14 days
following placing the pipeline segment into service unless the operator
has submitted for PHMSA review, in accordance with Sec. 192.18, a
notification that operation of the RMV or alternative equivalent
technology within that 14-day timeframe is not economically,
technically, or operationally feasible. An operator may also submit for
PHMSA review, in accordance with the notification procedures in Sec.
192.18, a request for extension of the valve installation compliance
deadline requirements of Sec. 192.179 and this section demonstrating
that installation of an RMV or alternative equivalent technology in
connection with particular near-term construction and replacement
projects would be economically, technically, or operationally
infeasible (e.g., by reference to prohibitive costs, difficulty in
securing required access rights and permits, and component/labor
availability).
For the purposes of the RMV and alternative equivalent technology
installation requirements, PHMSA created a definition for a ``shut-off
segment,'' which is a pipeline segment that is entirely located between
at least two RMVs or alternative equivalent technologies. If any
crossover or lateral pipe for commodity receipts or deliveries connects
to the shut-off segment between the upstream-most and downstream-most
RMVs or alternative equivalent technologies, the shut-off segment also
extends to valves on those crossover connections or laterals used for
receipt or delivery so that, when all valves are closed, there is no
flow path for commodity to be transported from outside the shut-off
segment to the rupture site. Laterals that
[[Page 20974]]
connect to shut-off segments and that contribute less than 5 percent of
the total shut-off segment volume may have RMVs or alternative
equivalent technologies installed at locations other than mainline
receipt or delivery points. A shut-off segment can include multiple
HCAs, and operators are not required to select the closest valve to the
shut-off segment as an RMV or alternative equivalent as long as the
proper valve spacing is maintained.
The requirements of this section apply to all applicable pipe
replacement projects, even those that do not otherwise directly involve
the addition or replacement of a valve. Consistent with the
requirements for RMV and alternative equivalent technology
installation, this section does not apply to pipe segments in Class 1
or Class 2 locations that have a PIR less than or equal to 150 feet.
This section also establishes valve spacing for RMVs and
alternative equivalent technologies installed in accordance with this
section, where the distance between such RMVs and alternative
equivalent technologies must not exceed 8 miles in Class 4 locations,
15 miles in Class 3 locations, and 20 miles in all other locations.
Operators using a manual valve as an alternative equivalent
technology in lieu of an RMV for the purposes of this section must
appropriately locate personnel to ensure valve shut-off in accordance
with this section and the RMV performance requirements in Sec.
192.636.
Sec. 192.635 Notification of Potential Rupture
In this section, PHMSA provides the criteria for a ``notification
of potential rupture,'' as that term is defined in Sec. 192.3.
Sec. 192.636 Transmission Lines: Valve Capabilities
In this section, PHMSA establishes the operational requirements for
RMVs and alternative equivalent technologies. Following the
``notification of potential rupture,'' an operator must, after
identifying a rupture, close such valves as soon as practicable, but no
later than within 30 minutes (measured from rupture identification).
Operators may request to plan to leave RMVs or alternative equivalent
technologies open for longer than 30 minutes following rupture
identification if the operator previously has coordinated the plan with
appropriate local emergency responders, notified PHMSA, and adequately
demonstrated to PHMSA that closing such valves or technologies would be
detrimental to public safety.
RMVs and alternative equivalent technologies must be capable of
being monitored or controlled by remote or on-site personnel, operated
during all operating conditions, and monitored for valve status.
Operators using ASVs as RMVs do not need to monitor those valves
remotely if the operator has the capability to monitor pressures or gas
flow rate on the pipeline in order to identify and locate a rupture
pursuant to the requirements of this rulemaking.
Operators of pipelines in Class 1, non-HCAs may request, within
their notification under Sec. 192.18 seeking PHMSA review for
installation of manual valves as alternative equivalent technologies as
contemplated by this final rule, an exemption from the valve operation
requirements of Sec. 192.636(b). Operators seeking such an exemption
must provide for PHMSA review within that notification the closing
times for those manual valves.
Sec. 192.745 Valve Maintenance: Transmission Lines
In this final rule, PHMSA is revising Sec. 192.745 by adding
paragraphs (c), (d), and (e) to incorporate the maintenance,
inspection, and operator drills required to ensure operators can close
an RMV or alternative equivalent technology as soon as practicable, but
no more than 30 minutes, after identification of a rupture. PHMSA is
finalizing initial validation drill requirements and requirements for
periodic validation tests for any manually or locally operated valve
installed as an alternative equivalent technology in lieu of an RMV.
Operators are not required to close the valves fully during such
drills; a closure of 25 percent, at a minimum, is sufficient to be
compliant, unless the operator has information that requires additional
closure requirements for the valve to be compliant with the
requirement. If the 30-minute-maximum closure time cannot be achieved
during the drill, the operator must revise their response efforts and
repair any valves to achieve compliance as soon as practicable but no
later than 12 months after the drill. Operators may request, pursuant
to the notification procedure at Sec. 192.18, an extension of the 12-
month repair timeline if such repair within 12 months would be
economically, technically, or operationally infeasible (e.g., by
reference to prohibitive costs, difficulty in securing required access
rights and permits, long procurement lead times, and component/labor
availability). Alternative valve shut-off measures must be in place
within 7 days of a failed drill. In accordance with Sec. 192.631(c)
and (e), operators must also conduct a point-to-point verification
between SCADA displays, sensors, communications equipment, and any RCVs
installed in accordance with Sec. Sec. 192.179 or 192.634.
Per this final rule, each operator is required to identify
corrective actions and lessons learned resulting from the validation
and confirmation drills and share and implement them across its entire
network of pipeline systems.
Sec. 192.935 What additional preventive and mitigative measure must an
operator take?
In this final rule, PHMSA is revising Sec. 192.935(c) to clarify
the requirements for conducting RMV evaluations for HCAs, particularly
when an operator installs such valves as preventive and mitigative
measures to improve response times for pipeline ruptures and mitigate
the consequences of a rupture. RMVs installed in accordance with this
section must meet all other RMV requirements in part 192.
PHMSA is also requiring that risk analyses and assessments
conducted under this section be reviewed by the operator and certified
by a senior executive of the company. Review and certification must
occur at least once per calendar year, with the period between reviews
not to exceed a period of 15 months, and must also occur within 3
months of an incident or a safety-related condition. Such analyses and
assessments must consider new or existing operational and integrity
matters that could affect rupture-mitigation processes and procedures.
V. Section-by-Section Analysis for Changes to 49 CFR Part 195 for
Hazardous Liquid Pipelines
Sec. 195.2 Definitions
Section 195.2 provides definitions for various terms used
throughout part 195. Most of the requirements of this final rule would
be triggered by an operator identifying a rupture following the
notification of a potential rupture. Therefore, PHMSA is amending Sec.
195.2 to define the ``notification of potential rupture'' in terms of
notification of, or observation by, an operator of indicia specified in
Sec. 195.417.
Once an operator is notified of a potential rupture, they must
identify the rupture, if one exists. Therefore, PHMSA has established a
concept of ``rupture identification'' to mean the point when a pipeline
operator has sufficient information reasonably to determine that a
rupture occurred. The final rule at Sec. 195.402 requires that
operators must document, in their operations manual, their method for
rupture identification. An operator, after
[[Page 20975]]
identifying a rupture, would be required to close the RMVs or
alternative equivalent technologies necessary to isolate the ruptured
pipeline segment.
As a part of this rulemaking, operators are required to install
RMVs or alternative equivalent technologies on certain pipeline
segments, including those that are ``entirely replaced onshore
hazardous liquid or carbon dioxide pipeline segments.'' RMVs are
defined in this rulemaking to mean ASVs or RCVs that a pipeline
operator uses to minimize the volume of hazardous liquid or carbon
dioxide released from the pipeline and to minimize the consequences of
a rupture. PHMSA has defined entirely replaced onshore hazardous liquid
or carbon dioxide pipeline segments to mean those pipeline replacement
projects where 2 or more miles of pipeline have been replaced within
any length of 5 contiguous miles of pipeline during any 24-month
period.
Sec. 195.11 What is a regulated rural gathering line and what
requirements apply?
Section 195.11 contains the requirements for regulated rural
gathering pipelines carrying hazardous liquid or carbon dioxide. In
this final rule, PHMSA is specifying that the only regulated rural
gathering pipelines that are required to install RMVs or alternative
equivalent technologies are those pipelines subject to Sec.
195.260(e), which requires the installation of RMVs or alternative
equivalent technologies on pipelines that span water crossings more
than 100 feet wide, from high water mark to high water mark.
Sec. 195.18 How To Notify PHMSA
In this final rule, operators can notify PHMSA in advance of their
intent to use a technology, compliance timeline, or method that differs
from that listed in the regulations, when that option is specifically
provided in the regulatory text. PHMSA retains discretion under Sec.
195.18 to reject, as appropriate, such requests. Accordingly, PHMSA has
revised this section to provide for a consistent notification procedure
across part 195 whenever an operator is required to notify PHMSA as a
part of a requirement of this final rule. This provision is similar to
the notification procedure created for part 192.
Sec. 195.258 Valves: General
In this final rule, PHMSA is requiring the installation of RMVs or
alternative equivalent technologies on certain pipelines. This section
specifies that operators must install RMVs, or alternative equivalent
technologies, on onshore hazardous liquid or carbon dioxide pipeline
segments with diameters greater than or equal to 6 inches that are
constructed, or meet the definition of entirely replaced onshore
hazardous liquid or carbon dioxide pipeline segments, after April 10,
2023. RMVs and alternative equivalent technologies installed in
accordance with this section must meet the existing valve spacing
requirements of Sec. 195.260, and all alternative equivalent
technologies installed in accordance with this section must meet the
operational requirements of RMVs outlined in Sec. 195.419. These
installation requirements for entirely replaced onshore hazardous
liquid or carbon dioxide pipeline segments only apply to those pipeline
replacement projects that involve the addition, replacement, or removal
of an existing valve.
If an operator seeks to install alternative equivalent technology
pursuant to this section, the operator must, in advance of such
installation, submit a notification making such a request to PHMSA in
accordance with Sec. 195.18. The operator must include in that
notification a site-specific technical and safety evaluation
demonstrating that technology provides an equivalent level of safety to
an RMV by reference to factors including, but not limited to, the
following: Design, construction, maintenance, and operating procedures;
technology design and operational 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.
If an operator requests use of manual valves as an alternative
equivalent technology, the notification submitted to PHMSA must also
demonstrate site-specific economic, technical, or operational
infeasibility of installing an RMV (e.g., by reference to 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.
An operator may also submit for PHMSA review, in accordance with
the notification procedures in Sec. 195.18, a project-specific request
for extension of the compliance deadline in this section. That
notification must demonstrate installation of an RMV or alternative
equivalent technology in connection with near-term construction and
replacement projects would be economically, technically, or
operationally infeasible (e.g., by reference to prohibitive economic
costs, difficulty in securing required access rights and permits, and
component/labor availability).
Sec. 195.260 Valves: Location
Section 195.260 finalizes requirements for the location of valves
on newly constructed and entirely replaced onshore hazardous liquid or
carbon dioxide pipelines, where such pipeline segments installed after
April 10, 2023, must have valve spacing that does not exceed 15 miles
for pipelines that could affect HCAs, as that term is defined in Sec.
195.450. For those pipelines that could not affect HCAs, the valve
spacing requirements for such pipelines cannot exceed 20 miles. An
operator installing valves that protect HCAs must install those valves
at locations determined through the operator's process for identifying
preventive and mitigative measures established pursuant to Sec.
195.452(i) and Appendix C, Section B of part 195. An operator may
submit for PHMSA review, in accordance with the notification procedures
in Sec. 195.18, a request for extension of the compliance deadline for
valve installation and spacing in this section. That notification must
demonstrate that the compliance timeline for valve spacing required by
this final rule would be economically, technically, or operationally
infeasible in connection with particular near-term construction and
replacement projects (e.g., 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).
PHMSA has also revised the valve location requirements for those
pipelines that cross waterways that are more than 100 feet wide from
high water mark to high water mark. Accordingly, in this final rule,
operators must install valves at locations outside of the 100-year
flood plain or otherwise install valves that are equipped with control
equipment that would not be made inoperable by flood conditions.\49\
Additionally, the maximum spacing between valves protecting multiple
[[Page 20976]]
adjacent water crossings cannot exceed 1 mile.
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\49\ A 100-year flood plain is an area that has a 1-in-100
chance of having a flood event that could be equaled or exceeded in
any 1 year, and it has an average recurrence interval of 100 years.
100-year flood plains are determined by the Federal Emergency
Management Agency, which operates the official flood hazard Mapping
Service Center in support of the National flood insurance program,
and they offer flood zone maps online. If another agency, such as a
State authority, is responsible for determining the 100-year flood
plain for the area where the pipeline is located, the operator
should use those resources and documents.
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In this section, PHMSA has also finalized spacing requirements for
HVL pipelines in high-population areas or other populated areas, as
defined in Sec. 195.450. These pipelines must have a maximum valve
spacing of 7\1/2\ miles if they have been constructed or where 2 or
more miles of pipeline have been replaced within a span of 5 contiguous
miles within a 24-month period, following April 10, 2023. The maximum
valve spacing for HVL pipelines can be increased by 1.25 times the
distance to a maximum of a 9\3/8\-mile spacing if the operator submits
for PHMSA review, in accordance with Sec. 195.18, within its
notification (1) an evaluation of the safety of the alternative
spacing, referencing 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 in the event of a
rupture; and (2) a demonstration that the installation of a valve at
the otherwise-required spacing is economically, technically or
operationally infeasible (e.g., by reference to 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).
Additionally, operators may notify PHMSA, using the procedure at
Sec. 195.18, if, in particular cases, the valve installation or valve
spacing requirements of certain paragraphs of this section are not
necessary to achieve an equivalent level of safety at a particular
site. That notification must include a supporting technical and safety
evaluation referencing 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 in the event of a
rupture.
Sec. 195.402 Procedural Manual for Operations, Maintenance, and
Emergencies
In this final rule, PHMSA revised Sec. 195.402 to require that
emergency procedures provide for rupture mitigation in response to a
rupture event. PHMSA is also requiring that operators maintain liaison
with and contact the appropriate public safety answering point (i.e.,
9-1-1 emergency call center), if such a service is available, in the
event of pipeline emergencies. In lieu of communicating with individual
fire, police, or other public entities, operators may instead establish
liaison with appropriate local emergency coordinating agencies, such as
9-1-1 emergency call centers or county emergency managers, as
appropriate.
PHMSA is requiring, through this final rule, that operators must
learn the responsibilities, resources, jurisdictional areas, and
emergency contact telephone numbers for each Federal, State, and local
government organization that may respond to a pipeline emergency
involving their pipeline facilities, and inform such officials of the
operator's ability to respond to and communicate during pipeline
emergencies. PHMSA has not changed the existing requirements for
operators to maintain liaison with fire, police, and other public
officials, as appropriate.
In conjunction with the definition of a ``notification of potential
rupture,'' PHMSA has in this final rule codified at Sec. 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. At a minimum,
the procedures must specify the sources of information, operational
factors, and other criteria that the operator will use to evaluate a
notification of a potential rupture as an actual rupture. Those written
procedures should also incorporate procedures for 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.
195.417(a)(1); or 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).
Further, PHMSA has revised this section to define the elements that
an operator must incorporate when conducting a post-accident or -
failure analysis of ruptures and other accident and failure events
involving the activation of RMVs or alternative equivalent
technologies. PHMSA has not made changes, otherwise, to the existing
requirements in this section for operators of hazardous liquid and
carbon dioxide pipelines to establish procedures for analyzing
accidents and failures.
The revision requires the operator to identify potential preventive
and mitigative measures that could be taken to reduce or limit the
release volume and damage from similar events in the future. The post-
incident review would include but not be limited to detection and
mitigation actions, response time, valve location, valve actuation, and
SCADA system performance. Upon completing the post-accident analysis,
the operator must develop and implement the lessons learned throughout
its suite of procedures, including in pertinent operator personnel
training and qualification programs, and in design, construction,
testing, maintenance, operations, and emergency procedure manuals and
specifications. In accordance with this section, an operator must also
complete a summary of the post-incident review within 90 days of the
incident, and, while the investigation is pending, conduct quarterly
status reviews until the investigation is complete and a final post-
incident summary is prepared. The final post-incident summary and all
other reviews and analyses produced under the requirements of this
section must be reviewed, dated, and signed by the operator's
appropriate senior executive officer. Further, an operator must keep
the final post-incident summary, all investigation and analysis
documents used to prepare it, and records of lessons learned for the
useful life of the pipeline. The requirements to produce a summary
report are not applicable to gas distribution pipelines.
PHMSA has also modified the failure and accident investigation
requirements at Sec. 195.402 to require operators subject to that
provision to incorporate lessons learned from those investigations into
their written procedures, including personnel training and
qualification programs, and design, construction, testing, maintenance,
operations, and emergency procedure manuals and specifications.
Sec. 195.417 Notification of Potential Rupture
In this section, PHMSA provides the criteria for a ``notification
of potential rupture,'' as that term is defined in Sec. 195.2.
Sec. 195.418 Valves: Onshore Valve Shut-Off for Rupture Mitigation
This section requires operators to install or use RMVs or
alternative equivalent technologies on many newly
[[Page 20977]]
constructed and entirely replaced onshore hazardous liquid or carbon
dioxide pipeline segments with diameters of 6 inches or greater. Such
valves would be required to be operational within 14 days of placing
the pipeline segment into service unless the operator has submitted for
PHMSA review, in accordance with the notification procedure at Sec.
195.18, a request for extension demonstrating that operation of that
RMV or alternative equivalent technology within that 14-day timeframe
is not economically, technically, or operationally feasible. The
requirements of this section apply to all applicable pipe replacement
projects, even those that do not otherwise directly involve the
addition or replacement of a valve.
For the purposes of the RMV and alternative equivalent technology
installation requirements, PHMSA created a definition for a ``shut-off
segment,'' which is a pipeline segment that is entirely located between
at least two RMVs or alternative equivalent technologies. If any
crossover or lateral pipe for commodity receipts or deliveries connects
to the shut-off segment between the upstream-most and downstream-most
RMV or alternative equivalent technology, the shut-off segment also
extends to valves on those crossover connections or laterals, whether
those laterals are used for receipt or delivery, so that, when all
valves are closed, there is no flow path for commodity to be
transported from outside the shut-off segment to the rupture site.
Laterals that connect to shut-off segments and that contribute less
than 5 percent of the total shut-off segment volume may have RMVs or
alternative equivalent technologies installed at locations other than
mainline receipt or delivery points. A shut-off segment can include
multiple HCAs, and operators are not required to select the closest
valve to the shut-off segment as an RMV or alternative equivalent
technology as long as the proper valve spacing is maintained.
This section also establishes valve spacing for RMVs or alternative
equivalent technology installed in accordance with this section, where
the distance between such RMVs and alternative equivalent technologies
must not exceed 15 miles for lines carrying non-HVLs, and 7\1/2\ miles
for lines carrying HVLs. The maximum valve spacing intervals for RMVs
and alternative equivalent technologies on pipelines carrying HVLs may
be increased by 1.25 times the spacing distance to a maximum of 9\3/8\
miles, subject to review by PHMSA of an operator's request
demonstrating that installation of a valve at a 7-mile to a 7\1/2\-mile
spacing is economically, technically, or operationally infeasible.
Operators using a manual valve as an alternative equivalent
technology in lieu of an RMV for the purposes of this section must
appropriately designate and locate personnel near the valve to ensure
valve shut-off in accordance with this section and the RMV performance
requirements in Sec. 195.419.
Sec. 195.419 Valve Capabilities
In this section, PHMSA establishes the operational requirements for
RMVs and alternative equivalent technologies installed pursuant to this
final rule. Following a ``notification of potential rupture,'' an
operator must identify whether a rupture is occurring on their system
and close RMVs and alternative equivalent technologies as soon as
practicable, but no later than within 30 minutes of rupture
identification, or, if applicable, no later than the shut-down times
used in calculating a worst-case discharge in accordance with Sec.
194.105(b)(1), whichever shut-off time is a shorter time interval.
RMVs and alternative equivalent technologies must be capable of
being monitored or controlled by remote or on-site personnel, operated
during all operating conditions, and monitored for valve status.
Operators using ASVs as RMVs do not need to monitor those valves
remotely if the operator has the capability to monitor pressures or
product flow rate on the pipeline in order to identify and locate a
rupture.
Operators of pipelines in non-HCAs or of segments that could not
affect an HCA may submit for PHMSA review, within a notification under
Sec. 195.18 requesting installation of manual valves as an alternative
equivalent technology, an exemption from the valve operation
requirements of Sec. 195.419(b). An operator seeking such an exemption
must provide for PHMSA review within that notification the closing
times for those manual valves.
Sec. 195.420 Valve Maintenance
In this final rule, PHMSA is revising Sec. 195.420 to incorporate
the maintenance, inspection, and operator drills required to ensure
operators can close an RMV or alternative equivalent technology
installed under this final rule as soon as practicable, but within 30
minutes following rupture identification or within their shut-down
times used in calculating the worst-case discharge in accordance with
Sec. 194.105(b)(1), whichever is a shorter time interval. PHMSA is
finalizing initial validation drill requirements and requirements for
periodic confirmation drills for any manually or locally operated valve
used as an alternative equivalent technology in lieu of an RMV.
Operators are not required to close the valves fully during such
drills; a closure of 25 percent, at a minimum, is sufficient to be
compliant. If the 30-minute-maximum closure time cannot be achieved
during the drill, or shorter time pursuant to its part 194 worst-case
discharge calculations, the operator must revise their response efforts
and repair any valves to achieve compliance as soon as practicable but
no later than 12 months after the drill. Operators may request,
pursuant to the notification procedure at Sec. 195.18, an extension of
the 12-month repair timeline if such repair within 12 months would be
economically, technically, or operationally infeasible (e.g., by
reference to prohibitive costs, difficulty in securing required access
rights and permits, long procurement lead times, and component/labor
availability). Alternative valve shut-off measures must be in place
within 7 days of a failed drill. For each RCV installed under
Sec. Sec. 195.258(c) or 195.418, the operator must conduct a point-to-
point verification between SCADA displays, the installed valves,
sensors, and communications equipment in accordance with Sec.
195.446(c) and (e), or perform an equivalent verification.
Per this final rule, operators are required to identify corrective
actions and lessons learned resulting from the validation and
confirmation drills and share and implement them across its entire
network of pipeline systems.
Sec. 195.452 Pipeline Integrity Management in High Consequence Areas
In this final rule, PHMSA is revising Sec. 195.452(i)(4) to
clarify the requirements for conducting emergency flow restricting
device evaluations for HCAs, particularly when an operator installs
such valves as preventive and mitigative measures to improve response
times for, and mitigate the consequences of, pipeline ruptures.
Emergency flow restriction devices that are installed in accordance
with this section must meet all RMV requirements in part 195.
PHMSA is also requiring that risk analyses and assessments
conducted under this section be completed prior to placing into service
all onshore pipelines with diameters of 6 inches or greater and that
are constructed or that have had 2 or more miles of pipeline replaced
within 5 contiguous miles within a 24-month period after April 10,
2023. The implementation of emergency
[[Page 20978]]
flow restricting device findings for any RMVs installed must meet Sec.
195.418.
VI. Regulatory Analyses and Notices
A. Statutory/Legal Authority for This Rulemaking
This final rule is published pursuant to the authority granted to
the Secretary of Transportation by the Federal Pipeline Safety Statutes
(49 U.S.C. 60101 et seq.). Section 60102(a) authorizes issuance of
regulations governing design, installation, inspection, emergency plans
and procedures, testing, construction, extension, operation,
replacement, and maintenance of pipeline facilities. The final rule
also implements a statutory mandate at 49 U.S.C. 60102(n) requiring the
Secretary to issue regulations requiring the installation of RMVs or
equivalent technology on new and entirely replaced transmission lines.
See also 49 U.S.C. 5103 (regulatory authority to prescribe regulations
for transportation of hazardous materials), and 30 U.S.C. 185(w)(3))
(authority to prescribe reporting requirements for pipelines traversing
Federal lands). The Secretary delegated these authorities to the PHMSA
Administrator in 49 CFR 1.97.
B. Executive Order 12866 and DOT Regulatory Policies and Procedures
Executive Order 12866 (``Regulatory Planning and Review'') \50\
requires that ``agencies should assess all costs and benefits of
available regulatory alternatives, including the alternative of not
regulating. Agencies should consider quantifiable measures and
qualitative measures of costs and benefits that are difficult to
quantify.'' Further, Executive Order 12866 requires that ``agencies
should maximize net benefits (including potential economic,
environmental, public health and safety, and other advantages;
distributive impacts; and equity), unless a statute requires another
regulatory approach.'' Similarly, DOT Order 2100.6A (``Rulemaking and
Guidance Procedures'') requires that regulations issued by PHMSA and
other DOT Operating Administrations should consider an assessment of
the potential benefits, costs, and other important impacts of the
proposed action and should quantify (to the extent practicable) the
benefits, costs, and any significant distributional impacts, including
any environmental impacts.
---------------------------------------------------------------------------
\50\ 58 FR 51735 (Oct. 4, 1993).
---------------------------------------------------------------------------
This action has been determined to be significant under Executive
Order 12866. The final rule has been reviewed by the Office of
Management and Budget (OMB) in accordance with Executive Order 12866
and is consistent with the requirements of Executive Order 12866, 49
U.S.C. 60102(b)(5), and DOT Order 2100.6A. The Office of Information
and Regulatory Affairs (OIRA) has not designated this rule as a ``major
rule'' as defined by the Congressional Review Act (5 U.S.C. 801 et
seq.).
Executive Order 12866 and DOT Order 2100.6A also require PHMSA to
provide a meaningful opportunity for public participation, which also
reinforces requirements for notice and comment under the Administrative
Procedure Act (5 U.S.C. 551 et seq.). Therefore, in the NPRM, PHMSA
sought public comment on its proposed revisions to the Federal Pipeline
Safety Regulations and the preliminary cost and benefit analyses in the
Preliminary RIA, as well as any information that could assist in
quantifying the costs and benefits of this rulemaking. Those comments
are addressed in this final rule, and additional discussion about the
costs and benefits of the final rule are provided within the RIA posted
in the rulemaking docket.
The table below summarizes the annualized costs for the provisions
in the final rule at a 3 percent and a 7 percent discount rate:
Table 1--Annualized Costs of the Final Rule
[Millions 2019$]
------------------------------------------------------------------------
7% 3%
System type Discount Discount
rate rate
------------------------------------------------------------------------
Natural gas....................................... $2.5 $1.0
Hazardous liquid.................................. 3.4 1.5
---------------------
Total........................................... 5.9 2.5
------------------------------------------------------------------------
The benefits of the final rule consist of improved safety and
avoided unquantified environmental harms (including, but not limited
to, unquantified greenhouse gas emissions) from 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. Benefits of the final rule will depend on
the degree to which compliance actions result in additional safety
measures, relative to the baseline, and the effectiveness of these
measures in preventing or mitigating future pipeline releases or other
incidents.
C. Executive Order 13132: Federalism
PHMSA analyzed this final rule in accordance with Executive Order
13132 (``Federalism'').\51\ Executive Order 13132 requires agencies to
assure meaningful and timely input by State and local officials in the
development of regulatory policies that may have ``substantial direct
effects on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government.''
---------------------------------------------------------------------------
\51\ 64 FR 43255 (Aug. 10, 1999).
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The final rule does not have a substantial direct effect on the
State and local governments, the relationship between the Federal
government and the States, or the distribution of power and
responsibilities among the various levels of government. This
rulemaking action does not impose substantial direct compliance costs
on State and local governments. Section 60104(c) of Title 49 of the
United States Code prohibits certain State safety regulation of
interstate pipelines. States can augment pipeline safety requirements
for intrastate pipelines regulated by PHMSA, but may not approve safety
requirements less stringent than those required by Federal law. A State
may also regulate an intrastate pipeline facility that PHMSA does not
regulate. The preemptive effect of this final rule is limited to the
minimum level necessary to achieve the objectives of the statutory
authorities under which the final rule is promulgated. Therefore, the
consultation and funding requirements of Executive Order 13132 do not
apply.
D. Regulatory Flexibility Act
The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) requires
agencies to prepare a Final Regulatory Flexibility Analysis (FRFA) for
any final rule subject to notice-and-comment rulemaking under the
Administrative Procedure Act unless the agency head certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. This final rule was developed in accordance
with Executive Order 13272 (``Proper Consideration of Small Entities in
Agency Rulemaking'') \52\ to promote compliance with the Regulatory
Flexibility Act and to ensure that the potential impacts of the
rulemaking on small entities has been properly considered.
---------------------------------------------------------------------------
\52\ 67 FR 53461 (Aug. 16, 2002).
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PHMSA prepared a FRFA, which is available in the docket for the
rulemaking. In it, PHMSA certifies that the rule will not have a
significant impact on a substantial number of small entities.
[[Page 20979]]
E. National Environmental Policy Act
The National Environmental Policy Act (42 U.S.C. 4321 et seq.;
NEPA) requires Federal agencies to consider the consequences of major
Federal actions and prepare a detailed statement on actions
significantly affecting the quality of the human environment. The
Council on Environmental Quality implementing regulations (40 CFR parts
1500-1508) require Federal agencies to conduct an environmental review
considering (1) the need for the action, (2) alternatives to the
action, (3) probable environmental impacts of the action and
alternatives, and (4) the agencies and persons consulted during the
consideration process. DOT Order 5610.1C (``Procedures for Considering
Environmental Impacts'') establishes departmental procedures for
evaluation of environmental impacts under NEPA and its implementing
regulations.
PHMSA has completed its NEPA analysis. Based on the final
Environmental Assessment (EA), PHMSA determined that an environmental
impact statement is not required for this rulemaking because it will
not have a significant impact on the human environment. The final EA
and Finding of No Significant Impact have been placed into the docket
and address comments received on an earlier draft EA.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
PHMSA analyzed this final rule per the principles and criteria in
Executive Order 13175 (``Consultation and Coordination With Indian
Tribal Governments'') \53\ and DOT Order 5301.1 (``Department of
Transportation Policies, Programs, and Procedures Affecting American
Indians, Alaska Natives, and Tribes''). Executive Order 13175 requires
agencies to assure meaningful and timely input from Tribal Government
representatives in the development of rules that significantly or
uniquely affect Tribal communities by imposing ``substantial direct
compliance costs'' or ``substantial direct effects'' on such
communities or the relationship and distribution of power between the
Federal Government and Tribes.
---------------------------------------------------------------------------
\53\ 65 FR 67249 (Nov. 6, 2000).
---------------------------------------------------------------------------
PHMSA assessed the impact of the rulemaking and determined that it
would not significantly or uniquely affect Tribal communities or Tribal
governments. The rulemaking's regulatory amendments are facially
neutral and would have broad, national scope; PHMSA, therefore, does
not expect this rulemaking to significantly or uniquely affect Tribal
communities, much less impose substantial compliance costs on Native
American Tribal governments or mandate Tribal action. And insofar as
PHMSA expects the rulemaking will improve pipeline safety and reduce
environmental risks, PHMSA does not expect it would entail
disproportionately high adverse risks for Tribal communities. PHMSA
also received no comments alleging ``substantial direct compliance
costs'' or ``substantial direct effects'' on Tribal communities and
Governments. For these reasons, PHMSA has determined the funding and
consultation requirements of Executive Order 13175 and DOT Order 5301.1
do not apply.
G. Executive Order 13211
Executive Order 13211 (``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use'') \54\
requires Federal agencies to prepare a Statement of Energy Effects for
any ``significant energy action.'' Executive Order 13211 defines a
``significant energy action'' as any action by an agency (normally
published in the Federal Register) that promulgates, or is expected to
lead to the promulgation of, a final rule or regulation that (1) (i) is
a significant regulatory action under Executive Order 12866 or any
successor order and (ii) is likely to have a significant adverse effect
on the supply, distribution, or use of energy (including a shortfall in
supply, price increases, and increased use of foreign supplies); or (2)
is designated by the Administrator of the OIRA as a significant energy
action.
---------------------------------------------------------------------------
\54\ 66 FR 28355 (May 18, 2001).
---------------------------------------------------------------------------
This final rule is a significant action under Executive Order
12866; however, it is expected to have an annual effect on the economy
of less than $100 million. Further, this action is not likely to have a
significant adverse effect on the supply, distribution, or use of
energy in the United States. The Administrator of OIRA has not
designated the final rule as a significant energy action. For
additional discussion of the anticipated economic impact of this
rulemaking, please review the RIA posted in the rulemaking docket.
H. Paperwork Reduction Act
Under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.),
no person is required to respond to an information collection unless it
has been approved by OMB and displays a valid OMB control number.
Pursuant to implementing regulations at 5 CFR 1320.8(d), PHMSA is
required to provide interested members of the public and affected
agencies with an opportunity to comment on information collection and
recordkeeping requests.
PHMSA published an NPRM seeking public comment on its proposed
revisions to the Federal Pipeline Safety Regulations finalized in this
rulemaking. Based on comments received and the updated provisions
contained within this final rule, PHMSA is expanding the notification
and recordkeeping requirements for gas and hazardous liquid pipeline
operators. The provisions in this final rule include the following
Paperwork Reduction Act impacts:
Operators are required to document certain procedures and to
maintain records pertaining to various aspects of their RMV and
alternative equivalent technology operations. Operators who have
experienced a rupture or RMV shut-off are required to complete a post-
incident or -accident analysis. The summary of this analysis, all
documents used to prepare it, and records of lessons learned must be
kept for the useful life of the pipeline.
Operators must also develop written rupture identification
procedures to evaluate and identify whether a notification of potential
rupture is an actual rupture event or non-rupture event. These
procedures must, at a minimum, specify the sources of information,
operational factors, and other criteria that operator personnel use to
evaluate a notification of potential rupture.
The final rule (at 49 CFR 192.179 and 49 CFR 195.258) requires
operators who elect to use alternative equivalent technology to notify
PHMSA's Office of Pipeline Safety at least 90 days in advance of use.
An operator choosing this option must submit a technical and safety
evaluation (including design, construction, and operating procedures)
for the alternative equivalent technology to the Associate
Administrator of Pipeline Safety with the notification. PHMSA would
then have 90 days to object to the alternative equivalent technology
via letter from the Associate Administrator of Pipeline Safety;
otherwise, the alternative equivalent technology would be acceptable
for use. Operators who wish to use a manual valve as an alternative
equivalent technology will also be required to include within their
notification to PHMSA an explanation that installation of an RMV would
be economically, technically, or operationally infeasible.
An operator may seek PHMSA's approval for an exemption from several
other regulatory installation and
[[Page 20980]]
operational requirements under the final rule by notifying PHMSA in
certain instances. For example, an operator of a gas pipeline may plan
to leave an RMV open for more than 30 minutes following rupture
identification if the operator demonstrates to PHMSA, in accordance
with the notification procedures in Sec. 192.18, that closing an RMV,
or alternative equivalent technology would be detrimental to public
safety. Likewise, for hazardous liquid pipeline segments not in an HCA
and which could not affect an HCA, an operator may request exemption
from specified requirements if it can demonstrate to PHMSA, in
accordance with the notification procedures in Sec. 195.18, that
installing an otherwise-required RMV, or alternative equivalent
technology, would be economically, technically, or operationally
infeasible. Similarly, the maximum valve spacing for HVL pipelines can
be increased by 1.25 times the distance to a maximum of 9 \3/8\ miles
if the operator submits a notification for PHMSA review demonstrating
that the installation of a valve at the otherwise-required spacing is
economically, technically, or operationally infeasible. Lastly, the
final rule also identifies procedures for operators of gas and
hazardous liquid lines to submit for PHMSA review a notification
requesting extension of required timelines (e.g., for RMV or
alternative equivalent technology installation, RMV operability post-
installation) specified in the final rule.
PHMSA proposes to create an information collection under OMB
Control Number 2137-0637 titled, ``Rupture Mitigation Valve
Recordkeeping Requirements'' to account for the expanded recordkeeping
requirements in this final rule. PHMSA also proposes to create an
information collection under OMB Control Number 2137-0638 titled,
``Rupture Mitigation Valve Notification Requirements'' to account for
the expanded notification requirements in this final rule.
PHMSA will request approval of these information collections from
the Office of Management and Budget (OMB) based on the requirements
that trigger components of the Paperwork Reduction Act and will notify
the public through a separate notice published in the Federal Register
upon OMB approval of the information collection requirements.
The following information is provided for each of these information
collections: (1) Title of the information collection; (2) OMB control
number; (3) current expiration date; (4) type of request; (5) abstract
of the information collection activity; (6) description of affected
public; (7) estimate of total annual reporting and recordkeeping
burden; and (8) frequency of collection. The information collection
burdens are estimated as follows:
1. Title: ``Rupture Mitigation Valve Recordkeeping Requirements.''
OMB Control Number: 2137-0637.
Current Expiration Date: To be determined by OMB.
Abstract: The ``Amendments to parts 192 and 195 to Require Valve
Installation and Minimum Rupture Detection Standards Final Rule''
requires operators of gas and hazardous liquid pipelines to document
certain procedures and to maintain records pertaining to various
aspects of their RMV and alternative equivalent technology operations.
Operators who have experienced a rupture or RMV valve shut-off are
required to complete a post-incident review. The post-incident summary,
all investigation and analysis documents used to prepare it, and
records of lessons learned must be kept for the life of the pipeline.
PHMSA estimates that it will take operators, on average, 40 hours to
comply with this requirement.
Operators must also develop written rupture identification
procedures to evaluate and identify whether a notification of potential
rupture is an actual rupture event or non-rupture event as soon as
practicable. These procedures must, at a minimum, specify the sources
of information, operational factors, and other criteria that operator
personnel use to evaluate a notification of potential rupture. PHMSA
estimates that it will take operators 40 hours to comply with this
requirement. Operators are also required to maintain certain records if
they experience certain circumstances involving their RMV operations.
On average, PHMSA expects that it will take operators 8 hours to
complete these recordkeeping requirements.
PHMSA estimates that 1,812 operators (1,304 natural gas and 508
hazardous liquid operators) will be potentially impacted by these
requirements. At minimum, all 1,812 operators will be required to
develop written rupture identification procedures. PHMSA estimates 46
of these operators will experience a rupture that will require the
completion of a post-incident or -accident summary. PHMSA expects that
10 percent of the affected community will be subject to the various
other recordkeeping requirements. As a result, PHMSA expects this
information collection to result in 4,213 responses and 85,724 burden
hours annually.
Affected Public: Operators of PHMSA-Regulated Pipelines.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 4,213.
Total Annual Burden Hours: 85,724.
Frequency of Collection: On occasion.
2. Title: ``Rupture Mitigation Valve Notification Requirements.''
OMB Control Number: 2137-0638.
Current Expiration Date: To be determined by OMB.
Abstract: The ``Amendments to Parts 192 and 195 to Require Valve
Installation and Minimum Rupture Detection Standards Final Rule''
requires operators to notify PHMSA in certain instances regarding
installation and operation of RMVs and alternative equivalent
technologies. 49 CFR 192.179 and 195.258 require operators who elect to
use alternative equivalent technology to notify the Office of Pipeline
Safety at least 90 days in advance of use. An operator choosing this
option must include a technical and safety evaluation, including
design, construction, and operating procedures for the alternative
equivalent technology with the notification. Operators who wish to use
a manual valve as an alternative equivalent technology will also be
required to include within their notification to PHMSA an explanation
that installation of an RMV would be economically, technically, or
operationally infeasible. PHMSA expects most operators to use standard
technology and, as such, estimates this notification requirement will
result in approximately four responses annually. PHMSA estimates each
operator will spend 40 hours annually compiling the necessary
components of this notification requirement.
Operators must notify PHMSA if an RMV cannot be made operational
within 14 days of installation. Operators must also notify PHMSA if a
valve cannot be repaired or replaced within 12 months. PHMSA expects
roughly 10 percent of operators to experience these circumstances
taking 2 hours to complete the notification requirement.
An operator may seek exemption from certain regulatory requirements
by notifying PHMSA in certain instances. For example, an operator may
plan to leave an RMV open for more than 30 minutes following rupture
identification if the operator demonstrates to PHMSA, that closing an
RMV, or alternative equivalent technology, would be detrimental to
public safety.
Likewise, for hazardous liquid pipeline segments not in an HCA
which could not affect an HCA, an operator may request exemption from
certain requirements if it can demonstrate to
[[Page 20981]]
PHMSA that installing an otherwise-required RMV, or alternative
equivalent technology, would be economically, technically, or
operationally infeasible. PHMSA expects 10 percent of operators to make
each of these and other notifications annually. PHMSA estimates that it
will take operators, on average, 8 hours to make these notifications.
Affected Public: Operators of PHMSA-Regulated Pipelines.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 598.
Total Annual Burden Hours: 2,378.
Frequency of Collection: On occasion.
Questions regarding these information collections should be
directed to Angela Hill, Office of Pipeline Safety (PHP-30), Pipeline
and Hazardous Materials Safety Administration, 2nd Floor, 1200 New
Jersey Avenue SE, Washington, DC 20590-0001. Telephone: 202-366-1246.
I. Unfunded Mandates Reform Act of 1995
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1501 et seq.)
requires agencies to assess the effects of Federal regulatory actions
on State, local, and Tribal governments, and the private sector. For
any NPRM or final rule that includes a Federal mandate that may result
in the expenditure by State, local, and Tribal governments, in the
aggregate, or by the private sector of $100 million or more (adjusted
annually for inflation) in any given year, the agency must prepare,
among other things, a written statement that qualitatively and
quantitatively assesses the costs and benefits of the Federal mandate.
As explained in the RIA, PHMSA determined that this final rule does
not impose enforceable duties on State, local, or Tribal governments or
on the private sector of $100 million or more (adjusted annually for
inflation) in any one year. A copy of the RIA is available for review
in the docket. Therefore, the Department has determined that no
assessment is required pursuant to UMRA.
J. Privacy Act Statement
Anyone may search the electronic form of all comments received for
any of our dockets. You may review DOT's complete Privacy Act Statement
\55\ at http://www.dot.gov/privacy.
---------------------------------------------------------------------------
\55\ 65 FR 19476 (Apr. 11, 2000).
---------------------------------------------------------------------------
K. Regulation Identifier Number
A regulation identifier number (RIN) is assigned to each regulatory
action listed in the Unified Agenda of Federal Regulations. The
Regulatory Information Service Center publishes the Unified Agenda in
April and October of each year. The RIN number contained in the heading
of this document can be used to cross-reference this action with the
Unified Agenda.
L. Executive Order 13609 and International Trade Analysis
Executive Order 13609 (``Promoting International Regulatory
Cooperation'') \56\ requires agencies consider whether the impacts
associated with significant variations between domestic and
international regulatory approaches are unnecessary or may impair the
ability of American business to export and compete internationally. In
meeting shared challenges involving health, safety, labor, security,
environmental, and other issues, international regulatory cooperation
can identify approaches that are at least as protective as those that
are or would be adopted in the absence of such cooperation.
International regulatory cooperation can also reduce, eliminate, or
prevent unnecessary differences in regulatory requirements.
---------------------------------------------------------------------------
\56\ 77 FR 26413 (May 4, 2012).
---------------------------------------------------------------------------
Similarly, the Trade Agreements Act of 1979 (Pub. L. 96-39), as
amended by the Uruguay Round Agreements Act (Pub. L. 103-465),
prohibits Federal agencies from establishing any standards or engaging
in related activities that create unnecessary obstacles to the foreign
commerce of the United States. For purposes of these requirements,
Federal agencies may participate in the establishment of international
standards, so long as the standards have a legitimate domestic
objective, such as providing for safety, and do not operate to exclude
imports that meet this objective. The statute also requires
consideration of international standards and, where appropriate, that
they be the basis for U.S. standards.
PHMSA participates in the establishment of international standards
to protect the safety of the American public. PHMSA has assessed the
effects of the rulemaking and determined that it will not cause
unnecessary obstacles to foreign trade.
M. Environmental Justice
DOT Order 5610.2(b) and Executive Orders 12898 (``Federal Actions
to Address Environmental Justice in Minority Populations and Low-Income
Populations''),\57\ 13985 (``Advancing Racial Equity and Support for
Underserved Communities Through the Federal Government''),\58\ 13990,
and 14008 require DOT operational administrations to achieve
environmental justice as part of their mission by identifying and
addressing, as appropriate, disproportionately high and adverse human
health or environmental effects, including interrelated social and
economic effects, of their programs, policies, and activities on
minority populations, low-income populations, and other underserved
disadvantaged communities.
---------------------------------------------------------------------------
\57\ 59 FR 7629 (Feb. 16, 1994).
\58\ 86 FR 7009 (Jan. 20, 2021).
---------------------------------------------------------------------------
PHMSA has evaluated this final rule under DOT Order 5610.2(b) and
the Executive Orders listed above and determined it will not cause
disproportionately high and adverse human health and environmental
effects on minority populations, low-income populations, or other
underserved and disadvantaged communities. The rulemaking is facially
neutral and national in scope; it is neither directed toward a
particular population, region, or community, nor is it expected to
adversely impact any particular population, region, or community. And
insofar as PHMSA expects the rulemaking would reduce the safety and
environmental risks associated with affected natural gas and hazardous
liquid pipelines, many of which are sited in the vicinity of
environmental justice communities,\59\ PHMSA does not expect the
regulatory amendments introduced by this final rule would entail
disproportionately high adverse risks for minority populations, low-
income populations, or other underserved and other disadvantaged
communities in the vicinity of those pipelines. Lastly, as explained in
final EA, PHMSA expects that the regulatory amendments in this final
rule will yield GHG emissions reductions, thereby reducing the risks
posed by anthropogenic climate change to minority, low-income,
underserved, and other disadvantaged populations and communities.
---------------------------------------------------------------------------
\59\ See Ryan Emmanuel, et al., ``Natural Gas Gathering and
Transmission Pipelines and Social Vulnerability in the United
States,'' 5:6 GeoHealth (June 2021), https://agupubs.onlinelibrary.wiley.com/toc/24711403/2021/5/6 (concluding
that natural gas gathering and transmission infrastructure is
disproportionately sited in socially-vulnerable communities).
---------------------------------------------------------------------------
List of Subjects
49 CFR Part 192
Gas, Natural gas, Pipeline safety, Reporting and recordkeeping
requirements.
[[Page 20982]]
49 CFR Part 195
Anhydrous ammonia, Carbon dioxide, Petroleum, Pipeline safety,
Reporting and recordkeeping requirements.
In consideration of the foregoing, PHMSA amends 49 CFR parts 192
and 195 as follows:
PART 192--TRANSPORTATION OF NATURAL GAS AND OTHER GAS BY PIPELINE:
MINIMUM FEDERAL SAFETY STANDARDS
0
1. The authority citation for part 192 continues to read as follows:
Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et seq.,
and 49 CFR 1.97.
0
2. In Sec. 192.3, definitions for ``entirely replaced onshore
transmission pipeline segments'', ``notification of potential
rupture'', and ``rupture-mitigation valve'' are added in alphabetical
order to read as follows:
Sec. 192.3 Definitions.
* * * * *
Entirely replaced onshore transmission pipeline segments means, for
the purposes of Sec. Sec. 192.179 and 192.634, where 2 or more miles,
in the aggregate, of onshore transmission pipeline have been replaced
within any 5 contiguous miles of pipeline within any 24-month period.
* * * * *
Notification of potential rupture means the notification to, or
observation by, an operator of indicia identified in Sec. 192.635 of a
potential unintentional or uncontrolled release of a large volume of
gas from a pipeline.
* * * * *
Rupture-mitigation valve (RMV) means an automatic shut-off valve
(ASV) or a remote-control valve (RCV) that a pipeline operator uses to
minimize the volume of gas released from the pipeline and to mitigate
the consequences of a rupture.
* * * * *
0
3. In Sec. 192.9, paragraphs (d)(1) and (e)(1)(i) are revised to read
as follows:
Sec. 192.9 What requirements apply to gathering lines?
* * * * *
(d) * * *
(1) If a line is new, replaced, relocated, or otherwise changed,
the design, installation, construction, initial inspection, and initial
testing must be in accordance with requirements of this part applicable
to transmission lines. Compliance with Sec. Sec. 192.67, 192.127,
192.179(e), 192.179(f), 192.205, 192.227(c), 192.285(e), 192.506,
192.634, and 192.636 is not required.
* * * * *
(e) * * *
(1) * * *
(i) Except as provided in paragraph (h) of this section for pipe
and components made with composite materials, the design, installation,
construction, initial inspection, and initial testing of a new,
replaced, relocated, or otherwise changed Type C gathering line, must
be done in accordance with the requirements in subparts B though G and
J of this part applicable to transmission lines. Compliance with
Sec. Sec. 192.67, 192.127, 192.179(e), 192.179(f), 192.205,
192.227(c), 192.285(e), 192.506, 192.634, and 192.636 is not required;
* * * * *
0
4. In Sec. 192.18, paragraph (c) is revised to read as follows:
Sec. 192.18 How to notify PHMSA.
* * * * *
(c) Unless otherwise specified, if an operator submits, pursuant to
Sec. 192.8, Sec. 192.9, Sec. 192.179, Sec. 192.506, Sec. 192.607,
Sec. 192.619, Sec. 192.624, Sec. 192.632, Sec. 192.634, Sec.
192.636, Sec. 192.710, Sec. 192.712, Sec. 192.745, Sec. 192.921, or
Sec. 192.937, a notification for use of a different integrity
assessment method, analytical method, sampling approach, or technique
(e.g., ``other technology'' or ``alternative equivalent technology'')
than otherwise prescribed in those sections, that notification must be
submitted to PHMSA for review at least 90 days in advance of using the
other method, approach, compliance timeline, or technique. An operator
may proceed to use the other method, approach, compliance timeline, or
technique 91 days after submitting the notification unless it receives
a letter from the Associate Administrator for Pipeline Safety informing
the operator that PHMSA objects to the proposal, or that PHMSA requires
additional time and/or more information to conduct its review.
0
5. In Sec. 192.179, paragraphs (e) through (h) are added to read as
follows:
Sec. 192.179 Transmission line valves.
* * * * *
(e) For onshore transmission pipeline segments with diameters
greater than or equal to 6 inches that are constructed after April 10,
2023, the operator must install rupture-mitigation valves (RMV) or an
alternative equivalent technology whenever a valve must be installed to
meet the appropriate valve spacing requirements of this section. An
operator seeking to use alternative equivalent technology must notify
PHMSA in accordance with the procedures set forth in paragraph (g) of
this section. All RMVs and alternative equivalent technologies
installed pursuant to this paragraph must meet the requirements of
Sec. Sec. 192.634 and 192.636. Exempted from this paragraph's
installation requirements are pipeline segments in Class 1, or Class 2
locations that have a potential impact radius (PIR), as defined in
Sec. 192.903, of 150 feet or less. An operator may request an
extension of the installation compliance deadline requirements of this
paragraph (e) if it can demonstrate to PHMSA, in accordance with the
notification procedures in Sec. 192.18, that those installation
compliance deadlines would be economically, technically, or
operationally infeasible for a particular new pipeline.
(f) For entirely replaced onshore transmission pipeline segments,
as defined in Sec. 192.3, with diameters greater than or equal to 6
inches and that are installed after April 10, 2023, the operator must
install RMVs or an alternative equivalent technology whenever a valve
must be installed to meet the appropriate valve spacing requirements of
this section. An operator seeking to use alternative equivalent
technology must notify PHMSA in accordance with the procedures set
forth in paragraph (g) of this section. All RMVs and alternative
equivalent technologies installed pursuant to this paragraph must meet
the requirements of Sec. Sec. 192.634 and 192.636. The requirements of
this paragraph apply when the applicable pipeline replacement project
involves a valve, either through addition, replacement, or removal.
This paragraph's installation requirements do not apply to pipe
segments in Class 1 or Class 2 locations that have a PIR, as defined in
Sec. 192.903, that is less than or equal to 150 feet. An operator may
request an extension of the installation compliance deadline
requirements of this paragraph if it can demonstrate to PHMSA, in
accordance with the notification procedures in Sec. 192.18, that those
installation compliance deadlines would be economically, technically,
or operationally infeasible for a particular pipeline replacement
project.
(g) If an operator elects to use alternative equivalent technology
in accordance with paragraph (e) or (f) of this section, the operator
must notify PHMSA in accordance with the procedures in Sec. 192.18.
The operator must include a technical and safety evaluation in its
notice to PHMSA. Valves that are installed as alternative equivalent
technology must comply with Sec. Sec. 192.634 and 192.636. An operator
requesting use of manual valves as an alternative equivalent
[[Page 20983]]
technology must also include within the notification submitted to PHMSA
a demonstration that installation of an RMV as otherwise required would
be economically, technically, or operationally infeasible. An operator
may use a manual compressor station valve at a continuously manned
station as an alternative equivalent technology, and use of such valve
would not require a notification to PHMSA in accordance with Sec.
192.18, but it must comply with Sec. 192.636.
(h) The valve spacing requirements of paragraph (a) of this section
do not apply to pipe replacements on a pipeline if the distance between
each point on the pipeline and the nearest valve does not exceed:
(1) Four (4) miles in Class 4 locations, with a total spacing
between valves no greater than 8 miles;
(2) Seven-and-a-half (7\1/2\) miles in Class 3 locations, with a
total spacing between valves no greater than 15 miles; or
(3) Ten (10) miles in Class 1 or 2 locations, with a total spacing
between valves no greater than 20 miles.
0
6. Section 192.610 is added to read as follows:
Sec. 192.610 Change in class location: Change in valve spacing.
(a) If a class location change on a transmission pipeline occurs
after October 5, 2022, and results in pipe replacement, of 2 or more
miles, in the aggregate, within any 5 contiguous miles within a 24-
month period, to meet the maximum allowable operating pressure (MAOP)
requirements in Sec. 192.611, Sec. 192.619, or Sec. 192.620, then
the requirements in Sec. Sec. 192.179, 192.634, and 192.636, as
applicable, apply to the new class location, and the operator must
install valves, including rupture-mitigation valves (RMV) or
alternative equivalent technologies, as necessary, to comply with those
sections. Such valves must be installed within 24 months of the class
location change in accordance with the timing requirement in Sec.
192.611(d) for compliance after a class location change.
(b) If a class location change occurs after October 5, 2022, and
results in pipe replacement of less than 2 miles within 5 contiguous
miles during a 24-month period, to meet the MAOP requirements in Sec.
192.611, Sec. 192.619, or Sec. 192.620, then within 24 months of the
class location change, in accordance with Sec. 192.611(d), the
operator must either:
(1) Comply with the valve spacing requirements of Sec. 192.179(a)
for the replaced pipeline segment; or
(2) Install or use existing RMVs or alternative equivalent
technologies so that the entirety of the replaced pipeline segments are
between at least two RMVs or alternative equivalent technologies. The
distance between RMVs and alternative equivalent technologies for the
replaced segment must not exceed 20 miles. The RMVs and alternative
equivalent technologies must comply with the applicable requirements of
Sec. 192.636.
(c) The provisions of paragraph (b) of this section do not apply to
pipeline replacements that amount to less than 1,000 feet within any
one contiguous mile during any 24-month period.
0
7. In Sec. 192.615, paragraphs (a)(2), (6), (8), and (11) are revised,
paragraph (a)(12) is added, and paragraph (c) introductory text is
revised to read as follows:
Sec. 192.615 Emergency plans.
(a) * * *
(2) Establishing and maintaining adequate means of communication
with the appropriate public safety answering point (i.e., 9-1-1
emergency call center), where direct access to a 9-1-1 emergency call
center is available from the location of the pipeline, and fire,
police, and other public officials. Operators may establish liaison
with the appropriate local emergency coordinating agencies, such as 9-
1-1 emergency call centers or county emergency managers, in lieu of
communicating individually with each fire, police, or other public
entity. An operator must determine the responsibilities, resources,
jurisdictional area(s), and emergency contact telephone number(s) for
both local and out-of-area calls of each Federal, State, and local
government organization that may respond to a pipeline emergency, and
inform such officials about the operator's ability to respond to a
pipeline emergency and the means of communication during emergencies.
* * * * *
(6) Taking necessary actions, including but not limited to,
emergency shutdown, valve shut-off, or pressure reduction, in any
section of the operator's pipeline system, to minimize hazards of
released gas to life, property, or the environment.
* * * * *
(8) Notifying the appropriate public safety answering point (i.e.,
9-1-1 emergency call center) where direct access to a 9-1-1 emergency
call center is available from the location of the pipeline, and fire,
police, and other public officials, of gas pipeline emergencies to
coordinate and share information to determine the location of the
emergency, including both planned responses and actual responses during
an emergency. The operator must immediately and directly notify the
appropriate public safety answering point or other coordinating agency
for the communities and jurisdictions in which the pipeline is located
after receiving a notification of potential rupture, as defined in
Sec. 192.3, to coordinate and share information to determine the
location of any release, regardless of whether the segment is subject
to the requirements of Sec. 192.179, Sec. 192.634, or Sec. 192.636.
* * * * *
(11) Actions required to be taken by a controller during an
emergency in accordance with the operator's emergency plans and
requirements set forth in Sec. Sec. 192.631, 192.634, and 192.636.
(12) Each operator must develop written rupture identification
procedures to evaluate and identify whether a notification of potential
rupture, as defined in Sec. 192.3, is an actual rupture event or a
non-rupture event. These procedures must, at a minimum, specify the
sources of information, operational factors, and other criteria that
operator personnel use to evaluate a notification of potential rupture
and identify an actual rupture. For operators installing valves in
accordance with Sec. 192.179(e), Sec. 192.179(f), or that are subject
to the requirements in Sec. 192.634, those procedures must provide for
rupture identification as soon as practicable.
* * * * *
(c) Each operator must establish and maintain liaison with the
appropriate public safety answering point (i.e., 9-1-1 emergency call
center) where direct access to a 9-1-1 emergency call center is
available from the location of the pipeline, as well as fire, police,
and other public officials, to:
* * * * *
0
8. Section 192.617 is revised to read as follows:
Sec. 192.617 Investigation of failures and incidents.
(a) Post-failure and incident procedures. Each operator must
establish and follow procedures for investigating and analyzing
failures and incidents as defined in Sec. 191.3, including sending the
failed pipe, component, or equipment for laboratory testing or
examination, where appropriate, for the purpose of determining the
causes and contributing factor(s) of the failure or incident and
[[Page 20984]]
minimizing the possibility of a recurrence.
(b) Post-failure and incident lessons learned. Each operator must
develop, implement, and incorporate lessons learned from a post-failure
or incident review into its written procedures, including personnel
training and qualification programs, and design, construction, testing,
maintenance, operations, and emergency procedure manuals and
specifications.
(c) Analysis of rupture and valve shut-offs. If an incident on an
onshore gas transmission pipeline or a Type A gathering pipeline
involves the closure of a rupture-mitigation valve (RMV), as defined in
Sec. 192.3, or the closure of alternative equivalent technology, the
operator of the pipeline must also conduct a post-incident analysis of
all of the factors that may have impacted the release volume and the
consequences of the incident and identify and implement operations and
maintenance measures to prevent or minimize the consequences of a
future incident. The requirements of this paragraph (c) are not
applicable to distribution pipelines or Types B and C gas gathering
pipelines. The analysis must include all relevant factors impacting the
release volume and consequences, including, but not limited to, the
following:
(1) Detection, identification, operational response, system shut-
off, and emergency response communications, based on the type and
volume of the incident;
(2) Appropriateness and effectiveness of procedures and pipeline
systems, including supervisory control and data acquisition (SCADA),
communications, valve shut-off, and operator personnel;
(3) Actual response time from identifying a rupture following a
notification of potential rupture, as defined at Sec. 192.3, to
initiation of mitigative actions and isolation of the pipeline segment,
and the appropriateness and effectiveness of the mitigative actions
taken;
(4) Location and timeliness of actuation of RMVs or alternative
equivalent technologies; and
(5) All other factors the operator deems appropriate.
(d) Rupture post-failure and incident summary. If a failure or
incident on an onshore gas transmission pipeline or a Type A gathering
pipeline involves the identification of a rupture following a
notification of potential rupture, or the closure of an RMV (as those
terms are defined in Sec. 192.3), or the closure of an alternative
equivalent technology, the operator of the pipeline must complete a
summary of the post-failure or incident review required by paragraph
(c) of this section within 90 days of the incident, and while the
investigation is pending, conduct quarterly status reviews until the
investigation is complete and a final post-incident summary is
prepared. The final post-failure or incident summary, and all other
reviews and analyses produced under the requirements of this section,
must be reviewed, dated, and signed by the operator's appropriate
senior executive officer. The final post-failure or incident summary,
all investigation and analysis documents used to prepare it, and
records of lessons learned must be kept for the useful life of the
pipeline. The requirements of this paragraph (d) are not applicable to
distribution pipelines or Types B and C gas gathering pipelines.
0
9. Section 192.634 is added to read as follows:
Sec. 192.634 Transmission lines: Onshore valve shut-off for rupture
mitigation.
(a) Applicability. For new or entirely replaced onshore
transmission pipeline segments with diameters of 6 inches or greater
that are located in high-consequence areas (HCA) or Class 3 or Class 4
locations and that are installed after April 10, 2023, an operator must
install or use existing rupture-mitigation valves (RMV), or an
alternative equivalent technology, according to the requirements of
this section and Sec. Sec. 192.179 and 192.636. RMVs and alternative
equivalent technologies must be operational within 14 days of placing
the new or replaced pipeline segment into service. An operator may
request an extension of this 14-day operation requirement if it can
demonstrate to PHMSA, in accordance with the notification procedures in
Sec. 192.18, that application of that requirement would be
economically, technically, or operationally infeasible. The
requirements of this section apply to all applicable pipe replacement
projects, even those that do not otherwise involve the addition or
replacement of a valve. This section does not apply to pipe segments in
Class 1 or Class 2 locations that have a potential impact radius (PIR),
as defined in Sec. 192.903, that is less than or equal to 150 feet.
(b) Maximum spacing between valves. RMVs, or alternative equivalent
technology, must be installed in accordance with the following
requirements:
(1) Shut-off segment. For purposes of this section, a ``shut-off
segment'' means the segment of pipe located between the upstream valve
closest to the upstream endpoint of the new or replaced Class 3 or
Class 4 or HCA pipeline segment and the downstream valve closest to the
downstream endpoint of the new or replaced Class 3 or Class 4 or HCA
pipeline segment so that the entirety of the segment that is within the
HCA or the Class 3 or Class 4 location is between at least two RMVs or
alternative equivalent technologies. If any crossover or lateral pipe
for gas receipts or deliveries connects to the shut-off segment between
the upstream and downstream valves, the shut-off segment also must
extend to a valve on the crossover connection(s) or lateral(s), such
that, when all valves are closed, there is no flow path for gas to be
transported to the rupture site (except for residual gas already in the
shut-off segment). Multiple Class 3 or Class 4 locations or HCA
segments may be contained within a single shut-off segment. The
operator is not required to select the closest valve to the shut-off
segment as the RMV, as that term is defined in Sec. 192.3, or the
alternative equivalent technology. An operator may use a manual
compressor station valve at a continuously manned station as an
alternative equivalent technology, but it must be able to be closed
within 30 minutes following rupture identification, as that term is
defined at Sec. 192.3. Such a valve used as an alternative equivalent
technology would not require a notification to PHMSA in accordance with
Sec. 192.18.
(2) Shut-off segment valve spacing. A pipeline subject to paragraph
(a) of this section must have RMVs or alternative equivalent technology
on the upstream and downstream side of the pipeline segment. The
distance between RMVs or alternative equivalent technologies must not
exceed:
(i) Eight (8) miles for any Class 4 location,
(ii) Fifteen (15) miles for any Class 3 location, or
(iii) Twenty (20) miles for all other locations.
(3) Laterals. Laterals extending from shut-off segments that
contribute less than 5 percent of the total shut-off segment volume may
have RMVs or alternative equivalent technologies that meet the
actuation requirements of this section at locations other than mainline
receipt/delivery points, as long as all of the laterals contributing
gas volumes to the shut-off segment do not contribute more than 5
percent of the total shut-off segment gas volume based upon maximum
flow volume at the operating pressure. For laterals that are 12 inches
in diameter or less, a check valve that allows gas to flow freely in
one direction and contains a mechanism to automatically prevent flow in
the other direction may be used as an alternative equivalent technology
where it is
[[Page 20985]]
positioned to stop flow into the shut-off segment. Such check valves
that are used as an alternative equivalent technology in accordance
with this paragraph are not subject to Sec. 192.636, but they must be
inspected, operated, and remediated in accordance with Sec. 192.745,
including for closure and leakage to ensure operational reliability. An
operator using such a check valve as an alternative equivalent
technology must notify PHMSA in accordance with Sec. Sec. 192.18 and
192.179 develop and implement maintenance procedures for such equipment
that meet Sec. 192.745.
(4) Crossovers. An operator may use a manual valve as an
alternative equivalent technology in lieu of an RMV for a crossover
connection if, during normal operations, the valve is closed to prevent
the flow of gas by the use of a locking device or other means designed
to prevent the opening of the valve by persons other than those
authorized by the operator. The operator must develop and implement
operating procedures and document that the valve has been closed and
locked in accordance with the operator's lock-out and tag-out
procedures to prevent the flow of gas. An operator using such a manual
valve as an alternative equivalent technology must notify PHMSA in
accordance with Sec. Sec. 192.18 and 192.179.
(c) Manual operation upon identification of a rupture. Operators
using a manual valve as an alternative equivalent technology as
authorized pursuant to Sec. Sec. 192.18 and 192.179 must develop and
implement operating procedures that appropriately designate and locate
nearby personnel to ensure valve shut-off in accordance with this
section and Sec. 192.636. Manual operation of valves must include time
for the assembly of necessary operating personnel, the acquisition of
necessary tools and equipment, driving time under heavy traffic
conditions and at the posted speed limit, walking time to access the
valve, and time to shut off all valves manually, not to exceed the
maximum response time allowed under Sec. 192.636(b).
0
10. Section 192.635 is added to read as follows:
Sec. 192.635 Notification of potential rupture.
(a) As used in this part, a ``notification of potential rupture''
refers to the notification of, or observation by, an operator (e.g., by
or to its controller(s) in a control room, field personnel, nearby
pipeline or utility personnel, the public, local responders, or public
authorities) of one or more of the below indicia of a potential
unintentional or uncontrolled release of a large volume of gas from a
pipeline:
(1) An unanticipated or unexplained pressure loss outside of the
pipeline's normal operating pressures, as defined in the operator's
written procedures. The operator must establish in its written
procedures that an unanticipated or unplanned pressure loss is outside
of the pipeline's normal operating pressures when there is a pressure
loss greater than 10 percent occurring within a time interval of 15
minutes or less, unless the operator has documented in its written
procedures the operational need for a greater pressure-change threshold
due to pipeline flow dynamics (including changes in operating pressure,
flow rate, or volume), that are caused by fluctuations in gas demand,
gas receipts, or gas deliveries; or
(2) An unanticipated or unexplained flow rate change, pressure
change, equipment function, or other pipeline instrumentation
indication at the upstream or downstream station that may be
representative of an event meeting paragraph (a)(1) of this section; or
(3) Any unanticipated or unexplained rapid release of a large
volume of gas, a fire, or an explosion in the immediate vicinity of the
pipeline.
(b) A notification of potential rupture occurs when an operator
first receives notice of or observes an event specified in paragraph
(a) of this section.
0
11. Section 192.636 is added to read as follows:
Sec. 192.636 Transmission lines: Response to a rupture; capabilities
of rupture-mitigation valves (RMVs) or alternative equivalent
technologies.
(a) Scope. The requirements in this section apply to rupture-
mitigation valves (RMVs), as defined in Sec. 192.3, or alternative
equivalent technologies, installed pursuant to Sec. Sec. 192.179(e),
(f), and (g) and 192.634.
(b) Rupture identification and valve shut-off time. An operator
must, as soon as practicable but within 30 minutes of rupture
identification (see Sec. 192.615(a)(12)), fully close any RMVs or
alternative equivalent technologies necessary to minimize the volume of
gas released from a pipeline and mitigate the consequences of a
rupture.
(c) Open valves. An operator may leave an RMV or alternative
equivalent technology open for more than 30 minutes, as required by
paragraph (b) of this section, if the operator has previously
established in its operating procedures and demonstrated within a
notice submitted under Sec. 192.18 for PHMSA review, that closing the
RMV or alternative equivalent technology would be detrimental to public
safety. The request must have been coordinated with appropriate local
emergency responders, and the operator and emergency responders must
determine that it is safe to leave the valve open. Operators must have
written procedures for determining whether to leave an RMV or
alternative equivalent technology open, including plans to communicate
with local emergency responders and minimize environmental impacts,
which must be submitted as part of its notification to PHMSA.
(d) Valve monitoring and operation capabilities. An RMV, as defined
in Sec. 192.3, or alternative equivalent technology, must be capable
of being monitored or controlled either remotely or by on-site
personnel as follows:
(1) Operated during normal, abnormal, and emergency operating
conditions;
(2) Monitored for valve status (i.e., open, closed, or partial
closed/open), upstream pressure, and downstream pressure. For automatic
shut-off valves (ASV), 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 within each pipeline segment located between RMVs or
alternative equivalent technologies to identify and locate a rupture.
Pipeline segments that use manual valves or other alternative
equivalent technologies must have the capability to monitor pressures
or gas flow rates on the pipeline to identify and locate a rupture; and
(3) Have a back-up power source to maintain SCADA systems or other
remote communications for remote-control valve (RCV) or automatic shut-
off valve (ASV) operational status, or be monitored and controlled by
on-site personnel.
(e) Monitoring of valve shut-off response status. The position and
operational status of an RMV must be appropriately monitored through
electronic communication with remote instrumentation or other
equivalent means. An operator does not need to monitor remotely an
ASV's status if the operator has the capability to monitor pressures or
gas flow rate on the pipeline to identify and locate a rupture.
(f) Flow modeling for automatic shut-off valves. Prior to using an
ASV as an RMV, an operator must conduct flow modeling for the shut-off
segment and any laterals that feed the shut-off segment, so that the
valve will close within 30 minutes or less following rupture
identification, consistent with the operator's procedures, and in
accordance with Sec. 192.3 and this section. The flow modeling must
[[Page 20986]]
include the anticipated maximum, normal, or any other flow volumes,
pressures, or other operating conditions that may be encountered during
the year, not exceeding 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 that could affect the ASV set pressures and the 30-
minute valve closure time after notification of potential rupture, as
defined at Sec. 192.3, 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 time/pressure chart for the segment containing the ASV if a rupture
occurs. An operator must conduct this flow modeling prior to making
flow condition changes in a manner that could render the 30-minute
valve closure time unachievable.
(g) Manual valves in non-HCA, Class 1 locations. For pipeline
segments in a Class 1 location that do not meet the definition of a
high consequence area (HCA), an operator submitting a notification
pursuant to Sec. Sec. 192.18 and 192.179 for use of manual valves as
an alternative equivalent technology may also request an exemption from
the requirements of Sec. 192.636(b).
0
12. In Sec. 192.745, paragraphs (c) through (f) are added to read as
follows:
Sec. 192.745 Valve maintenance: Transmission lines.
* * * * *
(c) For each remote-control valve (RCV) installed in accordance
with Sec. 192.179 or Sec. 192.634, an operator must conduct a point-
to-point verification between SCADA system displays and the installed
valves, sensors, and communications equipment, in accordance with Sec.
192.631(c) and (e).
(d) For each alternative equivalent technology installed on an
onshore pipeline under Sec. 192.179(e) or (f) or Sec. 192.634 that is
manually or locally operated (i.e., not a rupture-mitigation valve
(RMV), as that term is defined in Sec. 192.3):
(1) Operators must achieve a valve closure time of 30 minutes or
less, pursuant to Sec. 192.636(b), through an initial drill and
through periodic validation as required in paragraph (d)(2) of this
section. An operator must review and document the results of each phase
of the drill response to validate the total response time, including
confirming the rupture, and valve shut-off time as being less than or
equal to 30 minutes after rupture identification.
(2) Within each pipeline system and within each operating or
maintenance field work unit, operators must randomly select a valve
serving as an alternative equivalent technology in lieu of an RMV for
an annual 30-minute-total response time validation drill that simulates
worst-case conditions for that location to ensure compliance with Sec.
192.636. Operators are not required to close the valve fully during the
drill; a minimum 25 percent valve closure is sufficient to demonstrate
compliance with drill requirements unless the operator has operational
information that requires an additional closure percentage for
maintaining reliability. The response drill must occur at least once
each calendar year, with intervals not to exceed 15 months. Operators
must include in their written procedures the method they use to
randomly select which alternative equivalent technology is tested in
accordance with this paragraph.
(3) If the 30-minute-maximum response time cannot be achieved
during the drill, the operator must revise response efforts to achieve
compliance with Sec. 192.636 as soon as practicable but no later than
12 months after the drill. Alternative valve shut-off measures must be
in place in accordance with paragraph (e) of this section within 7 days
of a failed drill.
(4) Based on the results of response-time drills, the operator must
include lessons learned in:
(i) Training and qualifications programs;
(ii) Design, construction, testing, maintenance, operating, and
emergency procedures manuals; and
(iii) Any other areas identified by the operator as needing
improvement.
(5) The requirements of this paragraph (d) do not apply to manual
valves who, pursuant to Sec. 192.636(g), have been exempted from the
requirements of Sec. 192.636(b).
(e) Each operator must develop and implement remedial measures to
correct any valve installed on an onshore pipeline under Sec.
192.179(e) or (f) or Sec. 192.634 that is indicated to be inoperable
or unable to maintain effective shut-off as follows:
(1) Repair or replace the valve as soon as practicable but no later
than 12 months after finding that the valve is inoperable or unable to
maintain effective shut-off. An operator must request an extension from
PHMSA in accordance with Sec. 192.18 if repair or replacement of a
valve within 12 months would be economically, technically, or
operationally infeasible; and
(2) Designate an alternative valve acting as an RMV within 7
calendar days of the finding while repairs are being made and document
an interim response plan to maintain safety. Such valves are not
required to comply with the valve spacing requirements of this part.
(f) An operator using an ASV as an RMV, in accordance with
Sec. Sec. 192.3, 192.179, 192.634, and 192.636, must document and
confirm the ASV shut-in pressures, in accordance with Sec. 192.636(f),
on a calendar year basis not to exceed 15 months. ASV shut-in set
pressures must be proven and reset individually at each ASV, as
required, on a calendar year basis not to exceed 15 months.
0
13. In Sec. 192.935, paragraph (c) is revised and paragraph (f) is
added to read as follows:
Sec. 192.935 What additional preventive and mitigative measures must
an operator take?
* * * * *
(c) Risk analysis for gas releases and protection against ruptures.
If an operator determines, based on a risk analysis, that a rupture-
mitigation valve (RMV) or alternative equivalent technology would be an
efficient means of adding protection to a high-consequence area (HCA)
in the event of a gas release, an operator must install the RMV or
alternative equivalent technology. In making that determination, an
operator must, at least, evaluate the following factors--timing of leak
detection and pipe shutdown capabilities, the type of gas being
transported, operating pressure, the rate of potential release,
pipeline profile, the potential for ignition, and location of nearest
response personnel. An RMV or alternative equivalent technology
installed under this paragraph must meet all of the other applicable
requirements in this part.
* * * * *
(f) Periodic evaluations. Risk analyses and assessments conducted
under paragraph (c) of this section must be reviewed by the operator
and certified by a senior executive of the company, for operational
matters that could affect rupture-mitigation processes and procedures.
Review and certification must occur once per calendar year, with the
period between reviews not to exceed 15 months, and must also occur
within 3 months of an incident or safety-related condition, as those
terms are defined at Sec. Sec. 191.3 and 191.23, respectively.
[[Page 20987]]
PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE
0
14. The authority citation for part 195 continues to read as follows:
Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et. seq.,
and 49 CFR 1.97.
0
15. In Sec. 195.2, definitions for ``entirely replaced onshore
hazardous liquid or carbon dioxide line segments'', ``notification of
potential rupture'', and ``rupture-mitigation valve'' are added in
alphabetical order to read as follows:
Sec. 195.2 Definitions.
* * * * *
Entirely replaced onshore hazardous liquid or carbon dioxide
pipeline segments, for the purposes of Sec. Sec. 195.258, 195.260, and
195.418, means where 2 or more miles of pipe, in the aggregate, have
been replaced within any 5 contiguous miles within any 24-month period.
* * * * *
Notification of Potential Rupture means the notification to, or
observation by, an operator of indicia identified in Sec. 195.417 of a
potential unintentional or uncontrolled release of a large volume of
commodity from a pipeline.
* * * * *
Rupture-mitigation valve (RMV) means an automatic shut-off valve
(ASV) or a remote-control valve (RCV) that a pipeline operator uses to
minimize the volume of hazardous liquid or carbon dioxide released from
the pipeline and to mitigate the consequences of a rupture.
* * * * *
0
16. In Sec. 195.11, paragraph (b)(2) is revised to read as follows:
Sec. 195.11 What is a regulated rural gathering line and what
requirements apply?
* * * * *
(b) * * *
(2) For steel pipelines contracted, replaced, relocated, or
otherwise changed after July 3, 2009:
(i) Design, install, construct, initially inspect, and initially
test the pipeline in compliance with this part, unless the pipeline is
converted under Sec. 195.5.
(ii) Except for pipelines subject to Sec. 195.260(e), such
pipelines are not subject to the rupture-mitigation valve (RMV) and
alternative equivalent technology requirements in Sec. Sec. 195.258(c)
and (d), 195.418, and 195.419.
* * * * *
0
17. Section 195.18 is added to read as follows:
Sec. 195.18 How to notify PHMSA.
(a) An operator must provide any notification required by this part
by:
(1) Sending the notification by electronic mail to
[email protected]; or
(2) Sending the notification by mail to ATTN: Information Resources
Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New
Jersey Ave. SE, Washington, DC 20590.
(b) An operator must also notify the appropriate State or local
pipeline safety authority when an applicable pipeline segment is
located in a State where OPS has an interstate agent agreement, or an
intrastate pipeline segment is regulated by that State.
(c) Unless otherwise specified, if an operator submits, pursuant to
Sec. 195.258, Sec. 195.260, Sec. 195.418, Sec. 195.419, Sec.
195.420 or Sec. 195.452 a notification requesting use of a different
integrity assessment method, analytical method, sampling approach,
compliance timeline, or technique (e.g., ``other technology'' or
``alternative equivalent technology'') than otherwise prescribed in
those sections, that notification must be submitted to PHMSA for review
at least 90 days in advance of using that other method, approach,
compliance timeline, or technique. An operator may proceed to use the
other method, approach, compliance timeline, or technique 91 days after
submittal of the notification unless it receives a letter from the
Associate Administrator of Pipeline Safety informing the operator that
PHMSA objects to the proposal, or that PHMSA requires additional time
and/or information to conduct its review.
0
18. In Sec. 195.258, paragraphs (c) through (e) are added to read as
follows:
Sec. 195.258 Valves: General.
* * * * *
(c) For all onshore hazardous liquid or carbon dioxide pipeline
segments with diameters greater than or equal to 6 inches that are
constructed after April 10, 2023, the operator must install rupture-
mitigation valves (RMV) or an alternative equivalent technology
whenever a valve must be installed to meet the appropriate valve
spacing requirements of this section and Sec. 195.260. An operator
using alternative equivalent technology must notify PHMSA in accordance
with the procedure in paragraph (e) of this section. All RMVs and
alternative equivalent technology installed as required by this section
must meet the requirements of Sec. 195.419. An operator may request an
extension of the installation compliance deadline requirements of this
paragraph if it can demonstrate to PHMSA, in accordance with the
notification procedures in Sec. 195.18, that those installation
deadline requirements would be economically, technically, or
operationally infeasible for a particular new pipeline.
(d) For all entirely replaced onshore hazardous liquid or carbon
dioxide pipeline segments with diameters greater than or equal to 6
inches that have been replaced after April 10, 2023, the operator must
install RMVs or an alternative equivalent technology whenever a valve
must be installed to meet the appropriate valve spacing requirements of
this section. An operator using alternative equivalent technology must
notify PHMSA in accordance with the procedure in paragraph (e) of this
section. All valves installed as required by this section must meet the
requirements of Sec. 195.419. The requirements of this paragraph (d)
apply when the applicable pipeline replacement project involves a
valve, either through addition, replacement, or removal. An operator
may request an extension of the installation compliance deadline
requirements of this paragraph if it can demonstrate to PHMSA, in
accordance with the notification procedures in Sec. 195.18, that those
installation deadline requirements would be economically, technically,
or operationally infeasible for a particular pipeline replacement
project.
(e) If an operator elects to use alternative equivalent technology
in accordance with paragraph (c) or (d) of this section, the operator
must notify PHMSA in accordance with Sec. 195.18. The operator must
include a technical and safety evaluation in its notice to PHMSA.
Valves that are installed as alternative equivalent technology must
comply with Sec. Sec. 195.418, 195.419, and 195.420. An operator
requesting use of manual valves as an alternative equivalent technology
must also include within the notification submitted to PHMSA a
demonstration that installation of an RMV as otherwise required would
be economically, technically, or operationally infeasible. An operator
may use a manual compressor station valve at a continuously manned
station as an alternative equivalent technology. Such a valve used as
an alternative equivalent technology would not require a notification
to PHMSA in accordance with Sec. 195.18, but it must comply with
Sec. Sec. 195.419 and 195.420.
0
19. Section 195.260 is revised to read as follows:
[[Page 20988]]
Sec. 195.260 Valves: Location.
A valve must be installed at each of the following locations:
(a) On the suction end and the discharge end of a pump station in a
manner that permits isolation of the pump station equipment in the
event of an emergency.
(b) On each pipeline entering or leaving a breakout storage tank
area in a manner that permits isolation of the tank from other
facilities.
(c) On each pipeline at locations along the pipeline system that
will minimize or prevent safety risks, property damage, or
environmental harm from accidental hazardous liquid or carbon dioxide
discharges, as appropriate for onshore areas, offshore areas, and high-
consequence areas (HCA). For newly constructed or entirely replaced
onshore hazardous liquid or carbon dioxide pipeline segments, as that
term is defined at Sec. 195.2, that are installed after April 10,
2023, valve spacing must not exceed 15 miles for pipeline segments that
could affect or are in HCAs, as defined in Sec. 195.450, and 20 miles
for pipeline segments that could not affect HCAs. Valves on pipeline
segments that are located in HCAs or which could affect HCAs must be
installed at locations as determined by the operator's process for
identifying preventive and mitigative measures established pursuant to
Sec. 195.452(i) and by using the selection process in section I.B of
appendix C of part 195, but with a maximum distance that does not
exceed 7\1/2\ miles from the endpoints of the HCA segment or the
segment that could affect an HCA. An operator may request an exemption
from the compliance deadline requirements of this section for valve
installation at the specified valve spacing if it can demonstrate to
PHMSA, in accordance with the notification procedures in Sec. 195.18,
that those compliance deadline requirements would be economically,
technically, or operationally infeasible.
(d) On each lateral takeoff from a pipeline in a manner that
permits shutting off the lateral without interrupting flow in the
pipeline.
(e) On each side of one or more adjacent water crossings that are
more than 100 feet (30 meters) wide from high water mark to high water
mark, as follows:
(1) Valves must be installed at locations outside of the 100-year
flood plain or be equipped with actuators or other control equipment
that is installed so as not to be impacted by flood conditions; and
(2) The maximum spacing interval between valves that protect
multiple adjacent water crossings cannot exceed 1 mile in length.
(f) On each side of a reservoir holding water for human
consumption.
(g) On each highly volatile liquid (HVL) pipeline that is located
in a high-population area or other populated area, as defined in Sec.
195.450, and that is constructed, or where 2 or more miles of pipe have
been replaced within any 5 contiguous miles within any 24-month period,
after April 10, 2023, with a maximum valve spacing of 7\1/2\ miles. The
maximum valve spacing intervals may be increased by 1.25 times the
distance up to a 9 \3/8\-mile spacing, provided the operator:
(1) Submits for PHMSA review a notification pursuant to Sec.
195.18 requesting alternative spacing because installation of a valve
at a particular location between a 7-mile to a 7\1/2\-mile spacing
would be economically, technically, or operationally infeasible, and
that an alternative spacing would not adversely impact safety; and
(2) Keeps the records necessary to support that determination for
the useful life of the pipeline.
(h) An operator may submit for PHMSA review, in accordance with
Sec. 195.18, a notification requesting site-specific exemption from
the valve installation requirements or valve spacing requirements of
paragraph (c), (e), or (f) of this section and demonstrating such
exemption would not adversely affect safety. An operator may also
submit for PHMSA review, in accordance with Sec. 195.18, a
notification requesting an extension of the compliance deadline
requirements for valve installation and spacing of this section because
those compliance deadline requirements would be economically,
technically, or operationally infeasible for a particular new
construction or pipeline replacement project.
0
20. In Sec. 195.402, paragraphs (c)(4), (5), and (12) and (e)(1), (4),
(7), and (10) are revised to read as follows:
Sec. 195.402 Procedural manual for operations, maintenance, and
emergencies.
* * * * *
(c) * * *
(4) Determining which pipeline facilities are in areas that would
require an immediate response by the operator to prevent hazards to the
public, property, or the environment if the facilities failed or
malfunctioned, including segments that could affect high-consequence
areas (HCA) or are in HCAs, and valves specified in Sec. 195.418 or
Sec. 195.452(i)(4).
(5) Investigating and analyzing pipeline accidents and failures,
including sending the failed pipe, component, or equipment for
laboratory testing or examination where appropriate, to determine the
cause(s) and contributing factors of the failure and to minimize the
possibility of a recurrence.
(i) Post-failure and -accident lessons learned. Each operator must
develop, implement, and incorporate lessons learned from a post-failure
and accident review into its written procedures, including in pertinent
operator personnel training and qualifications programs, and in design,
construction, testing, maintenance, operations, and emergency procedure
manuals and specifications.
(ii) Analysis of rupture and valve shut-offs; preventive and
mitigative measures. If a failure or accident on an onshore hazardous
liquid or carbon dioxide pipeline involves the closure of a rupture-
mitigation valve (RMV), as defined in Sec. 195.2, or the closure of an
alternative equivalent technology, the operator of the pipeline must
also conduct a post-failure or -accident analysis of all of the factors
that may have impacted the release volume and the consequences of the
release and identify and implement operations and maintenance measures
to minimize the consequences of a future failure or incident. The
analysis must include all relevant factors impacting the release volume
and consequences, including, but not limited to, the following:
(A) Detection, identification, operational response, system shut-
off, and emergency-response communications, based on the type and
volume of the release or failure event;
(B) Appropriateness and effectiveness of procedures and pipeline
systems, including supervisory control and data acquisition (SCADA),
communications, valve shut-off, and operator personnel;
(C) Actual response time from identifying a rupture following a
notification of potential rupture, as defined at Sec. 195.2, to
initiation of mitigative actions and isolation of the segment, and the
appropriateness and effectiveness of the mitigative actions taken;
(D) Location and timeliness of actuation of all RMVs or alternative
equivalent technologies; and
(E) All other factors the operator deems appropriate.
(iii) Rupture post-failure and accident summary. If a failure or
accident on an onshore hazardous liquid or carbon dioxide pipeline
involves the identification of a rupture following a notification of
potential rupture; the closure of an RMV, as those terms are defined in
Sec. 195.2; or the closure of an
[[Page 20989]]
alternative equivalent technology, the operator must complete a summary
of the post-failure or -accident review required by paragraph
(c)(5)(ii) of this section within 90 days of the failure or accident.
While the investigation is pending, the operator must conduct quarterly
status reviews until the investigation is completed and a final post-
failure or -accident review is prepared. The final post-failure or -
accident summary and all other reviews and analyses produced under the
requirements of this section must be reviewed, dated, and signed by the
operator's appropriate senior executive officer. An operator must keep,
for the useful life of the pipeline, the final post-failure or -
accident summary, all investigation and analysis documents used to
prepare it, and records of lessons learned.
* * * * *
(12) Establishing and maintaining adequate means of communication
with the appropriate public safety answering point (i.e., 9-1-1
emergency call center), where direct access to a 9-1-1 emergency call
center is available from the location of the pipeline, and fire,
police, and other public officials. Operators must determine the
responsibilities, resources, jurisdictional area(s), and emergency
contact telephone numbers for both local and out-of-area calls of each
Federal, State, and local government organization that may respond to a
pipeline emergency, and inform the officials about the operator's
ability to respond to the pipeline emergency and means of communication
during emergencies. Operators may establish liaison with the
appropriate local emergency coordinating agencies, such as 9-1-1
emergency call centers or county emergency managers, in lieu of
communicating individually with each fire, police, or other public
entity.
* * * * *
(e) * * *
(1) Receiving, identifying, and classifying notices of events that
need immediate response by the operator or notice to the appropriate
public safety answering point (i.e., 9-1-1 emergency call center),
where direct access to a 9-1-1 emergency call center is available from
the location of the pipeline, and fire, police, and other appropriate
public officials, and communicating this information to appropriate
operator personnel for prompt corrective action. Operators may
establish liaison with the appropriate local emergency coordinating
agencies, such as 9-1-1 emergency call centers or county emergency
managers, in lieu of communicating individually with each fire, police,
or other public entity.
* * * * *
(4) Taking necessary actions, including but not limited to,
emergency shutdown, valve shut-off, or pressure reduction, in any
section of the operator's pipeline system, to minimize hazards of
released hazardous liquid or carbon dioxide to life, property, or the
environment. Each operator must also develop written rupture
identification procedures to evaluate and identify whether a
notification of potential rupture, as defined in Sec. 195.2, is an
actual rupture event or non-rupture event. These procedures must, at a
minimum, specify the sources of information, operational factors, and
other criteria that operator personnel use to evaluate a notification
of potential rupture, as defined at Sec. 195.2. For operators
installing valves in accordance with Sec. 195.258(c), Sec.
195.258(d), or that are subject to the requirements in Sec. 195.418,
those procedures should provide for rupture identification as soon as
practicable.
* * * * *
(7) Notifying the appropriate public safety answering point (i.e.,
9-1-1 emergency call center), where direct access to a 9-1-1 emergency
call center is available from the location of the pipeline, and fire,
police, and other public officials, of hazardous liquid or carbon
dioxide pipeline emergencies to coordinate and share information to
determine the location of the release, including both planned responses
and actual responses during an emergency, and any additional
precautions necessary for an emergency involving a pipeline
transporting a highly volatile liquid (HVL). The operator must
immediately and directly notify the appropriate public safety answering
point or other coordinating agency for the communities and
jurisdiction(s) in which the pipeline is located after notification of
potential rupture, as defined at Sec. 195.2, has occurred to
coordinate and share information to determine the location of the
release, regardless of whether the segment is subject to the
requirements of Sec. 195.258 (c) or (d), Sec. 195.418, or Sec.
195.419.
* * * * *
(10) Actions required to be taken by a controller during an
emergency, in accordance with the operator's emergency plans and
Sec. Sec. 195.418 and 195.446.
* * * * *
0
21. Section 195.417 is added to read as follows:
Sec. 195.417 Notification of potential rupture.
(a) As used in this part, a notification of potential rupture means
refers to the notification to, or observation by, an operator (e.g., by
or to its controller(s) in a control room, field personnel, nearby
pipeline or utility personnel, the public, local responders, or public
authorities) of one or more of the below indicia of a potential
unintentional or uncontrolled release of a large volume of hazardous
liquids from a pipeline:
(1) An unanticipated or unexplained pressure loss outside of the
pipeline's normal operating pressures, as defined in the operator's
written procedures. The operator must establish in its written
procedures that an unanticipated or unplanned pressure loss is outside
of the pipeline's normal operating pressures when there is a pressure
loss greater than 10 percent occurring within a time interval of 15
minutes or less, unless the operator has documented in its written
procedures the operational need for a greater pressure-change threshold
due to pipeline flow dynamics (including changes in operating pressure,
flow rate, or volume), that are caused by fluctuations in product
demand, receipts, or deliveries;
(2) An unanticipated or unexplained flow rate change, pressure
change, equipment function, or other pipeline instrumentation
indication at the upstream or downstream station that may be
representative of an event meeting paragraph (a)(1) of this section; or
(3) Any unanticipated or unexplained rapid release of a large
volume of hazardous liquid, a fire, or an explosion, in the immediate
vicinity of the pipeline.
(b) A notification of potential rupture occurs when an operator
first receives notice of or observes an event specified in paragraph
(a) of this section.
0
22. Section 195.418 is added to read as follows:
Sec. 195.418 Valves: Onshore valve shut-off for rupture mitigation.
(a) Applicability. For newly constructed and entirely replaced
onshore hazardous liquid or carbon dioxide pipeline segments, as
defined at Sec. 195.2, with diameters of 6 inches or greater that
could affect high-consequence areas or are located in high consequence
areas (HCA), and that have been installed after April 10, 2023, an
operator must install or use existing rupture-mitigation valves (RMV),
as defined at Sec. 195.2, or alternative equivalent technologies
according to the requirements of this section and Sec. 195.419. RMVs
and alternative
[[Page 20990]]
equivalent technologies must be operational within 14 days of placing
the new or replaced pipeline segment in service. An operator may
request an extension of this 14-day operation requirement if it can
demonstrate to PHMSA, in accordance with the notification procedures in
Sec. 195.18, that application of that requirement would be
economically, technically, or operationally infeasible. The
requirements of this section apply to all applicable pipe replacements,
even those that do not otherwise directly involve the addition or
replacement of a valve.
(b) Maximum spacing between valves. RMVs and alternative equivalent
technology must be installed in accordance with the following
requirements:
(1) Shut-off Segment. For purposes of this section, a ``shut-off
segment'' means the segment of pipeline located between the upstream
valve closest to the upstream endpoint of the replaced pipeline segment
in the HCA or the pipeline segment that could affect an HCA and the
downstream valve closest to the downstream endpoint of the replaced
pipeline segment of the HCA or the pipeline segment that could affect
an HCA so that the entirety of the segment that could affect the HCA or
the segment within the HCA is between at least two RMVs or alternative
equivalent technologies. If any crossover or lateral pipe for commodity
receipts or deliveries connects to the replaced segment between the
upstream and downstream valves, the shut-off segment also extends to a
valve on the crossover connection(s) or lateral(s), such that, when all
valves are closed, there is no flow path for commodity to be
transported to the rupture site (except for residual liquids already in
the shut-off segment). Multiple segments that could affect HCAs or are
in HCAs may be contained within a single shut-off segment. All entirely
replaced onshore hazardous liquid or carbon dioxide pipeline segments,
as defined in Sec. 195.2, that could affect or are in an HCA must
include a minimum of one valve that meets the requirements of this
section and section 195.419. The operator is not required to select the
closest valve to the shut-off segment as the RMV or alternative
equivalent technology. An operator may use a manual pump station valve
at a continuously manned station as an alternative equivalent
technology. Such a manual valve used as an alternative equivalent
technology would not require a notification to PHMSA in accordance with
Sec. 195.18.
(2) Shut-off segment valve spacing. Pipeline segments subject to
paragraph (a) of this section must be protected on the upstream and
downstream side with RMVs or alternative equivalent technologies. The
distance between RMVs or alternative equivalent technologies must not
exceed:
(i) For pipeline segments carrying non-highly volatile liquids
(HVL): 15 miles, with a maximum distance not to exceed 7\1/2\ miles
from the endpoints of a shut-off segment: or
(ii) For pipeline segments carrying HVLs: 7\1/2\ miles. The maximum
valve spacing intervals for these valves may be increased by 1.25 times
the spacing distance, up to a 9\3/8\-mile spacing at an endpoint,
provided the operator notify PHMSA in accordance with Sec. 195.260
(g).
(3) Laterals. Laterals extending from shut-off segments that
contribute less than 5 percent of the total shut-off segment volume may
have RMVs or alternative equivalent technologies that meet the
actuation requirements of this section at locations other than mainline
receipt/delivery points, as long as all of these laterals contributing
hazardous liquid volumes to the shut-off segment do not contribute more
than 5 percent of the total shut-off segment volume, based upon maximum
flow volume at the operating pressure. A check valve may be used as an
alternative equivalent technology where it is positioned to stop flow
into the lateral. Check valves used as an alternative equivalent
technology in accordance with this paragraph are not subject to Sec.
195.419 but must be inspected, operated, and remediated in accordance
with Sec. 195.420, including for closure and leakage, to ensure
operational reliability. An operator using a such a valve as an
alternative equivalent technology must submit a request to PHMSA in
accordance with Sec. 195.18.
(4) Crossovers. An operator may use a manual valve as an
alternative equivalent technology for a crossover connection if, during
normal operations, the valve is closed to prevent the flow of hazardous
liquid or carbon dioxide with a locking device or other means designed
to prevent the opening of the valve by persons other than those
authorized by the operator. The operator must document that the valve
has been closed and locked in accordance with the operator's lock-out
and tag-out procedures to prevent the flow of hazardous liquid or
carbon dioxide. An operator using a such a valve as an alternative
equivalent technology must submit a request to PHMSA in accordance with
Sec. 195.18.
(c) Manual operation upon identification of a rupture. Operators
using a manual valve as an alternative equivalent technology pursuant
to paragraph (a) of this section must develop and implement operating
procedures and appropriately designate and locate nearby personnel to
ensure valve shut-off in accordance with this section and Sec.
195.419. Manual operation of valves must include time for the assembly
of necessary operating personnel, the acquisition of necessary tools
and equipment, driving time under heavy traffic conditions and at the
posted speed limit, walking time to access the valve, and time to
manually shut off all valves, not to exceed the response time in Sec.
195.419(b).
0
23. Section 195.419 is added to read as follows:
Sec. 195.419 Valve capabilities.
(a) Scope. The requirements in this section apply to rupture-
mitigation valves (RMV), as defined in Sec. 195.2, or alternative
equivalent technology, installed pursuant to Sec. Sec. 195.258 and
195.418.
(b) Rupture identification and valve shut-off time. If an operator
observes or is notified of a release of hazardous liquid or carbon
dioxide that may be representative of an unintentional or uncontrolled
release event meeting a notification of potential rupture (see
Sec. Sec. 195.2 and 195.417), including any unexplained flow rate
changes, pressure changes, equipment functions, or other pipeline
instrumentation indications observed by the operator, the operator
must, as soon as practicable but within 30 minutes of rupture
identification (see Sec. 195.402(e)(4)), identify the rupture and
fully close any RMVs or alternative equivalent technologies necessary
to minimize the volume of hazardous liquid or carbon dioxide released
from a pipeline and mitigate the consequences of a rupture.
(c) Valve shut-off capability. A valve must have the actuation
capability necessary to close an RMV or alternative equivalent
technology to mitigate the consequences of a rupture in accordance with
the requirements of this section.
(d) Valve monitoring and operational capabilities. An RMV, as
defined in Sec. 195.2, or alternative equivalent technology, must be
capable of being monitored or controlled by either remote or onsite
personnel as follows:
(1) Operated during normal, abnormal, and emergency operating
conditions;
(2) Monitored for valve status (i.e., open, closed, or partial
closed/open), upstream pressure, and downstream pressure. For automatic
shut-off valves
[[Page 20991]]
(ASV), an operator does not need to monitor remotely a valve's status
if the operator has the capability to monitor pressures or flow rate
within each pipeline segment located between RMVs or alternative
equivalent technologies to identify and locate a rupture. Pipeline
segments that use an alternative equivalent technology must have the
capability to monitor pressures and hazardous liquid or carbon dioxide
flow rates on the pipeline in order to identify and locate a rupture;
and
(3) Have a back-up power source to maintain supervisory control and
data acquisition (SCADA) systems or other remote communications for
remote-control valve (RCV) or ASV operational status or be monitored
and controlled by on-site personnel.
(e) Monitoring of valve shut-off response status. The position and
operational status of an RMV must be appropriately monitored through
electronic communication with remote instrumentation or other
equivalent means. An operator does not need to monitor remotely an
ASV's status if the operator has the capability to monitor pressures or
hazardous liquid or carbon dioxide s flow rate on the pipeline to
identify and locate a rupture.
(f) Flow modeling for automatic shut-off valves. Prior to using an
ASV as an RMV, the operator must conduct flow modeling for the shut-off
segment and any laterals that feed the shut-off segment, so that the
valve will close within 30 minutes or less following rupture
identification, consistent with the operator's procedures, and in
accordance with Sec. 195.2 and this section. The flow modeling must
include the anticipated maximum, normal, or any other flow volumes,
pressures, or other operating conditions that may 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 hazardous liquid or carbon dioxide receipt
tie-ins. If operating conditions change that could affect the ASV set
pressures and the 30-minute valve closure time following a notification
of potential rupture, as defined at Sec. 195.2, 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. 195.420. The
flow model must include a time/pressure chart for the segment
containing the ASV if a rupture event occurs. An operator must conduct
this flow modeling prior to making flow condition changes in a manner
that could render the 30-minute valve closure time unachievable.
(g) Pipelines not affecting HCAs. For pipeline segments that are
not in a high-consequence area (HCA) or that could not affect an HCA,
an operator submitting a notification pursuant to Sec. Sec. 195.18 and
195.258 for use of manual valves as an alternative equivalent
technology may also request an exemption from the valve operation
requirements of Sec. 195.419(b).
0
24. In Sec. 195.420, paragraph (b) is revised and paragraphs (d)
through (g) are added to read as follows:
Sec. 195.420 Valve maintenance.
* * * * *
(b) Each operator must, at least twice each calendar year, but at
intervals not exceeding 7\1/2\ months, inspect each valve to determine
that it is functioning properly. Each rupture-mitigation valve (RMV),
as defined in Sec. 195.2, or alternative equivalent technology that is
installed under Sec. 195.258(c) or Sec. 195.418, must also be
partially operated. Operators are not required to close the valve fully
during the drill; a minimum 25 percent valve closure is sufficient to
demonstrate compliance, unless the operator has operational information
that requires an additional closure percentage for maintaining
reliability.
* * * * *
(d) For each remote-control valve (RCV) installed in accordance
with Sec. 195.258(c) or Sec. 195.418, an operator must conduct a
point-to-point verification between SCADA system displays and the
installed valves, sensors, and communications equipment, in accordance
with Sec. 195.446(c) and (e).
(e) For each alternative equivalent technology installed under
Sec. 195.258(c) or (d) or Sec. 195.418(a) that is manually or locally
operated (i.e., not an RMV, as that term is defined in Sec. 195.2):
(1) Operators must achieve a response time of 30 minutes or less,
as required by Sec. 195.419(b), through an initial drill and through
periodic validation as required by paragraph (e)(2) of this section. An
operator must review each phase of the drill response and document the
results to validate the total response time, including the
identification of a rupture, and valve shut-off time as being less than
or equal to 30 minutes after rupture identification.
(2) Within each pipeline system, and within each operating or
maintenance field work unit, operators must randomly select an
authorized rupture-mitigation alternative equivalent technology for an
annual 30-minute-total response time validation drill simulating worst-
case conditions for that location to ensure compliance with Sec.
195.419. Operators are not required to close the alternative equivalent
technology fully during the drill; a minimum 25 percent valve closure
is sufficient to demonstrate compliance with the drill requirements
unless the operator has operational information that requires an
additional closure percentage for maintaining reliability. The response
drill must occur at least once each calendar year, at intervals not to
exceed 15 months. Operators must include in their written procedures
the method they use to randomly select which alternative equivalent
technology is tested in accordance with this paragraph.
(3) If the 30-minute-maximum response time cannot be achieved in
the drill, the operator must revise response efforts to achieve
compliance with Sec. 195.419 no later than 12 months after the drill.
Alternative valve shut-off measures must be in accordance with
paragraph (f) of this section within 7 days of the drill.
(4) Based on the results of the response-time drills, the operator
must include lessons learned in:
(i) Training and qualifications programs;
(ii) Design, construction, testing, maintenance, operating, and
emergency procedures manuals; and
(iii) Any other areas identified by the operator as needing
improvement.
(f) Each operator must implement remedial measures as follows to
correct any valve installed on an onshore pipeline in accordance with
Sec. 195.258(c), or an RMV or alternative equivalent technology
installed in accordance with Sec. 195.418, that is indicated to be
inoperable or unable to maintain effective shut-off:
(1) Repair or replace the valve as soon as practicable but no later
than 12 months after finding that the valve is inoperable or unable to
maintain shut-off. An operator may request an extension of the
compliance deadline requirements of this section if it can demonstrate
to PHMSA, in accordance with the notification procedures in Sec.
195.18, that repairing or replacing a valve within 12 months would be
economically, technically, or operationally infeasible; and
(2) Designate an alternative compliant valve within 7 calendar days
of the finding while repairs are being made and document an interim
response plan to maintain safety. Alternative compliant valves are not
required to
[[Page 20992]]
comply with valve spacing requirements of this part.
(g) An operator using an ASV as an RMV, in accordance with
Sec. Sec. 195.2, 195.260, 195.418, and 195.419, must document, in
accordance with Sec. 195.419(f), and confirm the ASV shut-in pressures
on a calendar year basis not to exceed 15 months. ASV shut-in set
pressures must be proven and reset individually at each ASV, as
required by Sec. 195.419(f), at least each calendar year, but at
intervals not to exceed 15 months.
0
25. In Sec. 195.452, paragraph (i)(4) is revised to read as follows:
Sec. 195.452 Pipeline integrity management in high consequence
areas.
* * * * *
(i) * * *
(4) Emergency Flow Restricting Devices (EFRD). If an operator
determines that an EFRD is needed on a pipeline segment that is located
in, or which could affect, a high-consequence area (HCA) in the event
of a hazardous liquid pipeline release, an operator must install the
EFRD. In making this determination, an operator must, at least,
evaluate the following factors--the swiftness of leak detection and
pipeline shutdown capabilities, the type of commodity carried, the rate
of potential leakage, the volume that can be released, topography or
pipeline profile, the potential for ignition, proximity to power
sources, location of nearest response personnel, specific terrain
within the HCA or between the pipeline segment and the HCA it could
affect, and benefits expected by reducing the spill size. An RMV
installed under this paragraph must meet all of the other applicable
requirements in this part.
(i) Where EFRDs are installed on pipeline segments in HCAs and that
could affect HCAs with diameters of 6 inches or greater and that are
placed into service or that have had 2 or more miles of pipe replaced
within 5 contiguous miles within a 24-month period after April 10,
2023, the location, installation, actuation, operation, and maintenance
of such EFRDs (including valve actuators, personnel response,
operational control centers, supervisory control and data acquisition
(SCADA), communications, and procedures) must meet the design,
operation, testing, maintenance, and rupture-mitigation requirements of
Sec. Sec. 195.258, 195.260, 195.402, 195.418, 195.419, and 195.420.
(ii) The EFRD analysis and assessments specified in this paragraph
(i)(4) must be completed prior to placing into service all onshore
pipelines with diameters of 6 inches or greater and that are
constructed or that have had 2 or more miles of pipe within any 5
contiguous miles within any 24-month period replaced after April 10,
2023. Implementation of EFRD findings for RMVs must meet Sec. 195.418.
(iii) An operator may request an exemption from the compliance
deadline requirements of this section if it can demonstrate to PHMSA,
in accordance with the notification procedures in Sec. 195.18, that
installing an EFRD by that compliance deadline would be economically,
technically, or operationally infeasible.
* * * * *
Issued in Washington, DC, on March 31, 2022, under authority
delegated in 49 CFR 1.97.
Tristan H. Brown,
Deputy Administrator.
[FR Doc. 2022-07133 Filed 4-7-22; 8:45 am]
BILLING CODE 4910-60-P