[Federal Register Volume 88, Number 96 (Thursday, May 18, 2023)]
[Proposed Rules]
[Pages 31890-31979]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2023-09918]
[[Page 31889]]
Vol. 88
Thursday,
No. 96
May 18, 2023
Part III
Department of Transportation
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Pipeline and Hazardous Materials Safety Administration
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49 CFR Parts 191, 192, and 193
Pipeline Safety: Gas Pipeline Leak Detection and Repair; Proposed Rule
Federal Register / Vol. 88, No. 96 / Thursday, May 18, 2023 /
Proposed Rules
[[Page 31890]]
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DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
49 CFR Parts 191, 192, and 193
[Docket No. PHMSA-2021-0039]
RIN 2137-AF51
Pipeline Safety: Gas Pipeline Leak Detection and Repair
AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
Department of Transportation (DOT).
ACTION: Notice of proposed rulemaking (NPRM).
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SUMMARY: PHMSA proposes regulatory amendments that implement
congressional mandates in the Protecting our Infrastructure of
Pipelines and Enhancing Safety Act of 2020 to reduce methane emissions
from new and existing gas transmission pipelines, distribution
pipelines, regulated (Types A, B, C and offshore) gas gathering
pipelines, underground natural gas storage facilities, and liquefied
natural gas facilities. Among the proposed amendments for part 192-
regulated gas pipelines are strengthened leakage survey and patrolling
requirements; performance standards for advanced leak detection
programs; leak grading and repair criteria with mandatory repair
timelines; requirements for mitigation of emissions from blowdowns;
pressure relief device design, configuration, and maintenance
requirements; and clarified requirements for investigating failures.
Finally, PHMSA proposes expanded reporting requirements for operators
of all gas pipeline facilities within DOT's jurisdiction, including
underground natural gas storage facilities and liquefied natural gas
facilities.
DATES: Written comments on this NPRM must be submitted by July 17,
2023. The agency will, consistent with 49 CFR 190.323, consider late-
filed comments to the extent practicable.
ADDRESSES: You may submit comments identified by the docket number
PHMSA-2021-0039 by any of the following methods:
E-Gov Web: https://www.regulations.gov. This site allows the public
to enter comments on any Federal Register notice issued by any agency.
Follow the online instructions for submitting comments.
Mail: Docket Management System: U.S. Department of Transportation,
1200 New Jersey Avenue SE, West Building Ground Floor, Room W12-140,
Washington, DC 20590-0001.
Hand Delivery: U.S. DOT Docket Management System, West Building
Ground Floor, Room W12-140, 1200 New Jersey Avenue SE, Washington, DC
20590-0001 between 9 a.m. and 5 p.m., Monday through Friday, except
Federal holidays.
Fax: 1-202-493-2251.
Instructions: Please include the docket number PHMSA-2021-0039 at
the beginning of your comments. If you submit your comments by mail,
submit two copies. If you wish to receive confirmation that PHMSA has
received your comments, include a self-addressed stamped postcard.
Internet users may submit comments at https://www.regulations.gov/.
Note: Comments are posted without changes or edits to https://www.regulations.gov, including any personal information provided. There
is a privacy statement published on https://www.regulations.gov.
Privacy Act: In accordance with 5 U.S.C. 553(c), DOT solicits
comments from the public to better inform its rulemaking process. DOT
posts these comments, without edit, including any personal information
the commenter provides, to www.regulations.gov, as described in the
system of records notice (DOT/ALL-14 FDMS), that can be reviewed at
www.dot.gov/privacy.
Confidential Business Information: Confidential Business
Information (CBI) is commercial or financial information that is both
customarily and actually treated as private by its owner. Under the
Freedom of Information Act (FOIA, 5 U.S.C. 552), CBI is exempt from
public disclosure. If your comments responsive to this document contain
commercial or financial information that is customarily treated as
private, that you actually treat as private, and that is relevant or
responsive to this notice, it is important that you clearly designate
the submitted comments as CBI. Pursuant to 49 CFR 190.343, you may ask
PHMSA to give confidential treatment to information you give to the
agency by taking the following steps: (1) mark each page of the
original document submission containing CBI as ``Confidential''; (2)
send PHMSA, along with the original document, a second copy of the
original document with the CBI deleted; and (3) explain why the
information you are submitting is CBI. Submissions containing CBI
should be sent to Sayler Palabrica, Office of Pipeline Safety (PHP-30),
Pipeline and Hazardous Materials Safety Administration (PHMSA), 2nd
Floor, 1200 New Jersey Avenue SE, Washington, DC 20590-0001, or by
email at [email protected]. Any commentary PHMSA receives that
is not specifically designated as CBI will be placed in the public
docket.
Docket: For access to the docket to read background documents or
comments received, go to http://www.regulations.gov. Follow the online
instructions for accessing the docket. Alternatively, you may review
the documents in person at the street address listed above.
FOR FURTHER INFORMATION CONTACT: Sayler Palabrica, Transportation
Specialist, by telephone at 202-744-0825 or by email at
[email protected].
SUPPLEMENTARY INFORMATION:
I. Executive Summary
A. Purpose of Regulatory Action
B. Summary of the Major Regulatory Provisions
C. Costs and Benefits
II. Background
A. The Urgency of Methane Emissions Reductions in Confronting
the Climate Crisis
B. Dimensions of the Climate Crisis
C. Methane Emissions From Gas Pipeline Facilities
D. The Need for Updating PHMSA Regulations To Incorporate
Advanced Leak Detection Programs To Reduce Unintentional Releases
From Gas Pipelines
E. The Limits of PHMSA Regulation and State and Operator
Initiatives in Reducing Intentional Methane Releases From Gas
Pipeline Facilities
III. Federal Efforts To Address Climate Change by Reducing Methane
Emissions
A. The PIPES Act of 2020
B. Administration Efforts Confronting the Climate Crisis
C. PHMSA Implementation of the PIPES Act of 2020
IV. Summary of Proposals
A. Leakage Survey and Patrol Frequencies and Methodologies
B. Advanced Leak Detection Programs
C. Leak Grading and Repair
D. Qualification of Leakage Survey, Investigation, and Repair
Personnel
E. Reporting and National Pipeline Mapping System
F. Mitigating Vented and Emissions From Gas Pipeline Facilities
G. Design, Configuration, and Maintenance of Pressure Relief
Devices
H. Investigation of Failures
I. Type B and Type C Gathering Pipelines
J. Miscellaneous Changes in Parts 191 and 192 to Reflect
Codification in Federal Regulation of the Congressional Mandate To
Address Environmental Hazards of Leaks From Gas Pipelines
V. Section-by-Section Analysis
VI. Regulatory Analyses and Notices
I. Executive Summary
A. Purpose of Regulatory Action
This notice of proposed rulemaking (NPRM) proposes a series of
regulatory
[[Page 31891]]
amendments to the Federal pipeline safety regulations (49 CFR parts 190
through 199) in response to a bipartisan congressional mandate in the
Protecting our Infrastructure of Pipelines and Enhancing Safety Act of
2020 (PIPES Act of 2020, Pub. L. 116-260) and in support of the Biden-
Harris Administration's U.S. Methane Emissions Reduction Action Plan.
The amendments would reduce both ``fugitive emissions'' (meaning
unintentional emissions resulting from leaks and equipment failures)
and ``vented emissions'' (meaning those emissions resulting from
blowdowns, equipment design features, and other intentional releases,
also called ``intentional emissions'') from over 2.7 million miles of
gas transmission, distribution, and gathering pipelines and other gas
pipeline facilities as well as 403 underground natural gas storage
facilities (UNGSFs) and 165 liquefied natural gas (LNG) facilities,
thereby improving public safety, promoting environmental justice, and
addressing the climate crisis.
The Federal pipeline safety regulations currently covering leak
detection and repair reflect a regulatory approach focused on public
safety risks posed by incidents on gas pipeline facilities. The
regulations do not sufficiently capture environmental costs, align with
the importance attached to environmental protection in PHMSA's enabling
statutes,\1\ or reflect the scientific consensus that prompt reductions
in methane emissions from natural gas infrastructure are critical to
limiting the impacts of climate change. This current approach also
foregoes opportunities to ensure timely identification and repair of
leaks that can degrade into catastrophic failures and incidents
threatening to public safety. The Federal leak detection and repair
standards for gas pipelines have remained largely unchanged since the
1970s despite significant improvements in leak detection technology and
operator practices and the increasingly urgent and tangible threats
from climate change. The current pipeline safety regulations do not
include any meaningful performance standards for leak detection
equipment, nor requirements that leverage the significant advancements
in the sensitivity, efficiency, and variety of leak detection
technologies in the last five decades. Further, the current pipeline
safety regulations do not explicitly require repair of all--or even
most--leaks on gas pipeline facilities. Leaks that an operator
determines do not to present an existing or probable public safety
hazard do not need to be repaired at all regardless of the resulting
environmental harms posed by that release. Current regulations also do
not prescribe specific timeframes for the timely repair of hazardous or
any other leaks, other than leaks associated with certain metal loss,
cracking, and denting defects that are discovered on gas transmission
piping during an integrity assessment in accordance with gas
transmission integrity management in subpart O of 49 CFR part 192 or
Sec. 192.714. Additionally, despite a new self-executing section of
the PIPES Act of 2020, described below, current regulations tolerate
significant intentional emissions of methane and other gases, even in
non-emergency situations, by allowing venting, blowdowns, and other
large-volume releases of gas from all PHMSA-jurisdictional pipeline
facilities without restriction. Consistent with the pipeline safety
regulations' historical lack of emphasis on the environmental
consequences of gas releases, PHMSA's minimum incident reporting
threshold was established principally to better reflect the economic
consequence of lost gas \2\ and was set at 3 million standard cubic
feet (MMCF), which leaves many large-volume gas releases unreported.
And PHMSA has no reporting requirements for intentional releases of gas
at all.
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\1\ 49 U.S.C. 60102(b)(1)(B)(ii), 60102(b)(2)(A)(iii),
60102(b)(5), 60102(q)(1)(B), 60102(q)(2)(B)(i).
\2\ Prior to the adoption of the volumetric incident criterion,
the cost of lost gas was included in the property damage
calculation. In the NPRM that proposed the adoption of a volumetric
threshold, PHMSA described both a petition from the Interstate
Natural Gas Association of America noting that more incidents were
reportable due to changes in the cost of gas, as well as a GAO
recommendation (GAO-06-946) to adjust the incident reporting
criteria to account for the cost of lost gas. That NPRM did not
identify environmental considerations among the motivations for that
change in incident reporting requirements. See 74 FR 31675, 31677
(July 2, 2009).
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Congress targeted these regulatory shortcomings in the bipartisan
PIPES Act of 2020. Section 113 mandated that PHMSA establish
performance standards for leak detection and repair programs for
certain part 192-regulated \3\ gas gathering, transmission, and
distribution operators reflecting commercially available advanced
technology and practices for the identification, location,
categorization, and repair of all leaks that are hazardous to public
safety or the environment. Section 114 of the PIPES Act of 2020,
moreover, requires operators of all pipeline facilities with
maintenance and inspection procedures to update pertinent manuals to
address the elimination of hazardous leaks and minimize releases of
natural gas--whether fugitive emissions from leaks or intentional
releases due to venting from maintenance and other activities--and
repair or remediate pipelines known to leak. And section 118 of the
PIPES Act of 2020 clarified that PHMSA must consider environmental
benefits equally with public safety benefits. The mandates in the PIPES
Act of 2020 align with the importance of addressing climate change by
reducing methane emissions.
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\3\ Throughout this NPRM, PHMSA uses the phrase ``part 192-
regulated gas gathering pipelines'' to refer to offshore gas
gathering pipelines, as well as Types A, B, and C ``regulated
onshore gas gathering'' pipelines--all of which are subject to
certain part 192 requirements under Sec. Sec. 192.8 and 192.9. Such
``part 192-regulated gas gathering pipelines'' does not include
``reporting-regulated'' or ``Type R'' gas gathering pipelines as
defined in Sec. Sec. 191.3 and 192.8(c)(3), which are not subject
to part 192 safety requirements. Similarly, PHMSA also refers to
``part 192-regulated gas pipelines'' to collectively refer to gas
transmission, distribution, offshore gathering, and Types A, B, and
C onshore gathering pipelines subject to part 192 requirements.
``Gas pipeline facilities'' is defined as ``a pipeline, a right of
way, a facility, a building, or equipment used in transporting gas
or treating gas during its transportation''--this broader definition
applies to all part 192-regulated gas pipelines, UNGSFs, and part
193-regulated LNG facilities. See 49 U.S.C. 60101(a)(3).
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PHMSA proposes a number of regulatory revisions to minimize
emissions of methane and other (flammable, toxic, or corrosive) gases
from, and improve public safety of, new and existing offshore gas
gathering, regulated onshore gas gathering, transmission and
distribution pipelines, UNGSFs and LNG facilities. PHMSA expects that
the proposed regulatory amendments would yield prompt and meaningful
reduction of methane emissions, a key contributor to climate change;
improve public safety; and mitigate the disproportionate burden of
those environmental and safety risks historically placed on minority,
low-income, or other underserved and disadvantaged populations and
communities.
B. Summary of the Regulatory Provisions
This NPRM contains the following proposed changes to the
regulations: (1) strengthen leakage survey and patrolling requirements
at Sec. Sec. 192.9, 192.705, 192.706, 192.723 for all part 192-
regulated gas pipelines, as well as introduce periodic methane leakage
survey requirements for part 193-regulated LNG facilities; (2)
introduce for all part 192-regulated gas pipelines an Advanced Leak
Detection Program (ALDP) performance standard at a new Sec. 192.763
reflecting the capabilities of
[[Page 31892]]
commercially available advanced technologies and practices; (3) amend
Sec. 192.703 to require operators of all part 192-regulated gas
pipelines to grade and repair all leaks, and not merely those that pose
public safety risks; (4) establish for all part 192-regulated gas
pipelines minimum criteria for leak grades and associated repair
schedules prioritized by safety and environmental hazard at a new Sec.
192.760; (5) require reductions in intentional sources of methane
emissions by minimizing releases associated with blowdowns and other
vented emissions from gas transmission, offshore gas gathering, and
Type A gas gathering pipelines (at Sec. 192.770) and LNG facilities
(at Sec. 193.2523); (6) require operators of certain part 192-
regulated gas pipelines to reduce emissions associated with the design,
configuration, and maintenance of pressure relief devices (Sec. Sec.
192.199 and 192.773); (7) codify in Federal regulations a congressional
requirement for operators of gas pipeline facilities to implement
written procedures to eliminate hazardous leaks, minimize releases of
natural gas, and remediate or replace pipelines known to leak
(Sec. Sec. 192.9, 192.12, 192.605, 193.2503, and 193.2605); (8) expand
reporting requirements (at Sec. Sec. 191.3 and 191.19) and
recordkeeping requirements (at Sec. Sec. 192.760 and 192.773) to
provide higher-quality information on unintentional and intentional gas
releases from gas pipeline facilities; (9) require that Types A, B, and
C gathering pipeline operators submit geospatial pipeline location data
to the National Pipeline Mapping System (NPMS) pursuant to Sec.
191.29; (10) incorporate explicit reference to environmental harm among
the ``hazards'' addressed in certain parts 191 and 192 requirements;
and (11) introduce, for certain components and equipment within part
193-regulated LNG facilities, at a new Sec. 193.2624, requirements for
periodic methane leakage surveys using leak detection equipment and
repair of identified leaks pursuant to operators' written maintenance
or abnormal operations procedures. PHMSA proposes an effective date for
this rulemaking of 6 months following publication of a final rule in
the Federal Register. The eleven proposed requirements are described in
the paragraphs immediately below, and further detail is provided in
sections IV and V.
First, PHMSA proposes increased leakage survey frequencies for
distribution pipelines outside of business districts,\4\ annual leakage
surveys for distribution pipelines that lack cathodic protection or
which are known to leak based on their material (cast-iron,
cathodically unprotected steel, wrought-iron, and certain plastic
pipelines), design, or operational and maintenance history; and for gas
transmission, offshore gathering, and Types A, B, and C gathering
pipelines in high consequence areas (HCAs), with the most frequent
leakage surveys to be performed on gas transmission and Types A and B
gathering pipelines located in HCAs within Class 4 locations. PHMSA
also proposes to increase minimum patrolling frequencies for gas
transmission, offshore gathering, and Type A gathering pipelines and to
introduce requirements for annual patrolling of Type B and Type C
gathering pipelines. Finally, PHMSA proposes to establish methane
leakage survey requirements for LNG facilities other than tanks.
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\4\ The term ``business district'' is not defined in part 192.
However, in a letter of interpretation PHMSA stated that the term
normally refers to an area ``associated with the assembly of people
in shops, offices and the like,'' marked by the conduct of ``buying
and selling commodities and services, and related transactions.''
See PHMSA, Interpretation Response Letter No. PI-72-038 (Aug. 16,
1972).
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Second, PHMSA proposes to introduce an ALDP performance standard
that would require operators of part 192-regulated gas pipelines to
demonstrate, by conducting engineering tests and analyses, that their
suite of leak detection equipment, procedures, and analytics are
capable of detecting all leaks above a minimum concentration threshold
when measured in close proximity to the pipeline. PHMSA proposes to
require that leakage surveys be performed using commercially available
advanced technology and practices consistent with the proposed ALDP
performance standard. PHMSA also proposes to require a minimum
sensitivity for leak detection equipment used in leakage surveys and
leak investigations. PHMSA proposes to limit the use of human or animal
senses for leakage surveys to offshore, submerged gas transmission and
gathering pipelines. Human senses may also be used for gas transmission
and regulated gas gathering lines in Class 1 and Class 2 locations
outside of HCAs, but only with prior notification to and no objection
from PHMSA in accordance with Sec. 192.18.
Third, PHMSA proposes to require operators of gas transmission,
distribution, and part 192-regulated gathering pipelines to identify,
locate, classify, and repair in a timely manner all leaks. Part 192
provisions governing the repair of leaks are narrowly focused on public
safety risks associated with ignition of large-volume, instantaneous
releases and accumulated gas; they are unclear regarding when, if at
all, most leaks must be repaired. Although some--not all--part 192-
regulated pipelines are subject to a general maintenance requirement in
Sec. 192.703(c) to ``promptly repair hazardous leaks,'' part 192
maintenance requirements neither define ``hazardous leak'' in terms of
risks to the environment nor establish meaningful timelines for repair
of hazardous or any other leaks. These proposed amendments would
address the section 113 mandate of the PIPES Act of 2020 requiring
identification, location, classification, and repair of leaks hazardous
to either public safety or the environment.
Fourth, this NPRM proposes that operators of gas transmission,
distribution, and part 192-regulated gathering pipelines must classify
and repair all identified leaks on a schedule that depends on the
severity of public safety and environmental risks. PHMSA's proposed
requirements build on the tiered framework of the Gas Piping Technology
Committee (GPTC) ``Guide for Gas Transmission and Distribution Piping
Systems'' \5\ leak grading and repair criteria. PHMSA's proposed
framework would require the classification of every leak (as either
grade 1, grade 2, or grade 3) and to prioritize remediation of leaks
posing the most significant risks to public safety or the environment.
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\5\ Gas Piping Technology Committee Z380, ANSI GPTC Z380.1-2022,
``The Guide for Gas Transmission, Distribution, and Gathering Piping
Systems'' Including Addenda 1 and 2 (2022).
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Fifth, PHMSA proposes requirements for the mitigation of
intentional emissions such as blowdowns on gas transmission, offshore
gas gathering, and Type A gas gathering pipelines and LNG facilities.
This proposal requires an operator to choose from among prescribed,
proven, cost-effective mitigation measures when performing blowdowns
related to operations, maintenance, or construction.
Sixth, PHMSA proposes requirements for operators of gas
transmission, distribution, offshore gathering, and Types A, B, and C
gathering pipelines to design and configure all new and modified
pressure relief and limiting devices to minimize unnecessary releases
and to assess and remediate any relief devices that operate outside of
the tolerances established in the operator's procedures. These proposed
[[Page 31893]]
requirements would minimize unintended and unnecessary releases of gas
to the atmosphere, better protecting against environmental and public
safety hazards posed by malfunctioning or poorly designed and
configured pressure relief devices.
Seventh, PHMSA proposes to codify in regulation self-executing
requirements from section 114 of the PIPES Act of 2020, which obliges
operators of gas pipeline facilities to have written procedures that
address the elimination of hazardous leaks, minimize releases of
natural gas, and provide for repair or replacement of pipelines known
to leak based on material, design, or past operating and maintenance
histories. These changes would support PHMSA's cooperation with states
undertaking inspection and enforcement activity in connection with
those requirements.
Eighth, this NPRM proposes a series of changes to part 191
reporting requirements. PHMSA proposes to introduce requirements for
reporting large-volume releases of gas from all gas pipeline
facilities, including intentional releases, that are not currently
captured by the definition of an incident in part 191. Specifically,
this NPRM proposes to create a report for both unintentional releases
and, for the first time, intentional releases of 1 MMCF or more of gas
from any gas pipeline facility. PHMSA also proposes revisions to annual
reporting requirements for gas transmission, distribution, offshore
gathering, and Types A, B, and C gathering pipelines to convey
information regarding the number and grade of all leaks detected and
repaired each calendar year as well as estimated emissions from those
leaks.
Ninth, this NPRM further proposes to extend NPMS reporting
requirements at Sec. 191.29 to offshore gas gathering pipelines as
well as Types A, B, and C onshore gas gathering pipelines.
Tenth, this NPRM proposes incorporation of explicit reference to
environmental harm among the ``hazards'' addressed in certain part 191
and 192 requirements, consistent with section 118 of the PIPES Act of
2020. PHMSA's proposed expansion of the concept of ``hazards'' to
encompass environmental harms would not extend to integrity management
(IM) regulations in part 192, subparts O (gas distribution pipelines)
and P (gas transmission pipelines), which would remain focused on
safety, and certain other existing requirements directed at hazards to
public safety in particular (described in detail in section IV.J).
Finally, this NPRM proposes a new Sec. 193.2624 that would oblige
operators of part 193-regulated LNG facilities to perform quarterly
methane leakage surveys of non-tank equipment and components within an
LNG facility using leak detection equipment satisfying the minimum 5
parts per million (ppm) sensitivity proposed elsewhere within this
NPRM. Operators would also need to repair any leaks identified in a
manner and on a schedule consistent with their maintenance or abnormal
operations procedures. PHMSA also proposes conforming changes to annual
report forms for LNG facilities to ensure meaningful reporting of
methane leaks discovered and repaired pursuant to the proposed Sec.
193.2624.
C. Costs and Benefits
Consistent with Executive Order (E.O.) 12866 and the requirements
of the Federal Pipeline Safety Laws,\6\ PHMSA has prepared an
assessment of the benefits and costs (to include pertinent commercial
benefits, public safety benefits, environmental benefits, equity
benefits, compliance costs, and other risks) of this proposed rule, as
well as reasonable alternatives. PHMSA estimates that emission
reductions under the proposed rule correspond to approximately 72
percent of unintentional emissions from regulated gathering pipelines,
17 percent of unintentional emissions from transmission pipelines, and
44 to 62 percent of unintentional emissions from distribution
pipelines. These shares are relative to modeled baseline emissions
projected over the period of analysis based on the pipeline mileage,
empirical emission factors, and existing survey and repair practices.
Further, PHMSA estimates that the total avoided blowdown emissions
under the proposed rule correspond to approximately 43 percent of
baseline blowdown emissions. PHMSA estimates that the proposed rule
would result in monetized net benefits between $341 to $1,440 million
per year using a 3 percent discount rate. PHMSA also anticipates
additional unquantified benefits to public safety and the environment,
each discussed throughout this NPRM and its supporting documents
(including the Preliminary Regulatory Impact Analysis (RIA) and draft
Environmental Assessment (EA), each available in the docket for this
NPRM).
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\6\ 49 U.S.C. 60101 et seq. (Federal Pipeline Safety Laws). The
specific provision referenced in the above discussion is 49 U.S.C.
60102(b)(5).
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The regulatory amendments proposed in this NPRM are expected to
improve public safety, reduce threats to the environment (including,
but not limited to, reduction of methane emissions contributing to the
climate crisis), and promote environmental justice for minority
populations, low-income populations, and other underserved and
disadvantaged communities. Additionally, reducing product losses
results in cost savings for natural gas shippers and consumers and
improves the efficiency and reliability of U.S. energy infrastructure.
PHMSA expects that each of the elements of this rulemaking as proposed
in this NPRM would be technically feasible, reasonable, cost-effective,
and practicable because of the public safety, environmental, and equity
benefits of the proposed regulatory amendments described in this NPRM
and its supporting documents (including the Preliminary RIA and draft
EA) which justify any associated costs. PHMSA has preliminarily
determined that the proposed rule is superior to alternatives
considered in the Preliminary RIA.
II. Background
A. The Urgency of Methane Emissions Reductions in Confronting the
Climate Crisis
The primary component of natural gas is methane (CH4).
Methane is a greenhouse gas, or GHG, which means that its concentration
in the atmosphere affects the climate and temperature of the Earth by
trapping heat in the atmosphere. Methane is released from both natural
and anthropogenic sources, the latter of which includes leaks and other
releases from natural gas pipeline systems. Methane is the second most
abundant anthropogenic GHG in the Earth's atmosphere, after carbon
dioxide (CO2), by concentration and accounts for the second-
greatest contribution to total radiative forcing (warming effect).\7\
The Environmental Protection Agency (EPA) calculated that methane made
up approximately 11 percent (by mass of CO2 equivalents) of
the annual GHG emissions in 2019 within the United States, whereas
carbon dioxide made up 79 percent of the total GHG emissions over the
same period.\8\ According to the 2021 installment of the Sixth
Assessment Report (2021 IPCC Report) from Working Group I of the
Intergovernmental Panel on Climate Change (IPCC), the atmospheric
concentration of methane gas was
[[Page 31894]]
measured at 1,866 parts per billion (ppb), compared with 410 ppm of
carbon dioxide.\9\
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\7\ National Oceanic and Atmospheric Administration (NOAA),
``Annual Greenhouse Gas Index'' at Figure 3 & Table 2 (Spring 2022),
https://gml.noaa.gov/aggi/aggi.html.
\8\ EPA, ``Overview of Greenhouse Gases,'' https://www.epa.gov/ghgemissions/overview-greenhouse-gases#methane (last accessed
December 5, 2022).
\9\ IPCC, Climate Change 2021: The Physical Science Basis.
Contribution of Working Group I to the Sixth Assessment Report of
the Intergovernmental Panel on Climate Change, Summary for
Policymakers (SPM)-5 (2021). In the 2021 IPCC Report, atmospheric
concentration of CH4 since 1984 (1980 for CO2)
is based on merging observed gas concentration in the lower
troposphere from the NOAA Global Monitoring Laboratory and the
Advanced Global Atmospheric Gases Experiment monitoring networks.
Emissions in 1850 and earlier are estimated based on assessments of
multiple ice cores. 2021 IPCC Report, Table 2.2 and Table AIII.1a.
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However, this comparatively small concentration of methane in the
atmosphere makes an outsized contribution to climate change. The 2021
IPCC Report notes that anthropogenic methane emissions account for
approximately one-third of warming of global average surface
temperatures attributed to well-mixed GHG \10\ emissions since
1850.\11\ The IPCC also noted that in 2019, atmospheric CH4
concentrations were higher than at any time in 800,000 years, and that
``strong, rapid and sustained reductions in CH4 emissions''
would be needed to offset short-term warming effects.\12\
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\10\ According to the IPCC, well-mixed GHGs include
CO2, N2O, and CH4. 2021 IPCC
Report, 2.2. These gases ``generally have lifetimes of more than
several years'' and therefore are relatively uniformly distributed
within the troposphere (lower-atmosphere). 2021 IPCC Report, 2.2.3.
\11\ 2021 IPCC Report, SPM-8.
\12\ 2021 IPCC Report, SPM-9, SPM-36.
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Once emitted into the atmosphere, some GHGs can persist in the
atmosphere for a long time. Carbon dioxide, for instance, remains in
the atmosphere for 300 to 1000 years.\13\ Methane, on the other hand,
is more short-lived than CO2 but is much more potent in
trapping heat in the atmosphere. Methane only lasts in the atmosphere
for approximately 12 years once released; however, it traps
approximately 25 times more energy than an equal mass of carbon dioxide
over a 100-year period.\14\ Because methane is a more potent, but more
short-lived, GHG compared to carbon dioxide, reducing methane emissions
would have a more rapid and significant effect on reducing heat-
trapping potential of the atmosphere than an equivalent reduction in
carbon dioxide and would therefore result in a greater effect on
climate change mitigation in the short term.\15\
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\13\ Buis, ``The Atmosphere: Getting a Handle on Carbon
Dioxide'' (Oct. 9, 2019).
\14\ EPA, ``Overview of Greenhouse Gases,'' https://www.epa.gov/ghgemissions/overview-greenhouse-gases (last accessed July 20,
2022).
\15\ EPA, ``Importance of Methane,'' https://www.epa.gov/gmi/importance-methane (last accessed July 20, 2022).
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Authoritative scientific projections underscore the need for
achieving a prompt reduction in methane emissions. The 2021 IPCC Report
concluded that urgent action to reduce emissions across all GHG
categories is necessary to minimize global warming and avoid the most
destructive effects of climate change.\16\ The report details five
possible future emissions and warming scenarios: two high emissions
scenarios (SSP3-7.0 and SSP5-8.5), an intermediate scenario with
emissions similar to the status quo through mid-century (SSP2-4.5), and
two relatively low-emissions scenarios (SSP1-1.9 and SSP1-2.6). Of
these, only the two low-emissions scenarios are likely to hold
temperature increases below the Paris Agreement's target of limiting
the increase in global average surface temperature to 2.0 [deg]C above
1850 levels by the end of the century,\17\ and only the very low-
emissions scenario (SSP1-1.9) is likely to limit warming to 1.5 [deg]C
by the end of the century (specifically, between 1.0 [deg] to 1.8
[deg]C above 1850 levels, consistent with the Paris Agreement). Both of
those low-emissions scenarios require cutting methane emissions by
approximately half of 2015 levels before 2050.\18\ Rapid and full-scale
efforts to reduce methane and other GHG emissions are needed to achieve
the very low-emissions scenario (SSP1-1.9).\19\ In contrast, the
intermediate scenario (SSP2-4.5) results in potentially dangerous
warming of 2.0 [deg]C by midcentury, rising to between 2.1 [deg] to 3.5
[deg]C by 2100.
---------------------------------------------------------------------------
\16\ PHMSA acknowledges much of the discussion in section II and
elsewhere in this NPRM is focused on methane emissions from natural
gas pipeline facilities, as those facilities constitute the great
majority of gas pipeline facilities subject to parts 191 and 192.
However, PHMSA parts 191 and 192 requirements are not limited to
natural gas pipelines; rather, they also apply to pipeline
facilities transporting other gases which are flammable, toxic, or
corrosive--releases of which may entail significant public safety or
environmental consequences (including potential contributions to
climate change) in their own right. See Sec. Sec. 191.3 and 192.3
(definitions of ``gas'' for the purposes of parts 191 and 192,
respectively).
\17\ 2021 IPCC Report, 1.2.
\18\ 2021 IPCC Report, SPM-16, Table SPM.1.
\19\ 2021 IPCC Report, Table SPM.1.
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B. Dimensions of the Climate Crisis
Near-term methane emissions reductions are especially compelling
because global climate change is already causing observable, damaging
effects on the environment. The 2021 IPCC Report shows that the
environmental and social consequences of climate change are no longer
abstract, distant problems: scientists note increased surface
temperature, extreme weather events, rising sea levels, and other
consequences are being felt today and predict those effects will
intensify in the coming decades without immediate action to control GHG
emissions to avoid or stave off the worst effects of climate change.
Higher average surface temperatures will result in sea level rise,
severe heat waves, and more intense extreme weather events (hurricanes,
storms, droughts, and floods), in turn altering water supplies,
damaging habitats, and promoting wildfires. According to the findings
from the 3rd and 4th National Climate Assessment Reports released by
the U.S. Global Change Research Program,\20\ these dimensions of
climate change will have severe consequences for the human population
throughout the United States including alteration of population
distributions; widespread property damage; compromised local economies;
disrupted agriculture, fisheries, and other ecosystems; and degraded
public health.
---------------------------------------------------------------------------
\20\ See U.S. Global Change Research Program, Climate Science
Special Report: Fourth National Climate Assessment, Volume I (2017);
U.S. Global Change Research Program, Climate Change Impacts in the
United States: The Third National Climate Assessment (2014).
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The most immediate impact of climate change worldwide has been, and
will continue to be, an increase in average surface temperatures. The
average global surface temperature during 2021 was 1.51 degrees
Fahrenheit (0.84 degrees Celsius) warmer than the average temperature
in the 20th century (57.0 degrees Fahrenheit) and was 1.87 degrees
Fahrenheit (1.04 degrees Celsius) warmer than the average temperature
between 1880-1900, which NOAA describes as a ``reasonable surrogate for
pre-industrial conditions.'' \21\ That observed surface temperature
increase has resulted in cascading consequences for the natural world
already; as more GHGs are added to the atmosphere, the rate of warming
is expected to continue to accelerate.
---------------------------------------------------------------------------
\21\ See NOAA National Centers for Environmental Information,
Monthly Global Climate Report for Annual 2021 (Jan. 2022), https://www.ncei.noaa.gov/news/global-climate-202112.
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Increasing the average surface temperature of the Earth changes the
frequency and intensity of extreme temperature events. Higher average
surface temperatures means that heat waves everywhere will become more
frequent and more intense.\22\ The IPCC estimates that current levels
of warming
[[Page 31895]]
have made 10-year extreme heat events \23\ approximately 1.2 degrees
Fahrenheit more intense and 2.8 times more frequent. Likewise, the IPCC
estimates that 50-year extreme heat events have become 4.8 times more
frequent. The estimated frequency and intensity of extreme heat events
will increase further with additional warming, especially in warmer
summer months.\24\
---------------------------------------------------------------------------
\22\ 2021 IPCC Report, SPM-8, SPM-18.
\23\ Defined by the IPCC as ``daily maximum temperatures over
land that were exceeded on average once in a decade (10-year event)
or once every 50 years (50-year event) during the 1850-1900
reference period.'' See 2021 IPCC Report, SPM-24.
\24\ 2021 IPCC Report, SPM-23.
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A well-known consequence of elevated (average and instantaneous)
surface temperatures is rising sea levels. The global sea level has
risen by about 5.9-9.8 inches (0.15-0.25 meters) between 1901 and 2018
and the rate of increase and degree to which sea level rise can be
attributed with confidence to anthropogenic climate change have both
increased since 1971.\25\ The IPCC has determined that it is
``virtually certain'' that the global sea level will rise further by
2100, as land ice continues to melt and seawater expands as it warms,
with greater sea level rise resulting from higher GHG emissions
scenarios.\26\ An expected contributor to global sea level rise is the
loss of virtually all summer ice from the Arctic Ocean before 2050.\27\
Global average sea levels are projected to rise an additional 1.0-4.3
feet by 2100 under intermediate emissions scenarios, with a global sea
level rise in excess of 8 feet possible by 2100 under higher emissions
scenarios.\28\
---------------------------------------------------------------------------
\25\ 2021 IPCC Report, SPM-6.
\26\ 2021 IPCC Report, SPM-28.
\27\ European Space Agency (ESA), ``Simulations Suggest Ice-Free
Arctic Summers by 2050'' (May 13, 2020), https://climate.esa.int/en/projects/sea-ice/news-and-events/news/simulations-suggest-ice-free-arctic-summers-2050/.
\28\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Southeast at 758. (2018).
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Rising average surface temperatures also alter water cycles and
weather patterns such as precipitation and hurricanes. As noted above,
higher average and instantaneous surface temperatures will result in
loss of soil moisture in most regions. Meanwhile, some areas are
increasingly likely to experience heavy downpours, while other areas
will likely receive far less precipitation than in years past.\29\
Areas that are projected to have less total precipitation and higher
temperatures will likely become more susceptible to drought and
wildfires as a result; as described below, the United States has
already seen the acreage affected by wildfires trend upwards in recent
decades. Scientists also project that the recent trend toward more
frequent heavy precipitation events will continue, even in areas where
the total precipitation is expected to decrease, which could lead to
increased flooding risks, erosion, and land subsidence. As further
noted below, earth and water movement are also threats to pipeline
integrity that can lead to pipeline incidents and accidents that
threaten public safety and the environment.\30\ Similarly, scientists
have observed that it is likely that hurricanes have become stronger
and more intense and determined that it is likely that anthropogenic
climate change has increased rainfall rates associated with hurricanes
and other tropical cyclones.\31\
---------------------------------------------------------------------------
\29\ 2021 IPCC Report, SPM-15.
\30\ PHMSA, ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Earth Movement and Other Geological Hazards,''
87 FR 33576 (June 2, 2019) (Advisory Bulletin ADB-2022-01).
\31\ 2021 IPCC Report, SPM-9.
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The United States has a front-row seat to the effects of climate
change. Already, many areas of the United States are seeing increases
in the duration and frequency of heat waves and altered precipitation
patterns. The 2021 IPCC Report describes observed increases in extreme
heat and drought events occurring around the world, including western
North America.\32\ The Colorado River in the Southwest United States is
facing its first-ever water shortage, a phenomenon that is directly
linked to warming temperatures. Due to this historic shortage, in 2022,
the U.S. Department of the Interior`s Bureau of Reclamation proposed
significant cuts to water allocations from the Colorado River to
Arizona, Nevada, and Mexico in order to ensure continued operation of
hydroelectric generation facilities.\33\ In late June and early July of
2021, the Western part of the United States and Canada suffered a heat
wave that was likely exacerbated by climate change, with consequences
ranging as far north as the Yukon territory in Canada, and as far
inland as the State of Montana. Much of the Pacific Northwest reached
temperatures that were 20 to 35 degrees Fahrenheit above normal during
this heat wave, with several daily high temperature records being
broken. Temperatures grew so hot that nighttime low temperatures in
many areas were higher than historical average daytime high
temperatures.
---------------------------------------------------------------------------
\32\ 2021 IPCC Report, SPM-12.
\33\ Yanchin, ``Interior Threatens Colorado River Cuts,'' E&E
News (Oct. 28, 2022), https://www.eenews.net/articles/interior-threatens-colorado-river-cuts/.
---------------------------------------------------------------------------
Higher average surface temperatures and extreme instantaneous
temperatures have also exacerbated wildfires in the United States.
Prolonged heat has led to dry vegetation, and the heat and dry
vegetation have contributed to the severity of several wildfires.
According to the research compiled in the 4th National Climate
Assessment, drought in California and the Colorado River Basin have
made forests ``more susceptible to burning'' and caused ``spring-like
temperatures to occur earlier in the year,'' extending the western fire
season \34\ and doubling the cumulative forest area burned by wildfires
between 1984 and 2015.\35\ Wildfires pose serious health risks,
including illnesses from smoke inhalation and contaminated drinking
water, and cause significant property damage ($3.1 billion in the Los
Angeles area alone from 1990 to 2009, or approximately $4 billion in
2021 dollars).\36\ The 4th National Climate Assessment cautions that
the frequency and intensity of wildfires in the Western United States
will increase with further warming, with higher emissions scenarios
estimating a 25% increase in wildfires in the Southwest region and
three times as many wildfires that exceed 5,000 hectares in size.\37\
Researchers at the University of California, Los Angeles and Columbia
University have determined that the 22-year period from 2000-2021 was
the driest such period in the Southwestern United States since the year
800, due in large part to climate change.\38\ Climate change poses a
significant threat of extending the drought even further. In fact, the
Southwestern drought is expected to persist through at least the end of
2022 and become the longest megadrought on record in the Southwestern
United States, further endangering sources of water, and the
[[Page 31896]]
communities that rely on them, throughout the region.\39\
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\34\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Southwest at 1115, 1116 (2018).
\35\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Southwest at 1115, 1135 & Figure 25.4 (2018).
\36\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Southwest at 1116 (2018); Inflation adjustment via
Consumer Price Index inflation from December 2009 to December 2021.
\37\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Southwest at 1116 (2018).
\38\ Williams et al., ``Rapid Intensification of the Emerging
Southwestern North American Megadrought in 2020-2021,'' 12 Nature
Climate Change (Mar. 1, 2022).
\39\ Williams et al., ``Rapid Intensification of the Emerging
Southwestern North American Megadrought in 2020-2021,'' 12 Nature
Climate Change (Mar. 1, 2022).
---------------------------------------------------------------------------
The United States will also experience dramatically altered
precipitation and weather patterns from climate change. Increases in
GHG concentrations in the atmosphere have already led to increased
Atlantic hurricane activity, and a warming climate is projected to
cause extreme rainfall and significant regional flooding from
hurricanes, nor'easters, and other severe storms, in addition to
exacerbating the intensity of hurricanes in the Atlantic and eastern
North Pacific.\40\ While projections are difficult to make for
infrequent, smaller weather events like tornadoes and severe
thunderstorms, these events have also been recently exhibiting changes
that may be caused by climate change.\41\ Moreover, tornadoes can be
generated by hurricanes (such as the 25 tornadoes produced by Hurricane
Irma in 2017, mostly along the east coast of Florida), and more intense
hurricanes could generate more tornadoes.
---------------------------------------------------------------------------
\40\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Our Changing Climate at 74, 95 (2018) (noting the
heaviest rainfall amounts from recent storms have been estimated to
be 6-7% greater than the most intense storms of the early 1900s).
\41\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Our Changing Climate at 97 (2018).
---------------------------------------------------------------------------
Climate change-induced sea level rise is and will continue to be
experienced in the United States. Sea level rise has already led to
more frequent high tide flooding. One study of flooding in 27
communities cited in the Fourth National Climate Assessment found that
the frequency of high tide flooding in several communities has
increased by a factor of 5 or more, and that such flooding increased by
a factor of 10 or more in Atlantic City (NJ), Baltimore (MD), Annapolis
(MD), Wilmington (DE), Port Isabel (TX), and Honolulu (HI).\42\ In the
Southeast, tidal data from the National Oceanic and Atmospheric
Administration shows sea level rise of 1-3 feet has already occurred
over the past 100 years. The effects of sea level rise are not
distributed equally across the world, nor along the U.S. coastline;
instead, the Northeast United States, eastern coast of Florida, and
western Gulf Coast regions will likely experience the worst impacts
from rising sea levels and coastal flooding due to ocean circulation,
land subsidence, and uneven ice melt. The 4th National Climate
Assessment identifies an average of 2 to 4.5 feet as the most probable
sea level rise in the Northeast United States before 2100 with worst-
case estimates projecting sea level rise of more than 11 feet over the
same period.\43\ Under higher emission projections, the 4th National
Climate Assessment found it likely that all U.S. coastlines, other than
Alaska, will experience sea level rise greater than the global averages
due to Antarctic ice loss. By 2100, sea level rise is likely to
submerge real estate worth between $238-507 billion across the United
States and force the migration of substantial elements of the U.S.
population.\44\ Average sea level rise of 6 feet by 2100 could displace
an estimated 13.1 million people along the U.S. coasts.\45\
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\42\ Sweet & Park, ``From the Extreme to the Mean: Acceleration
and Tipping Points of Coastal Inundation from Sea Level Rise,
Earth's Future 2 at 579-600 (2014).
\43\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Northeast at 692 (2018).
\44\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Coastal Effects at 330, 335 (2018).
\45\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Coastal Effects at 335 (2018).
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These and other dimensions of the climate crisis also have
disastrous near and long-term consequences for human health. The EPA
Administrator, as early as 2009 \46\ (and again in 2016),\47\
determined that methane along with 5 other ``well-mixed greenhouse
gases'' together constituted a harmful air pollutant that endangered
public health and welfare of persons. According to the 2016 assessment
of human health impacts of climate change from the U.S. Global Change
Research Program (2016 Assessment), climate change will likely
contribute to ``thousands to tens of thousands of premature heat-
related deaths in the summer'' in the United States in the years
ahead.\48\ Indeed, the heat wave in summer 2021 discussed above
resulted in excess heat-related deaths of 143 in Washington, 119 in
Oregon, 13 in California, and 619 in British Columbia according to
public health authorities.\49\ The 2016 Assessment also notes climate
change is likely to result in ``meteorological conditions increasingly
conducive to forming ozone over most of the United States,'' which is
likely to result in ``premature deaths, hospital visits, lost school
days, and acute respiratory symptoms.'' \50\ The 4th National Climate
Assessment also notes that, in addition to the immediate hazard to life
and property, climate change-induced wildfires will result in direct
hazards to human health in the form of burns, smoke inhalation,
exacerbation of particulate and ozone pollution, and negative impacts
on water quality.\51\
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\46\ 74 FR 66495 (Dec. 15, 2009).
\47\ 81 FR 54422 (Aug. 15, 2016).
\48\ U.S. Global Change Research Program, The Impacts of Climate
Change on Human Health in the United States: A Scientific
Assessment--Executive Summary at 6 (2016).
\49\ U.S. Department of Health and Human Services, Office of
Climate Change and Health Equity, Climate and Health Outlook:
Extreme Heat (June 2022), https://www.hhs.gov/sites/default/files/climate-health-outlook-june-2022.pdf; British Columbia, ``Minister's
Statement on 619 Lives Lost During 2021 Heat Dome'' (June 7, 2022).
https://news.gov.bc.ca/26965.
\50\ Methane also directly contributes to adverse air quality
because it is a chemical precursor to ozone.
\51\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Water at 154 (2018); U.S. Global Change Research Program,
Impacts, Risks, and Adaptation in the United States: Fourth National
Climate Assessment, Volume II--Air Quality at 514, 519 (2018); U.S.
Global Change Research Program, Impacts, Risks, and Adaptation in
the United States: Fourth National Climate Assessment, Volume I--
Southeast at 755 (2018).
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Increased intensity and frequency of extreme weather events (such
as hurricanes and floods) from climate change also threaten human life
and property. In the Northeast, high-tide flooding will impact low-
lying areas with increased frequencies and could result in an
additional $6--9 billion in damages per year by 2100 in high emissions
scenarios.\52\ In 2017, Hurricane Irma caused, in the United States,
the deaths of 84 people and costs of approximately $50 billion (with
Florida suffering most of these costs). In the Midwest, the Fourth
National Climate Assessment found precipitation has increased by
between 5% to 15% since the 1901-1960 period; the Fourth National
Climate Assessment projects that seasonal precipitation during winter
and spring associated with flood risk could increase by ``by up to 33%
by the end of the century.'' \53\ Extreme precipitation events and
river flooding could damage private property and transportation
infrastructure and overwhelm stormwater treatment facilities, resulting
in water quality impacts, especially in communities with combined sewer
overflows. In the Southern Great Plains States, increased frequency and
severity of severe floods was also projected for the southern
[[Page 31897]]
Great Plains states, potentially resulting in significant costs from
flood damage and adaptation costs.\54\ The Fourth National Climate
Assessment also found climate change-induced degradation of natural
habitats, agricultural resources, water resources, and other ecological
resources threaten the viability of subsistence and commercial
activities that Federally recognized Indian Tribes depend on, such as
``agriculture, hunting and gathering, fisheries, forestry, energy,
recreation, and tourism,'' and threaten Tribal water allocations in the
Western United States.\55\
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\52\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Northeast at 695 (2018).
\53\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Midwest at 914-16 (2018).
\54\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Southern Great Plains at 1003-06 (2018).
\55\ U.S. Global Change Research Program, Impacts, Risks, and
Adaptation in the United States: Fourth National Climate Assessment,
Volume II--Tribes and Indigenous Peoples at 579 (2018).
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Increased severe whether phenomena caused by climate change further
threaten human health by wreaking havoc on public services and
infrastructure. Hurricane Nicholas in the Gulf of Mexico in September
2021 caused widespread flooding and weeks of blackouts on the U.S. Gulf
Coast, much as the increasingly long wildfire season in California is
now routinely accompanied by threats of rolling blackouts. The summer
2021 heat wave that blanketed the Western United States damaged
transportation infrastructure, closing multiple lanes on Interstate 5
and causing trains to operate at reduced speeds as a precaution against
the potential deformation of rail tracks. Earlier, the 2017 Atlantic
hurricane season produced the second and third costliest hurricanes in
U.S. history, hurricane Harvey and Hurricane Maria. Hurricane Harvey
caused more than 60 inches of rainfall over the Texas Gulf Coast,
including the Houston metro area, and resulted in at least 68 direct
casualties and approximately $125 billion in storm-related damage.\56\
Hurricane Maria caused widespread devastation in Puerto Rico, resulting
in approximately $90 billion dollars in damage and the near total loss
of electric, water, and telecommunication infrastructure across the
island, and electrical outages persisted for months across much of the
island.\57\
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\56\ Eric S. Blake and David A. Zelinsky. NOAA National
Hurricane Center. `National Hurricane Center Tropical Cyclone
Report.'' May 9, 2018. https://www.nhc.noaa.gov/data/tcr/AL092017_Harvey.pdf.
\57\ Richard J. Pasch, Andrew B. Penny, and Robbie Berg. NOAA
National Hurricane Center. ``National Hurricane Center Tropical
Cyclone Report: Hurricane Maria.'' February 14, 2019. At page 7.
https://www.nhc.noaa.gov/data/tcr/AL152017_Maria.pdf.
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Pipeline infrastructure is similarly vulnerable to the impacts of
climate change. For example, well-documented threats to pipeline
infrastructure from natural force damage (which includes incidents
caused by acts of nature such as flooding, land movement, and
lightning) are likely to be exacerbated by climate change. On April 11,
2019, PHMSA published an advisory bulletin on the threat that severe
flooding can have on pipeline integrity, especially at water
crossings.\58\ As described in further detail in the advisory bulletin,
flooding and related earth movements can cause damage to pipelines in
and around water crossings from direct water force, impacts from
debris, added strain on pipeline structures through changes in loading
conditions, and other means. Flooding can also threaten pipeline
integrity by causing damage to aboveground, safety-critical components
such as valves, pressure regulators, relief devices, and pressure
sensors. A weather-induced failure of a gas pipeline can result in
releases that threaten public safety and further contribute to climate
change. On May 2, 2019, PHMSA issued another advisory bulletin to
remind operators of the risks to pipeline facilities from large earth
movement, including subsidence and erosion events that can be
intensified due to climate change.\59\ PHMSA issued an update to this
advisory bulletin on June 2, 2022, noting recent incidents and
accidents underscoring the risks described in Advisory Bulletin ADB-
2019-02.\60\ This most recent bulletin notes that changing weather
patterns due to climate change can weaken soil stability, increasing
the likelihood of earth movement damage to pipeline facilities.
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\58\ PHMSA, ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Flooding, River Scour, and River Channel
Migration,'' 84 FR 14715 (Apr. 11, 2019) (Advisory Bulletin ADB-
2019-01).
\59\ PHMSA, ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Earth Movement and Other Geological Hazards,''
84 FR 18919 (May 2, 2019) (Advisory Bulletin ADB-2019-02).
\60\ PHMSA, ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by Earth Movement and Other Geological Hazards,''
87 FR 22576 (June 2, 2022) (Advisory Bulletin ADB-2022-01).
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PHMSA has also documented serious pipeline integrity threats from
hurricanes in an advisory bulletin published on September 1, 2011,
titled ``Pipeline Safety: Potential for Damage to Pipeline Facilities
Caused by the Passage of Hurricanes.'' \61\ This advisory bulletin
notes that hurricanes can directly damage pipelines, cause submerged
pipelines to become exposed, or otherwise cause pipeline facilities to
become a hazard to navigation. The advisory bulletin also noted that in
2005, Hurricane Katrina and Hurricane Rita caused extensive damage to
onshore and offshore oil and gas production and transportation
infrastructure in the Gulf of Mexico, which took substantial time and
resources to contain and remediate. PHMSA expects more severe and
frequent hurricanes will amplify the risk of damage to pipeline
facilities, to the detriment of coastal communities, environments, and
the reliability of the U.S. oil and gas industry.
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\61\ PHMSA, ``Pipeline Safety: Potential for Damage to Pipeline
Facilities Caused by the Passage of Hurricanes,'' 76 FR 54531 (Sept.
1, 2011) (Advisory Bulletin ADB-11-050).
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Finally, these and other consequences of climate change have been,
and are expected to continue to be, disproportionately borne by
vulnerable populations in the United States--in particular by minority
and low-income populations, outdoor laborers, children, and the
elderly.\62\ Some communities of color may be uniquely vulnerable to
climate change health impacts in the United States because they live in
areas where the impacts of climate change (e.g., extreme temperatures
and flooding) are likely to be the most significant, and because these
communities tend to have limited adaptive opportunities due to a
greater dependence on climate-sensitive resources (such as local water
and food supplies), economic opportunities (e.g., seasonal labor), and
limited access to social and information resources. The 2016 scientific
assessment on the Impacts of Climate Change on Human Health similarly
found that social determinants of health (e.g., access to healthcare,
economic stability) are highly likely to contribute to climate change-
related health impacts.\63\ And insofar as gas transmission and gas
gathering pipeline infrastructure is often located in the vicinity of
socially vulnerable populations,\64\ those populations would face the
greatest risks in the event of a release from a gas pipeline damaged by
climate change-induced extreme weather events.
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\62\ U.S. Global Change Research Program, The Impacts of Climate
Change on Human Health in the United States: A Scientific
Assessment--Executive Summary at 6 (2016).
\63\ U.S. Global Change Research Program, The Impacts of Climate
Change on Human Health in the United States: A Scientific Assessment
at 21 (2016).
\64\ See Emanuel et al., ``Natural Gas Gathering and
Transmission Pipelines and Social Vulnerability in the United
States,'' 5 GeoHealth (June 2021).
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C. Methane Emissions From Gas Pipeline Facilities
Most gas produced or consumed in the United States is transported
by a gas
[[Page 31898]]
pipeline at some stage of its lifecycle. PHMSA is, by statute (49
U.S.C. 60101 et seq.), responsible for regulating the interstate
transportation of gas by pipeline facilities, which can include the
gathering, transmission, and distribution of natural gas as well as
other gases regulated under parts 191 and 192.\65\ Federal law,
however, provides that the certified State agencies have jurisdiction
to regulate purely intrastate gas pipeline facilities. Certain
certified State programs may also inspect interstate pipelines, such as
interstate distribution systems. Both Federal and State regulation of
gas pipeline facilities has historically been directed toward the
immediate, direct risks to public safety (and indirect risks to the
environment) associated with the ignition of natural gas releases--less
so on the direct threat to environmental risks, including those risks
posed by un-ignited, released methane, that invariably contribute to
climate change.\66\
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\65\ Parts 191 and 192 govern not only natural gas, but also any
``flammable gas, or gas which is toxic or corrosive.'' See
Sec. Sec. 191.3 and 192.3 (definitions of ``gas''). Consequently,
the proposed revisions to parts 191 and 192 within this NPRM would
apply not only to natural gas pipelines but also to other gas
pipeline governed by parts 191 and 192.
\66\ PHMSA acknowledges that in revising its Pipeline Safety
Regulations over the years, it has identified environmental benefits
of those efforts in much the same way that it has identified other
benefits (e.g., reduced compliance cost for operators, equity, etc.)
of those rulemakings. However, PHMSA submits those non-safety
benefits were generally presented as secondary benefits of safety-
focused regulatory amendments.
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1. Gas Pipeline Facilities
PHMSA regulations cover several types of gas pipeline facilities,
including gas gathering pipelines, gas transmission pipelines, gas
distribution pipelines, LNG facilities, and UNGSFs.
Gathering Pipelines
A gas gathering pipeline is defined in Federal regulations at Sec.
192.3 as a pipeline that transports gas from a production facility to a
transmission pipeline or main. More generally, these pipelines
``gather'' gas from production facilities for transport to a gas
processing plant for further transportation across transmission
pipelines. The precise points where a gathering pipeline begins and
ends are defined in Sec. Sec. 192.8 and 192.9 and the first edition of
American Petroleum Institute (API) Recommended Practice 80,
``Guidelines for the Definition of Onshore Gas Gathering Lines.'' \67\
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\67\ API, Recommended Practice 80: Guidelines for the Definition
of Onshore Gas Gathering Lines (Apr. 2000) (API RP 80).
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Section 192.9(b) provides that offshore gas gathering pipelines are
generally subject to the same part 192 requirements as gas transmission
pipelines. Section 192.8 also defines three types of regulated onshore
gas gathering pipelines subject to part 192 requirements: Type A, Type
B, and Type C gathering pipelines. Operators reported 8,290 miles of
Type A pipelines, 3,078 miles of Type B pipelines, and 5,706 miles of
offshore gathering lines in their 2021 annual reports. Type C gathering
line operators will be required to submit their first annual report for
calendar year 2022 in 2023; PHMSA estimates that there are
approximately 90,000 miles of Type C gathering lines.\68\ Type A and
Type B gathering pipelines are located in Class 2, Class 3, or Class 4
locations. Type A gathering pipelines are higher-pressure pipelines and
subject to most part 192 safety requirements applicable to gas
transmission pipelines, while Type B gathering pipelines are lower
pressure pipelines subject to a smaller subset of specific part 192
safety requirements listed in Sec. 192.9(d). The Type C gathering
pipeline designation was established in a final rule titled ``Pipeline
Safety: Safety of Gas Gathering Pipelines: Extension of Reporting
Requirements, Regulation or Large, High-Pressure Lines, and Other
Related Amendments'' published on Nov. 15, 2021.\69\ Type C gathering
pipelines are located in Class 1 locations, have an outside diameter
greater than or equal to 8.625 inches, and operate at high
pressure.\70\ These pipelines are subject to scaled safety requirements
in Sec. 192.9(e), with more part 192 safety requirements applicable as
a function of the risk posed to public safety based on the diameter of
the Type C segment (which affects the potential energy of a pipeline
rupture and explosion) and its proximity to nearby populated
structures. For example, Sec. 192.9(e) provides that while all Type C
lines are required to carry out a damage prevention program, leakage
survey requirements only attach to either the largest (outside diameter
greater than 16 inches) Type C lines, or those Type C lines with
smaller diameters (8.625 inches through 16 inches) near buildings
intended for human occupancy.
---------------------------------------------------------------------------
\68\ See PHMSA, Doc. No. PHMSA-2011-0023, ``Regulatory Impact
Analysis: Pipeline Safety: Expansion of Gas Gathering Regulation
Final Rule'' at 11, 15 (Nov. 2021) (Gas Gathering RIA).
\69\ 86 FR 63266 (Gas Gathering Final Rule). Certain smaller-
diameter Type C gas gathering pipelines are the subject of a
temporary enforcement discretion whereby PHMSA has committed not to
pursue enforcement action against those pipelines for alleged
violations of certain part 192 safety requirements before May 17,
2024. See PHMSA, ``Notice of Limited Enforcement Discretion for
Particular Type C Gas Gathering Pipelines'' (July 8, 2022), https://www.phmsa.dot.gov/news/notice-limited-enforcement-discretion-particular-type-c-gas-gathering-pipelines.
\70\ See the pressure criteria in the second column of table 1
in Sec. 192.8(c)(2).
---------------------------------------------------------------------------
Type A, Type B, and certain Type C gathering pipelines (namely,
those Type C gathering pipelines that are installed, replaced,
relocated, or otherwise changed after May 16, 2023) must comply with
the design, construction, initial inspection, and initial testing
requirements applicable to gas transmission lines, and must therefore
be constructed from similar materials. According to annual reports
submitted to PHMSA, gas transmission pipelines and Type A and Type B
regulated onshore gathering lines are generally made from steel and, to
a lesser extent, polyethylene plastic. An operator may also use two
polyamide compounds, PA-11 and PA-12. Composite materials \71\ may be
used with notification to PHMSA on a Type C gathering pipeline. PHMSA
expects that most Type C gathering pipelines, which have operational
characteristics similar to gas transmission and Type A regulated gas
gathering pipelines, are made of steel, but Type C pipelines existing
prior to May 16, 2023, may have been constructed with non-standard
materials.
---------------------------------------------------------------------------
\71\ ``Composite materials'' are defined in Sec. 192.3 as
materials used to make pipe or components manufactured with a
combination of either steel and/or plastic and with a reinforcing
material to maintain its circumferential or longitudinal strength.
---------------------------------------------------------------------------
Transmission Pipelines
A gas transmission pipeline is defined in Sec. 192.3 to include
any pipeline, other than a gathering pipeline, that transports gas from
a gathering pipeline or storage facility to a distribution center,
storage facility, or large-volume customer such as a gas power station
or an LNG facility. In 2021, operators reported 301,524 miles of gas
transmission pipelines on their annual reports. Additionally, a
pipeline other than a gathering pipeline that operates at a hoop stress
of 20% or more of the specified minimum yield strength (SMYS),\72\ or
that transports gas within a storage field, is also classified as a gas
transmission pipeline. An operator may also voluntarily designate a
pipeline as a gas transmission pipeline that would otherwise meet the
definition of a gas gathering pipeline or gas distribution
[[Page 31899]]
pipeline. Gas transmission pipelines are typically steel, larger
diameter (6 to 48 inches), high-pressure lines (operating pressures
generally between 200 and 1500 pounds per square inch) transporting
large volumes of gas long distances.
---------------------------------------------------------------------------
\72\ SMYS is defined in 49 CFR 192.3 to mean specified minimum
yield strength, which is a measure of tensile strength. As an
example, Trade B pipe made to API 5L specification has a specified
minimum yield strength (SMYS) of 35,000 pounds per square inch (psi)
40 percent of SMYS (35,000 x 0.40) is 14,000 psi.
---------------------------------------------------------------------------
Distribution Pipelines
A gas distribution pipeline is defined at Sec. 192.3 as a pipeline
other than a gas transmission pipeline or gathering pipeline.
Distribution pipelines are typically a part of a distribution system
that transports gas received from a transmission pipeline by a
distribution center (often located at the so-called ``city gate''), and
then to homes and businesses through a network of gas mains and service
pipelines.\73\ A gas distribution service pipeline feeds gas to one or
two customers, while a distribution main is the common source of supply
for two or more service pipelines. In 2021, distribution operators
reported 2,300,793 miles of gas distribution mains and service lines on
their annual reports. While virtually all gas transmission piping is
fabricated from steel, gas distribution pipeline materials vary
depending on the vintage and usage. Modern systems are predominately
polyethylene plastic and protected steel (i.e., coated with corrosion-
resistant materials and/or equipped with cathodic protection); older
systems may contain cast-iron or bare (not protected) steel piping.
Distribution pipelines made of copper, wrought iron, and non-
polyethylene plastic also exist but are less common.
---------------------------------------------------------------------------
\73\ Under 49 U.S.C. 60105 and 60106, States may assume safety
authority over intrastate gas pipelines through certifications and
agreements with PHMSA. Currently, the District of Columbia, Puerto
Rico, and all States except Alaska and Hawaii exercise safety
oversight authority over all intrastate gas distribution pipelines
within State lines. These State programs conduct regular inspections
and enforce State safety regulations over intrastate distribution
pipelines. See PHMSA's State Programs website for more information:
https://www.phmsa.dot.gov/working-phmsa/state-programs/state-programs-overview (last accessed Dec. 20, 2022).
---------------------------------------------------------------------------
LNG Facilities
An LNG facility is defined in Federal regulations at 49 CFR part
193 \74\ as a gas pipeline facility that is used for liquefying natural
gas or synthetic gas or transferring, storing, or vaporizing LNG. LNG
means natural gas or synthetic gas having methane as its principal
constituent, and which has been changed to a liquid, thereby reducing
the volume of the gas to facilitate storage and long-distance
transportation. LNG facilities are subject to the safety requirements
in part 193. LNG facilities include gas pipeline facilities that either
change gas into LNG (liquefaction) or that change LNG back into a vapor
or gaseous state (vaporization). LNG facilities also include transfer
piping systems that transfer LNG between any of the following:
liquefaction process facilities, storage tanks, vaporizers,
compressors, cargo transfer systems, and facilities other than gas
pipeline facilities. In 2021, operators reported 168 in-service LNG
facilities on their annual reports.
---------------------------------------------------------------------------
\74\ Part 193 requirements may change as a result of regulatory
amendments proposed in a forthcoming notice of proposed rulemaking
issued under RIN 2137-AF45. PHMSA's references to part 193 within
this NPRM--including the proposed amended regulatory text at its
conclusion--reflect current regulatory text and organization.
---------------------------------------------------------------------------
Underground Natural Gas Storage Facilities
Finally, an UNGSF is defined at Sec. 192.3 as a gas pipeline
facility that stores natural gas underground incidental to the
transportation of natural gas, including: (1) a depleted hydrocarbon
reservoir; (2) an aquifer reservoir; or (3) a solution-mined salt
cavern. In addition to the storage reservoir or cavern itself, an UNGSF
includes: injection, withdrawal, monitoring, and observation wells;
wellbores and downhole components; wellheads and associated wellhead
piping; wing-valve assemblies that isolate the wellhead from connected
piping beyond the wing-valve assemblies; and any other equipment,
facility, right-of-way, or building used in the underground storage of
natural gas. Most underground natural gas storage occurs in depleted
natural gas reservoirs. UNGSFs are subject to specific safety
requirements set forth in Sec. 192.12.
2. Sources of Emissions From Gas Pipeline Facilities
Emissions of methane and other gases subject to PHMSA's regulations
under part 192 occur in all sectors of the natural gas industry--from
production/extraction facilities, gathering pipelines, processing
facilities (where the gas is made suitable for transportation and use),
transmission pipelines, distribution pipelines, and end user
facilities.\75\ Emissions occur during normal operation, routine
maintenance, and abnormal conditions (such as incidents). Gas pipeline
facilities emit methane and other gases from ``fugitive emissions''
from system upsets (incidents and abnormal operations that result in
the release of gas); unintentional leaks from line pipe, flanges,
valves, meter sets, and other equipment; and intentional releases (such
as when a gas pipeline facility is blown down for repairs or
maintenance or through pressure relief device operation as designed or
configured). Older pipelines and pipelines known to leak based on their
material (e.g., legacy materials such as cast iron, wrought iron,
unprotected steel, and certain historic plastics), design, or past
operating and maintenance history are generally more susceptible to
leaks.
---------------------------------------------------------------------------
\75\ Although the evaluation of release data discussed in this
section II.C.2 and subsequent sections is focused on the location,
frequency, and severity of leaks on natural gas pipeline facilities,
that analysis is largely applicable to leaks on other part 192-
regulated gas pipeline facilities. Indeed, certain part 192-
regulated gas pipeline facilities (e.g., gas pipeline facilities
transporting hydrogen gas) may be particularly susceptible to leaks
because of (inter alia) the smaller size of hydrogen gas molecules
compared to methane molecules of which natural gas is mostly
composed.
---------------------------------------------------------------------------
The EPA compiles and publishes data on the magnitude and sources of
methane emissions from gas gathering, transmission, and distribution
pipelines and other gas pipeline facilities. The EPA has two
complementary programs for characterizing GHG emissions such as
methane: the Inventory of Greenhouse Gas Emissions and Sinks
(Greenhouse Gas Inventory, or GHGI), and the Greenhouse Gas Reporting
Program (GHGRP).
The 2022 GHGI estimates a time series of total annual
national-level GHG emissions across sectors of the economy using a
large number of data inputs including GHGRP, research studies, and
national and subnational activity data sets. The most recent final GHGI
(2022 GHGI) includes estimates from 1990 through 2020.\76\ The GHGI
includes estimates of GHG emissions from sources including fossil fuel
combustion, industrial processes, agriculture, and transportation. The
GHGI is updated annually.
---------------------------------------------------------------------------
\76\ EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks:
1990-2020 (Apr. 15, 2022) (2022 GHGI).
---------------------------------------------------------------------------
The Greenhouse Gas Reporting Program (GHGRP) has, since
2010, collected facility-level emissions data from certain large GHG
emission sources, fuel and industrial gas suppliers, and CO2
injection sites in the United States including large suppliers or
facilities that emit more than 25,000 metric tons of CO2
equivalent per year.\77\
---------------------------------------------------------------------------
\77\ In the GHGI, the EPA estimates that the global warming
potential of 1 metric ton of CH4 is equivalent to 25
metric tons of CO2 over a 100-year time horizon. (40 CFR
98, Table A-1 to Subpart A of Part 98).
---------------------------------------------------------------------------
For the 2020 reporting year, subpart W facilities in the GHGRP
included 164 reports from distribution operators and 45 reports from
gas transmission pipeline operators. However, GHGRP
[[Page 31900]]
data is not congruent with the pipelines subject to PHMSA regulations.
For example, the 45 gas transmission pipeline operators submitting
reports under GHGRP for the 2020 reporting year correspond only to
approximately \2/3\ of gas transmission pipeline mileage
nationwide.\78\ Additionally, certain entire sectors, such as the
agricultural sector, are not required to report to the GHGRP. The
creation of the GHGRP was provided for by Congress in the fiscal year
2008 Consolidated Appropriations Act (Pub. L. 110-161) and promulgated
under section 114 of the Clean Air Act.\79\ Data must be reported to
EPA by March 31 of each year. Petroleum and natural gas industries,
including natural gas distribution facilities, onshore natural gas
gathering and boosting, onshore natural gas transmission pipelines
(including compression), and LNG storage/terminal facilities are
covered under 40 CFR part 98, subpart W.
---------------------------------------------------------------------------
\78\ One operator may submit multiple GHGRP reports if they
operate multiple systems or in multiple states.
\79\ 42 U.S.C. 7414.
---------------------------------------------------------------------------
The GHGI estimates for methane emissions are generally developed by
multiplying an emissions factor by an activity factor. For example, for
distribution main leaks, an emission factor in kg CH4 per
mile by material type is multiplied by mileage data by material type
(an activity factor) from PHMSA annual reports. Each itemized emissions
segment or source in the GHGI has its own emissions factor, in many
cases derived from GHGRP data. EPA annually updates the methodology in
the GHGI to improve accuracy and completeness.\80\ The current GHGI
quantifies emissions from leaks in pipelines using the following
approaches and data:
---------------------------------------------------------------------------
\80\ Refer to tables 3.6-2, 3.6-6, and 3.6-17 of Annex 36 of the
2022 GHGI for more information on the methodologies or data sources
used by EPA to develop each emissions factor.
---------------------------------------------------------------------------
Gathering pipeline leaks. Emission factors are developed
using year specific GHGRP data. GHGRP data are used as the activity
factor as well. GHGRP data are reported by material type.
Transmission pipeline leaks. Data from EPA/GRI 1996 were
used to develop the emission factor. PHMSA mileage data are used as the
national activity factor.
Distribution pipeline leaks. Data from Lamb et al. 2015
were combined with EPA/GRI 1996 to develop the material-specific
emission factors. PHMSA main mileage and service line count data are
used as the national activity factor, by material type.
Recent research using modern leak detection equipment indicates
that overall fugitive methane emissions from gas pipeline facilities
may be significantly underestimated in current methane emissions
estimates. The methodology of multiplying an activity factor (such as
pipeline mileage) by an emissions factor to extrapolate an estimate of
overall emissions for a given source is considered a ``bottom-up''
approach that can be contrasted with a ``top-down'' approach taking
total emissions measured at larger (e.g., national) scales and
attributing emissions to specific sources through modeling. Top-down
approaches regularly estimate higher total emissions in the atmosphere
than have been estimated by bottom-up approaches (sometimes referred to
as the ``top-down/bottom-up gap''). For example, recent analysis using
top-down methods from the International Energy Agency (IEA) released in
early 2022 found that global methane emissions from the energy sector
are about 70% greater than the official statistics reported by national
governments.\81\ IEA used satellite-based sensor technologies,
atmospheric methane measurements, and data processing techniques to
capture total emissions over large areas and attribute those emissions
to facility-level sources, rather than by simply multiplying activity
factors by bottom-up emissions factors. Other studies comparing the two
approaches have consistently shown that bottom-up approaches may
underestimate total U.S. methane emissions by 50% or more.\82\ One
explanation suggested for the significant discrepancy in estimated
emissions is that bottom-up methods under-sample large but infrequent
emissions events such as malfunctions and venting, possibly due to the
difficulty and risks associated with taking samples during such
events.\83\ Furthermore, as discussed below, recent research also
indicates that potential under-estimation of pipeline facility
emissions could be particularly pronounced in connection with
distribution and gathering pipelines. EPA has recently proposed
adjustments to its GHGRP data collection for reporting equipment leaks
from natural gas distribution sources (including pipeline mains and
services, below grade transmission-distribution transfer stations, and
below grade metering-regulating stations) and for reporting emissions
from equipment at onshore petroleum and natural gas production and
onshore petroleum and natural gas gathering and boosting
facilities.\84\ Additional discussion of emissions factors for gas
pipelines is available in the Preliminary RIA for this NPRM available
in the rulemaking docket.
---------------------------------------------------------------------------
\81\ IEA, Press Release, ``Methane emissions from the energy
sector are 70% higher than official figures'' (Feb. 23, 2022),
https://www.iea.org/news/methane-emissions-from-the-energy-sector-are-70-higher-than-official-figures. IEA's analysis may
underestimate the full extent of methane emissions as satellite data
used by the organization do not provide complete coverage of all
global oil and gas operations.
\82\ Zavala-Araiza et al., ``Reconciling Divergent Estimates of
Oil and Gas Methane Emissions,'' 112 Proceedings of the National
Academy of Sciences of the United States of America 11597-98 (Dec.
22, 2015); Lyon et al., ``Constructing a Spatially Resolved Methane
Emission Inventory for the Barnett Shale Region,'' 49 Environmental
Science & Technology at 8147, 8154 (July 7, 2015); Alvarez et al.,
``Assessment of Methane Emissions from the U.S. Oil and Gas Supply
Chain,'' Science 186 (June 21, 2018).
\83\ Brandt et al., ``Methane Leakage from North American
Natural Gas Systems,'' Science 343, 345 (Feb. 13, 2014); Zavala-
Araiza et al., 2015, at 15598; Lyon, at al., 2015, at 8147, 8155;
Alvarez et al., 2018, at 183. The authors of the Brandt, Zavala-
Araiza, and Lyon studies also suggest that this underestimation of
emissions could be due to (or exacerbated by) incomplete activity
factors that omit certain emissions source activities (such as
inaccurate component counts or even the omission of entire
facilities). Further, the authors of the Brandt study point to
limited sample sizes and changing technologies as other potential
sources of error in bottom-up emissions estimates.
\84\ EPA, ``Revisions and Confidentiality Determinations for
Data Elements under the Greenhouse Gas Reporting Rule--Notice of
Proposed Rulemaking'' 87 FR 36920, 36927 (June 21, 2022).
---------------------------------------------------------------------------
Methane Emissions Data--All Natural Gas Pipeline Facilities
The 2022 GHGI estimated annual net methane emissions from U.S.
natural gas systems in 2020 to be 6,6,137 thousand metric tons
(kt).\85\ Gas transmission, gas distribution, transportation-related
gas and LNG storage, and regulated gas gathering lines as determined in
Sec. 192.8 are regulated by PHMSA. On the other hand, exploration,
production, gas processing plants, and Type R unregulated gas gathering
lines are not regulated by PHMSA.). Assuming approximately one third of
gathering and boosting emissions are attributable to regulated gas
gathering lines, approximately half of net methane emissions from
natural gas systems are from PHMSA-regulated pipeline facilities. The
sector classifications used in the GHGI may not correspond precisely
with the regulatory definitions of different types of pipeline
facilities in the Federal Pipeline Safety Regulations. In EPA's GHGI,
the gathering and
[[Page 31901]]
boosting sources include gathering and boosting stations (with multiple
sources on site) and gathering pipelines. Those sources include PHMSA-
regulated gas gathering lines, Type R gathering lines, and some
pipelines and activities that are better described as production and
not transportation.\86\ The GHGI data cited in this section is for
natural gas systems, and therefore would be covered under the
regulatory classifications in part 192. The EPA definition is similar
in principle to the definition of a gas ``gathering line'' in part 192,
although it references some gas treatment processes that could be
classified as a ``production operation'' rather than as a gathering
pipeline under Sec. 192.9 and the first edition of API RP 80, and
therefore not under PHMSA's jurisdiction. However, for the purposes of
estimating emissions from leaks and incidents on PHMSA-regulated gas
gathering pipelines, PHMSA believes that the emissions rate associated
with ``pipeline leaks'' from ``gathering and boosting'' piping as
defined by EPA would not be significantly different than the emissions
rate for gas gathering pipelines as defined by PHMSA.
---------------------------------------------------------------------------
\85\ Natural gas systems include exploration, production,
gathering, processing, transmission, storage, and distribution of
gas. The 2022 GHGI inventory introduced estimates of post-meter
emissions. Emissions from power generation are estimated elsewhere
in the GHGI.
\86\ 2022 GHGI. Pg. 3-90.
---------------------------------------------------------------------------
While natural gas exploration and production (i.e., the upstream
sector) is the single largest source category, approximately one-third
of total methane emissions are attributed to transmission, storage, and
distribution systems, and an additional one-fourth of total methane
emissions is attributed to natural gas gathering and boosting systems.
A summary of these high-level emissions estimates is shown in the table
below and represent the net methane emissions \87\ for 2020 from
section 3.7 and annex 3.6 of the 2022 GHGI. These figures represent
only methane emissions and do not include, for example, CO2
emissions from compressor station engines.
---------------------------------------------------------------------------
\87\ Net emissions estimates include estimated emissions
reductions from reported implementation of EPA Methane Challenge and
Gas STAR best practices by operators in the production, transmission
and storage and distribution sectors and estimated reductions from
EPA regulatory requirements.
2022 GHGI: 2020 Natural Gas Systems Net Methane Emissions
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Exploration and Production (excluding 1,964 32
gathering).............................
Gathering and Boosting.................. 1,500 24
Processing Plants....................... 494 8
Transmission, Storage, and LNG.......... 1,625 26
Distribution............................ 554 9
-------------------------------
Total............................... 6,137 100
------------------------------------------------------------------------
Methane Emissions Data--Natural Gas Distribution Pipelines
The GHGI estimates that in 2020, approximately half of methane
emissions from natural gas distribution systems was caused by leaks
from and incidents on gas distribution line pipe. Leaks from customer
meters, meter stations, and regulator stations comprise most of the
remaining emissions. Recent studies indicate, however, that current
methane emissions data likely significantly under-estimates methane
emissions from gas distribution pipelines. For example, a national
study focusing on the natural gas distribution sector estimated
emissions from mains that were five times larger than those in the GHGI
estimate for 2017 estimates (0.69 million metric tons of methane vs.
0.14 million metric tons) \88\ and by extension the GHGI estimate for
2020 as well (0.69 million metric tons of methane vs. 0.13 million
metric tons).\89\ The current methodology for calculating the emissions
factors from natural gas distribution main and service pipelines in the
GHGI was most recently updated in 2016 \90\ and relies on a 1996 report
by the U.S. EPA and the Gas Research Institute (GRI) \91\ and a 2015
study by Lamb et. al.\92\ The 2020 study by Weller et.al. attributed
the differences to a larger number of leaks than previously estimated
and better quantification of the largest leaks from the distribution
sector (so-called ``super-emitter'' leaks), which contribute
significantly to overall emissions.\93\
---------------------------------------------------------------------------
\88\ Weller et al., ``A National Estimate of Methane Leakage
from Pipeline Mains in Natural Gas Local Distribution Systems,'' 54
Environmental Science & Technology 8958, 8966 (June 10, 2020).
\89\ EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks:
1990-2020, Annex 3.6-1 (Apr. 15, 2022).
\90\ U.S. EPA. ``Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2014: Revisions to Natural Gas Distribution Emissions''.
Pgs. 10-13. (April 2016). https://www.epa.gov/sites/default/files/2016-08/documents/final_revision_ng_distribution_emissions_2016-04-14.pdf.
\91\ EPA & Gas Research Institute, Methane Emissions from the
Natural Gas Industry (June 1996) (the 1996 GRI/EPA Report).
\92\ Lamb et al., ``Direct Measurements Show Decreasing Methane
Emissions from Natural Gas Local Distribution Systems in the United
States,'' 49 Environmental Science & Technology 5161 (Mar. 31,
2015).
\93\ Weller et al., 2020, at 8958-59.
2022 GHGI: 2020 Natural Gas Distribution Systems Emissions by Category
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Main Pipeline Leaks..................... 132.0 23.8
Service Pipeline Leaks.................. 70.8 12.8
Mishaps (e.g., Incidents)............... 68.6 12.4
Meter/Regulator Stations................ 44.4 8.0
Customer Meters......................... 235.4 42.5
Pipeline Blowdown....................... 2.1 0.4
Relief Device Venting................... 1.2 0.2
-------------------------------
Total............................... 554.5 100
------------------------------------------------------------------------
Note the PHMSA definition of a service pipeline in Sec. 192.3 includes
the customer meter in most configurations.
[[Page 31902]]
Unlike natural gas transmission systems, the GHGI separately
estimates emissions from natural gas distribution mains and service
pipelines by construction material.\94\ PHMSA has monitored trends in
legacy pipe materials for years, as these materials pose safety
risks.\95\ The GHGI data demonstrates that replacing leak-prone pipe,
such as aging cast iron, can have a significant effect in reducing
methane emissions from gas distribution systems. Despite dramatically
increased natural gas production and consumption between 1990 and 2019,
methane emissions from natural gas distribution systems have fallen
steadily from 1,819 kt CH4 in 1990 to 554.5 kt
CH4 in 2020 (as quantified by GHGI). This reduction in
methane emissions corresponds to a decline in cast-iron and
cathodically unprotected steel pipe mileage over the same period. And
while cast iron mains currently represent less than 1 percent of total
distribution main miles--approximately 18,000 miles of cast iron or
wrought iron distribution main remain in place as of 2021--leaks on
such facilities account for approximately one-fifth of GHGI's estimated
total fugitive emissions from all natural gas distribution mains in
2020. Additionally, PHMSA incident report data shows that cast iron
mains are vulnerable to integrity failures resulting in incidents;
around 8 percent of the incidents that occurred on gas distribution
mains between 2010 and 2021 occurred on cast iron mains. GHGI and PHMSA
data, therefore, demonstrates that replacing leak-prone materials on
gas distribution pipelines can reduce fugitive emissions and incidents
and suggest that similar environmental and public safety benefits could
be achieved by upgrading gas transmission and gas gathering pipelines
made from materials known to leak. PHMSA and its predecessor agency,
the Research and Special Programs Administration (RSPA), have
identified replacement of cast iron and bare steel pipe as a policy
priority for reducing gas distribution leaks and incidents for over two
decades. Further, on November 15, 2021, the Bipartisan Infrastructure
Law (Pub. L. 117-57) appropriated $200 million per year for PHMSA's
Natural Gas Distribution Infrastructure Safety and Modernization Grants
program, which provides grant funding to municipally or community-owned
gas distribution pipeline facilities for the purposes of replacing
legacy pipeline facilities.\96\
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\94\ 2022 GHGI, Annex 3.6.
\95\ PHMSA, ``Pipe Replacement Background'' (Apr. 26, 2021),
https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/pipeline-replacement-background (last accessed Dec. 20, 2022).
\96\ See PHMSA. ``Natural Gas Distribution Infrastructure Safety
and Modernization Grants'' (Aug. 2, 2022), https://www.phmsa.dot.gov/grants/pipeline/natural-gas-distribution-infrastructure-safety-and-modernization-grants (last accessed Dec.
20, 2022).
---------------------------------------------------------------------------
Methane Emissions Data--Natural Gas Transmission and Storage
The GHGI estimates natural gas transmission pipelines in 2020
emitted 1,300 kt of methane emissions, excluding storage; however, the
causes are very different than distribution. Leaks from natural gas
transmission line pipe represent a small share of emissions estimated
in the GHGI: only 3.3 kt of a total 1,504 kt of net methane emissions
from the transmission and storage sector. As shown in the table below,
vented and fugitive emissions (i.e., leaks) from natural gas
transmission compressor stations, compressors, and regulating and
metering stations comprise a significant portion of total methane
emissions from pipeline facilities. GHGI data on the natural gas
transmission and storage segment reflects both onshore and offshore
sources.
2022 GHG Inventory: 2020 Natural Gas Transmission Methane Emissions
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Pipeline Leaks.......................... 3.3 0.3
Pipeline Venting (including blowdowns 221.3 17.0
and upset venting).....................
Station Venting (including blowdowns)... 168.9 13.0
Dehydrator Venting...................... 2.6 0.2
Flaring................................. 0.6 0.0
Pneumatic Devices....................... 36.3 2.8
Compressor Station Fugitive Emissions... 702.8 54.1
Compressor Exhaust...................... 164.1 12.6
-------------------------------
Total............................... 1,300.0 100.0
------------------------------------------------------------------------
Note: Pipeline venting includes releases from ruptures and other
incidents.
The table below shows emissions from compressor stations on natural
gas transmission pipelines in additional detail. Emissions from
generators includes emissions from natural gas storage facilities
dedicated to a compressor station.
2022 GHG Inventory: 2020 Natural Gas Transmission Compressor Station
Methane Emissions
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Fugitive Emissions...................... 145.1 14.0
Reciprocating Compressor................ 419.5 40.5
Centrifugal Compressor (Wet Seals)...... 57.0 5.5
Centrifugal Compressor (Dry Seals)...... 81.3 7.8
Engine Exhaust.......................... 148.8 14.4
Turbine Exhaust......................... 1.6 0.2
Generator Engines (inc. Storage)........ 13.8 1.3
Generator Turbine (inc. Storage)........ 0.004 0.0
Station Venting......................... 168.9 16.3
-------------------------------
[[Page 31903]]
Total............................... 1,035.8 100.0
------------------------------------------------------------------------
Additionally, the table below shows emissions from natural gas
storage facilities.\97\
---------------------------------------------------------------------------
\97\ The nature and use of tankage as storage incidental to the
movement of gas by pipeline dictates whether storage facilities are
pipeline facilities subject to the jurisdiction of 49 U.S.C. 60101,
et seq.
2022 GHG Inventory: 2020 Natural Gas Storage Methane Emissions
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Station and Compressor Fugitive 24.5 7.6
Emissions..............................
Reciprocating Compressors............... 102.9 32.2
Storage Wells........................... 11.3 3.5
Metering and Regulating (Transmission 75.3 23.5
Interconnect)..........................
Metering and Regulating (Farm Taps & 17.5 5.5
Direct Sales)..........................
Dehydrator Venting...................... 4.5 1.4
Flaring................................. 1.1 0.4
Engine Exhaust.......................... 22.7 7.1
Turbine Exhaust......................... 0.2 0.1
Generators (inc. Transmission).......... 13.8 4.3
Pneumatic Devices....................... 17.3 5.4
Station Venting......................... 28.9 9.0
-------------------------------
Total............................... 319.9 100.0
------------------------------------------------------------------------
Though the 2022 GHGI does not track relief and control device
releases as a separate emissions source for natural gas transmission
and storage facilities, PHMSA incident report data indicates that such
releases are a significant contributor to methane emissions. A pressure
relief device is designed to allow gas to escape from a pressurized
system to protect the system from overpressurization. Relief devices
and other pressure control devices are critical to the safe operation
of a pipeline system when they function as intended. However, a poorly
designed or poorly configured pressure relief device can result in
releases of gas to the atmosphere larger than strictly necessary to
protect pipeline integrity. Conversely, a relief device or control
device that fails to release gas as designed or configured will not
provide adequate protection from overpressurization and may rupture,
presenting a hazard to public safety and the environment. Between 2010
and 2021, PHMSA incident report data yields that ``malfunction of
control/relief equipment,'' including control valves, relief valves,
pressure regulators, and emergency shutdown device system failures,\98\
was listed as the cause for 30% of incidents and 21% of unintentional
gas emissions from reportable incidents on gas transmission pipelines.
Approximately 95% of these incidents are reportable due to reported
unintentional emissions exceeding 3 MMCF, although these incidents are
occasionally reportable because repair costs or other monetary damages
exceed the property damage criterion in Sec. 191.3. Out of these 480
incidents, 114 involved the failure of a relief valve. The next most
commonly involved component in these failures were emergency shutdown
devices, which resulted in 54 incidents over this time period.
---------------------------------------------------------------------------
\98\ See PHMSA, Form F 7100.2, ``Incident Report -Gas
Transmission and Gathering System'' at section G6 (May 2022).
---------------------------------------------------------------------------
Recent studies also suggest that current methane emissions data
likely underestimates emissions from natural gas transmission and
storage facilities. The emission factor for transmission pipeline leaks
in the GHGI is based on volume 9 of the 1996 GRI/EPA Report. The
emissions factor is derived from the frequency of leak repairs reported
on operators' annual reports to RSPA and self-reported leak
measurements from distribution mains, both collected in 1991.\99\ The
authors of one study noted that the difficulty in accurately measuring
abnormal ``super-emitter'' events from natural gas transmission and
storage facilities using on-site measurements suggests that bottom-up
methodologies underestimate emissions from ``super-emitter'' events,
and consequently total emissions.\100\ For example, the 1996 GRI/EPA
Report relied on limited RSPA incident report data which did not even
include a volumetric incident definition criterion as used under
current PHMSA reporting requirements.\101\ The RSPA incident report
form in 1991 similarly did not require operators to provide an estimate
of release volume. While current methane emissions data attempts to
address this concern by factoring in ``super-emitter'' estimates, this
remains a source of uncertainty for any type of point-in-time
measurement.\102\ Further, certain infrequent but significant incidents
at UNGSFs such as the release of 86 billion cubic feet (BCF) of natural
gas from the Aliso Canyon facility
[[Page 31904]]
failure in 2015, the release of 6 BCF of natural gas from the Moss
Bluff facility in 2004, and the release of 143 BCF of natural gas from
the Yaggy storage field in 2001 demonstrate both the uncertainty in
estimating methane emissions from UNGSFs and the potential for
substantial methane emissions (which in turn result in public safety
harms) from such facilities.\103\
---------------------------------------------------------------------------
\99\ EPA & Gas Research Institute, Methane Emissions from the
Natural Gas Industry, Volume 9: Underground Pipelines. (June 1996).
Pgs. 38 and 46.
\100\ Zimmerle et al., ``Methane Emissions from the Natural Gas
Transmission and Storage System in the United States,'' 49
Environmental Science & Technology 9374 (July 21, 2015).
\101\ See, e.g., RSPA Form F7100.2 (Rev. 3--1984), ``PHMSA Gas
Transmission & Gathering Incident Data--mid 1984 to 2001'',
available at https://www.phmsa.dot.gov/data-and-statistics/pipeline/distribution-transmission-gathering-lng-and-liquid-accident-and-incident-data (last accessed Jan. 4, 2023).
\102\ See Alvarez et al., ``Assessment of Methane Emissions from
the U.S. Oil and Gas Supply Chain,'' Science 186, Table 1 (June 21,
2018) (finding that bottom-up quantifications of methane emissions
may underestimate natural gas transmission and storage emissions by
nearly 30% when compared with top-down quantifications).
\103\ PHMSA, ``Pipeline Safety: Safe Operations of Underground
Storage Facilities for Natural Gas,'' 81 FR 6334 (Feb. 5, 2016)
(Advisory Bulletin ADB-2016-02).
---------------------------------------------------------------------------
Methane Emissions Data--Gathering Pipelines
The GHGI estimates for ``natural gas gathering and boosting''
systems have estimated fugitive emissions from line pipe leaks that are
much higher than for natural gas transmission systems. As shown in the
table below, the GHGI estimates 126.7 kt of methane emissions from
pipeline leaks in natural gas gathering and boosting systems (estimated
at 381,909 miles in the GHGI) \104\ compared with 3.3 kt for natural
gas transmission systems (302,252 miles). In the RIA for the 2021 Gas
Gathering Final Rule, PHMSA estimated that there were approximately
426,000 miles of unregulated rural gas gathering pipelines,\105\ in
addition to the 17,064 miles of regulated offshore and onshore Type A
and Type B regulated gas gathering pipelines reported by operators in
2021. Additionally, the EPA mileage estimate may include mileage that
could be considered under Sec. 192.8 to be production pipelines rather
than gathering pipelines. The EPA mileage therefore provides an
estimate of gathering pipeline mileage and resulting total emissions
estimates from such facilities that may not accurately represent
emissions from the subset of PHMSA-regulated gathering pipeline
sources.
---------------------------------------------------------------------------
\104\ 2022 GHGI, Annex 36 Table 3.6-7.
\105\ Gas Gathering RIA at 15; PHMSA, ``Annual Report Mileage
for Natural Gas Transmission and Gathering Systems.'' (Aug. 1,
2022), https://www.phmsa.dot.gov/data-and-statistics/pipeline/annual-report-mileage-natural-gas-transmission-gathering-systems
(last accessed Aug. 19, 2022).
2022 GHG Inventory: Natural Gas Gathering and Boosting Methane Emissions
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Station Combustion Slip................. 407.1 27
Station Compressors..................... 306.9 20
Station Tanks........................... 244.3 16
Station Pneumatic Devices............... 202.0 13
Pipeline Leaks.......................... 126.7 8
Station Yard Piping..................... 93.3 6
Station Blowdowns....................... 44.9 3
Station Dehydrator Vents and Leaks...... 25.7 2
Station Pneumatic Pumps................. 27.2 2
Pipeline Blowdowns...................... 9.4 1
Station Flare Stacks.................... 11.1 1
Station Separators...................... 1.4 0
Station Acid Gas Removal Units.......... 0.1 0
-------------------------------
Total............................... 1500.0 100
------------------------------------------------------------------------
Note: Total includes Type R gas gathering pipelines and production
operations not regulated under part 192.
Recent research also suggests that, as in the case of other gas
pipeline facilities, current methane emissions data likely understates
emissions from natural gas gathering pipelines. One study conducted in
the New Mexico Permian Basin in 2022 estimated emissions from natural
gas production and gathering facilities in that region that were 6.5
times larger than GHGI estimates.\106\ In the study, methane emissions
were estimated using a comprehensive aerial survey spanning 35,923
square kilometers (including over 15,000 kilometers of natural gas
pipelines) over 115 flight days. This large sample size was intended to
better capture infrequent ``super-emitter'' events, and the study found
that 50% of observed emissions were attributable to large emissions
sources with average methane emissions rates greater than 308 kilograms
per hour. Even as studies in the past few years have increasingly
sounded the alarm that leaks from gathering pipelines and boosting
stations are significant contributors to climate change, GHGI emissions
factors for those facilities have decreased over the same time period
due to changes in GHGRP inputs.\107\ Moreover, studies aiming to
improve gas gathering pipeline emissions factors with more accurate
data (like one conducted on the Utica Shale in 2020) \108\ suggest that
self-reported emissions information from GHGRP reporting on which GHGI
emissions data for gathering pipelines is based may underestimate
actual emissions rates. Any point-in-time measurement of methane
emissions can miss large but infrequent events (particularly
methodologies that use smaller sample areas such as ground-based
approaches), thus underestimating total emissions when used to
extrapolate beyond the sample area to an entire region.\109\
---------------------------------------------------------------------------
\106\ Chen et al., ``Quantifying Regional Methane Emissions in
the New Mexico Permian Basin with a Comprehensive Aerial Survey,''
56 Environmental Science & Technology 4317 (Mar. 23, 2022) (finding
that ``[m]idstream assets were also a significant source [of
emissions], with 29 20 t/h [(metric tonnes per hour)]
emitted from pipelines (including underground gas gathering
pipelines) and 26 16 t/h emitted from compressor
stations without a well on site'').
\107\ GHGI emissions factors for gathering pipeline leaks were
identified as 354.7 CH4/mile in 2017 but decreased to
288.5 in the 2022 GHGI. See 2022 GHGI, Annex 36 Table 3.6-2. See
also Li et al., ``Gathering Pipeline Methane Emissions in Utica
Shale Using an Unmanned Aerial Vehicle and Ground-Based Mobile
Sampling,'' Atmosphere (July 5, 2020) (calling for improved gas
gathering pipeline methane emissions factors for the Utica Shale
region based on data from both aerial surveys and ground-based
vehicle sampling); Chen et al., 2022, at 4317-18 (observing that,
while ``uncertainty remains about the emissions rates in the Permian
Basin'', recent studies conducted in that region ``consistently find
emissions significantly in excess of government estimates'').
\108\ Li et al., ``Gathering Pipeline Methane Emissions in Utica
Shale Using an Unmanned Aerial Vehicle and Ground-Based Mobile
Sampling,'' Atmosphere (July 5, 2020).
\109\ Chen et al., 2022, at 4321-22 (``[T]he clear impact of
large emissions found by this study suggests that estimates from
ground-based methane surveys may be underestimating total emissions
by missing low-frequency, high-impact large emissions.'').
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[[Page 31905]]
Methane Emissions Data--LNG Facilities
As shown in the tables below, the GHGI estimates that blowdowns
account for 80 percent of estimated methane emissions from LNG storage
facilities, and nearly half of methane emissions from all LNG
facilities.
2022 GHG Inventory: LNG Storage Facility 2020 Methane Emissions
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Equipment Leaks, Compressors, Flares, 1.4 13
etc....................................
Blowdowns............................... 8.4 80
Engine Exhaust.......................... 0.6 5
Turbine Exhaust......................... 0.1 1
------------------------------------------------------------------------
2022 GHG Inventory: LNG Import Terminal 2020 Methane Emissions
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Equipment Leaks, Compressors, Flares, 0.1 22
etc....................................
Blowdowns............................... 0.2 33
Engine Exhaust.......................... 0.2 45
Turbine Exhaust......................... 0.0 <1
------------------------------------------------------------------------
2022 GHG Inventory: LNG Export Terminal 2020 Methane Emissions
------------------------------------------------------------------------
Source Kt CH4 Percent
------------------------------------------------------------------------
Equipment Leaks, Compressors, Flares, 4.0 53
etc....................................
Blowdowns............................... 0.3 4
Engine Exhaust.......................... 1.4 18
Turbine Exhaust......................... 2.0 26
------------------------------------------------------------------------
Fugitive emissions represent the majority of estimated methane
emissions from LNG import and export terminals. While LNG facilities
are often designed with boil-off gas recovery systems to avoid routine
continuous venting of natural gas during operations, methane regularly
escapes from LNG facilities through compressor rod packing and valve
leakage, incomplete combustion during flaring, and other various
process venting sources.\110\ Similar to gas transmission facilities,
additional emissions are attributable to releases from relief devices
and O&M related venting. Likewise, fugitive emissions from gas
treatment equipment at liquefaction plants are likely similar to those
from comparable equipment on other pipeline or gas processing
facilities.\111\ Methane may also be lost to the atmosphere during pipe
transfers of LNG to or from an LNG facility, whether through loading
for transport or off-loading for storage or vaporization. Even if
initially captured, boil-off gas and other fugitive emissions from LNG
facilities may still be vented directly to the atmosphere without
combustion during normal operation.\112\ And, as with any pipe
transporting natural gas, the pressurized piping that runs throughout
LNG facilities is susceptible to integrity failures and other
incidents,\113\ including pipeline leaks that can precipitate
explosions.\114\ For example, Cheniere reported that the Sabine Pass
LNG terminal constituted approximately 40 miles of plant piping for its
import facilities and an additional 285 miles of plant piping for its
first four of six liquefaction trains,\115\ and the operator of the
Cameron LNG terminal reported approximately 255 miles of piping in
their liquefaction project consisting of three liquefaction
trains.\116\ In addition, Freeport LNG similarly reported its
liquefaction project's pretreatment and three liquefaction trains
included approximately 192 miles of plant piping, providing ample
opportunities for methane to escape during normal and emergency
operations.
---------------------------------------------------------------------------
\110\ API, Compendium of Greenhouse Gas Emissions Methodologies
for the Natural Gas and Oil Industry at 6-121 through 6-126 (Nov.
2021).
\111\ API, Compendium of Greenhouse Gas Emissions Methodologies
for the Natural Gas and Oil Industry at 6-121 through 6-122 (Nov.
2021).
\112\ API, Compendium of Greenhouse Gas Emissions Methodologies
for the Natural Gas and Oil Industry at 6-123 (Nov. 2021). For
example, boil-off gas may be vented if the vapor generation rate
exceeds the capacity of the boil-off gas compressors or the re-
liquefaction unit. API's compendium estimates typical losses at
0.05% of total tank volume per day when boil-off gas is vented from
an LNG storage vessel. See also Soraghan & Lee, ``LNG explosion
shines light on 42-year-old gas rules'' EnergyWire. (June 28, 2022),
https://www.eenews.net/articles/lng-explosion-shines-light-on-42-year-old-gas-rules/ (noting that an LNG terminal had reported
several natural gas releases to the state Department of
Environmental Quality, including one release of 180,000 pounds of
methane in January 2022).
\113\ See, e.g., PHMSA, CPF No. 4-2022-051-NOPSO, ``In the
Matter of Freeport LNG Development LP: Notice of Proposed Safety
Order'' at 3 (June 30, 2022), (describing the LNG release and
natural gas vapor cloud that resulted from the June 8, 2022 incident
at the Quintana Island LNG facility, which may have been caused by
the overpressure and rupture of a segment of LNG transfer line
between the facility's LNG storage tank area and its dock
facilities).
\114\ See, e.g., ``Algerian LNG Complex Explosion Caused by Gas
Pipeline Leak,'' Oil & Gas Journal (Feb. 18, 2004). A gas pipeline
leak was ultimately determined to be the cause of the Skikda,
Algeria LNG terminal explosion on January 20, 2004, that killed 27
people, injured 74 others, and resulted in an estimated $800
million-$1 billion in damages to the Skikda port facilities,
including the destruction of three of the LNG terminal's six
liquefaction trains. See also Romero, ``Algerian Explosion Stirs
Foes of U.S. Gas Projects,'' New York Times (Feb. 14, 2004).
\115\ Cheniere. ``Cheniere Energy Analyst/Investor Day.'' (Apr.
2014). Pgs. 12-13.
\116\ Cameron LNG. https://cameronlng.com/lng-facility/economic-impact/.
---------------------------------------------------------------------------
However, emissions for LNG facilities have proven difficult to
estimate due to the limited availability of accurate, complete
emissions data, with insufficient differentiation between intentional
and fugitive emissions.\117\
[[Page 31906]]
Bottom-up methodologies for estimating LNG emissions typically use
generalized emissions factors averaged across the entire sector despite
significant differences between suppliers and each step of the supply
chain.\118\ Emissions estimates using this approach may apply a single
emissions factor to all types of LNG facilities, even though the wave
of recently built LNG export terminals could have little in common with
an LNG peak shaver or storage facility. Developing accurate emissions
estimates is also hampered by selection bias. Specifically, EPA
currently uses data reported in accordance with 40 CFR part 98, subpart
W (i.e., GHGRP) to develop GHGI emissions factors for LNG facilities
(with the exception of LNG storage facility blowdowns). However,
operators of LNG facilities need only report emissions under subpart W
if total emissions reach the reporting threshold of 25,000 metric tons
of CO2 equivalent per year. Many LNG storage facilities fall
under that threshold, introducing uncertainty into aggregate emissions
calculated using only a subset of LNG storage facilities.\119\
---------------------------------------------------------------------------
\117\ Oxford Institute for Energy Studies, Measurement,
Reporting, and Verification of Methane Emissions from Natural Gas
and LNG Trade: Creating Transparent and Credible Frameworks at 51
(Jan. 2022).
\118\ See Roman-White et al., ``LNG Supply Chains: A Supplier-
Specific Life-Cycle Assessment for Improved Emission Accounting,''
ACS Sustainable Chemistry & Engineering at 10857, 10861 (2021).
\119\ EPA, Memorandum, ``Inventory of U.S. Greenhouse Gas
Emissions and Sinks 1990-2017: Updates to Liquefied Natural Gas
Segment'' at 2-3 (Apr. 2019). While EPA identified between 94-98 LNG
storage facilities as active each year from 2011-2017, only 8 such
facilities reported emissions under Subpart W during that timeframe.
---------------------------------------------------------------------------
Further, even among those LNG facilities that report their
emissions to EPA, there is a potential for great variation in emissions
reported within and across reporting years due to small sample sizes:
the small number of LNG facilities reporting emissions to EPA (only 5
storage facilities and 11 import and export facilities as of August
2022 \120\) make resulting methane emissions estimates susceptible to
substantial year-to-year fluctuation and limit the predictive value of
such estimates for subsequent years.\121\ Lastly, operators of LNG
storage facilities are not required to report LNG storage blowdown
emissions under GHGRP--instead, GHGI estimates for LNG storage blowdown
emissions consist of generalized data based on a 1996 study of blowdown
emissions on gas transmission compressor stations and UNGSFs.\122\
---------------------------------------------------------------------------
\120\ See EPA, ``GHGRP Petroleum and Natural Gas Systems,''
https://www.epa.gov/ghgreporting/ghgrp-petroleum-and-natural-gas-systems#emissions-table (last accessed March 16, 2023).
\121\ For example, in 2016, one LNG storage facility was
responsible for more than 82% of all LNG storage facility methane
emissions and one LNG import terminal was responsible for more than
95% of all LNG terminal methane emissions reported to EPA under
Subpart W. EPA, Memorandum, ``Inventory of U.S. Greenhouse Gas
Emissions and Sinks 1990-2017: Updates to Liquefied Natural Gas
Segment'' at 3-8 & Tables 5, 8 (April 2019).
\122\ EPA, Memorandum, ``Inventory of U.S. Greenhouse Gas
Emissions and Sinks 1990-2017: Updates to Liquefied Natural Gas
Segment'' at 1 (April 2019).
---------------------------------------------------------------------------
D. The Need for Updating PHMSA Regulations To Incorporate Advanced Leak
Detection Programs To Reduce Unintentional Releases From Gas Pipelines
PHMSA's regulations have historically prioritized addressing public
safety risks posed by ignition of instantaneous, large-volume releases
or accumulated gas. This focus on public safety is vital and can
support PHMSA's renewed and expanded commitment to addressing
environmental risks as well. However, current regulations can allow
leaks of methane and other gases from gas gathering, transmission, and
distribution pipeline facilities to continue undetected and unrepaired
for extended periods of time.\123\ This approach therefore foregoes the
emissions reduction potential of commercially available, advanced leak
detection technologies and practices within integrated ALDPs. This
historical approach also forgoes opportunities for timely
identification and remediation of leaks from gas pipelines that can
develop into catastrophic incidents. State and voluntary industry
efforts to improve leak detection and repair on gas pipelines are
emerging, but are insufficient to reduce unintentional emissions of
methane and other gases without PHMSA regulations that support and
backstop those efforts.
---------------------------------------------------------------------------
\123\ PHMSA notes that the limitations of current part 191 and
192 regulations for meaningful and timely identification, repair,
and reporting of leaks discussed in this section II.D. may be
particularly acute in connection with the pipeline transportation of
gaseous hydrogen, which is a much smaller molecule (with potentially
greater leakage potential) than methane.
---------------------------------------------------------------------------
1. PHMSA Regulations Pertinent to Unintentional Releases of Methane and
Other Gases
PHMSA's current regulatory requirements pertaining to gas pipeline
leak detection, repair, maintenance, and reporting reflect a focus on
public safety risks from ignition of instantaneous, large-volume
releases or accumulated gas while treating risks to the environment as
less important. PHMSA maintenance requirements at part 192, subpart M
explicitly require only a subset of unintentional releases from gas
pipelines--namely those unintentional releases thought to create an
actual or probable harm to public safety--need be identified, repaired,
or reported. Nor do those maintenance requirements in the subpart M
regulations include explicit requirements for the replacement or
remediation of pipes known to leak based on material, design, or past
operating and maintenance history.\124\ And PHMSA IM regulations at
part 192 subparts O (gas transmission pipelines) and P (gas
distribution pipelines) allow considerable operator discretion in
determining which leaks merit repairs and the timing of those repairs.
PHMSA reporting requirements at part 191 similarly are calibrated to
provide information regarding instantaneous, large-volume releases
rather than granular data on operator leak detection and repair
efforts, or the releases of gas from those leaks.
---------------------------------------------------------------------------
\124\ An exception is that part 192, subpart M acknowledges
cast-iron piping's susceptibility to leakage and contains provisions
focused on a single mechanism (graphitization-derived corrosion) for
development of leaks, and then only after indicia of that mechanism
have emerged. Specifically, Sec. 192.489(a) requires replacement of
each segment of cast iron or ductile iron pipe with general
graphitization (a type of corrosion) that could cause a fracture or
leak. Section 192.489(b) similarly requires replacement, repair, or
internal sealing for localized graphitization on cast and ductile
iron pipeline segments that could result in leakage.
---------------------------------------------------------------------------
Gas Pipelines Generally
Part 192, subpart M contains minimum maintenance requirements for
gas gathering, transmission, and distribution pipelines.\125\ Gas
transmission (Sec. 192.706), distribution (Sec. 192.723), offshore
gas gathering, and Type A, Type B, and certain Type C gathering
(Sec. Sec. 192.9 and 192.706) pipeline operators must perform periodic
leakage surveys. When leaks are discovered, both their severity and the
operating conditions of the pipeline are used to determine whether and
when a repair is performed. PHMSA's subpart M requirements contain
broad language at Sec. 192.703(c) mandating repair of all ``hazardous
leaks . . . promptly.'' However, subpart M neither
[[Page 31907]]
defines a ``hazardous'' leak nor provides guidance on what exactly
constitutes a ``prompt'' repair of such leaks. Although Sec. 192.1001
describes a ``hazardous leak'' only in terms of an existing or probable
hazard to persons or property (and not the environment), that
regulatory definition applies only to the gas distribution system IM
requirements in part 192, subpart P. The Sec. 192.703(c) repair
mandate is also inapplicable to most Type C gas gathering
pipelines.\126\
---------------------------------------------------------------------------
\125\ Certain part 192 regulations will be revised on
codification of a recent PHMSA rulemaking that will become effective
on May 24, 2023. See PHMSA, ``Safety of Gas Transmission Pipelines:
Repair Criteria, Integrity Management Improvements, Cathodic
Protection, Management of Change, and Other Related Amendments--
Final Rule,'' 87 FR 52224 (Aug. 24, 2022) (RIN2 Final Rule). PHMSA's
references to part 192 within this NPRM--including the proposed
amended regulatory text at its conclusion--reflect the regulatory
text and organization as amended by the RIN2 Final Rule unless
otherwise noted. The RIN2 Final Rule contains enhanced repair
criteria that can affect leak repairs, but the requirements are
generally directed toward phenomena (cracking, corrosion-induced
metal loss, dents) distinct from the detection, grading, and repair
of all leaks as proposed in this NPRM.
\126\ Only ca. 20,000 miles of the ca. 91,000 miles of Type C
gas gathering pipelines are subject to Sec. 192.703(c). PHMSA, Doc.
No. PHMSA-2011-0023-0488, ``Regulatory Impact Analysis for Gas
Gathering Final Rule'' at 11, 15 (Nov. 2021).
---------------------------------------------------------------------------
Part 191 reporting requirements similarly reflect PHMSA's
historical focus on public safety risks from ignition of instantaneous,
large-volume releases or accumulated gas.\127\ Incident reports for gas
distribution (Form F7100.1), transmission and part-192 regulated
gathering (Form F7100.2), and Type R gathering pipelines (Form
F7100.2.2) provide limited information regarding unintentional
releases, as only unintentional releases of at least 3 MMCF need be
reported. And while annual reports for gas distribution (Form F7100.1-
1), transmission and part-192 regulated gathering (Form F7100.2-1), and
Type R gathering pipelines (Form F7100.2-3) include information on the
number of leaks repaired in the preceding calendar year, the
instructions for those annual report forms expressly exclude reporting
of repairs on a broad category of leaks: releases that can be corrected
by ``lubrication, adjustment, or tightening'' are not considered
``leaks'' for annual reporting of repairs.\128\ The instructions for
annual reports other than for gas distribution pipelines also do not
require reporting of repairs of any leaks other than leaks that are
hazardous; and the instructions for all annual report forms
characterize leaks as ``hazardous'' with respect to public safety,
omitting mention of hazards to the environment. Further, none of
PHMSA's annual reports require operators to submit information on
either the total number of leaks detected in the reporting period, the
rolling tally of all unrepaired leaks, or estimated emissions
associated with leaks during the reporting period.
---------------------------------------------------------------------------
\127\ PHMSA annual and incident forms and instructions discussed
in this paragraph can be found on PHMSA's website at https://www.phmsa.dot.gov/forms/operator-reports-submitted-phmsa-forms-and-instructions. https://www.phmsa.dot.gov/forms/operator-reports-submitted-phmsa-forms-and-instructions.
\128\ PHMSA annual reporting requirements for part 193-regulated
LNG facilities contain a similar exception from leak reporting
requirements. See PHMSA, Form 7300.1-3, ``Annual Report Form for
Liquefied Natural Gas Facilities (Oct. 2014); PHMSA, Instructions
for Form 7300.1-3 at 4 (Oct. 2014) (stating that ``a non-hazardous
release that can be eliminated by lubrication, adjustment, or
tightening is not a leak'').
---------------------------------------------------------------------------
Lastly, only gas transmission pipelines are required to provide
geospatial data on their pipeline systems in accordance with the NPMS
requirements at 49 U.S.C. 60132 and 49 CFR 191.29. Gas distribution and
gathering pipelines have no requirement to provide geospatial data for
NPMS.
Part 192--Regulated Gas Gathering Pipelines
Operators of offshore gas gathering, Type A, Type B, and certain
Type C gathering pipelines must comply with the leakage survey
requirements (at Sec. 192.706) applicable to gas transmission
pipelines and repair any hazardous leaks detected (per Sec. 192.703).
However, most Type C gathering pipelines--specifically, those with an
outer diameter between 8.625'' and 16'' not near an occupied building--
are, pursuant to Sec. 192.9(f)(1), not subject to any part 192 leakage
survey and repair requirements, whether for ``hazardous'' leaks or any
other leaks. Additionally, only offshore gas gathering and Type A
gathering pipelines are subject to other subpart M maintenance
requirements, including right-of-way patrols (Sec. 192.705), general
transmission pipeline requirements for making permanent or temporary
repairs (Sec. 192.711), and recordkeeping (Sec. 192.709). Type B and
Type C gathering pipelines need only comply with the specific
requirements listed in Sec. 192.9(d) and (e), which do not include
patrol, repair, and recordkeeping requirements.
Gas Transmission Pipelines
All gas transmission pipelines are subject to maintenance
requirements at part 192, subpart M. Section 192.706 requires gas
transmission operators to perform leakage surveys on most gas
transmission pipelines at least once every calendar year. However, that
provision does not require the use of leak detection equipment for
those leakage surveys. Leak detection equipment is only required if a
gas transmission pipeline is not odorized in accordance with Sec.
192.625 and the pipeline is located in a Class 3 or Class 4 location;
otherwise, leak detection can be by human senses only, such as visual
observation of dead vegetation or blowing debris. Operators required to
conduct a leakage survey with leak detection equipment must do so at
least twice each year in Class 3 locations, and at least four times
each calendar year in Class 4 locations.
In addition to leakage surveys, Sec. 192.705 requires operators of
gas transmission pipelines to have a patrolling program to monitor
conditions on and adjacent to pipeline rights-of-way. These patrols are
visual surveys, commonly performed using aircraft, and are intended to
find leaks and other conditions affecting the safety and operation of
the pipeline. Patrols commonly identify potential or current pipeline
integrity threats caused by external changes, including construction,
excavation, blasting, earth movements, and flooding. Information
gathered from these patrols can prevent further damage to the pipeline
or target leakage surveys or integrity assessments to locations that
may have been damaged. This can prevent leaks, potentially fatal
incidents, or damage that could result in shutdowns and maintenance-
related releases of methane and other gases to the atmosphere. For
example, if an operator spots construction activity along the line,
they can dispatch personnel to observe construction to minimize the
risk of excavation-related damage to the pipeline. According to
incidents reports submitted to PHMSA, such excavation damage is a
leading cause of incidents that result in injuries and fatalities and
pipeline breaks with very high emissions rates. The patrol frequency
depends on the class location of the pipeline, the pipeline's diameter,
operating pressure, terrain, weather, and other relevant factors. Gas
transmission pipeline operators must perform patrols at least four
times each calendar year in Class 4 locations, at least twice each
calendar year in Class 3 locations, and at least once each calendar
year in Class 1 and Class 2 locations. If the pipeline is located at a
highway or railroad crossing in a Class 1 or Class 2 location, the
minimum patrol frequency is increased to at least twice each calendar
year. In Class 3 locations, the minimum patrol frequency at highway and
railroad crossings is four times each calendar year.
As explained above, Sec. 192.703(c) requires all transmission
operators to repair leaks that are ``hazardous'' to public safety
``promptly''--but PHMSA regulations contain few guardrails as to what
``promptly'' means. Repair requirements at Sec. 192.711 require that
operators take immediate temporary measures for leaks that impair the
serviceability of a steel transmission pipeline operating above 40
percent of SMYS if a permanent repair is not feasible.
Section 192.711(b) requires that permanent repair be made as soon
as feasible or as specified under the
[[Page 31908]]
operators' IM program under subpart O but does not specify when
permanent repairs are necessary.\129\ Like the general repair
requirement in Sec. 192.703, these requirements frame leak repair
obligations in terms of public safety risks and use ambiguous language
(``as soon as feasible'') to describe the timing of any repair
obligations. In recognition of this regulatory gap, PHMSA has
referenced the GPTC Guide in guidance and letters of interpretation on
how operators should comply with these provisions of part 192.\130\
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\129\ The RIN2 Final Rule will amend Sec. 192.711(b) by
replacing the existing requirement that permanent repairs of safety-
adverse conditions on certain onshore gas transmission pipelines
must be made ``as soon as feasible'' with a cross-reference to a new
Sec. 192.714 prescribing repair schedules set forth in an industry
standard. See 87 FR at 52271 (introducing a new Sec. 192.714
referencing ASME/ANSI B31.8S-2004, Supplement to B31.8 on Managing
System Integrity of Gas Pipelines at section 7, Figure 4 (Jan. 14,
2005)). However, those repair schedules--which are intended for
``anomalies and defects'' consisting of dents, corrosion metal loss,
and cracking rather than leaks--contemplate that some repairs may
not be required for years. The RIN2 Final Rule does not disturb the
existing requirement to effectuate permanent repairs ``as soon as
feasible'' for other part 192-regulated gas pipelines not subject to
subpart O IM requirements.
\130\ See, e.g., PHMSA, ``Distribution Integrity Management:
Guidance for Master Meter and Small Liquefied Petroleum Gas Pipeline
Operators'' (2013) at 2 (directing larger distribution pipeline
operators to refer to GPTC guidelines); PHMSA, Interpretation
Response Letter No. PI-93-009 (February 11, 1993) (recommending
public stakeholder consult the GPTC Guide for further determination
of instruments and techniques to be used in certain leak detection
activities); see also PHMSA, Interpretation Response Letter No. PI-
99-0105 (December 1, 1999) (stating that the GPTC Guide ``is a
document endorsed by us which contains information and some methods
to assist the gas pipeline operator in complying with the
regulations contained in 49 CFR part 192'').
---------------------------------------------------------------------------
Subpart O requirements similarly provide little direction on how
gas transmission pipelines that are located in HCAs \131\ must manage
leak detection and repair, instead giving operators considerable
discretion to determine when and how they address leaks on their
pipelines. Subpart O requires operators to identify, prioritize,
assess, evaluate, repair, and validate the integrity of their pipelines
that have the potential to cause injury or death in the event of a
failure. In addition, operators must measure IM plan performance to
support continual improvement of their programs. Operators of gas
transmission pipelines subject to the IM regulations may develop IM
plans reflecting idiosyncratic choices regarding identification of
specific integrity risks to their pipelines, selection of proper
assessment tools; periodic assessment of the pipe for anomalies, and
procedures for taking prompt action to address and repair anomalous
conditions discovered through pipeline integrity assessments.
Additionally, the subpart O regulations do not explicitly require
operators to repair all leaks; operators can determine the precise
timing of ``prompt'' repairs based on the operator's evaluation of risk
to public safety. Further, Sec. 192.93 provides operators up to 6
months from the date that an integrity assessment was performed to
confirm discovery of an anomalous condition. Repair criteria at Sec.
192.933 require that anomalous conditions posing the greatest risks to
public safety be repaired immediately, but other anomalies that an
operator determines pose less significant public safety risks need to
be repaired within a year of discovery, or only monitored during
subsequent risk assessments and integrity assessments for any change
that may require remediation. Section 192.935 directs operators to take
additional measures beyond those required elsewhere in part 192 to
prevent, and mitigate the consequences of, pipeline failures in HCAs,
but that provision identifies enhanced leak detection and monitoring
programs as merely one potential item on a menu from which operators
may choose in order to meet this requirement.\132\
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\131\ Subpart O contains IM requirements for transmission
pipelines in HCAs. Annual reports submitted by operators in 2020
yields that only 7% (ca. 21,000 miles) of the 301,000 miles of gas
transmission pipelines are subject to IM requirements at subpart O.
\132\ Amendments to subpart O requirements pursuant to the RIN2
Final Rule will not disturb the pertinent requirements of that
subpart described above.
---------------------------------------------------------------------------
Gas Distribution Pipelines
Distribution pipelines are subject to select part 192, subpart M
maintenance requirements. Section 192.721 requires operators to patrol
distribution mains at frequencies that consider the severity of the
conditions that would cause failure or leakage, and the consequent
hazard to public safety. Distribution mains subject to physical
movement or external loading that could fail or leak must be patrolled
at least twice each calendar year if located outside of business
districts, and at least four times every calendar year if located
within business districts. Distribution leakage survey requirements are
defined in Sec. 192.723. In business districts, operators must conduct
leakage surveys of distribution pipelines with leak detection equipment
at least once every calendar year. These surveys must include testing
the atmosphere in utility manholes, at cracks in the pavement and
sidewalks, and at other locations, providing opportunities to find
leaks. Outside of business districts, operators must perform leakage
surveys using leak detection equipment as frequently as necessary, but
not less than once every 5 calendar years. Gas distribution operators
are subject to repair requirements for hazardous leaks at Sec.
192.703, but that requirement provides no specific guidance on repair
timelines and fails to mention environmental risks.
The distribution IM program (DIMP) regulations in subpart P require
distribution pipeline operators to identify, prioritize, assess,
evaluate, repair, and validate the integrity of gas distribution
pipelines that have the potential to cause injury or death in the event
of a leak or failure. Section 192.1007 requires operators to
demonstrate an understanding of their gas distribution systems based on
reasonably available information. Operators then must apply the
knowledge acquired through reasonably available information to identify
threats to the integrity of their gas distribution systems. Threats can
include a variety of phenomena: corrosion, excavation damage, vehicular
strikes, poorly fitting connections, and other threats. Operators must
evaluate and rank the risk to their systems from those threats, and
then identify and implement measures to address those risks. DIMP
regulations require operators to periodically (at least once every 5
years) evaluate the threats, risks, and results of the performance
measures to gauge the effectiveness of their DIMPs in controlling each
threat. And Sec. 192.1007(d) explicitly requires distribution pipeline
operators to either repair all leaks when found or have an ``effective
leak management program.'' However, subpart P prescribes few specific
requirements for those leak management programs or criteria for
determining their effectiveness, requiring a distribution pipeline
operator only to monitor (as a performance measure for evaluating a
DIMP), the number of leaks it eliminates or repairs; to categorize such
leaks by cause, material; to determine whether they are ``hazardous'';
and to report such measures annually to PHMSA. Indeed, the preamble to
the 2009 final rule codifying subpart P merely suggested that each
operator ``should develop a program based on their knowledge of their
pipeline system'' with the GPTC Guide identified as an aid in
developing such a program.\133\
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\133\ PHMSA, ``Pipeline Safety: Integrity Management for Gas
Distribution Pipelines--Final Rule,'' 74 FR 63905, 63917 (Dec 4,
2009). PHMSA is undertaking a complementary rulemaking under RIN
2137-AF53 (``Pipeline Safety: Safety of Gas Distribution Pipelines
and Other Pipeline Safety Initiatives'') responding to congressional
mandates in title II of The PIPES Act of 2020 directing PHMSA to,
among other things, amend its subpart P distribution IM program
requirements. PHMSA expects that the leak detection, grading, and
repair requirements for gas distribution pipelines proposed herein
would reinforce any changes to subpart P proposed in that
rulemaking.
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[[Page 31909]]
2. Shortcomings of Current PHMSA Regulations in Addressing
Unintentional Releases From Gas Pipelines
PHMSA regulations pertinent to leaks from gas pipelines focus on
risks to public safety posed by ignition of instantaneous, large-volume
releases or accumulated gas from gas pipeline facilities--an approach
that is vital for protecting public safety but that foregoes
opportunities to address environmental harms, including methane
emissions' contribution to climate change. This approach has proven
unsuccessful in timely identification and remediation of leaks that can
have a substantial impact on the environment or even evolve into
incidents posing catastrophic risks to public safety.
As explained above, part 192 subpart M maintenance requirements
contain only a single repair requirement specific to leaks, which is
applicable only to some part 192-regulated gas gathering, transmission,
and distribution pipelines: Sec. 192.703(c)'s requirement that
``hazardous leaks'' be repaired ``promptly.'' However, the term
``hazardous leak'' is nowhere defined in subpart M. Rather, what other
limited evidence there is in PHMSA regulations elaborating on the
meaning of ``hazardous leak'' pertains either to entirely different
elements of part 192 (specifically, the Sec. 192.1001 definition of
``hazardous leak'' within DIMP requirements in subpart P) or part 191
reporting requirements.\134\ These regulatory provisions both describe
``hazardous leak'' with respect to potential or present risks to public
safety; they are silent regarding risks to the environment.
---------------------------------------------------------------------------
\134\ See, e.g., PHMSA, Form F7100.1-1 Instructions (May 2021)
(defining hazardous leaks as those representing an ``existing or
probable hazard to persons or property and requires immediate repair
or continuous action until the conditions are no longer
hazardous''). The instructions for annual report forms for other gas
pipeline facilities contain similar language.
---------------------------------------------------------------------------
Similarly, subpart M does not elaborate on the requirement that all
hazardous leaks be repaired ``promptly.'' Section 192.711 allows
operators to repair hazardous leaks and other conditions as soon as
feasible for non-IM repairs, and as prescribed by Sec. 192.933(d) for
IM repairs. If a permanent repair is infeasible, Sec. 192.711 merely
requires that any temporary measure addresses public safety, again
excluding the environment from explicit consideration.
Part 192 nowhere specifies remote or continuous monitoring for
pipeline leaks apart from a recent limited requirement pertaining to
detection of ruptures (rather than leaks) on certain new gas
transmission pipelines with rupture mitigation valves.\135\ Frequencies
of leakage survey (Sec. 192.706) and patrol (Sec. 192.705)
requirements are generally keyed to location and the likelihood of
nearby people--proxies for risks to public safety but not the
environment. Consequently, the majority of part 192-regulated gas
transmission and some part 192-regulated, onshore gathering mileage in
the United States (in particular, Types A and B gathering pipelines in
more populated areas, and a minority of Type C lines \136\) need only
have annual leakage surveys, with as long as 15 months between surveys.
The default leak detection survey periodicity for gas distribution
pipelines outside of business districts is only once every 5 years.
Similarly, PHMSA regulations at subpart M allow gas transmission and
select part 192-regulated gathering pipeline mileage to have right-of-
way patrols only once a year, if at all. Finally, patrols on gas
distribution pipelines inside business districts are required twice a
year.
---------------------------------------------------------------------------
\135\ PHMSA, ``Pipeline Safety: Requirement of Valve
Installation and Minimum Rupture Detection Standards--Final Rule,''
87 FR 20940, 20985 (Apr. 8, 2022) (introducing a new Sec. 192.636).
\136\ Only ca. 20,000 miles of the ca. 91,000 miles of Type C
gas gathering pipelines are subject to Sec. 192.706 leakage survey
requirements. PHMSA, Doc. No. PHMSA-2011-0023-0488, ``Regulatory
Impact Analysis for Gas Gathering Final Rule'' at 11, 15 (Nov.
2021).
---------------------------------------------------------------------------
Subpart M maintenance requirements governing the use of leak
detection equipment also reflect the same historical focus on acute
public safety risks. Subpart M regulations are silent on specific
technologies or equipment operators should employ in their leak
detection surveys. For example, leakage surveys on gas distribution
lines, certain regulated gathering lines, and un-odorized transmission
pipelines in Class 3 and Class 4 locations must be performed with leak
detection equipment--but part 192 neither requires particular
technologies, nor establishes performance standards for leak detection
equipment. Leakage surveys on other gas transmission pipelines (e.g.,
odorized lines and all pipelines in Class 1 and Class 2 locations) and
patrols of pipeline rights-of-way can rely entirely on human senses
such as smell or sight, which are imprecise and substantially limited
in their effectiveness. Evidence of a leak detectible by human senses
includes dead vegetation caused by natural gas displacing oxygen in the
soil, blowing soil, bubbling water, or noise. However, it may take a
long time for evidence of a gas leak on vegetation to appear visibly
from the air. Further, the reliability of vegetation surveys is
inconsistent and depends heavily on soil and climate conditions, the
characteristics of the vegetation, the time of year, and other factors.
For example, the impacts of gas leaks on vegetation may not be visible
during seasonal or climate conditions that produce dead vegetation, and
in some soil conditions gas can temporarily increase vegetation growth.
Finally, vegetation surveys are ineffective in areas with no or sparse
vegetation, such as paved areas, particularly rocky areas, or deserts.
PHMSA is not aware of research on the effectiveness of vegetation
surveys versus instrumented surveys in general, however operators who
begin performing instrumented surveys (such as the aerial survey
examples described in section II.D.4) generally report more leaks
discovered using instrumented surveys.
Additionally, PHMSA's IM regulations do not require identification
and remediation of all leaks. PHMSA's IM regulations apply to about 7
percent of gas transmission pipelines.\137\ And no part 192-regulated
gathering pipelines (even Types A and C pipelines with operating
characteristics and threats to public safety and the environment
comparable to transmission lines) \138\ are subject to any IM
requirements. IM requirements also reflect a historical focus on
identifying, preventing, and remediating risks to public safety from
large-volume, instantaneous releases or accumulated gas rather than
environmental harms. While the gas transmission IM regulations at
subpart O oblige some transmission operators to find and eliminate
pipeline anomalies posing risks to public safety, those regulations do
not require repair of all leaks discovered and allow for substantial
delay in the evaluation and subsequent repair of leaks that operators
[[Page 31910]]
(largely at their discretion) consider not to pose acute public safety
risks. DIMP regulations require gas distribution pipeline operators to
have an ``effective leak management program,'' but those regulations
provide few standards regarding what constitutes an ``effective''
program and can instead give considerable deference to an operator's
discretion regarding which leaks are repaired and when. Further,
neither subparts O nor P require operator IM plans to consider
replacement or remediation as a preventative or mitigative measure for
pipe materials known to leak, despite data demonstrating that cast
iron, wrought iron, unprotected steel, and certain plastic pipelines
are more susceptible to leaks and other losses of pipeline integrity.
PHMSA's IM regulations are also not designed to address leaks with low
release rates that persist for a long period of time, which can make
significant contributions to climate change.
---------------------------------------------------------------------------
\137\ The effectiveness of its IM regulations for gas
transmission pipelines at subpart O relies on operators'
identification that those requirements apply--which is not a given.
See NTSB, Pipeline Accident Brief 13-01, ``Rupture of Florida Gas
Transmission Pipeline and Release of Natural Gas'' (Aug. 13, 2013)
(finding that a gas transmission pipeline operator's exclusion of a
segment from its IM plan due to mischaracterization of a Class 1
location contributed to a subsequent rupture).
\138\ See Gas Gathering Final Rule, 87 FR at 6367-68, 63278-79
and 63282-84.
---------------------------------------------------------------------------
PHMSA part 191 reporting requirements also reflect a narrow focus
on public safety risks rather than environmental harms such as the
contribution of methane leaks to climate change, or environmental
degradation from the release of other flammable, toxic or corrosive
gases. Incident reporting requirements are expressed in terms of
personal injury, commercial harm, property damage, or minimum release
volumes that are far too high (3 MMCF) to capture any but the largest
unintentional leaks from pipeline facilities--corresponding to a
volumetric release rate of 340 cubic feet per hour (CFH) or more over a
one-year period. Although annual reports submitted to PHMSA contain
information on all leaks repaired each year, the instructions for those
annual reports explicitly discourage reporting of leaks that can be
eliminated by ``lubrication, adjustment or tightening'' on the narrow
presumption that such releases were not necessarily hazardous from a
public safety perspective. Operators are also not required to submit in
their annual reports the total number of leaks--of any type--detected
in the reporting period; the number of outstanding unrepaired leaks
from year-to-year; or estimated emission volumes from any category of
detected leaks.
Finally, the exclusion of all gas gathering pipelines from NPMS
reporting requirements inhibits PHMSA, State regulators, operators, and
members of the public from knowing the location and operating
characteristics of pipelines. Such knowledge would help identify and
remediate leaks and avoid excavation damage. Although all part 192-
regulated gathering pipelines are subject to damage prevention
requirements of Sec. 192.614, those requirements are not reinforced by
the NPMS requirements identifying the precise location of pipeline
infrastructure.
3. Real-World Consequences of Delayed Repair and Prolonged Releases
From Leaks on Gas Pipelines
The shortcomings of existing regulations pertaining to leak
detection and repair described above are not abstract risks; operators
currently allow leaks from gas pipelines to continue emitting methane
and other gases for extended periods of time, thereby threatening the
environment as well as public safety and human health.
Infrequent leak detection and patrol periodicities provide extended
time intervals within which leaks can develop and worsen, thereby
resulting in prolonged methane and other emissions to the atmosphere.
Infrequent leak detection and patrol periodicities also entail
increased public safety risks. Specifically, PHMSA's regulations have
long recognized the safety risk associated with potential ignition of
leaks, as evidenced by heightened leak surveying and maintenance
requirements throughout part 192 for pipelines located in areas where
buildings intended for human occupancy are more prevalent (Class 3 or 4
locations) as well as requirements to prevent the accumulation of gas
in confined spaces (see, e.g., Sec. Sec. 192.167(c)(2), 192.353(c),
192.355(b)(2), and 192.361(e)(3)). But leaks on gas pipelines that are
not associated with potential ignition of leaks also entail public
safety risks. Leaks of toxic or corrosive gases from part 192-regulated
pipeline facilities can have serious public safety consequences. And
leaks of any type can degrade into catastrophic failures--sometimes
referred to as the ``leak-before-break'' concept.\139\ Additionally,
the absence of baseline leak detection equipment technology
requirements for conducting leakage surveys can also inhibit timely
opportunities to identify, evaluate, and remediate leaks. The absence
(in subparts M, O, and P) of repair criteria and mandatory repair
schedules for all leaks compounds the delays and methodological
shortcomings in identifying leaks. And PHMSA's limited reporting
requirements for leaks from all types of gas pipeline facilities can
complicate its ability to identify systemic pipeline integrity issues
or support enforcement actions against specific operators. Lastly, the
exemption of all gas gathering pipeline facilities from NPMS reporting
requirements inhibits timely leak detection and introduces heightened
vulnerability to a principal mechanism (excavation damage) for loss of
pipeline integrity.
---------------------------------------------------------------------------
\139\ See, e.g., Wilkowski, ``Leak-Before-Break, What Does It
Really Mean?'' 122 Journal of Pressure Vessel Technology 267 (Aug.
2000); Zhang, et al., ``Paper: Preventive Leak Detection for High
Pressure Gas Transmission Networks,'' AAAI 2017 (2017); see also
GPTC Guide appendix G-192-11 table 3c, recommending that grade 3
leaks be re-evaluated within 15 months or during the next required
leakage survey.
---------------------------------------------------------------------------
PHMSA further estimates that, due to those limitations in its
regulatory regime, thousands of leaks persist across part 192-regulated
gas pipelines. With respect to gas distribution pipelines, PHMSA annual
report data between 2010 and 2021 yields roughly the same per-mile,
nationwide averages of repairs of all leaks (0.225 leaks repaired/mile
in 2010 and 0.230 in 2021) and repairs of hazardous leaks (0.089 in
2010 and 0.086 in 2021). PHMSA assumes that the average per-mile rate
at which new leaks are created (controlled for material type) remains
constant, suggesting either that operators may not be reporting to
PHMSA a significant number of leak repairs on their gas distribution
pipelines; operators are not discovering or repairing a significant
number of leaks on their gas distribution pipelines; or existing
regulatory requirements and operator repair practices have not yielded
improvements in reducing the frequency of leak repairs (and perhaps
have failed to yield improvements in leak identification) on gas
distribution pipelines for nearly a decade. PHMSA incident report data
for gas distribution pipelines shows that distribution system operators
reported only 377 incident reports identified as leaks (rather than
ruptures or mechanical punctures) during the entire period from 2010
through 2020. This represents a miniscule percentage of the 510,224
leak repairs reported on operators' annual reports in 2020 alone, a
figure which does not include leaks that are not scheduled for repair
at all. Forty-five percent of these reported leaks were attributable to
causes that progressed over time (e.g., corrosion failure, equipment
failure, and material failure), which may have been discovered earlier
through more frequent leakage surveys, patrols, and repair practices.
As described later in this section, evidence that leaks that are large
in release volume or hazardous to public safety are not reliably
detected or repaired is further supported by available state-
[[Page 31911]]
level information shows persistent backlogs of grade 3 leaks and
research with advanced leak detection methods, which suggests that
operators may not reliably detect releases with large volumes or that
are hazardous to public safety.
Data from States employing the three-tiered GPTC Guide leak grading
framework (discussed in section II.E.) for gas distribution pipeline
facilities demonstrates that most leaks on distribution main and
service pipelines that are identified by operators are not subject to
PHMSA repair requirements as hazardous leaks, and can persist for
extended periods before repair. By way of example, the 2020 Pipeline
Safety Performance Measures Report from New York State reports that out
of 19,683 leaks on main and service pipelines discovered by 11 natural
gas local distribution companies in 2019, 7,403 (37.6%) were grade 1
leaks that approximate to ``hazardous leaks'' under PHMSA repair
requirements in Sec. 192.703(c), while an additional 5,468 (27.8%)
were grade 2 leaks, and 5,768 (29.3%) were grade 3 leaks using New York
State requirements similar to the GPTC Guide criteria.\140\ New York
State has adopted repair deadlines mirroring those in the GPTC Guide
for grade 2 leaks (12 months or 6 months, depending on potential
hazard, see 16 NYCRR 255.813-255.815). However, neither the GPTC Guide
nor New York regulations (as of October 2022) require repair of grade 3
leaks, resulting in a backlog of almost 10,000 outstanding unrepaired
leaks in 2020.\141\ Each of these unrepaired leaks will continue to
release methane (or other gases) to atmosphere until remediated, and
each could increase in size between patrols or leakage surveys.
Minority populations and other disadvantaged communities often bear the
brunt of unrepaired leaks on those gas distribution systems.\142\ The
IM regulations at subpart P have proven insufficient to prevent leaks,
as all the gas distribution pipelines, including those in the New York
data described above, had been subject to DIMP regulations.
---------------------------------------------------------------------------
\140\ State of New York Department of Public Service, Case 21-G-
0165, ``2020 Pipeline Safety Performance Measures Report'' (June 17,
2021), https://www3.dps.ny.gov/W/PSCWeb.nsf/All/9DBA66C148A1310985257B2600750639?OpenDocument. Note that New York
leak classification requirements use the term ``types'' rather than
``grades,'' however they are conceptually identical.
\141\ State of New York Department of Public Service, Case 21-G-
0165, ``2020 Pipeline Safety Performance Measures Report'' at
Appendix K (June 17, 2021), https://www3.dps.ny.gov/W/PSCWeb.nsf/All/9DBA66C148A1310985257B2600750639?OpenDocument.
\142\ Luna et al., ``An Environmental Justice Analysis of
Distribution-Level Natural Gas Leaks in Massachusetts, USA,'' 162
Energy Policy 112778 (2022). This study of the distribution of gas
leaks reported to the Massachusetts Department of Public Utilities
found consistently higher densities of unrepaired leaks in the homes
of people of color, lower income persons, renters, adults with lower
levels of education, and limited English-speaking households. These
same groups were more likely to experience slower repair times and
significantly older unrepaired leaks.
---------------------------------------------------------------------------
The number of leaks from gas transmission pipelines are also
significant. A review of PHMSA incident data yields that over 500
(roughly 40%) of the 1,300 incidents reported by gas transmission
operators between 2010 and 2020 involved hazardous leaks.\143\ PHMSA's
IM regulations at subpart O do not ensure that pipeline operators
prevent such leaks. Of the over 500 leaks reported as incidents on gas
transmission pipelines between 2010-2020, nearly a quarter of those
incidents occurred on gas transmission pipelines subject to subpart O
requirements. Further, incident reports on gas transmission pipelines
show that many were either identified during leakage surveys or patrols
or were attributed to causes that could have degraded over time. PHMSA
therefore expects that more frequent patrols and leakage surveys and
prompt remediation would result in earlier detection and potential
avoidance of leak degradation that would lead to incidents.
---------------------------------------------------------------------------
\143\ This calculation is based on a review of gas transmission
pipeline incident reports, excluding incidents attributed to other
causes such as ``mechanical puncture,'' ``rupture'' or ``other.''
---------------------------------------------------------------------------
Annual report data similarly suggests a large number of leaks on
gas transmission pipelines and the potential value of enhanced leak
detection and repair requirements for promptly identifying and
remediating those leaks. In annual reports submitted between 2012-2021,
operators of gas transmission pipelines reported repairing an average
of 13,600 leaks repaired per year across the 302,000 miles of gas
transmission pipelines nationwide. But part 191 requires annual
reporting of only the number of leaks repaired--not all detected leaks
(even hazardous leaks detected but not repaired). In addition, part 192
does not provide clear timelines for ``prompt'' repair of hazardous
leaks, much less any timeline for other leaks. Even if unreported, non-
hazardous leaks occurred on gas transmission pipelines at just a
fraction of the average, per-mile rate of hazardous leak repairs noted
in annual reports over the last decade, there would be a significant
number of additional, unreported leaks on gas transmission pipelines
each year. Those unreported leaks would generally not be subject to
prescribed repair timelines under existing PHMSA regulations. Although
some of those leaks could be identified and corrected in a timely
manner pursuant to PHMSA's IM regulations at subpart O, the limited
application of those requirements (only transmission pipelines in HCAs)
and the significant discretion given to operators in designing and
executing IM plans do not guarantee any such leaks would be identified
and remediated promptly.
PHMSA similarly understands that its existing regulations tolerate
the persistence of numerous leaks on part 192-regulated gas gathering
pipelines. Data from incidents on Types A and B gas gathering pipelines
across 2010-2020 yields an average, per-mile rate of incidents--83
incidents on 11,542 miles of pipeline (0.0072 incidents/mile)--nearly
double that of gas transmission pipelines (0.00435 incidents/mile) over
the same period. Further, leaks are a more frequent cause of incidents
on Types A and B gas gathering pipelines than for gas transmission
pipelines--operators attributed nearly 80% of the incidents reported on
Types A and B gathering pipelines to leaks. And PHMSA understands from
reviewing incident reports for Types A and B gathering pipelines that
many of those incidents could have been avoided or mitigated by more
timely detection and repair. Annual report data for Types A and B
gathering pipelines tells a similar story. In 2020 annual reports,
Types A and B gathering operators reported 1,574 hazardous leak repairs
on 298,795 miles of onshore gas transmission pipelines (5.3 leaks per
1,000 miles) and 153 hazardous leak repairs on 11,542 miles of Type A
and Type B regulated onshore gas gathering pipelines (13.3 leaks per
1,000 miles). If the number of hazardous leak repairs corresponds to
the total number of hazardous leaks identified, Types A and B gathering
pipelines would have an average, per-mile rate of hazardous leaks more
than twice that of gas transmission pipelines. Similar to the
discussion above regarding distribution and transmission lines, the
annual report-derived values understate the total number of leaks on
Types A and B gathering lines. Therefore, the total number of leaks on
Types A and B gathering lines not subject to any meaningful Federal
repair requirements is likely even higher. Furthermore, the number and
persistence of leaks on Type C pipelines are likely to be higher than
on Types A and B gas gathering pipelines because Type C gathering
pipelines have historically avoided any meaningful
[[Page 31912]]
State or Federal reporting or design requirements.\144\
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\144\ See, e.g., PHMSA, Doc. No. PHMSA-2011-0023-0504,
``Response to Petition for Reconsideration of the Gas Gathering
Final Rule'' at 3 (Apr. 1, 2022).
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The number and persistence of leaks on gas distribution,
transmission, and gathering pipelines tolerated by PHMSA regulations
entail considerable risks to public safety.\145\ Each of those leaks
discussed above that were or became incidents reported pursuant to part
191 involved significant public safety consequences: specifically, one
or more of death, personal injury necessitating in-patient
hospitalization, property damage of $122,000 or more (excluding the
value of the gas itself), or 3 MMCF or more gas lost. Similarly, each
of the hazardous leaks observed on gas pipelines under existing PHMSA
regulations are a hazard with respect to public safety. Since leaks in
pressurized systems can over time degrade into catastrophic failures,
even those leaks that have not yet been reported as incidents or
otherwise designated as hazardous in that they do not involve an
existing or imminent risk of ignition can nevertheless give rise to
such risk if not repaired.
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\145\ PHMSA discusses in this section only direct public safety
consequences of leaks; however (as explained in section II.D.3),
leaks and other releases from gas pipelines can also have second-
order public safety impacts resulting from climate change-induced
natural force damage and equipment malfunction.
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Lastly, any leak from gas gathering pipelines entails unique public
safety risks. Natural gas gathering pipelines are often located in the
vicinity of socially vulnerable populations.\146\ Additionally,
unprocessed natural gas within gathering pipelines typically contains
significant quantities of volatile organic compounds (VOCs) and
hazardous air pollutants (HAPs) such as benzene (a known carcinogen).
As discussed in further detail in the Preliminary RIA, VOCs and HAPs
pose risks from long-term adverse health effects. VOC emissions are
precursors to ozone, and to a lesser extent fine particulate matter
(PM2.5). Both ambient ozone and PM2.5 are
associated with adverse health effects, including respiratory
morbidity, such as asthma attacks, hospital and emergency department
visits, lost school days, and premature respiratory mortality. HAPs
contained in unprocessed natural gas includes several substances that
are known or suspected carcinogens, including but not limited to
benzene, formaldehyde, toluene, xylenes, and ethylbenzene. Benzene and
formaldehyde are known human carcinogens, and ethylbenzene has been
identified as possibly carcinogenic in humans. Chronic (long-term)
inhalation of benzene can result in several adverse noncancer health
effects including arrested development of blood cells, anemia,
leukopenia, thrombocytopenia, and aplastic anemia, and acute (short-
term) exposure to benzene vapors has been reported to cause negative
respiratory effects. Formaldehyde inhalation exposure also causes a
range of noncancer health effects including irritation of the nose,
eyes, and throat, and repeated exposures cause respiratory tract
irritation, chronic bronchitis, and nasal epithelial lesions. There is
evidence that formaldehyde may also increase the risk of asthma and
chronic bronchitis in children. Inhalation of toluene, mixed xylenes,
and ethylbenzene can have neurological, respiratory, and
gastrointestinal effects, among others, with chronic exposure to
toluene potentially leading to developmental effects such as central
nervous system dysfunction, attention deficits, and other anomalies.
Further, corrosives entrained in the unprocessed natural gas can
accelerate corrosion in the vicinity of leaks, thereby increasing the
risk of a catastrophic failure. Recent incident data on Types A and B
gas gathering pipelines similarly underscores the unique risks to
public safety posed by the exemption of any part 192-regulated gas
gathering pipelines from PHMSA's NPMS reporting requirements. The
average, per-mile rate of incidents due to excavation damage reported
to PHMSA between 2010 and 2020 on Types A and B gathering pipelines was
comparable to that on distribution pipelines (0.023 and 0.027 annual
incidents per 1,000 miles, respectively); further, insufficient
locating practices have been reported to PHMSA as a contributing factor
in those incidents.
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\146\ Emanuel et al., ``Natural Gas Gathering and Transmission
Pipelines and Social Vulnerability in the United States,'' 5
GeoHealth (June 2021) (concluding that natural gas gathering and
transmission infrastructure is disproportionately sited in socially-
vulnerable communities).
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Aside from the public safety risks discussed above, leaks from gas
distribution, transmission, and gathering pipelines are also a
significant contributor to climate change. As discussed in section
II.C.2 of this NPRM, current methane emissions data identifies leaks
across line pipe alone on U.S. natural gas distribution, transmission,
and gathering as a significant contributor (the GHGI estimates nearly
328.9 kt CH4 in 2019) to U.S. methane emissions. But current
methane emissions estimates could materially understate actual methane
emissions. GHGRP reporting requirements do not capture all gas pipeline
mileage subject to PHMSA's regulations at parts 191 and 192,
introducing uncertainty into whether national average methane emissions
estimates derived from such reports may accurately be extrapolated to
all PHMSA-regulated gas pipelines. Additionally, recent evidence from
aerial surveys of a small (7,500 square kilometer) swath of the Permian
basin \147\ found leaks from natural gas gathering pipelines in the
Permian basin to be a larger source of methane emissions than would be
calculated using the national average in the GHGI.\148\ A series of
two-week aerial surveys conducted in the fall of 2019, summer of 2021,
and fall of 2021 conducted for the Environmental Defense Fund (EDF)'s
Permian Methane Analysis Project observed between 50 and 350 leaks
attributed to gas gathering line pipe, of which roughly half are likely
attributable to part 192-regulated gathering line pipe. PHMSA made this
assessment by comparing the leak coordinates for gathering line pipe
within the raw data of EDF's Permian Methane Analysis Project \149\ to
geospatial data for specific gathering pipelines downloaded from the
Texas Railroad Commission (TRRC) website.\150\ PHMSA then reviewed the
TRRC's database of attributes of those gathering pipelines to determine
diameter, using that metric to determine whether an observed leak was
on a part-192 regulated gathering pipeline. The leaks identified in
these aerial surveys, moreover, were not de minimis: the average leak
rate observed by EDF was 273 kg CH4/hour, correlating to
roughly a metric ton of methane emitted to atmosphere every five days.
Even this limited Permian Basin data could under-report the number and
scale of leaks from methane emissions from gas gathering pipelines if
projected
[[Page 31913]]
nationwide.\151\ Many of the gathering pipelines in the Permian basin
are relatively new pipelines, while older gas gathering infrastructure
in other production regions may leak at higher rates.
---------------------------------------------------------------------------
\147\ The entire Permian basin covers approximately 86,000
square miles--more than 220,000 square kilometers.
\148\ See Yu et al., ``Methane Emissions from Natural Gas
Gathering Pipelines in the Permian Basin,'' Environ. Sci. Technol.
Lett. (Nov. 8, 2022) (Yu Study) (``The EF [(emissions factor)]
derived from each of the four aerial surveys is more than an order
of magnitude higher than the EPA's published values [for national
average emissions].''). The emissions factors calculated from this
study were also ``4-13 times higher than the highest estimate
derived from a published ground-based survey of gathering lines.''
\149\ See EDF, Permian Methane Analysis Project, https://permianmap.org/ (last accessed July 20, 2022).
\150\ https://rrc.texas.gov/oil-and-gas/publications-and-notices/maps/ (last accessed July 25, 2022).
\151\ The Yu Study acknowledged that its data may also be
underestimating emissions from gathering pipelines. The authors
conservatively excluded any emissions sources in areas of co-located
gathering and transmission pipelines where the source could not be
definitively attributed, although the authors noted that it would be
reasonable to assume at least some of those sources were from
gathering pipelines. See Yu et al.
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4. Regulatory Requirements Lag Commercially Available, Advanced Leak
Detection Technologies
As explained above in section D.1, PHMSA regulations prescribe
requirements for identifying leaks--leakage surveys and rights of way
patrols--directed principally toward risks to public safety (from
ignition of instantaneous, large-volume releases or accumulated gas)
and not toward environmental harm that even small leaks can cause.
Consistent with that historical approach, PHMSA regulations permit
reliance on non-instrumented leak detection methods such as smell or
visual surveys of gas transmission pipeline infrastructure and rights
of way that are more appropriate for discovering ruptures or
accumulated gas than smaller leaks. When leak detection equipment is
required, PHMSA regulations specify neither particular leak detection
technologies nor minimum performance standards for detection of gas
concentration by leak detection equipment.
These shortcomings in PHMSA's regulatory regime allow operators to
rely on inadequate or ineffective leak detection equipment and
practices, rather than encouraging use of commercially available,
advanced leak detection technologies and practices appropriate to
different gases transported by gas pipeline facility subject to part
192. Many of these technologies and practices were discussed by PHMSA,
industry and academic research organizations, and vendors within a
virtual public meeting on advanced methane leak detection technology
and practices hosted by PHMSA on May 5-6, 2021 (2021 Public
Meeting).\152\ PHMSA staff also attended the Methane Detection
Technology Workshop hosted by EPA on August 23-24, 2021 (2021 EPA
Methane Detection Technology Workshop).153 154 155 156
Presenters at these meetings described how innovations in equipment
sensitivity, analytics, automation, and survey speed of leak detection
services could increase the effectiveness and decrease the cost of
detecting gas releases from oil and gas facilities.
---------------------------------------------------------------------------
\152\ Recordings, transcripts, and slides from the 2021 Public
Meeting are available at the meeting web page at https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=152. A number of
entities submitted written comments before and after the meeting
that are available in the rulemaking docket at Doc. No. PHMSA-2021-
0039.
\153\ Recordings are available at the EPA meeting web page at:
https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-
industry/epa-methane-detection-technology-
workshop#:~:text=Natural%20Gas%20Industry-
,EPA%20Methane%20Detection%20Technology%20Workshop%20%2D%2D%20August%
2023%20and%2024,oil%20and%20natural%20gas%20industry (last accessed
July 20, 2022).
\154\ See ``Attachment 1: Summary Report Methane Detection
Technology Workshop'' of ``Background Technical Support Document for
the Proposed New Source Performance Standards (NSPS) and Emissions
Guidelines (EG)'' at https://www.regulations.gov/ Docket ID No. EPA-
HQ-OAR-2021-0317-0166.
\155\ See ``EPA's Methane Detection Technology Virtual Workshop.
August 23-24, 2021. Audio'', ``Transcripts'', and ``Presentations''
at https://www.regulations.gov/ Docket ID No. EPA-HQ-OAR-2021-0317-
0183, EPA-HQ-OAR-2021-0317-0181, and EPA-HQ-OAR-2021-0317-0182
respectively.
\156\ See ``Controlling Air Pollution from the Oil and Natural
Gas industry. EPA Methane Detection Technology Workshop. August 23
and 24, 2021'' https://www.regulations.gov/ Docket ID No. EPA-HQ-
OAR-2021-0317-0183.
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At the 2021 Public Meeting, EDF presented a set of recommended
elements for an advanced methane leak detection system, including (1)
leak detection equipment with a parts-per-billion level of sensitivity
\157\ and the ability to capture other data for use in an algorithm to
understand the size and location of leaks; (2) a defined deployment
strategy or work practice to ensure that accurate data is being
collected; and (3) comprehensive data collection on topics such as leak
location, estimated leak flow rate or gas emission rate, a coverage map
showing which areas were successfully surveyed and which areas were
not, and a summary or cumulative loss estimate for the total area
surveyed. AGA observed in their remarks at the 2021 Public Meeting and
AGA et al.\158\ in their written comments that most currently available
leak detection technologies are focused on identifying indications of
methane leaks in the air (i.e., gas concentration) rather than
measuring the rate of leakage from a component. AGA et al.
characterized methane concentration as a more appropriate metric for
evaluating the public safety risks from explosion than for estimating
the amount of methane going to atmosphere.
---------------------------------------------------------------------------
\157\ EDF commented that parts-per-billion detection is
important in this effort in light of the potential for hidden
underground leaks, where only a small volume of gas may migrate
through the pavement despite a significant leak buried under the
street.
\158\ The American Gas Association (AGA), API, American Public
Gas Association, GPA Midstream Association (GPA), and Interstate
Natural Gas Association of America submitted joint comments (Doc.
No. PHMSA-2021-0039-0008) to the rulemaking docket after the 2021
Public Meeting. Throughout this NPRM, references to ``AGA et al.''
refer to those joint comments.
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Several stakeholders at the 2021 Public Meeting emphasized the
importance of flexibility in PHMSA's consideration of advanced leak
detection standards, recommending that PHMSA assess the suite of leak
detection technologies that are currently commercially available and
introduce requirements that promote continued development of advanced
technologies. EDF noted that it was essential that PHMSA set advanced
methane leak detection standards that ensure an ongoing process for
continuous technology improvement, recommending that PHMSA set a floor,
not a ceiling, to create a space in Federal standards to push for the
development of new ideas and improvements to technology over time for
future incorporation. AGA et al. also suggested that applying
prescriptive regulations could potentially limit the development of
different technologies and innovations, stating that providing
operators with flexibility can create opportunities and incentives for
developing new technologies and innovations in leak detection and
measurement. Similarly, the Pipeline Safety Trust (PST) stated that
performance-based regulations for advanced leak detection (ALD) and
methane reduction should use the capabilities of commercially available
ALD technologies as a starting point, but that the ALD performance
standards should change as commercially available technologies develop.
AGA et al. emphasized the value of leak data analysis in lieu of
requirements that operators use specific advanced leak detection
technologies. AGA et al. observed that studies across the gas industry
supply chain show that a majority of emissions come from a small number
of high-emitting leaks, and thus leak data analysis enables operators
to make substantial inroads on reducing methane emission by identifying
and prioritizing repair of the highest-emitting leaks. AGA et al. also
urged PHMSA to consider the affordability of any new regulatory
requirements and suggested that in some situations, a simpler, less
costly technology or practice may achieve safety and environmental
goals more successfully than a newer technology.
Notable commercially available, advanced leak detection
technologies
[[Page 31914]]
and practices \159\ are described briefly below.
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\159\ PHMSA acknowledges that much of the discussion of advanced
leak detection technologies and practices in this section is
presented in terms of advanced methane leak detection technologies
for use in connection with natural gas pipeline facilities, rather
than leak detection technologies and practices for other gases whose
transportation within pipeline facilities is subject to part 192.
However, many of the advanced leak detection technologies and
practices for methane are comparable to the technologies and
practices employed in connection with other gases.
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Hand-Held Leak Detection Equipment
The most common method for instrumented leakage surveys (meaning a
leakage survey performed using leak detection equipment) on natural gas
pipelines consists of surveys along the pipeline right-of-way with
handheld leak detection equipment. A surveyor typically uses a flame
ionization detector (FID), infrared gas detector, optical gas imaging
(OGI) device,) or other gas detector to sample gas above a buried
pipeline, inside underground structures, and possibly in the soil.
Handheld equipment is used to perform most leakage surveys, and any
advanced leak detection solution that does not operate directly on or
over the pipeline would still require confirmation of leak indications
on the ground by operator personnel with handheld equipment. For
aboveground or excavated leaks, gas detection instruments are often
supplemented with a ``soap test'' that involves applying a soapy
solution to the probable leak location. The location and size of the
bubbles produced by escaping gas provides an indication of the exact
location of the leak source and the relative size of the leak.
Handheld devices have been a focus of research and development
(R&D) by PHMSA, equipment manufacturers, and operators. Recent
innovations available on the market, including highly sensitive
handheld equipment and laser-based detectors capable of detecting gas
at a distance, have improved the effectiveness, efficiency, and safety
of traditional walking surveys. A walking survey can be effective at
detecting pipeline leaks, assuming that the location of the pipeline is
known, adequate equipment is used, and survey personnel follow
procedures that ensure the pipeline and potential migration paths are
properly surveyed, and there may not be an alternative to walking
surveys in some environments with poor equipment access. The
performance of leak detection equipment and procedures may vary
depending on weather and soil conditions or other environmental
factors. The GPTC Guide includes guidelines for performing leakage
surveys.
Walking surveys, however, tend to be expensive and time-consuming
because they require significant personnel resources to execute.
Effectiveness of even advanced handheld leak detection technologies can
be reduced by poor operator training, inadequate survey procedures, or
use of poorly maintained or uncalibrated equipment.
Automobile-Based Leak Detection Equipment
Similar equipment used in walking surveys can be mounted on cars
and trucks to allow efficient surveying of pipelines with adequate road
access. The effectiveness of a mobile survey depends on weather
conditions, the survey procedure, and whether the equipment has
acceptable access to the location of the pipeline and possible gas
migration paths. Some vendors have taken this concept a step further
and combined highly sensitive gas detectors, some capable of detecting
gas in the single ppb range, anemometers, GPS sensors, other sensors,
and advanced analytics to enhance the capabilities of vehicle-based
leakage surveys. Some advanced vehicle-based leak detection systems
typically function by combining gas readings and wind indications to
estimate the size and point of origin of a plume of gas as the vehicle
drives through it. These leak indications (and gaps in the survey
coverage) are then assessed by personnel with handheld equipment. For
example, two studies measured gas concentrations in Boston, MA, and
Washington, DC using Picarro mobile methane analyzer technology. In the
2004 survey of Washington, DC, the researchers surveyed 1500 miles of
streets using a Picarro G2301 spectrometer device and the Picarro A0491
Mobile Plume Mapping Kit (A combination of the gas analyzer, a GPS
device, and an anemometer). According to the equipment manufacturer,
the G2301 device has sub 0.5 ppb precision over 5 seconds and an
operating range of 0-20ppm when measuring methane,\160\ though testing
of the device during the Boston study found analyzer output to be
within 2.7 ppb of known gas concentration during testing.\161\ In
Washington, DC, out of 5,893 methane readings detected from the vehicle
with a concentration greater than 2.5 ppm, the minimum concentration
defined as a leak indication in the study, 1,112 were measured at 5 ppm
or greater.\162\ Additionally, the researchers inspected 19 of the
larger emissions sources with a handheld combustible gas indicator and
found gas concentration in nearby manholes exceeding 80% LEL (i.e., a
grade 1 hazardous leak) at 12 locations. Upon notifying the
distribution operator, a subsequent reinspection found that hazardous
conditions remained at nine leak locations. In Boston, 435 out of 3,356
methane indications were measured at 5 ppm or greater.\163\ However,
these measurements are based on ``in-plume'' measurements consistent
with the operation of the Picarro mobile methane analyzer and similar
vehicle-based systems rather than direct measurements within 5 inches
of the leak location. The concentration of each potential leak
indication measured in-plume is likely to be lower than the
concentration measured in the immediate vicinity of the emissions
source during a leak investigation.
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\160\ Picarro. G2301 Gas Concentration Analyzer Datasheet,
https://www.picarro.com/g2301_gas_concentration_analyzer (last
accessed Dec. 20, 2022).
\161\ Phillips et al., ``Mapping Urban Pipeline Leaks: Methane
Leaks Across Boston,'' 173 Environmental Pollution at 1-4 (2013).
\162\ Jackson et al., ``Natural Gas Pipeline Leaks Across
Washington, DC,'' 48 Environmental Science & Technology at 2051-2058
(2014).
\163\ Phillips et al., ``Mapping Urban Pipeline Leaks: Methane
Leaks Across Boston,'' 173 Environmental Pollution at 1-4 (2013).
---------------------------------------------------------------------------
Advanced vehicle-based leak detection systems were discussed
extensively during the 2021 Public Meeting. A number of technology
providers market automobile-based leak detection systems. EDF discussed
their experience with advanced vehicle-based leak detection systems in
partnership with Google and Pacific Gas and Electric (PG&E). According
to EDF, research indicates that advanced mobile leak detection systems,
vehicle-based platforms that rely on sensitive gas detectors,
anemometers, GPS devices, other sensors, and analytics to locate the
approximate source of gas plumes indicating possible leaks, can find
more leaks in distribution systems compared to traditional survey
methods. Also, according to EDF, one study found that surveys conducted
by ``traditional'' methods in two cities failed to find 65 percent of
the leaks that were discovered by advanced leak detection technologies,
including some grade 1 leaks. EDF further commented that quantifying
emissions can allow operators to prioritize replacement programs more
effectively to the largest individual leaks.
On the other hand, AGA noted issues with excessive ``false
positives'' from mobile survey technologies, where there are
indications of leaks where none exist. AGA also noted that mobile
survey technologies can fail to detect
[[Page 31915]]
indications of a leak when a leak does exist. False positives require
confirmation by operator personnel, and therefore cut into the cost-
effectiveness of such surveys. PHMSA, during the 2021 Public Meeting,
noted that there are challenges with certain leak detection
technologies depending on the area where the survey is being
performed.\164\ For instance, driving surveys might best be conducted
in densely populated areas where pipelines follow roadways. However, in
rural areas with gas transmission and gathering pipelines, it can be
more effective to use aerial surveys or continuous monitoring
technology because pipeline rights-of-ways may be difficult to traverse
on the ground. There might also be issues for operators using laser-
based and other line-of-sight equipment in some areas.
---------------------------------------------------------------------------
\164\ Similarly, GPA and API submitted joint comments (Doc. No.
PHMSA-2021-0039-0004) following the 2021 Public Meeting stating that
the differences between gas gathering pipelines and gas transmission
and distribution pipelines should be considered in developing any
new regulations, guidance documents, or enforcement policies related
to leak detection and repair.
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Aerial Sensors and Continuous Monitoring
Other areas of industry interest are aerial sensing platforms and
continuous monitoring. Aerial sensing involves gas detection equipment
mounted on fixed wing or rotary wing aircraft, unmanned aerial systems
(UAS), or satellites. Many aerial sensing methods are similar in
principle to those used in advanced vehicle-based leak detection
systems, except that the sensor suite is mounted on an aircraft or UAS,
instead of a car or truck. Other aerial platforms may use direct
sampling, laser-based methane detectors, LIDAR, OGI, or other methods
that detect methane gas concentrations along a pipeline right-of-way or
at aboveground facilities.
Recent research and perspectives shared at the August 2021 EPA
technology workshop described above illustrate the potential advantages
of aerial survey technologies for certain oil and gas facilities. The
primary advantage of aerial surveys is that the speed of an aircraft
can allow more efficient or more frequent surveys of large areas.
Depending on the configuration of the facility, aerial surveys are
potentially highly cost-effective. For example, during a panel
conversation on the first day of the 2021 EPA Methane Detection
Technology Workshop, Triple Crown Resources reported cost-effective
methane emissions reductions of up to 90% from upstream production
facilities via aerial surveys performed by Kairos Aerospace.\165\ In
addition to leak detection and repair procedures, the operator also
made changes to its operations and maintenance procedures to address
the minimization of releases from tanks and other equipment. In that
same panel, another operator reported that aerial surveys were not
cost-effective for all of their facilities, but that aerial surveys,
especially those mounted on UAS, have the additional advantage of being
able to maneuver around locations or facilities that may be difficult
for operator personnel to safely access with traditional
equipment.\166\ On the second day of the 2021 EPA Methane Detection
Technology Workshop, a representative of BPX Energy (British
Petroleum's onshore U.S. production business) described the company's
quarterly aerial survey program using fixed wing aircraft and UAS in
the Permian Basin, which is designed to detect, image, quantify, and
map methane sources with an emissions rate greater than 5.5 mcf/d.\167\
BPX reported that the aerial surveys can cover over 100 square miles
per day, although these surveys are susceptible to meteorological
conditions. The advantages of aerial surveys are likely to be most
significant on long-distance transmission lines that can be surveyed
efficiently with fixed wing aircraft. Likewise, long-distance or dense
gas gathering pipeline networks may also be cost-effective to survey by
air.
---------------------------------------------------------------------------
\165\ Johnson, Forrest and Wlazlo, Andrew. ``Airborne Methane
Surveys Pay for Themselves: An Economic Case Study of Increased
Revenue from Emissions Control'' Triple Crown Resources. EPA Methane
Detection Technology Workshop (August 23, 2021). https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/epa-methane-detection-technology-workshop. Day 1 at 2:32:15.
\166\ Berrnica, P.E., ``Key Takeaways from Deploying Four Novel
Methane Detection Technologies''.
\167\ Faye Gerard, Ph.D. ``BPX, Methane Measurements.'' BP
America. EPA Methane Detection Technology Workshop (August 24,
2021). https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/epa-methane-detection-technology-workshop. Day
2 at 2:39:10.
---------------------------------------------------------------------------
In contrast, drawbacks and limitations of aerial and continuous
monitoring are similar to those of motor vehicle-based systems. While
aircraft can access facilities that may be difficult to access with
ground-based vehicles, the speed and altitude required for operation of
fixed wing aircraft and helicopters can reduce the reliability of
detecting smaller releases since gas concentration decreases with
distance from the source and increased speed decreases the likelihood
that an accurate measurement will be taken as the vehicle intersects a
gas plume. Additionally, aerial surveys may not be cost-effective for
some system configurations. Most research and application of aerial
systems have been in the upstream sector on gas production, processing,
and gathering systems.
PHMSA expects that use of UAS for aerial monitoring will grow as
technology continues to advance, and the Federal Aviation
Administration (FAA) continues its work to integrate UAS into the
National Airspace System. On January 15, 2021, FAA published a final
rule to permit the operation of UAS at night and over people under
certain conditions.\168\ FAA is currently considering recommendations
from an Aviation Rulemaking Committee on a regulatory approach to
support beyond visual line of sight operations in the National Airspace
System.\169\
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\168\ FAA, ``Operation of Small Unmanned Aircraft Systems Over
People,'' 86 FR 4314 (Jan. 15, 2021).
\169\ Unmanned Aircraft Systems Beyond Visual Line Of Sight
Aviation Rulemaking Committee Final Report, March 2022, available at
https://www.faa.gov/regulations_policies/rulemaking/committees/documents/media/UAS_BVLOS_ARC_FINAL_REPORT_03102022.pdf.
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Continuous monitoring can take many forms and is a fast-maturing
area of development. The most straightforward means of providing
continuous monitoring is with stationary gas detectors that are able to
communicate with operator personnel or a control center. The most
straightforward means of continuous monitoring is mounting stationary
sensors such as gas samplers or laser-based detectors in the vicinity
of a pipeline. A stationary gas sampler must be located near potential
leak locations in order to detect leaks, laser-based systems must have
potential leak sources or migration paths within the line of sight and
effective range of the device, though some newer devices are capable of
scanning. Continuous monitoring with such sensors can therefore be
costly, since more devices are required versus using one device to
perform a survey, however real time leak information is a significant
advantage, especially for intermittent sources. For example, the BPX
Energy presentation at the 2021 EPA Methane Detection Technology
Workshop noted that the company's stationary sensors refresh every 15
minutes.\170\ For this reason, continuous monitoring can be especially
effective at aboveground facilities where probable fugitive emissions
sources are known
[[Page 31916]]
beforehand and at high-risk locations where real-time alarms can help
ensure public safety from fire and explosion risk.
---------------------------------------------------------------------------
\170\ Faye Gerard, Ph.D. ``BPX, Methane Measurements.'' BP
America. EPA Methane Detection Technology Workshop (August 24,
2021). https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/epa-methane-detection-technology-workshop. Day
2 at 2:48248.
---------------------------------------------------------------------------
Vendors and operators have been experimenting with a number of
methods such as pressure wave monitoring, acoustic monitoring, in-ditch
sensing with fiber optic sensors, and other devices. At the May 2021
Public Meeting, Siemens Energy and ProFlex Technologies presented on a
negative pressure wave sensing technology for detecting ``spontaneous
leaks'' on gas transmission, gas gathering, and similar applications.
In that technology, pressure sensors placed periodically along the
pipeline can detect anomalous negative pressure waves that propagate
from the location of a rupture. According to the technology provider,
the system can detect, by timing the rupture indications on the
upstream and downstream sensors, estimate the location of the rupture
within 20-50 linear feet. The technology provider claims that the
system can detect leaks between \1/2\ inch to 2 inches in area within a
few seconds, therefore is potentially a sensitive and reliable means of
detecting pipeline ruptures, however the system may not be able to
reliably detect smaller leaks.\171\
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\171\ ProFlex Technologies and Siemens. ``Siemens Energy
Spontaneous Leak Detection Service powered by ProFlex.'' May 2021.
https://primis.phmsa.dot.gov/meetings/FilGet.mtg?fil=1154.
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In-Residence Methane Detection Tools
Another emerging area of industry interest is in-home methane
detection. While gas piping downstream from the outlet of a customer
meter is not regulated under the Federal pipeline safety regulations,
PHMSA encourages the adoption of in-home methane detectors by
operators, States, and standards developing organizations. As a result
of NTSB investigations into a series of gas-related incidents in a
neighborhood in Dallas, Texas in late February of 2018,\172\ and an
investigation into an apartment explosion in Silver Spring, MD,\173\
the NTSB included in-home methane detection on its 2021-2022 NTSB Most
Wanted List.\174\ NTSB recommended that the International Code Council,
the National Fire Protection Association, and the Gas Technology
Institute (GTI) cooperate to develop standards and incorporate
provisions in applicable national codes to require methane detection
systems for all types of residential occupancies with gas service. The
NTSB recommended that, at a minimum, these requirements should cover
the installation, maintenance, placement of the detectors, and testing
requirements. The PST and other public safety advocacy groups have also
called on operators to install this technology wherever possible to
provide for better public and environmental safety, as this technology
can provide an extra level of protection against dangerous leaks. At
the 2021 Public Meeting, the PST stated that the increased usage of in-
home methane detectors would be relatively inexpensive and have the
potential to dramatically reduce injuries, property damage, and deaths
resulting from leaks and explosions from gas distribution systems.
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\172\ NTSB, Pipeline Accident Report 21-01, ``Atmos Energy
Corporation Natural Gas-Fueled Explosion; Dallas, Texas; February
23, 2018'' (Jan. 12, 2021).
\173\ NTSB, Pipeline Accident Report 19-01, ``Building Explosion
and Fire: Silver, Spring, Maryland: August 10, 2016'' (Apr 24,
2019).
\174\ NTSB, ``Improve Pipeline Leak Detection and Mitigation:
2021-2022 Most Wanted List of Transportation Improvements'' (Apr. 6,
2021).
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Integration of Advanced Technologies and Practices Within Advanced Leak
Detection Programs
Each of the commercially available, advanced technologies described
above have inherent limitations that make their use more or less
appropriate for use in connection with different gases, pipeline
facilities, operating environments, weather conditions, and other
factors. And even state-of-the-art equipment can deliver poor results
if the operator's procedures or training are inadequate or if equipment
malfunctions. For this reason, a number of speakers during the 2021
Public Meeting emphasized that ALDPs must consist of a portfolio of
mutually reinforcing advanced leak detection technologies, practices,
and policies, each providing defense-in-depth for the inherent or
operational limitations of other program elements.
An incident that occurred on a gas distribution pipeline operated
by Atmos Energy, in Dallas, Texas on February 23, 2018, that had been
surveyed shortly before the incident illustrates this truism.\175\
Prior the February 23 incident, two other gas-related fires occurred on
the same block on February 21 and February 22. The NTSB concluded that
it is likely that the three incidents are related, but fire department
investigators and operator personnel failed to pinpoint the source of
the leak that led to the February 23 incident. Since the fire
department and the operator had not identified the distribution
pipeline as the cause of the first two fires, no incident was reported
to PHMSA. Following the February 22 fire, Atmos performed a leakage
survey and repaired high-priority leaks on the pipeline segment
involved in the incident. Atmos Energy's leakage surveys incorporated
modern leak detection equipment such as FIDs, optical methane
detectors, remote methane leak detectors (RMLD, a type of laser-based
gas detector), and other devices. However, the manufacturer's
instructions for the RMLD devices used to perform the leakage survey
noted that the device performs sub-optimally in wet conditions and is
not to be used when sustained wind or gusts exceed 15 mph.
Additionally, the operator's combustible gas indicator could be damaged
when saturated. Due to precipitation, wind, and wet soil conditions,
the operator's RMLD survey was ineffective and the operator's barhole
\176\ procedures to measure gas concentrations in the soil could not be
performed. As a result, the operator failed to detect leaking gas from
a cracked main, resulting in a third, fatal explosion on February 23,
2018.
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\175\ NTSB, Pipeline Accident Report 21/01 ``Pipeline Accident
Report: Atmos Energy Corporation Natural Gas-Fueled Explosion:
Dallas, Texas: February 23, 2018'' (Jan. 12, 2021).
\176\ A barhole is a small hole dug into the ground in order to
measure the concentration of gas within the soil by taking a sample
within the barhole with a probe.
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5. State-Level and Operator Leak Detection and Repair Requirements
PHMSA regulations, as explained in section II.D.1 above, require
operators of part 192-regulated gas transmission and distribution
pipelines and certain regulated gathering pipelines to repair hazardous
leaks promptly--without providing meaningful guidance regarding which
leaks are hazardous, or precisely when any leaks must be repaired. The
limitations of regulatory initiatives undertaken by State authorities
and voluntary efforts (including methane emissions reduction
commitments and pertinent industry standards) by pipeline operators,
moreover, underscore the need for robust Federal leak detection,
grading, and repair requirements.
GPTC Guide
The GPTC is an ANSI-accredited committee (ANSI Z380, or the
Committee) that was formed in the late 1960s under the American Society
of Mechanical Engineers. The Committee operates under a consensus
process and is technically based and independent. The Committee is
composed of
[[Page 31917]]
approximately 100 members from all facets of the gas industry,
including gas distribution, transmission, storage, and gathering
operators and manufacturers of gas-related equipment. The Committee
also has members from the regulatory community, including PHMSA, the
National Transportation Safety Board (NTSB), and other Federal and
State regulatory agencies. Approximately 40 of the Committee's members,
including PHMSA, are voting members.
The Committee publishes the GPTC Guide as an implementation tool
facilitating compliance by gas pipeline operators with PHMSA regulatory
requirements.\177\ The first edition of the GPTC Guide was published in
1970, around the same time the Federal Pipeline Safety Regulations were
first promulgated. The GPTC Guide is under continuous review and may be
updated when prompted by pending rulemakings, NTSB reports, and
requests from stakeholders, including PHMSA, the National Association
of Pipeline Safety Representatives (NAPSR), or members of the public.
The Committee periodically reviews requests for updates and may create
a task group, if necessary, to issue new or amended guidance of
versions of the GPTC Guide. The current edition of the GPTC Guide is
the 2022 edition (including Addendum 1), published in June 2022.
---------------------------------------------------------------------------
\177\ GPTC Guide at 18 (``While the GPTC Guide is intended
principally to guide operators of natural gas pipelines, it is a
valuable reference for operators of other pipelines covered by Part
192'').
---------------------------------------------------------------------------
Like the Federal Pipeline Safety Regulations, the GPTC Guide's leak
grading and repair criteria are focused primarily on public safety
rather than environmental protection. While the GPTC Guide itself has
not been incorporated by reference in the Federal Pipeline Safety
Regulations, several States have adopted at least the tiered leak
grading criteria of the GPTC Guide and associated repair requirements
into their regulations governing gas pipelines,\178\ and PHMSA has
referenced it from time-to-time in its implementing guidance.\179\
Additionally, some gas pipeline operators incorporate sections of the
GPTC Guide into their operating and maintenance procedural manuals for
detecting, investigating, and classifying leaks.
---------------------------------------------------------------------------
\178\ See National Association of Pipeline Safety
Representatives (NAPSR), Compendium of State Pipeline Safety
Requirements and Initiatives Providing Increased Public Safety
Levels Compared to Code of Federal Regulations, Third Edition (Feb.
2022) (Compendium). References to ``NAPSR'' or to pertinent State
requirements in this NPRM will, unless otherwise noted, will be to
information within the Compendium.
\179\ See, e.g., PHMSA, ``Distribution Integrity Management:
Guidance for Master Meter and Small Liquefied Petroleum Gas Pipeline
Operators'' (2013) at 2 (directing larger distribution pipeline
operators to refer to GPTC guidelines); PHMSA, Interpretation
Response Letter No. PI-93-009 (February 11, 1993) (recommending
public stakeholder consult the GPTC Guide for further determination
of instruments and techniques to be used in certain leak detection
activities); see also PHMSA, Interpretation Response Letter No. PI-
99-0105 (December 1, 1999) (stating that the GPTC Guide ``is a
document endorsed by us which contains information and some methods
to assist the gas pipeline operator in complying with the
regulations contained in 49 CFR part 192'').
---------------------------------------------------------------------------
The GPTC Guide contains appendices that provide procedures that
comply with part 192. The GPTC Guide also provides guidance for
controlling methane leaks from natural gas pipeline leaks in Appendix
G-192-11 For gas distribution pipelines, section 6.2 of the DIMP
guidance in Appendix G-192-8 describes possible elements of an
``effective leak management program'' and references the criteria for
grading leaks from Appendix G-192-11 and, for liquefied petroleum gas
(LPG) systems, Appendix G-192-11A. Each section includes tables 3a, 3b,
and 3c summarizing the grading criteria and recommended repair
requirements. The grading criteria from GPTC Guide Appendix G-192-11
and Appendix G-192-11A are discussed below (hereafter, references to
the GPTC Guide refer specifically to Appendix G-192-11 and 11A unless
otherwise specified).
Section 5.5 of the GPTC Guide characterizes a grade 1 leak as a
``leak that represents an existing or probable hazard to persons or
property, and requires immediate repair or continuous action until the
conditions are no longer hazardous.'' This mirrors the definition of a
``hazardous leak'' at Sec. 192.1001. This characterization omits
consideration of potential hazard to the environment, and the phrase
``existing or probable hazard'' is not defined in any part of the GPTC
Guide. However, Table 3a of the GPTC Guide provides the following
examples of grade 1 leaks:
(1) Any leak that, in the judgment of operating personnel at the
scene, constitute an immediate hazard.
(2) Escaping gas that is ignited.
(3) Any indication of gas which has migrated into or under a
building, or into a tunnel.
(4) Any indication of gas which has migrated to at an outside wall
of a building where gas would likely migrate or into a tunnel.
(5) Any reading of 80% [of the lower explosive limit] LEL, or
greater, in a confined space.\180\
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\180\ The Lower Explosive Limit (LEL) is the lowest
concentration of gas that will burn in air in the presence of an
ignition source.
---------------------------------------------------------------------------
(6) Any reading of 80% LEL, or greater, in small substructures
(other than gas-associated substructures) from which gas would likely
migrate to the outside wall of a building.
(7) Any leak that can be seen, heard, or felt, and which is in a
location that may endanger the general public or property.
Building on the Sec. 192.703(c) requirement that hazardous leaks
(i.e., grade 1 leaks) be repaired promptly, the GPTC Guide further
specifies that an operator must take immediate and continuous action to
protect life and property until the conditions are no longer hazardous.
Per the GPTC Guide, such continuous actions could include: implementing
an emergency plan written in accordance with Sec. 192.615; evacuating
the premises; blocking off an area; re-routing traffic; eliminating
ignition sources; and venting the area by removing manhole covers, bar-
holing, or installing vent holes. The GPTC Guide also notes that, for
grade 1 leaks, operators should stop the flow of gas by closing valves
or by other means and notify appropriate police and fire departments.
A grade 2 leak is an intermediate risk classification in the GPTC
Guide. The GPTC Guide characterizes a grade 2 leak as a ``leak that is
non-hazardous at the time of detection but that requires or justifies a
scheduled repair based on probable future hazard.'' Like the
description of a grade 1 leak, the characterization of a grade 2 leak
in the GPTC Guide does not address hazards to the environment and does
not provide a definition for the term ``probable future hazard,''
although example criteria are provided in Table 3b of the GPTC Guide.
For grade 2 leaks, these criteria include leaks that require action
ahead of the ground freezing, or where changes in venting conditions
would likely cause gas to migrate to the outside wall of a building.
Grade 2 leaks could also include leaks with a reading of 40% of the LEL
or greater under a sidewalk in a wall-to-wall paved area that does not
qualify as a grade 1 leak; a reading of 100% LEL or greater anywhere
under a street in a wall-to-wall paved area that has significant gas
migration and does not qualify as a grade 1 leak; a reading between 20%
and 80% of the LEL in a confined space or in a small substructure; any
non-zero concentration reading on a pipeline
[[Page 31918]]
operating at 30% of SMYS or greater in a Class 3 or Class 4 location
that does not qualify as a grade 1 leak; and finally, any leak that, in
the judgment of the operating personnel at the scene, is of sufficient
magnitude to justify or require a scheduled repair. These examples
demonstrate that the grade 2 leak classification, like the grade 1
classification, focuses operators on hazards to persons and property,
without consideration of impacts on our environment.
The GPTC Guide requires that, upon detecting a grade 2 leak, an
operator should repair or clear the leak ``within one calendar year but
no later than 15 months from the date the leak was reported.'' The GPTC
Guide states that, in determining the repair priority for the leak, an
operator should consider the extent of gas migration, the proximity of
gas to buildings in sub-surface structures, and the soil conditions
(including frost cap, moisture, or natural venting). Operators can take
a range of actions in addressing grade 2 leaks under the GPTC Guide.
Some grade 2 leaks that are evaluated by the criteria listed above may
justify a scheduled repair within 5 working days, whereas others might
justify repair within 30 days. The GPTC Guide suggests that operators
should schedule some grade 2 leaks for repair on a ``normal routine
basis,'' with periodic re-inspection as necessary. The GPTC Guide
suggests that operators should reevaluate grade 2 leaks at least once
every 6 months until they are cleared, establishing a frequency of
reevaluation based on the location and magnitude of the leak.
The GPTC Guide characterizes a grade 3 leak as ``a leak that is
non-hazardous at the time of detection and can reasonably be expected
to remain non-hazardous.'' The term ``non-hazardous'' is not itself
defined, but comparison to the grade 1 and grade 2 descriptions
indicates that the grade 3 classification is intended to be a catch-all
classification for all leaks that do not constitute either grade 1 or
grade 2 leaks, including those leaks that are hazardous to the
environment without representing a potential risk to public safety.
Based on the criteria in Table 3c, grade 3 leaks would include leaks
where there is a reading of less than 80% LEL in a small gas-associated
substructure, any reading under a street in areas without wall-to-wall
paving where it is unlikely that gas could migrate to the outside wall
of a building, and any reading of less than 20% LEL in a confined
space. The GPTC Guide suggests that operators should reevaluate grade 3
leaks during their next scheduled survey, or within 15 months of the
date the leak is reported, whichever comes first, and continue
reevaluations until the leak is either regraded or is no longer
leaking. The GPTC Guide does not require the repair of grade 3 leaks.
In comments submitted following the 2021 Public Meeting, AGA et al.
noted the limitations of the GPTC Guide leak grading system with
respect to environmental safety in light of the GPTC Guide's focus on
repair and remediation of leaks that are hazardous to public safety
only.
The GPTC Guide provides for re-grading of existing leaks based on
changes identified during subsequent evaluations. If an operator
discovers, during a reevaluation, that a grade 2 or 3 leak has become
worse following its initial detection and grading to the point where it
would now be classified at a higher grade, an operator must upgrade the
leak to its appropriate grade and take appropriate action in accordance
with the new grade. The GPTC Guide also permits operators to downgrade
leaks by making temporary repairs to make the leak less hazardous. For
example, an operator may vent a grade 1 leak by drilling multiple
barholes into the soil in the immediate vicinity of the leak or by
leaving vault boxes open to the atmosphere before grading the leak.
These techniques can ensure that a leak is not an immediate hazard to
persons or property and justify downgrading the leak to a grade 2 leak.
As described in section II.D.1, existing regulations require repair
of hazardous leaks. In practice, the term hazardous leak has
corresponded to a grade 1 leak under the three-grade leak
classification framework in the GPTC Guide; a grade 1 leak is the most
urgent classification under this framework. Section 5.5 of appendix G-
192-11 of the GPTC Guide characterizes a grade 1 leak as one that
``represents an existing or probable hazard to persons or property and
requires immediate repair or continuous action until the conditions are
no longer hazardous.'' However, PHMSA regulations do not currently
require the repair of leaks other than hazardous leaks that would be
classified as grade 2 or grade 3 based on the GPTC Guide. Regarding the
replacement or remediation of pipelines known to leak, appendix G-192-
18 of the GPTC Guide suggests operators consider replacement of cast
iron pipe based on the maintenance and leak history and operational and
environmental circumstances and provides guidance on factors and
situations to consider.
State Leak Detection, Repair, and Reporting Requirements
State regulatory requirements impose a patchwork of obligations on
pipeline operators with respect to leak detection and repair. Pertinent
requirements vary from one State to the next and even within a single
State based on the type (gathering, transmission, or distribution) of
pipeline in question or the gas being transported. Many of those State
requirements are (like PHMSA's current regulations) directed toward
addressing imminent public safety risks rather than the climate and
potential future safety risks posed by gas pipeline leaks. And,
according to NAPSR data, only a minority of the States have leak
detection and repair regulations that exceed the current minimum
Federal regulations for any type of gas pipeline.\181\
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\181\ Zanter, Mary. ``Presentation of NAPSR at 2021 Public
Meeting'' (May 5, 2021), https://primis.phmsa.dot.gov/meetings/FilGet.mtg?fil=1150.
---------------------------------------------------------------------------
A handful of States require more frequent leakage surveys than
required by part 192. Many of those survey requirements apply to only
certain types of pipelines, with more demanding requirements for
distribution systems than for other types of gas pipelines (e.g.,
gathering, intrastate transmission lines). And those requirements
typically are directed toward addressing public safety rather than
environmental harms, targeting areas where gas is likely to accumulate,
where there is a high safety hazard in the case of a gas explosion, or
pipelines that are higher risk due to their pressure or material. For
example, the California Public Utility Commission requires annual
leakage surveys ``in the vicinity of schools, hospitals and churches,''
in addition to the requirements for business districts in Sec.
192.723, and requires that gas transmission pipelines be surveyed using
leak detection equipment at least twice each year. Maryland requires
annual leakage surveys for service pipelines serving places of public
assembly. South Carolina requires leakage surveys for cathodically
unprotected distribution pipelines at least once every 12 months,
rather than 3 years as specified in Sec. 192.723. Certain States also
require operators to conduct more frequent surveys based on the
location of the pipeline; for example, if the pipeline delivers gas to
high-occupancy buildings or buildings of public assembly such as
theaters, hospitals, or schools, or if the pipeline is near bridges or
other transportation infrastructure. Other States provide a definition
of the term ``business
[[Page 31919]]
district'' subject to more frequent leakage surveys in Sec. 192.723
but not defined in part 192. While a small minority of States do have
increased surveying of cast iron pipes under certain conditions, few
States require operators to replace or remediate these or other types
of leak-prone pipe materials.
A minority of States have more specific requirements for the use of
leak detection equipment than contemplated by current PHMSA
regulations. NAPSR's Compendium identified three States with leak
detection equipment requirements that are more demanding than PHMSA's
requirements. Those States' requirements seem largely focused on
methane leaks from natural gas pipelines rather than leaks from
pipeline facilities transporting other gases. A handful of states
specify allowable leak detection equipment, generally requiring the use
of an FID or equivalent device. For example, Maryland regulations
require the use of flame ionization, combustible gas indicator in a
barhole, optical methane detector, or other method approved by the
Maryland Public Service Commission. New Jersey adopted an energy-
related master plan in their overall State-wide climate goals that
specifically directs the State utility commission to establish a
standard for the use of advanced leak detection technologies when
performing leakage surveys. NAPSR data indicates, however, that a
majority of States do not have any more demanding requirements than
PHMSA for the leak detection equipment used by operators. NAPSR's
Compendium similarly indicates that few States have right-of-way patrol
requirements for gas gathering or transmission pipelines more demanding
than those in current PHMSA regulations.
Most States, moreover, do not have reporting requirements for leaks
that are more demanding than those in current PHMSA regulations.
NAPSR's Compendium indicates only a handful of States require periodic
submission of leak status reports for any type of pipeline to State
regulators, with a few States having recently adopted more
comprehensive leak reporting requirements to achieve methane emission
reduction goals. For example, California has established a
comprehensive reporting system for gas utilities to submit annual
methane leak abatement reports and compile emission reduction plans.
Apart from leak detection requirements, NAPSR's Compendium yields
that a majority of States have neither adopted the GPTC Guide's leak
grading and repair criteria, nor have regulatory requirements
supplementing the requirements for leak grading or leak repair in part
192. A few States (such as Texas, Kentucky, Massachusetts, and New
York) have adopted leak grading and repair standards similar to those
in the GPTC Guide. But many more States reported to NAPSR that they
automatically adopt PHMSA's pipeline safety regulations for leak
grading and repair into their regulations and do not otherwise
introduce more stringent requirements. Some of those States noted that
they assume some operators follow the guidance in the GPTC Guide on the
grading and repair of leaks described in section II.D.8. Few States
have specific requirements for replacement of gas pipelines known to
leak based on material, design, or past operating and maintenance
history; among those States, replacement initiatives generally focused
on gas distribution pipelines rather than gas gathering or transmission
pipelines.
Of that minority of States that have regulations exceeding the
current requirements in part 192 for grading and repairing leaks, most
indicated that they followed a grading system resembling the GPTC
grading system, where they classify leaks as grade 1, grade 2, or grade
3 based on relative safety hazards. However, these States may not
impose leak grading and repair requirements uniformly across each type
(gathering, transmission, and distribution) of pipeline. Mandatory
repair timelines also differed among those States--particularly with
respect to grades 2 and 3 leaks.
With respect to grade 2 leaks, some States do not have specific
requirements for monitoring and repair and defer to operator
procedures. Other States noted they require operators to recheck these
leaks on subsequent surveys, per an operator's procedures. Some States
have requirements for operators to reassess grade 2 leaks every 6
months, with a few States requiring additional (or monthly) surveys
until the leaks are cleared. There is also a wide variety of State
approaches to repair timelines for grade 2 leaks: the States largely
require the repair of grade 2 leaks anywhere from 12 months to 24
months after the date of discovery, with a handful of States requiring
more immediate repairs.
With respect to grade 3 leaks, monitoring requirements for grade 3
leaks also vary widely between those States with grade 3 leak grading
and repair requirements, with some States requiring operators to
monitor grade 3 leaks every 6 months, and other States requiring
operators to monitor grade 3 leaks every 15 months. The States that
have requirements for repairing grade 3 leaks follow one of two paths:
either the State requires that grade 3 leaks be repaired within a
prescriptive timeframe, such as 24, 30, or 36 months after discovery,
or the State requires operators to have only a defined maximum number
of outstanding grade 3 leaks. Some States only require operators to
repair grade 3 leaks if the leaks have a relatively high emission rate.
The methods for identifying high-emitting grade 3 leaks vary by State.
For example, Massachusetts defines an ``environmentally significant''
grade 3 leak as one with a ``leak extent'' (land area affected by gas
migration) of 2,000 square feet or greater, or with a highest barhole
reading of 50% or more gas in air and requires its repair within either
2 years or 12 months, depending on the extent of migration. Some States
noted that they required operators to perform additional leakage
surveys after repairs are completed.
Industry Methane Leak Detection and Repair Practices and Efforts
Pipeline operator leak detection and repair practices are similarly
insufficient to meet the risks to the environment and public safety
from leaks of methane and other gases from gas pipeline infrastructure.
Operators employ a spectrum of approaches and technology in connection
with leak detection and repair--most of which are focused on compliance
with pertinent Federal and State regulations that themselves
inadequately address the public safety and environmental risks arising
from all leaks on gas transmission, distribution, and part 192-
regulated gathering pipelines. Although recent voluntary industry
approaches pertaining to leak detection and repair are welcome, those
efforts generally exhibit shortcomings (including meager participation,
limited application to different pipeline facilities, absence of
meaningful leak reduction targets, or a lack of transparency, limited
application to natural gas pipelines), underscoring the need for timely
Federal regulatory intervention. Moreover, while progress has been made
on efforts to replace or remediate any pipeline known to leak based on
material (such as cast iron, unprotected steel, wrought iron, and
historic plastics with known issues), design, or past operating and
maintenance history, it remains an issue. For example, according to
PHMSA annual reports, 18,314 miles of cast or wrought iron distribution
mains and 6,518 service lines remained in operation at the end of 2021.
Individual operators' leak detection and repair programs have
historically
[[Page 31920]]
focused on ensuring compliance with pertinent Federal and State
requirements that (as explained above) generally lack meaningful
requirements for timely grading and repair of leaks other than
``hazardous leaks.'' For those leaks from gas transmission, regulated
gathering, and distribution facilities that are not considered
``hazardous'' under current PHMSA regulations, some operators may
incorporate the GPTC Guide leak identification, grading, and mitigation
criteria within their inspection and maintenance procedures, using the
``LEAKS'' mnemonic as an aide to their personnel tasked with managing
leak detection and remediation.\182\ However, not all operators
incorporate the GPTC Guide within their inspection and maintenance
procedures; similarly, operators who integrate the GPTC Guide in their
procedures include revision/amendment to those procedures, or may not
adopt those procedures across all types of gas pipelines on their
system.
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\182\ The ``LEAKS'' management system mnemonic consists of
Locating the leak, Evaluating its severity, Acting appropriately to
mitigate the leak, Keeping records, and Self-assessing to determine
if additional actions are necessary to keep the pipeline system
safe.
---------------------------------------------------------------------------
Individual operators employ a range of equipment and technologies,
with some operators employing advanced technologies such as infrared
technologies, FIDs, and laser gas detectors to satisfy pertinent
leakage survey requirements. For example, during the 2021 Public
Meeting, a representative from the Knoxville Utilities Board (KUB), a
gas distribution pipeline operator and member of the American Public
Gas Association (APGA), noted that it performs leakage surveys by using
handheld laser leak detectors while walking pipelines or travelling
rights-of-ways with a Segway. For its distribution mains, KUB stated
that it assesses those pipelines using a mobile method employing a
traditional laser detector mounted in a vehicle, driving at lower
speeds, and surveying major roads at night. During leakage surveys, if
KUB technicians find an indication of a leak, they pinpoint the leak's
specific location. If the leak can be fixed with a minor repair--
through an adjustment, a tightening, or lubrication--the technicians
will make the repair on-site. If the technicians find a grade 1 leak
during a survey, KUB stated the technicians stay on-site and provide
site safety until a repair crew can make the appropriate, immediate
repairs. KUB stated that they repair any discovered grade 2 leaks
within 90 days, and grade 3 leaks within 6 months, but they also noted
in their presentation during the 2021 Public Meeting that repair
schedules can vary from operator to operator. Similarly, Kinder Morgan
during the 2021 Public Meeting stated that it employed a variety of
methods and technologies (foot patrols; aerial surveys by fixed-wing
aircraft or helicopter; automobile-borne sensors when the right-of-way
is accessible) to perform right-of-way patrols on its transmission
lines. However, these practices are not universal; rather (as explained
above), the 2021 Public Meeting underscored that many operators are
only beginning to integrate advanced leak detection technologies
throughout their systems.
So far, voluntary industry standards have not resulted in operators
employing adequate leak detection and repair practices. The non-
mandatory Appendix M to ASME B31.8S, ``Gas Transmission and
Distribution Piping Systems'' contains leak grading and repair criteria
similar to the contents of the GPTC Guide.\183\ However, that
standard--like the GPTC Guide--specifies neither technology nor
performance requirements for operator leak detection programs, and it
contains no repair schedule for grade 3 leaks. In addition, PHMSA also
understands that not every gas pipeline operator incorporates ASME
B31.8-2007 into their inspection and maintenance procedures.
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\183\ ASME, B31.8-2007, Gas Transmission and Distribution Piping
Systems, 2007 Edition (2008) (ASME B31.8-2007). PHMSA regulations
incorporate by reference elements of ASME B31.8-2007 in connection
with yield strength testing procedure (Sec. 192.619(a)(1)(i)) or
the alternative MAOP requirements (Sec. 192.620)--but not non-
mandatory appendix M.
---------------------------------------------------------------------------
Following the May 2021 Public Meeting, AGA et al. highlighted a
handful of the voluntary industry initiatives to reduce methane
emissions--including leaks from gas gathering, transmission, and
distribution pipelines.\184\ However, publicly available information
regarding those efforts does not confirm that leaks on gas
transmission, distribution, and regulated gathering are detected and
repaired in a timely manner. Precisely which pipeline operators and
which pipeline facilities are captured by each initiative is generally
not clear, but participation is far from universal among operators and
pipeline facilities that would be subject to the amendments to part 192
contemplated in this NPRM. And even in those initiatives for which
there is publicly available, operator-specific information, the focus
is less on pipeline leak detection and repair than on other potential
sources of methane emissions (e.g., blowdowns, excavation damages). For
example, while the Methane Challenge Best Management Practice
Commitment Option documentation describes compressor station equipment
leaks, it does not address leak detection and repair on buried pipeline
facilities other than recommended replacement of cast iron and bare
steel distribution pipelines \185\ Indeed, a review of publicly
available information on the initiatives identified by AGA et al. does
not indicate discrete emissions reduction targets for different
operators or types of pipeline facilities. Only a minority of the
initiatives identified by industry trade groups publish any data on the
methane emissions reductions achieved--and that data does not show
which specific operators are achieving their performance targets.
Publicly available information does not demonstrate that these
voluntary initiatives have led to reductions in emissions of methane
and other gases.
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\184\ AGA et al. at Appendix A.
\185\ See EPA, ``Methane Challenge Program BMP Commitment Option
Technical Document'' at 10 and 24-28 (May 2022), https://www.epa.gov/system/files/documents/2022-05/MC_BMP_TechnicalDocument_2022-05.pdf (last accessed December 18,
2022).
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6. Damage Prevention
Reducing excavation damage to pipelines has historically been a
focus of PHMSA's efforts in controlling public safety risks from gas
pipelines--but is also an important component of mitigating harmful GHG
emissions. Excavation damage creates a safety hazard for the public,
the excavator, and the affected pipeline facility operator, and can
lead to significant emissions going unnoticed or ignored if not posing
an imminent public safety hazard. According to PHMSA data presented by
AGA representatives at the 2021 Public Meeting, excavation damage in
2020 alone resulted in the loss of 245,000 MCF of gas from gas
distribution pipelines--equivalent to the amount of emissions produced
by 34 million miles driven by a vehicle or 50 million pounds of coal
burned.\186\ PHMSA incident reports have identified incidents caused by
excavation damage that was not discovered for some time, or where no
excavation work was ever reported.
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\186\ Sames, ``Presentation of AGA at 2021 Public Meeting'' at
slide 7 (May 5, 2021), https://primis.phmsa.dot.gov/meetings/FilGet.mtg?fil=1139.
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Nevertheless, some State excavation damage prevention programs may
not adequately address these risks. PHMSA has taken steps in recent
years to establish and improve comprehensive implementation of State
programs
[[Page 31921]]
designed to prevent damage to underground pipeline facilities. First,
PHMSA published a final rule in 2015 establishing procedures at 49 CFR
part 198 for evaluating State excavation damage prevention law
enforcement programs and enforcing minimum Federal damage prevention
standards in States where damage prevention law enforcement is deemed
inadequate or does not exist.\187\ PHMSA audited State damage
prevention programs for adequacy under those new procedures in 2016,
determining that 27 States had inadequate damage prevention enforcement
programs. Second, PHMSA provides States with damage prevention grants
to establish and improve comprehensive State damage prevention
programs. Third, PHMSA's maintenance of the NPMS database gives
pipeline operators, emergency response personnel and State and Federal
regulatory authorities, as well as (to a lesser extent, given
restrictions on data access) members of the public, data on location
and other material characteristics of gas transmission pipelines,
thereby reinforcing Federal and State damage prevention initiatives.
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\187\ PHMSA, ``Pipeline Safety: Pipeline Damage Prevention
Programs--Final Rule,'' 80 FR 43835 (July 23, 2015).
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But even in States with robust damage prevention programs, limited
information on buried gas pipelines can hamstring efforts to reduce
excavation damage and marshal emergency response to any resulting
incidents. This is particularly true for gas gathering pipelines.
Despite recently expanded requirements that operators of certain gas
gathering pipelines maintain sufficient damage prevention programs
under Sec. 192.614, PHMSA regulations do not currently require
operators of gas gathering pipelines to submit geospatial location data
into NPMS. This regulatory gap means that State and Federal regulatory
authorities (and even some operators) may have limited understanding of
the location of those pipelines, thereby inhibiting damage prevention
efforts as well as emergency response in the event of an excavation
incident.
E. The Limits of PHMSA Regulation and State and Operator Initiatives in
Reducing Intentional Methane Releases From Gas Pipeline Facilities
In section 114 of the PIPES Act of 2020, Congress introduced
requirements for operators of gas pipeline facilities to update their
inspection and maintenance procedure to provide for the minimization of
all releases of natural gas from their facilities--including
intentional, vented emissions--in recognition of the significant
environmental harm from those emissions. As described in section II.C,
equipment venting, blowdowns, and other vented emissions of methane
account for a large portion of the total methane emissions from U.S.
natural gas pipeline facilities--particularly natural gas transmission
pipelines. However, despite the significant environmental impact of
those emissions, PHMSA and State pipeline safety regulations have
largely avoided explicit restrictions on vented emissions. Moreover,
the absence of robust reporting requirements for those emissions under
part 191 inhibits PHMSA's ability to identify systemic issues.
Part 191 does not require any reporting on intentional releases of
methane or other gases (regardless of the total volume of gas emitted)
unless a release causes death, hospitalization, or significant property
damage. Similarly, part 192 and part 193 regulations do not require an
operator to minimize intentional releases unless they could give rise
to a public safety hazard.\188\ These regulatory gaps could permit
situations such as pressure relief devices being configured to
establish overly-conservative actuation setpoints--resulting in
avoidable emissions being released because those pressure relief
devices vent methane more frequently than necessary to maintain system
pressure within safe operating bands. Incident reports and National
Response Center (NRC) reports submitted to PHMSA for pressure relief
device malfunctions provide a sense of the magnitude of potential
emissions from improperly configured pressure relief devices: each
incident can result in the release of millions of cubic feet of
methane.
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\188\ See, e.g., Sec. Sec. 192.169 and 192.617(a)(2) (requiring
discharge piping for compressor station pressure relief devices and
emergency shutdown systems vent to locations that would avoid public
safety hazards) and 192.199(e) (requiring pressure relief and
limiting devices have discharge stacks, vents, or outlet ports be
located where gas can be discharged into the atmosphere without
undue hazard).
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Similar to voluntary leak detection and repair efforts, voluntary
industry efforts to reduce emissions from blowdowns fall short in
minimizing vented emissions. PHMSA is unaware of any industry-level,
voluntary initiatives among operators of part 193 facilities to reduce
vented emissions. And voluntary operator efforts among gas pipelines
either parallel or directly invoke best practices recommended by the
EPA's voluntary methane programs such as the Methane Challenge Program
and the Natural Gas STAR programs.\189\ For the ``Best Management
Practices'' option in the Methane Challenge Program, an operator can
commit to cutting pipeline blowdown emissions by at least 50 percent by
any of the following methods: \190\
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\189\ EPA, ``Voluntary Methane Programs for the Oil and Natural
Gas Industry,'' https://www.epa.gov/natural-gas-star-program (last
accessed June 20, 2022). In 2018, members of the Interstate Natural
Gas Association of America (INGAA) agreed to adopt voluntary
commitments to minimize methane emissions from member transportation
and storage assets, including a commitment to reduce emissions from
blowdowns when repairs need to be made. The aforementioned EPA
programs and two industry initiatives, the ONE Future Coalition and
the Environmental Partnership, are featured prominently in the INGAA
commitments. The full list of commitments is available on INGAA's
website (https://www.ingaa.org/
File.aspx?id=38523&v=6553c6c8#:~:text=As%20part%20of%20our%20ongoing,
build%20a%20cleaner%20energy%20future) (last accessed July 20,
2022).
\190\ EPA, ``Natural Gas STAR Methane Challenge Program BMP
Commitment Option Technical Document'' at 21 (May 2022).
---------------------------------------------------------------------------
Routing gas to a compressor or capture system for
beneficial use;
Routing gas to a flare;
Routing gas to a low-pressure system by taking advantage
of existing piping connections between high- and low-pressure systems,
temporarily resetting or bypassing pressure regulators to reduce system
pressure prior to maintenance, or installing temporary connections
between high and low-pressure systems; or
Utilizing hot tapping, a procedure that makes a new
pipeline connection while the pipeline remains in service, flowing
natural gas under pressure, to avoid the need to blowdown gas.
The voluntary industry emissions reduction efforts above cannot
boast universal participation, but they hint at the potential for
significant reductions in vented emissions if applied across all gas
pipeline facility operators. In 2019 alone, a mere 8 participants in
the EPA's Methane Challenge transmission pipeline blowdown mitigation
program, operating 29 gas transmission pipeline facilities, reduced
emissions by 1.9 million metric tons of CO2 equivalent
estimated by calculation or measurement in accordance with 40 CFR part
98, subpart W or, for non-subpart W facilities, an alternative
method.\191\
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\191\ EPA, ``Methane Challenge Program Accomplishments,''
https://www.epa.gov/natural-gas-star-program/methane-challenge-program-accomplishments (last accessed July 20, 2022).
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III. Federal Efforts To Address Climate Change by Reducing Methane
Emissions
The urgency of reducing methane emissions to stave off or avoid the
worst
[[Page 31922]]
effects of climate change, coupled with the inability of existing
Federal, State, and industry efforts to rise to that challenge, have
catalyzed responses by the Federal legislative and executive branches
to reduce unintentional and vented methane releases from gas pipeline
facilities. Those efforts, which are discussed below, inform the
regulatory amendments proposed in this NPRM.
A. The PIPES Act of 2020
The PIPES Act of 2020, which was signed into law with broad
bipartisan congressional and widespread industry and stakeholder
support on December 27, 2020, directed a fundamental shift in PHMSA's
regulation of gas pipeline facilities: environmental benefits would
join public safety as a principal object of PHMSA regulation.\192\
Concerned in particular with the contribution of methane releases from
natural gas pipelines to climate change,\193\ Congress included within
that legislation three sections that would be implemented by this NPRM:
sections 113, 114, and 118.
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\192\ See 49 U.S.C. 60102(b)(5).
\193\ See, e.g., 166 Cong. Rec. H7305 (Dec. 21, 2020)
(memorializing a statement by Rep. Pallone that ``[t]his is a big
win in the fight against climate change, along with the
reauthorization of the Pipeline Safety Act, which reduces methane
leaks.''); ``Press Release from Senate Commerce Committee Leaders
Commending Passage of Pipeline Safety Legislation'' (Dec. 22, 2020),
https://www.commerce.senate.gov/2020/12/committee-leaders-commend-passage-of-pipeline-safety-legislation (quoting Sen. Cantwell as
stating ``This legislation also ensures that the latest technology
will be used to detect and prevent costly methane leaks, which is
especially important because methane leaks are a significant hazard
and a major contributor to global warming.'').
---------------------------------------------------------------------------
Section 113 of the PIPES Act of 2020 states that the Secretary of
Transportation shall issue regulations that require operators of gas
transmission pipeline facilities, gas distribution pipeline facilities,
and certain regulated gas gathering pipelines in Class 2, Class 3, and
Class 4 locations to conduct leak detection and repair programs to meet
the need for gas pipeline safety and to protect the environment. Such
regulations must include minimum performance standards that reflect the
capabilities of commercially available advanced leak detection
technologies that are appropriate for the type of pipeline, the
location of the pipeline, the pipeline's material of construction, and
the product transported by the pipeline. The leak detection and repair
programs must be able to identify, locate, and categorize all leaks
that are hazardous to human safety or the environment or that have the
potential to become explosive or otherwise hazardous to human safety.
The regulations must require the use of advanced leak detection
technologies and practices through continuous monitoring on or along
the pipeline, through periodic surveys with handheld equipment,
equipment mounted on mobile platforms, or other commercially available
technology. The regulations also must identify any scenarios where
operators may use leak detection practices that depend on human senses,
and include a schedule for repairing or replacing each leaking pipe,
except for a pipe with a leak so small that it poses no potential
hazard. Congress also expressly precluded the Secretary from reducing
the frequency of surveys or extending the duration of leak repair or
remediation timelines as required by PHMSA regulations on the date of
enactment of the PIPES Act of 2020. Section 113 does not alter the
Secretary's statutory authority to regulate gathering lines. Congress
directed PHMSA to issue regulations implementing section 113 no later
than December 27, 2021.
Section 114 of the PIPES Act of 2020 adjusts the requirements for
inspection and maintenance procedures. This self-executing provision of
the statute requires that pipeline operators ensure their inspection
and maintenance plans contribute to eliminating hazardous leaks of
gases (not limited to natural gas) and minimizing releases of natural
gas specifically from pipeline facilities; protect the environment; and
address the replacement or remediation of pipelines (including cast-
iron, bare-steel, unprotected steel, wrought-iron, and certain plastic
pipelines) that are known to leak based on material, design, or past
operating and maintenance history. Operators had one year from the date
of the enactment of the PIPES Act of 2020 (i.e., no later than December
27, 2021) to update their inspection and maintenance plans to address
these self-executing requirements.\194\
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\194\ Section 114 also requires the Government Accountability
Office to conduct a study to evaluate the procedures used by PHMSA
and States when evaluating operators' inspection and maintenance
plans, and subsequently issue a report regarding the findings of the
study and recommendations for how to further minimize releases of
natural gas from pipeline facilities without compromising pipeline
safety. Additionally, the Secretary is to, not later than 18 months
after the enactment of the PIPES Act of 2020, submit to Congress a
report discussing the best available technologies or practices to
prevent or minimize the release of natural gas, without compromising
pipeline safety, when making planned repairs, replacements, or
maintenance to a pipeline facility; or when intentionally venting or
releasing natural gas, including when blowing down pipelines. The
report must also discuss whether pipeline facilities can be
designed, without compromising pipeline safety, to mitigate the need
to intentionally vent natural gas.
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Lastly, section 118 of the PIPES Act of 2020 amended the criteria
set forth at 49 U.S.C. 60102(b)(5) governing issuance of any new
rulemakings to elevate consideration of environmental benefits on par
with other (e.g., public safety) anticipated benefits. That statutory
amendment reinforced the environmental purpose of section 113 of the
PIPES Act of 2020, as well as historical provisions (e.g., 49 U.S.C.
60102(b)(1)(B)(ii) and (b)(2)(A)(3)) within the Federal Pipeline Safety
Laws that authorize PHMSA to issue regulations acknowledging the
environmental protection benefits from regulation of gas pipeline
facilities.
Gas pipeline operators and related trade associations applauded the
passage through the Senate and later enactment of the PIPES Act of 2020
as part of the Consolidated Appropriations Act of 2021 (Pub. L. 116-
260). For example, API released a statement in support of the Senate's
passage of the legislation (S.2999) that became the PIPES Act of 2020,
stating that the ``PIPES Act takes important steps to make pipelines
safer for surrounding communities and the environment.'' \195\
Following enactment, INGAA described the PIPES Act of 2020 as a
``historic piece of legislation'' that ``enhances pipeline safety,
embraces the latest technologies, and aids in the further reduction of
methane emissions.'' \196\ At the 2021 Public Meeting, AGA et al.
expressed support for the PIPES Act of 2020 and initiatives that
protect the public and the environment, noting that their members have
committed to a range of initiatives to reduce methane emissions to
achieve goals for addressing climate change.\197\
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\195\ API, Press Release, ``API Statement of Senate Passage of
PIPES Act (Aug. 6, 2020), https://www.api.org/news-policy-and-issues/news/2020/08/06/api-statement-on-senate-passage-of-pipes-act.
\196\ INGAA, Press Release, ``INGAA Hails Passage of Historic
Pipeline Safety Reauthorization Bill in 2021 Omnibus Package'' (Dec.
21, 2020), https://www.ingaa.org/News/PressReleases/38353.aspx
(quoting President and CEO of INGAA, Amy Andryszak, praising
Congress's direction to PHMSA to update its regulations ``to reflect
the latest technologies and practices [to] . . . both enhance safety
and benefit the environment'').
\197\ Sames, Cristina. Pipeline Leak Detection, Leak Repair, and
Methane Emissions. AGA. May 5, 2021. Briefing materials, recordings,
and transcripts of the 2021 Public Meeting are available on the web
page for the meeting at https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=152.
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B. Administration Efforts Confronting the Climate Crisis
The U.S. Federal Government is taking aggressive action in response
to climate change. During his first week in
[[Page 31923]]
office, President Biden established the National Climate Task Force,
assembling leaders from across Federal agencies--including the
Secretary of Transportation--to enable a whole-of-government approach
to combatting the climate crisis.\198\ Essential in those efforts are a
spectrum of regulatory actions being undertaken across the U.S. Federal
Government to reduce methane emissions described in the U.S. Methane
Emissions Reduction Action Plan published in November 2021.\199\
Parallel proposals by EPA and PHMSA to reduce methane emissions from
natural gas infrastructure occupy a critical role in the
Administration's whole-of-government strategy for tackling the climate
crisis.
---------------------------------------------------------------------------
\198\ White House, ``Fact Sheet: President Biden Takes Executive
Actions to Tackle the Climate Crisis at Home and Abroad, Create
Jobs, and Restore Scientific Integrity Across Federal Government''
(Jan. 27, 2021), https://www.whitehouse.gov/briefing-room/statements-releases/2021/01/27/fact-sheet-president-biden-takes-executive-actions-to-tackle-the-climate-crisis-at-home-and-abroad-create-jobs-and-restore-scientific-integrity-across-federal-government/.
\199\ White House Office of Domestic Climate Policy, U.S.
Methane Emissions Reduction Action Plan (Nov. 2021), https://www.whitehouse.gov/wp-content/uploads/2021/11/US-Methane-Emissions-Reduction-Action-Plan-1.pdf; White House Office of Domestic Climate
Policy, Delivering on the U.S. Methane Emissions Reduction Action
Plan (Nov. 2022), https://www.whitehouse.gov/wp-content/uploads/2022/11/US-Methane-Emissions-Reduction-Action-Plan-Update.pdf.
---------------------------------------------------------------------------
1. Pertinent Executive Orders
Several recent E.O.s direct PHMSA and other Federal agencies to
undertake efforts to achieve substantial reductions of methane
emissions from the oil and gas sector as soon as possible.
Executive Order 13990
On January 20, 2021, the President signed E.O. 13990, titled
``Protecting Public Health and the Environment and Restoring Science to
Tackle the Climate Crisis'' \200\ announced the Administration's re-
commitment to environmental justice, science-based decision-making,
protecting public health and the environment, and ensuring Federal
agency actions account for the benefits of reducing climate pollution.
Toward that end, E.O. 13990 directed all executive departments and
agencies to immediately review and, as appropriate and consistent with
applicable law, take action to address the promulgation of Federal
regulations and other actions during previous years that conflict with
these important national objectives, and to immediately commence work
to confront the climate crisis.
---------------------------------------------------------------------------
\200\ 86 FR 7037 (Jan 25, 2021).
---------------------------------------------------------------------------
Executive Order 14008
On January 27, 2021, the President signed E.O. 14008, titled
``Tackling the Climate Crisis at Home and Abroad.'' \201\ E.O. 14008
puts ``the climate crisis at the center of U.S. foreign and domestic
policy,'' with a focus on a multilateral approach to putting the world
on a sustainable climate pathway and building resilience, both at home
and abroad, against the impacts of climate change. Abroad, E.O. 14008
expresses the Administration's intent for the United States to exercise
its leadership to meet the climate challenge by recommitting to the
Paris Agreement and engaging in international climate summits and
forums. Domestically, E.O. 14008 outlines a plan to focus on an all-in
approach that considers environmental justice for all communities
(especially those that have been underserved in the past), creates
clean energy jobs, and builds modern and sustainable infrastructure.
---------------------------------------------------------------------------
\201\ 86 FR 7619 (Feb 1, 2021).
---------------------------------------------------------------------------
2. Renewal of U.S. Commitments to International Efforts To Address
Climate Change
Consistent with the instruction in E.O. 13990, the President
returned the United States into the Paris Agreement on January 20,
2021.\202\ The Paris Agreement is an agreement within the United
Nations (UN) Framework Convention on Climate Change (UNFCCC) addressing
climate change mitigation, adaptation, and finance, that was drafted
throughout 2015 and was signed in 2016. The Paris Agreement was forged
to help the world avoid catastrophic planetary warming and to build
resilience around the world to the impacts from climate change that are
occurring, with a long-term goal of keeping the rise in global average
temperature to below 3.6 degrees Fahrenheit by reducing emissions of
GHGs. To achieve these goals, article 4 of the Paris Agreement requires
each party to prepare and maintain a ``nationally determined
contribution'' of emissions reduction or mitigation targets once every
5 years. As of October 2022, 194 members of the UNFCCC are parties to
the agreement; the United States had withdrawn from the agreement in
2020.
---------------------------------------------------------------------------
\202\ https://unfccc.int/process-and-meetings/the-paris-agreement/the-paris-agreement. https://unfccc.int/process-and-meetings/the-paris-agreement/the-paris-agreement.
---------------------------------------------------------------------------
Pursuant to section 102(e) of E.O. 14008, the United States also
submitted a new Nationally Determined Contribution (NDC), on April 4,
2021, after rejoining the Paris Agreement.\203\ In the NDC, the
Administration announced an ambitious ``economy-wide target of reducing
net greenhouse gas emissions by 50-52 percent below 2005 levels in
2030.'' The NDC includes a specific commitment to address methane
emissions by, among other efforts, ``plugging leaks from wells and
mains and across the natural gas distribution infrastructure.'' \204\
The NDC notes that the United States aims to achieve these targets with
a whole-of-government approach at the Federal level and ambitious
innovation from State, local, and tribal governments, and private
investment.
---------------------------------------------------------------------------
\203\ UNFCCC, Nationally Determined Contribution Registry
(Interim), ``The United States of America Nationally Determined
Contribution'' (April 4, 2021).
\204\ UNFCCC, Nationally Determined Contribution Registry
(Interim), ``The United States of America Nationally Determined
Contribution'' at 5 (April 4, 2021).
---------------------------------------------------------------------------
The United States further reinforced its commitment to reducing
methane emissions by joining the European Union and several other
countries in committing to the Global Methane Pledge ahead of the 26th
global climate summit (the 26th Conference of the Parties, or
COP26).\205\ In its joint statement with the European Union, the Biden-
Harris Administration committed to direct the U.S. EPA and PHMSA to
``reduce methane leakage from pipelines and related facilities,'' \206\
and announced that more than 100 countries had joined the Global
Methane Pledge and a commitment to reduce the world's methane emissions
30% from 2020 levels by 2030.\207\ The Administration has since
released a U.S. Methane Emissions Reduction Action Plan detailing its
comprehensive whole-of-government plan to reduce methane emissions
through a combination of regulatory actions, financial incentives,
increased transparency and data disclosure, and public and private
[[Page 31924]]
partnerships.\208\ The Administration continues to lead nations around
the globe in methane reduction efforts, including by reconvening the
Major Economies Forum on Energy and Climate (MEF) on multiple
occasions. The President reconvened the MEF most recently on June 17,
2022, to encourage participant countries to accelerate emissions
reduction progress and provide a forum for participants to share the
results of their Global Methane Pledge efforts.\209\ The regulatory
requirements proposed in this NPRM would help align the United States
with ongoing efforts from international partners to enhance methane
mitigation requirements for gas pipeline infrastructure.\210\
---------------------------------------------------------------------------
\205\ ``Joint U.S.-EU Statement on the Global Methane Pledge''
(Oct. 11, 2021), https://www.state.gov/joint-u-s-eu-statement-on-the-global-methane-pledge/https://www.state.gov/joint-u-s-eu-statement-on-the-global-methane-pledge/.
\206\ White House, ``Joint U.S.-E.U. Press Release on the Global
Methane Pledge'' (Sept. 18, 2021), https://www.whitehouse.gov/briefing-room/statements-releases/2021/09/18/joint-us-eu-press-release-on-the-global-methane-pledge/.
\207\ ``Fact Sheet: President Biden Tackles Methane Emissions,
Spurs Innovations, and Supports Sustainable Agriculture to Build a
Clean Energy Economy and Create Jobs'' (Nov. 2, 2021), https://www.whitehouse.gov/briefing-room/statements-releases/2021/11/02/fact-sheet-president-biden-tackles-methane-emissions-spurs-innovations-and-supports-sustainable-agriculture-to-build-a-clean-energy-economy-and-create-jobs/.
\208\ White House Office of Domestic Climate Policy, U.S.
Methane Emissions Reduction Action Plan (Nov. 2021), https://www.whitehouse.gov/wp-content/uploads/2021/11/US-Methane-Emissions-Reduction-Action-Plan-1.pdf.
\209\ https://www.whitehouse.gov/briefing-room/statements-releases/2022/06/18/chairs-summary-of-the-major-economies-forum-on-energy-and-climate-held-by-president-joe-biden/. At this meeting of
the MEF, the United States and the EU announced a new Global Methane
Pledge Energy Pathway which ``aims to encourage all nations to
capture the maximum potential of cost-effective methane mitigation
in the oil and gas sector and to eliminate routine flaring as soon
as possible, and no later than 2030.''
\210\ For example, the European Union in December 2021 proposed
legislation that would require member states to impose requirements
that, at a minimum: (1) call for use of leak detection technologies
with a minimum sensitivity comparable to those proposed in this
rulemaking; (2) require leaks of at least 500 ppm to be immediately
repaired or replaced and leaks of less than 500 ppm to be repaired
or replaced within at least 3 months; and (3) create a default
prohibition on all venting of methane (subject to certain
exceptions). See European Parliament, ``EU Briefing--Fit for 55
Package: Reducing Methane Emissions in the Energy Sector'' (Mar.
2022), https://www.europarl.europa.eu/RegData/etudes/BRIE/2022/729313/EPRS_BRI(2022)729313_EN.pdf. Similarly, Canada in September
2022 issued a national Methane Strategy outlining policy options for
reducing methane emissions from natural gas pipeline infrastructure.
See Envt. & Climate Change Canada, Faster and Further: Canada's
Methane Strategy (Sept. 2022), https://publications.gc.ca/collections/collection_2022/eccc/En4-491-2022-eng.pdf.
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3. EPA's Proposed New Source Performance Standards and Emissions
Guidelines for the Oil and Natural Gas Industry
On November 15, 2021, the EPA proposed new source performance
standards and emission guidelines for crude oil and natural gas
facilities.\211\ This action was in response to the January 20, 2021,
Executive Order titled ``Protecting Public Health and the Environment
and Restoring Science to Tackle the Climate Crisis.'' The 2021 action
proposed to update VOC and methane \212\ standards on the books for new
sources (located at 40 CFR part 60, subparts OOOO and OOOOa),\213\ add
new standards for new sources (which would be located at 40 CFR part
60, subpart OOOOb), and establish the first nationwide Emission
Guidelines for states to regulate methane emissions from existing
sources (which would be located at 40 CFR part 60, subpart OOOOc).\214\
On December 6, 2022, in a supplemental proposal, EPA proposed further
updates to its November 2021 proposal.\215\ The proposed standards are
developed based on the EPA's determination of the ``best system of
emissions reduction'' (BSER) under section 111 of the Clean Air Act.
The EPA's proposed emission standards, including emissions monitoring,
repair, and maintenance requirements, would apply to numerous types of
facilities (including pneumatic controllers and pumps, storage vessels,
and sweetening units amongst others) across a defined source
category.\216\ Among the gas pipeline facilities within the scope of
EPA's 40 CFR part 60 regulatory scheme are compressor stations on gas
transmission pipelines and boosting stations on gas gathering
pipelines.
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\211\ EPA, ``Standards of Performance for New, Reconstructed,
and Modified Sources and Emissions Guidelines for Existing Sources:
Oil and Natural Gas Sector Climate Review,'' 86 FR 63110 (Nov. 15,
2021).
\212\ EPA regulates greenhouse gases expressed in the form of
limitations on methane.
\213\ 40 CFR part 60, subpart OOOO regulates VOC only. 40 CFR
part 60, subpart OOOOa regulates both VOC and methane.
\214\ The proposed Emission Guidelines would address methane
only.
\215\ EPA, ``Standards of Performance for New, Reconstructed,
and Modified Sources and Emissions Guidelines for Existing Sources:
Oil and Natural Gas Sector Climate Review,'' 87 FR 74702 (Dec. 6,
2022) (EPA SNPRM).
\216\ The EPA defines the Crude Oil and Natural Gas source
category to mean (1) crude oil production, which includes the well
and extends to the point of custody transfer to the crude oil
transmission pipeline or any other forms of transportation; and (2)
natural gas production, processing, transmission, and storage, which
include the well and extend to, but do not include, the local
distribution company custody transfer station. For purposes of EPA's
proposed rulemaking, for crude oil, the EPA's focus is on operations
from the well to the point of custody transfer at a petroleum
refinery, while for natural gas, the focus is on all operations from
the well to the local distribution company custody transfer station
commonly referred to as the ``city-gate''.
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C. PHMSA Implementation of the PIPES Act of 2020
PHMSA's efforts to implement requirements from the PIPES Act of
2020 efforts dovetail with policy goals of the Biden-Harris
Administration described above. This proposed rulemaking in particular
is a key part of PHMSA's efforts to address these policy priorities and
is referenced in the White House ``U.S. Methane Emissions Reduction
Action Plan.'' \217\
---------------------------------------------------------------------------
\217\ White House Office of Domestic Climate Policy, U.S.
Methane Emissions Reduction Action Plan (Nov. 2021).
---------------------------------------------------------------------------
1. PHMSA's May 2021 Public Meeting
PHMSA held a public meeting on May 5-6, 2021, (2021 Public Meeting)
to provide stakeholder groups and members of the public an opportunity
to share perspectives on improving gas pipeline methane leak detection
and repair programs consistent with sections 113 and 114 of the PIPES
Act of 2020. The agenda for the meeting included examining the sources
of methane emissions from gas pipeline systems, the current regulatory
requirements for managing fugitive and vented emissions, current leak
detection and repair practices of the industry, and the use of advanced
technologies and practices to reduce methane emissions from gas
pipeline systems.
Stakeholders were invited to submit written comments in connection
with the 2021 Public Meeting. PHMSA received 7 comments from individual
pipeline operators, leak detection technology service providers, public
safety groups, and industry trade organizations, as summarized below.
The meeting itself included presentations and panel discussions from
representatives from PHMSA, EPA, NAPSR, EDF, PST, the United
Association of Plumbers and Pipefitters, GPTC, AGA, American Public Gas
Association, INGAA, GPA, Pipeline Regulatory Consultants, Gas
Technology Institute, the Methane Emissions Technology Evaluation
Center (METEC) at Colorado State University, QuakeWrap Inc., Bridger
Photonics, Safetylics, ProFlex Technologies, ABB, the Federal Energy
Regulatory Commission, and the National Association of Regulatory
Utility Commissioners. Presentations, recordings, and transcripts from
the meeting are available on PHMSA's public meeting web page.\218\
Certain comments made before, during, and after the meeting have been
summarized and discussed throughout this NPRM.
---------------------------------------------------------------------------
\218\ https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=152.
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2. June 2021 Advisory Bulletin
PHMSA published an advisory bulletin on June 10, 2021, calling
operators' attention to the self-executing requirements of section 114
of the PIPES Act of 2020.\219\ The bulletin advised
[[Page 31925]]
operators of pipeline facilities to update their inspection and
maintenance plans to address the elimination of hazardous leaks and
minimize gas releases from their pipeline facilities, including
intentional venting during normal operations. The bulletin also noted
that, per the statutory mandate, operators must revise their plans to
address the replacement or remediation of pipeline facilities that are
known to leak based on their material, design, or past operating and
maintenance history. The advisory bulletin noted that the PIPES Act of
2020 requires pipeline facility operators to complete these updates by
December 27, 2021.
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\219\ PHMSA, ``Pipeline Safety: Statutory Mandate to Update
Inspection and Maintenance Plans to Address Eliminating Hazardous
Leaks and Minimizing Releases of Natural Gas from Pipeline
Facilities,'' 86 FR 31002 (June 10, 2021) (ADB-2021-01).
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3. February 2022 PHMSA Webinar Addressing Inspection of Operators'
Plans To Eliminate Hazardous Leaks, Minimize Releases of Methane, and
Remediate or Replace Leak-Prone Pipe
On February 17, 2022, PHMSA held an informational public webinar
reviewing the requirements for pipeline operator inspection and
maintenance plans introduced by section 114 of the PIPES Act of
2020.\220\ This webinar was informational, with attendees having the
opportunity to submit written comments to the public meeting docket.
More than 1,500 individuals registered for the public webinar,
including representatives from the gas gathering, transmission, and
distribution sectors. During the webinar, PHMSA discussed key elements
of the new section 114 requirements and reviewed the applicable
timelines for the actions required under section 114. PHMSA also
discussed its planned approach to inspection of operators' programs and
procedures to reduce methane emissions and replace or remediate leak-
prone pipes.
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\220\ PHMSA's presentation during this webinar and a recording
of the webinar meeting are available on PHMSA's public meeting web
page at https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=159.
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IV. Summary of Proposals
A. Leakage Survey and Patrol Frequencies and Methodologies
Existing Federal regulations in subpart M of part 192 are focused
primarily on avoiding risks to public safety posed by of instantaneous,
large-volume releases or accumulated gas from gas pipelines, with less
attention given to environmental harms from methane leaks to the
atmosphere and releases of other flammable, toxic or corrosive gases.
Part 192 imposes leakage survey and patrol periodicities based on the
magnitude and probability of those public safety risks (via the proxies
of class location, business districts, and potential impact radius),
with operators required to conduct leakage surveys only once per
calendar year but with an interval between surveys not to exceed 15
months for most gas transmission pipelines, offshore gathering,
distribution pipelines inside of business districts, and some onshore
part-192 regulated gathering pipelines; distribution pipelines outside
of business districts are obliged to conduct surveys only once every
five years. Sections 192.706 and 192.723 outline requirements for
leakage surveys (including periodicity) on gas transmission and gas
distribution pipelines, respectively, and all offshore, Types A and B
gas gathering and certain Type C gathering pipelines must follow the
Sec. 192.706 leakage survey requirements for gas transmission lines.
Those existing prescribed periodicities are described in further detail
below.
Current regulations do not specify what technologies or equipment
must be used in the performance of leakage surveys, and most gas
gathering and transmission pipelines are exempt from odorization
requirements that could help identify leaks. Currently, leakage surveys
on all distribution lines and certain unodorized gas transmission and
gathering pipelines must be performed using ``leak detection
equipment,'' but this term is not currently defined in part 192. PHMSA
has historically declined to establish technology or performance
standards regarding leak detection equipment. Leakage surveys on
transmission pipelines in Class 1 or Class 2 locations or Class 3 and
Class 4 locations that are odorized can rely entirely on human senses
such as smell or sight. This NPRM proposes to set more specific
technical standards for leak detection equipment used for leakage
surveys, and these are described in detail in section IV.B of this
NPRM.
PHMSA regulations currently require only annual right-of-way
patrols on most gas transmission, offshore gathering, and Type A-
regulated onshore gathering lines. Patrols are visual surveys and do
not require the use of any equipment. Sections 192.705 and 192.721
define right-of-way patrolling requirements for gas transmission, (as
well as offshore and Type A gathering), and distribution pipelines,
respectively. While offshore and Type A gas gathering pipelines are
subject to the same requirements as transmission lines, Types B and C
gathering pipelines are not subject to any patrolling requirements.
Patrols are typically reliant on human senses (vision, sound, or scent)
and do not require the use of leak detection equipment (although
operators may incorporate leak detection equipment at their
discretion). An operator may combine a patrol with a leakage survey,
provided their procedures include both a visual survey of the right-of-
way and a leakage survey with leak detection equipment. Patrols can
detect unsafe conditions that may indicate a current or future leak or
incident. For example, visual right of way patrols can identify
construction activity that signifies a potential excavation damage
threat, earth and water movement that may indicate a natural force
damage threat, or population growth that may indicate change in class
location, change in HCA or Moderate Consequence Area status, and higher
potential consequences of an incident. Patrols can also detect certain
leaks by odor, by detecting dead vegetation, or by other indicia (e.g.,
bubbles from an offshore, submerged pipeline). However, those
approaches entail their own limitations; for example, reliance on smell
would not be effective unless the gas contains odorants and vegetation
surveys are only effective in certain soil and climate conditions (and
completely ineffective in areas with no or sparse vegetation such as
paved areas or deserts), and a noticeable impact on vegetation from a
leak may lag substantially behind the leak's emergence.
The limitations of PHMSA's existing leakage survey and patrol
regulations thus currently allow for extended periods of time during
which leaks can degrade into catastrophic integrity failures, allow gas
to build up and ignite, or emit a substantial amount of methane or
other (flammable, toxic or corrosive) gases to the environment. For gas
gathering lines conveying unprocessed natural gas, the risks to public
safety and the environment from infrequent (or non-existent) leak
survey requirements are particularly acute as any leaks releasing VOCs
and HAPs, such as benzene, and corrosive materials entrained with the
unprocessed natural gas can expedite degradation of pipeline integrity.
And leaks of toxic or corrosive gases from other gas pipeline
facilities can adversely affect environmental resources. The
environmental impacts of gas pipeline leaks and the estimated
environmental and public safety benefits of the requirements proposed
herein are discussed in further detail in section 5 of the Preliminary
RIA for this NPRM, available in the rulemaking docket. Further, the
widespread use of human senses in leakage surveys is a missed
opportunity to leverage existing
[[Page 31926]]
commercially available leak detection technology to protect against
these risks to public safety and the environment by ensuring that leaks
are identified and addressed in a timely manner. In addition to the
public safety and human health risks of undetected methane leaks, long
intervals between surveys also result in increased emissions of methane
or other flammable and toxic gases. For example, in a presentation on
the Fugitive Emissions Abatement Simulation Toolkit (FEAST) model at
the 2021 EPA Methane Detection Technology Workshop, modeling based on
controlled tests and field evaluations demonstrated that at a given
detection threshold, survey frequency is directly proportional to
fugitive emissions reductions.\221\ While the modeling shows decreasing
emissions abatement returns to increasing survey frequency, large drop-
offs begin to appear only after semiannual OGI surveys.
---------------------------------------------------------------------------
\221\ Ravikumar, Arvind Ph.D. ``FEAST-Based Evaluation of
Methane Leak Detection and Repair Programs Using New Technologies.''
EPA Methane Detection Technology Workshop (August 24, 2021). https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/epa-methane-detection-technology-workshop. Day 2 at 1:33:50.
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PHMSA therefore proposes to strengthen minimum leakage survey
frequencies for gas transmission and gathering pipelines located in
HCAs, aboveground offshore gas transmission and gathering pipelines,
distribution pipelines outside of business districts, and distribution
pipelines at a high risk of leakage. PHMSA also proposes to introduce
patrolling requirements for Type B and Type C gathering pipelines and
to increase the minimum patrolling frequency for all gas transmission,
offshore gathering, and Type A regulated onshore gas gathering
pipelines. Finally, while all operators may supplement instrumented
leakage surveys with visual and other sensory survey techniques, PHMSA
proposes to limit the exclusive use of human senses for leakage surveys
to submerged offshore gas transmission and submerged offshore gas
gathering pipelines and, subject to notification to and review by
PHMSA, onshore gas transmission and regulated onshore gas gathering
pipelines in Class 1 and Class 2 locations outside of HCAs. These
amendments would ensure timely detection of leaks. The proposed changes
to patrolling frequency would also increase the likelihood that
conditions that could result in leaks, potentially fatal incidents, or
damage that could result in shutdowns and maintenance-related releases
of methane to the atmosphere are detected.
These proposals (and all other proposed amendments to parts 191 and
192) apply generally to pipeline transportation of any ``gas,'' defined
in Sec. Sec. 191.3 and 192.3 as ``natural gas, flammable gas, or gas
which is toxic or corrosive.'' Although natural gas pipelines
constitute the vast majority of part 192-regulated gas pipeline mileage
today, the requirements for ``gas'' pipelines in parts 191 and 192
apply equally to pipelines transporting other gases, including over
1,500 miles of hydrogen gas pipelines in operation today.\222\ Unless
otherwise specified in the proposed amendments, the proposals in this
NPRM apply the same requirements to hydrogen gas pipelines (and other
gas pipelines) as to natural gas pipelines. PHMSA invites comment on
whether, within a final rule in this proceeding, there would be value
in adopting hydrogen gas pipeline-specific provisions (in lieu of or in
addition to the provisions proposed herein). Comments on this question
are especially helpful if they address the potential safety and
environmental benefits and potential costs of a particular approach,
including whether that approach would be technically feasible, cost-
effective, and practicable.
---------------------------------------------------------------------------
\222\ See PHMSA Interpretation Response Letter No. PI-92-030
(July 14, 1992) (noting PHMSA regulates hydrogen pipelines under
part 192); PHMSA, ``Presentation of Vincent Holohan for Workgroup#4:
Hydrogen Network Components at December 2021 Meeting'' at slide 11
(Dec. 1, 2021), https://primis.phmsa.dot.gov/meetings/FilGet.mtg?fil=1227.
---------------------------------------------------------------------------
PHMSA has not proposed in this NPRM to establish minimum leakage
survey frequencies or leak detection equipment requirements for UNGSFs.
This approach is consistent with current PHMSA regulations at Sec.
192.12, which do not require UNGSFs perform periodic leakage surveys
with leak detection equipment but rather oblige operators of UNGSFs to
perform an integrity assessment of each reservoir, cavern, and well as
often as necessary (but with a maximum interval between assessments
that does not exceed 7 years). Additionally, consensus industry
standards \223\ incorporated by reference in Sec. 192.12 include
recommendations and requirements for periodic UNGSF reservoir and
wellsite inspection and monitoring. However, PHMSA invites comment on
whether, within a final rule in this proceeding, there would be value
in prescribing leakage survey frequency and leak detection equipment
requirements for UNGSFs in Sec. 192.12. Comments on this question are
especially helpful if they address the potential safety and
environmental benefits and potential costs of a particular approach,
including whether that approach would be technically feasible, cost-
effective, and practicable.
---------------------------------------------------------------------------
\223\ API Recommended Practice 1170, Design and Operation of
Solution-Mined Salt Caverns Used for Natural Gas Storage--First
Edition (July 2015); API Recommended Practice 1171, Functional
Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs
and Aquifer Reservoirs--First Edition (Sept. 2015).
---------------------------------------------------------------------------
1. Distribution--Sec. 192.723
Section 192.723 outlines the current requirements for leakage
surveys on gas distribution systems. Leakage surveys on distribution
pipelines must be performed using leak detection equipment. Leakage
surveys in business districts must be performed at least once each
calendar year, with an interval between surveys not to exceed 15
months. On distribution pipelines outside of business districts that
are not cathodically protected and where electrical surveys for
corrosion are impractical (i.e., bare steel, unprotected steel, and
cast-iron systems), leakage surveys must be performed once every 3
calendar years, with an interval between surveys not to exceed 39
months. All other portions of a distribution system outside of business
district must currently be surveyed once every 5 calendar years at
intervals not exceeding 63 months. The term ``business district'' is
not defined. PHMSA invites comment on potential criteria for defining
the boundaries of a business district for potential inclusion within a
final rule in this proceeding. Comments on these potential criteria are
especially helpful if they address the potential safety and
environmental benefits and potential costs of a proposed or alternative
approach, including whether each proposal would be technically
feasible, cost-effective, and practicable.
As described in section III.C, fugitive emissions from leaks
represent the vast majority of total methane emissions from natural gas
distribution systems. However, the current Sec. 192.723 neither
articulates minimum performance standards for leak detection equipment
nor prescribes a particular technology to ensure that all leaks are
identified during leakage surveys on distribution pipelines. PHMSA
therefore proposes several regulatory amendments that would increase
the frequency and effectiveness of leakage surveys to identify and
repair leaks on gas distribution pipelines. First, PHMSA proposes that
leakage surveys be incorporated within operator ALDPs meeting the
minimum performance standards proposed in this NPRM and any detected
leaks be graded and repaired consistent with the grading
[[Page 31927]]
framework in this NPRM (each discussed further in section IV.B). These
proposals would better address the leading causes of methane emissions
from gas distribution systems by ensuring that leaks are detected and
repaired in a timely manner. Second, PHMSA proposes more frequent
leakage surveys to promote earlier detection and repair of leaks,
thereby improving the environment by reducing emissions from those
leaks, and improving the likelihood that leaks are detected before they
adversely impact public safety.
As described earlier, distribution leakage surveys are currently
required once every 1, 3, or 5 calendar years, depending on the
location and design of the pipeline. The 5-year maximum leakage survey
interval allows even leaks hazardous to people or property that must be
``repaired promptly'' under current Sec. 192.703 to remain undetected
for up to 5 years, often placing the burden on the general public to
detect and report potentially hazardous leaks via odor calls. In
addition to the potential hazard to public safety and human health, an
undetected leak will continue to emit methane to the environment until
it is detected and repaired. PHMSA therefore proposes to eliminate the
5-year survey frequency tier by moving leakage surveys outside of
business districts from at least once every 5 years into the next
frequency category: at least once every 3 calendar years, with an
interval between surveys not to exceed 39 months. Leakage surveys
inside of business districts would still be required annually. This
proposal would increase the frequency of leakage surveys on all
distribution pipelines outside of business districts, consistent with
the environmental and public safety risks of any leaks, while ensuring
that operators continue to prioritize frequency of surveys inside of
business districts where there is a higher risk to people and property.
Combined with the repair requirements proposed in the new Sec.
192.760, which proposes a maximum repair timeline of 24 months for
grade 3 leaks, this ensures that operators repair all leaks prior to
their next distribution leakage survey, preventing continued growth in
the backlog of unrepaired leaks. Some States have adopted similar
standards for leakage surveys outside of business districts, for
example the Commonwealth of Massachusetts requires leakage surveys
outside of ``principal business districts'' at least once every 24-
months.\224\
---------------------------------------------------------------------------
\224\ 220 Code of Massachusetts Regulations 101.06(21)(b).
---------------------------------------------------------------------------
Similarly, due to the increased environmental and safety risks of
distribution mains and service lines that are either without cathodic
protection, or known to leak based on material, design or past
operating and maintenance history, PHMSA proposes to require that
operators perform a leakage survey at least once each calendar year
with the interval between surveys not to exceed 15 months, mirroring
the high-priority survey frequency for unprotected pipelines and
pipelines inside of business districts. Currently, such pipelines mut
be assessed at the lowest frequencies: once every 3 calendar years for
cathodically unprotected distribution pipelines outside of business
districts; once every 5 calendar years for all other distribution
pipelines outside of business districts; or once every calendar year
for all distribution pipelines within business districts. As with
distribution pipelines outside of business districts, some States have
also adopted enhanced leak survey requirements for leak-prone pipe. For
example, the State of Kansas requires annual leakage surveys for
cathodically unprotected steel mains and ductile iron mains in class 2,
3, or 4 locations.\225\ Consistent with section 114 of the PIPES Act of
2020, materials known to leak include cast iron, unprotected steel,
wrought iron, and historic plastics with known issues. As described in
the emissions discussion in section II.C, certain materials are
responsible for a disproportionate amount of emissions from leaks, with
distribution mains composed of such materials being particularly
significant sources of emissions. PHMSA's proposal seeks to increase
the scrutiny of distribution systems outside of business districts at a
high risk of leakage by decreasing survey intervals and targeting
materials at a high risk of leakage. PHMSA's proposal also contemplates
that distribution pipeline operators would retain the option to
establish more frequent leakage surveys than proposed herein within
their operations and maintenance procedures or DIMP plans.
---------------------------------------------------------------------------
\225\ Kansas Administrative Regulations 82-11-4(b)(34)(b)(2)(i).
---------------------------------------------------------------------------
The following categories of distribution pipelines outside of
business districts would be subject to the proposed annual survey
requirement:
Cathodically unprotected pipelines on which electrical
surveys are impracticable, typically bare and unprotected distribution
lines;
Any distribution pipeline protected by a distributed anode
system where the cathodic protection survey under Sec. 195.463 showed
a deficient reading; and
Pipelines known to leak based on the material (including,
but not limited to, cast iron, unprotected steel, wrought iron, and
historic plastics with known issues), design, or past operating and
maintenance history of the pipeline.
PHMSA expects that, in determining whether a plastic pipe material
is a ``historic plastic with known issues'' making it at high risk of
leaks, operators should consider PHMSA and State regulatory actions and
industry technical resources identifying systemic integrity issues on
plastic pipe made from particular materials; or manufactured at
particular times or by particular companies, or fabricated and
installed pursuant to particular processes. By way of illustration,
PHMSA issues advisory bulletins cautioning operators regarding the
susceptibility of certain historic plastics to systemic integrity
issues. In 2007, in response to NTSB findings and data collection
performed by the Plastic Pipe Database Committee (PPDC), PHMSA issued
Advisory Bulletin ADB-07-01.\226\ That advisory bulletin called
operators' attention to cracking issues on pipe and components
manufactured by Century Utility Products, Inc.; low-ductile inner wall
``Aldyl A'' piping manufactured by Dupont before 1973; polyethylene gas
pipe made from PE 3306 resin; Delrin insert tap tees; and caps made of
Celcon (polyactal) on Plexco service tees. Similarly, State pipeline
safety regulatory actions, PHMSA pipeline failure investigation
reports, and NTSB findings can inform operator determinations whether
historic plastic pipe is at a high risk of leakage. Industry efforts
and resources are another resource for operators in determining whether
historic plastic pipe is known to leak. For example, the PPDC publishes
data submitted by program participants that incorporates information
regarding investigations of materials of concern or potential
concern.\227\ PHMSA expects that these and other authoritative
resources--coupled with an operator's own design expertise and
operational and maintenance history--would be adequate for a reasonably
prudent operator to determine whether the particular plastic pipe in
its distribution systems is at a high risk of leakage.
[[Page 31928]]
PHMSA invites comment on the value of either explicitly listing (either
within part 192 or within periodically-issued implementing guidance)
historic plastics known to leak, or deleting the scope qualification
``historic'' from the proposed regulatory text, for the purposes of the
proposed annual survey requirement or for replacement under section 114
of the PIPES Act of 2020. Comments on this question are especially
helpful if they address the potential safety and environmental benefits
and potential costs of a particular approach, including whether that
approach would be technically feasible, cost-effective, and
practicable.
---------------------------------------------------------------------------
\226\ ``Pipeline Safety: Updated Notification of Susceptibility
to Premature Brittle-Like Cracking of Older Plastic Pipe-Advisory
Bulletin ADB-07-01,'' 72 FR 51301 (September 6, 2007).
\227\ APGA, ``Plastic Pipe Database Collection Initiative,''
https://www.apga.org/programs/plasticpipedata (last accessed Dec.
20, 2022).
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PHMSA further proposes to require that operators perform a leakage
survey of a distribution pipeline segment after extreme weather events
or land movement occur that could damage that segment. This survey must
be completed within 72 hours of the cessation of the event, described
as the time when the location can be safely accessed by operator
personnel, or alternatively, within 72 hours of when the pipeline is
returned to service. Such a survey could qualify as a periodic survey,
and therefore reset the one- or three-year clock until the next
required periodic survey. Separately, PHMSA proposes to require
operators to investigate existing leaks when ground freezing and other
changes in environmental conditions (such as heavy rain or flooding-
inducing ground subsidence, erosion, or the installation of new
pavement) has occurred that could affect gas venting or migration to
nearby buildings. The required investigation would include conducting a
leakage survey for possible gas migration, but said survey would not
qualify as a periodic survey and would not reset the one- or three-year
clock until the next required periodic survey. Each of those changes in
environmental conditions can place new stresses on pipeline integrity
or can affect how and where gas vents from or migrates through the
ground. Therefore, each can cause new leaks or exacerbate or reveal
pre-existing leaks on distribution pipelines. These requirements are
designed to ensure prompt evaluation of whether environmental changes
have exacerbated existing leaks in a way that creates increased risk to
public safety and the environment. PHMSA invites comment on whether to
require assessments prior to extreme weather events in order for
operators to prepare for and prevent resulting leaks.\228\ Comments on
this question are especially helpful if they address the potential
safety and environmental benefits and potential costs of a particular
approach, including whether that approach would be technically
feasible, cost-effective, and practicable.
---------------------------------------------------------------------------
\228\ See, e.g., EPA's notice of proposed rulemaking titled
``Accidental Release Prevention Requirements: Risk Management
Programs Under the Clean Air Act; Safer Communities by Chemical
Accident Prevention,'' 87 FR 53556 (Aug. 31, 2022) (proposing to
require, under the Clean Air Act Risk Management Program, that
industrial chemical facilities evaluate ways to address natural
disasters and consider steps to prevent releases that may result,
even before such events occur).
---------------------------------------------------------------------------
The proposed amendments to gas distribution pipeline leakage survey
requirements are summarized in the table below.
Summary of Distribution Leakage Survey Amendments
------------------------------------------------------------------------
Facility Existing Proposed
------------------------------------------------------------------------
Outside of Business Districts... 5 years not to 3 years not to
exceed 63 months. exceed 39 months.
Pipelines known to leak 3 years not to Annually, not to
(cathodically unprotected pipe exceed 39 months. exceed 15 months.
in existing Sec. 192.723).
Inside Business Districts....... Annually, not to No change.
exceed 15 months.
---------------------------------------
Other Proposals................. --After environmental changes that can
affect gas migration.
--Following extreme weather events.
------------------------------------------------------------------------
Note: The most frequent survey would apply.
PHMSA expects its proposed amendments to leakage survey practices
would be reasonable, technically feasible, cost-effective, and
practicable for affected gas distribution operators. As explained
above, operators are already subject to prescriptive periodic leakage
surveys and patrols, and individual operators may have more demanding
requirements specified within their DIMP plans or as a function of
state-imposed requirements; affected operators also have the option to
sync their patrol and leakage survey requirements to minimize
compliance burdens (provided that the operator includes both a visual
survey of the right-of-way and a leakage survey with leak detection
equipment). PHMSA's proposed amendments would merely increase
prescribed frequencies within Federal regulation as a function of
factors (presence of cathodic protection; extreme weather events;
material composition, operating and maintenance history) probative of
leak susceptibility--and by extension, risks to public safety and the
environment. PHMSA further notes that, insofar as those factors
employed in the NPRM as bases for increased leakage survey frequency
are widely understood to be potential threats to the integrity of gas
distribution pipelines, they are among the phenomena that reasonably
prudent operators would evaluate, and potentially adopt mitigation
measures to address, in ordinary course when implementing current DIMP
requirements to protect public safety from releases of (natural,
flammable, toxic, or corrosive) pressurized gases from their pipelines
and minimize loss of commercially valuable commodities. Additionally,
operators would have flexibility (as appropriate for their needs and
their pipelines' operational characteristics and environment) in
choosing between commercially available, advanced leakage detection
equipment satisfying the performance standards proposed in this NPRM
for use in those leakage surveys. Viewed against those considerations
and the compliance costs estimated in the Preliminary RIA, PHMSA
expects its proposed amendments will be a cost-effective approach to
achieving the commercial, public safety and environmental benefits
discussed in this NPRM and its supporting documents. Lastly, the
proposed compliance timelines--based on an effective date of the
proposed requirements six months after the publication date of a final
rule in this proceeding--would provide operators ample time to
implement requisite changes in their leakage survey practices and
manage any related compliance costs.
In the Preliminary RIA, PHMSA considers an alternative where the 5-
[[Page 31929]]
year survey interval outside of business districts is maintained for
plastic pipe distribution pipelines without known leak issues. This
alternative is not being proposed because while recent-vintage plastic
pipe is understood to leak less than cast iron and bare steel, some
studies indicate that plastic piping systems may be leaking more than
previously thought.\229\ PHMSA invites comment concerning the value of
more or less frequent leakage surveys of plastic pipe systems, as well
as potential means to identify plastic pipe known to leak (e.g., via a
surveillance or sampling program) for inclusion within a final rule in
this rulemaking proceeding. Likewise, PHMSA seeks comment on the
alternative considered in the Preliminary RIA where distribution mains
would be required to be surveyed annually; typically, mains are likely
to be more accessible to pipeline operators than service lines crossing
private property and may therefore be more convenient to survey.
Comments on these questions are especially helpful to PHMSA when they
are supported by research or operational experience with leaks from
plastic pipe systems or distribution mains (as applicable), along with
the potential safety and environmental benefits and potential costs of
a particular approach (including whether that approach would be
technically feasible, cost-effective, and practicable).
---------------------------------------------------------------------------
\229\ Weller et al., 2020, for example.
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2. Transmission and Gathering--Sec. Sec. 192.9, 192.705, and 192.706
Section 192.706 currently requires gas transmission and Types A and
B gathering pipelines that are not odorized to be surveyed with leak
detection equipment at least twice each calendar year in Class 3
locations, and at least four times each calendar year in Class 4
locations. All other gas transmission, offshore gathering, Type A and
Type B gathering, and certain Type C gathering pipelines must be
surveyed once each calendar year. For these annual surveys, PHMSA does
not require leak detection equipment on gas transmission and offshore
gas gathering pipelines; however, Sec. 192.9 requires the use of leak
detection equipment for leakage surveys on Type B and Type C gas
gathering pipelines. Section 192.705 specifies frequencies for right-
of-way patrols along gas transmission, offshore gathering, and Type A
gathering pipelines; Types B and C gathering lines are not required to
conduct right-of-way patrols by Sec. 192.705.
Consistent with section 113 of the PIPES Act of 2020, PHMSA
proposes to require the use of leak detection equipment and practices
meeting the ALDP standard in proposed Sec. 192.763 (see section IV.B)
for leakage surveys on most onshore gas transmission and Types A, B and
C gathering pipelines. Leakage survey by human or animal senses would
be permitted for offshore gas transmission and offshore gathering
pipelines. Because leaks on submerged offshore pipelines are visibly
conspicuous due to bubbles or a sheen of gas condensate on the water's
surface, PHMSA is not proposing to require leak detection equipment be
used for leakage surveys of submerged offshore pipelines, including
platform risers up to the waterline. However, offshore platform piping
and riser piping above the waterline would be subject to the same
equipment and survey requirements as onshore gas transmission
pipelines. Leakage surveys for onshore pipelines would be permitted
without the use of leak detection equipment (i.e., with human senses or
animal senses) only for gas transmission and Types A, B, or C gathering
pipelines in non-HCA, Class 1 and Class 2 locations, and then only with
prior notification and review by PHMSA pursuant to Sec. 192.18. Visual
surveys and other survey methods depending exclusively on human or
animal senses would only be authorized if the operator can demonstrate
through tests and analyses included in the notification that the survey
method would be effective to meet the ALDP performance standard
proposed in Sec. 192.763(b) or (c). For example, a visual vegetation
survey would need to include procedures to ensure effective detection,
such as ensuing the location of a buried pipeline is determined before
a survey and performing vegetation surveys on foot rather than at a
distance from a vehicle or aircraft, and would not be approved in areas
where vegetation is absent. The notification must also include the
survey procedures and qualifications for surveyors. Leaks detected on
gas transmission, offshore gathering, and Types A, B, and C gathering
pipelines would need to be graded and repaired consistent with the
requirements proposed in this NPRM (see section IV.C). PHMSA welcomes
comments and data on the efficacy of the exclusive use of human senses
for leakage surveys, particularly on submerged offshore gas
transmission pipelines, submerged offshore gas gathering pipelines,
onshore gas transmission pipelines, and regulated onshore gas gathering
pipelines (for potential inclusion within a final rule in this
proceeding). Comments and data on this question are especially helpful
to PHMSA when they are supported by research or operational experience
with the exclusive use of human senses for leakage surveys, along with
the potential safety and environmental benefits and potential costs of
a particular approach (including whether that approach would be
technically feasible, cost-effective, and practicable).
As explained in section II.C above, leaks from natural gas
transmission line pipe are not as significant a source of methane
emissions compared with venting, blowdowns, and leaks from compressor
stations and other aboveground equipment. However, as explained above
in connection with leakage surveys on gas distribution lines, any leaks
of methane contribute to climate change and can entail public safety
risks--risks that are each more acute for gas transmission pipelines,
which generally operate at higher pressures and capacity than
distribution pipelines and are usually not odorized. Further, leaks
from gas pipeline facilities transporting other flammable, toxic, or
corrosive gases can entail significant public safety and environmental
consequences. PHMSA therefore proposes, to support more timely
detection and repair of leaks that pose a safety hazard, an increase in
the minimum leakage survey frequencies for each of the following,
calibrated based on a pipeline's proximity to occupied buildings or
HCAs: for gas transmission, offshore gathering, and Type A, B, and C
gathering pipelines located in HCAs from once each calendar year to
twice each calendar year (at intervals not exceeding 7\1/2\ months) if
within a Class 1, Class 2, or Class 3 location; and for gas
transmission and Types A or B gathering pipelines located within Class
4 locations within HCAs, from once each calendar year to four times
each calendar year (at intervals not exceeding 4\1/2\ months). For gas
transmission and Type A or B gas gathering pipelines that are
(consistent with the proposed revisions herein to Sec. 192.625) not
odorized, more frequent leak surveys would continue to be required to
account for the greater risks to public safety from their proximity to
occupied buildings: no less than twice each calendar year (at intervals
not exceeding 7\1/2\ months) for pipelines in Class 3 locations, and no
less than four times each calendar year (at intervals not exceeding
every 4\1/2\ months) in Class 4 locations. Leaks on gas transmission
pipelines, especially in Class 3 and Class 4 locations, would also be
subject to more stringent grading requirements
[[Page 31930]]
in the proposed leak grading and repair requirements described in
section IV.C.
As explained in section II.C above, fugitive methane emissions from
natural gas compressor stations on gas transmission and gas gathering
pipelines comprise a significant share of fugitive emissions from those
facilities. Other pipeline facilities with relatively complex design
and configuration--such as valve sites (including the valve components,
flanges, and tie-ins with line pipe), in-line instrument (ILI)
launchers and receivers, and tanks--have fugitive emissions profiles
better resembling compressor stations than line pipe. PHMSA therefore
proposes more frequent leakage surveys for each of those facilities on
gas transmission, offshore gathering, and Types A, B, and C gathering
pipelines. Such facilities in Class 1, Class 2, and Class 3 locations
would need to be surveyed twice each calendar year (at intervals not
exceeding 7\1/2\ months), compared with once per year under current
regulations. This is the same survey interval used for fugitive methane
emissions monitoring for compressor stations under the existing and
proposed EPA requirements (for example, 40 CFR 60.5397a(g)(2) for new
sources). More frequent leakage surveys for such facilities would
ensure operators detect and repair leaks earlier, reducing total
emissions and reducing the risk that a leak can degrade into a rupture
or other incident. Facilities in Class 4 locations would need to be
surveyed at least 4 times each calendar year (at intervals not
exceeding 4\1/2\ months) due to the potential for comparatively more
significant public safety risks in the event of a leak due to their
proximity to ignition sources and densely occupied buildings.
Summary of Transmission and Regulated Gathering Leakage Survey
Amendments
------------------------------------------------------------------------
Facility Existing Proposed
------------------------------------------------------------------------
Non-odorized Class 3............ Twice a year not No change.
to exceed 7\1/2\
months.
Non-odorized Class 4............ Four times a year No change.
not to exceed 4\1/
2\ months.
All other transmission.......... Once a year not to No change.
exceed 15 months.
HCA class 1, 2, or 3............ No specific Twice a year not
standard. to exceed 7\1/2\
months.
HCA class 4..................... No specific Four times a year
standard. not to exceed 4\1/
2\ months.
Valves, flanges, pipeline tie- No specific Same as proposed
ins with valves and flanges, standard. HCA frequencies.
ILI launcher and ILI receiver
facilities, and leak prone pipe.
Leak detection equipment........ Only required for Required except
non-odorized for non-HCA class
class 3 and class 1 and class 2
4. with a
notification.
Regulated gathering............. Existing Require proposed
transmission line leakage survey
requirements requirements for
apply to all regulated
offshore, Type A, gathering lines.
Type B, and
certain Type C
gathering lines.
------------------------------------------------------------------------
Note: The most frequent survey would apply.
PHMSA also proposes to increase the frequency of patrols on gas
transmission, offshore gathering, and Types A, B, and C gathering
pipelines by replacing the current, scaled approach within Sec.
192.705(b) of between one and four patrols per year based on class
location and the presence of a highway or railroad crossing with a
global, baseline requirement for those operators to perform 12 patrols
along the entirety of their pipelines each calendar year (at intervals
not exceeding 45 days). Patrols are primarily visual surveys of the
right of way and may be performed with or without leak detection
equipment. PHMSA understands those increased frequencies to be
appropriate because patrols are valuable not only for identifying
existing leaks and incidents, but also because they are a relatively
low-cost method for preemptive identification and mitigation of
potential threats to pipeline integrity. In conducting patrols,
operators should consider potential threats such as right of way
incursions (such as construction, excavation, or agricultural
activities), signs of earth movement or flooding, or the presence of
new structures potentially indicating a change in class location. In
addition to the general leak detection and pipeline integrity benefits
associated with performing right of way patrols described in section
IV.A.2, requiring patrols provides an opportunity to update class
location surveys and potential impact circle surveys. PHMSA further
notes that operators can control their compliance burdens from the
proposed increased patrols by coupling them with other operations and
maintenance tasks such as leakage surveys (provided that the operator
includes both a visual survey of the right-of-way and a leakage survey
with leak detection equipment) or by leveraging mobile technologies.
PHMSA expects its proposed amendments to leakage survey and right-
of-way patrol practices would be reasonable, technically feasible,
cost-effective, and practicable for affected gas transmission and
gathering pipeline operators. As explained above, operators of affected
gas transmission and gathering pipelines (some of which operators have
both gas transmission and gathering pipeline facilities within their
systems) are already subject to prescriptive periodic leakage surveys
requirements; affected operators also have the option to sync their
patrol and leakage survey requirements to minimize compliance burdens
(provided that the operator includes both a visual survey of the right-
of-way and a leakage survey with leak detection equipment). PHMSA's
proposed amendments would merely increase prescribed frequencies within
Federal regulation as a function of factors (including location in HCAs
and occupied buildings; components/equipment with complex
configurations; material composition; operating and maintenance
history) probative of leak susceptibility--and by extension, risks to
public safety and the environment. PHMSA further notes that, insofar as
those factors the NPRM employs as bases for increased leak detection
and patrol frequency are widely understood to be potential threats to
the integrity of pipelines, they are among the phenomena that
reasonably prudent operators would evaluate, and potentially adopt
mitigation measures to address, in ordinary course to protect public
safety and the environment from releases of pressurized (natural,
flammable, toxic, or corrosive) gases from their pipelines and minimize
loss of commercially valuable commodities. Additionally, operators
would have flexibility (as appropriate for their needs and their
pipelines' operational characteristics
[[Page 31931]]
and environment) in choosing between commercially available, advanced
leakage detection equipment satisfying the performance standards
proposed in this NPRM for use in those leakage surveys. Viewed against
those considerations and the compliance costs estimated in the
Preliminary RIA, PHMSA expects its proposed amendments will be a cost-
effective approach to achieving the commercial, public safety, and
environmental benefits discussed in this NPRM and its supporting
documents. Lastly, the proposed compliance timelines--based on an
effective date of the proposed requirements six months after the
publication date of a final rule in this proceeding (which would
necessarily be in addition to the time since issuance of this NPRM)--
would provide operators ample time to implement requisite changes in
their leakage survey practices and manage any related compliance costs.
3. Leakage Surveys and Patrols for Types B and C Gas Gathering
Pipelines--Sec. Sec. 192.9, 192.705, and 192.706
PHMSA proposes to apply to Types B and C gas gathering pipelines
the leakage survey and patrol requirements proposed in this NPRM for
gas transmission, offshore gathering, and Type A gathering pipelines.
PHMSA has long recognized the public safety risks associated with
gathering pipelines and has general authority under 49 U.S.C. 60102 to
issue minimum Federal pipeline safety standards necessary to ``meet the
need for gas pipeline safety [. . .] and protect [] the environment.''
For that reason, PHMSA has in the past extended select part 192
requirements--including leak survey requirements at Sec. 192.706--
applicable to gas transmission pipelines to a minority (only the
largest, or closest to occupied buildings) of the Type C gas gathering
pipelines posing the greatest risks to public safety. Existing Sec.
192.9 does not require operators of Type B and Type C gathering
pipelines to conduct patrols pursuant to Sec. 192.705.
However, the historical, limited approach in applying Sec. Sec.
192.705 (patrol) and 192.706 (leakage survey) requirements to Types B
and C gathering lines is inadequately protective of public safety and
the environment. Recent aerial methane emissions surveys discussed in
section II.C above yield that leaks from gas gathering line pipe, the
vast majority of which are Type C or Type R pipelines located in Class
1 locations, in particular are a significant contributor to methane
emissions. Further, the GHGI data discussed in section II.E reveals
that fugitive methane emissions from all types of gas gathering line
pipe vastly exceed emissions from gas transmission line pipe both in
total and on a per-mile basis. Leaks from gathering line pipe can
therefore be correspondingly greater contributors to the climate crisis
than leaks from gas transmission line pipe. Further, because natural
gas gathering pipelines carry unprocessed natural gas, any leak from
those pipelines would release VOCs and HAPs such as benzene to the
environment and risk accelerated degradation of pipeline integrity from
corrosives entrained in the natural gas. PHMSA understands that leaks
from gathering lines transporting other gases that are flammable,
toxic, or corrosive could entail significant public safety and
environmental consequences as well. Because of these significant risks
to public safety and the environment posed by Types B and C gathering
lines, PHMSA has proposed that all Type C gathering lines be subject to
the same Sec. 192.706 requirements governing leakage survey equipment
and frequency as gas transmission and Types A and B gathering
pipelines. Similarly, PHMSA proposes to require patrol frequencies for
Type B and Type C gathering lines identical to the patrol requirements
for as transmission and Type A gathering pipelines. PHMSA understands
that its proposed extension of these mutually-reinforcing, enhanced
patrol and leakage survey requirements would ensure timely prevention,
discovery and remediation of leaks on Types B and C gas gathering
lines. PHMSA invites comments concerning the value of requiring more or
less frequent leakage surveys of transmission and gathering pipelines
(for potential inclusion within a final rule in this proceeding).
Comments on these questions are especially helpful to PHMSA when they
are supported by research or operational experience, along with the
potential safety and environmental benefits and potential costs of a
particular approach (including whether that approach would be
technically feasible, cost-effective, and practicable).
PHMSA expects its proposed amendments to extend leakage survey and
right-of-way patrol practices to all Types B and C gas gathering
pipeline operators would be reasonable, technically feasible, cost-
effective, and practicable. Patrols and leakage surveys using leak
detection equipment are widely-employed tools adopted by reasonably
prudent operators in ordinary course for identifying and mitigating
leaks on, or threats to the integrity of, pipelines transporting
commercially valuable pressurized (natural, corrosive, toxic, or
flammable) gases. Precisely for that reason, PHMSA expects that some
Types B and C gas gathering pipeline operators affected by this NPRM's
proposed requirements for leakage survey and right-of-way patrols may
already voluntarily undertake leakage surveys and patrols on their
facilities. Those and other operators of Types B and C gas gathering
pipelines (some of which operators may also operate either gas
transmission or Type A gathering pipelines) may also have pipelines
within their systems subject to prescriptive periodic leakage survey
and patrol requirements under Federal or State law. PHMSA's proposed
amendments would, therefore, better align leakage survey and right-of-
way patrol practices and requirements for Types B and C gas gathering
lines with requirements for other 192-regulated gas pipelines.
Additionally, PHMSA's proposed periodicities for such surveys and
patrols would also turn on factors (including location in HCAs and
occupied buildings; components/equipment; material composition;
operating and maintenance history) well-understood to be probative of
leak susceptibility--and by extension, risks to public safety and the
environment. Affected operators would also have the option to sync
their patrol and leakage survey requirements to minimize compliance
burdens (provided that the operator includes both a visual survey of
the right-of-way and a leakage survey with leak detection equipment).
And operators would have flexibility (as appropriate for their needs
and their pipelines' operational characteristics and environment) in
choosing between commercially available, advanced leakage detection
equipment satisfying the performance standards proposed in this NPRM
for use in their leakage surveys. Viewed against those considerations
and the compliance costs estimated in the Preliminary RIA, PHMSA
expects its proposed amendments will be a cost-effective approach to
achieving the commercial, public safety, and environmental benefits
discussed in this NPRM and its supporting documents. Lastly, the
proposed compliance timelines--based on an effective date of the
proposed requirements six months after the publication date of a final
rule in this proceeding (which would necessarily be in addition to the
time since issuance of this NPRM)--would provide operators ample time
to implement requisite leakage survey and patrol practices and manage
any related compliance costs.
[[Page 31932]]
PHMSA solicits comment on whether it would be appropriate to apply
any of the requirements proposed herein to Type R gathering pipelines
not currently regulated under part 192. Comments on this question are
especially helpful if they address the potential safety and
environmental benefits and potential costs of that particular approach,
including whether that approach would be technically feasible, cost-
effective, and practicable.
4. Liquefied Natural Gas Facilities--Sec. 193.2624
Part 193 does not currently require that operators perform periodic
surveys of LNG facility components and equipment for methane leakage to
the atmosphere. However, as described in section II.C.2, equipment
leaks and other fugitive methane emissions are the second largest
methane emissions source from LNG storage facilities and the largest
methane emissions source from LNG export terminals.
PHMSA therefore proposes a new Sec. 193.2624 to require a
quarterly methane leakage survey using leak detection equipment and
remediation of any methane leaks discovered in accordance with the
operator's maintenance or abnormal operations procedures. Leaks
discovered would need to be remediated on a schedule established within
those procedures. Methane leakage surveys would only need to be
conducted on components and equipment containing methane or LNG in
normal operations. PHMSA further proposes a minimum equipment
sensitivity requirement of 5 ppm--along with validation and calibration
requirements--consistent with the proposed requirements governing the
performance of leak detection equipment described in section IV.B below
for part 192-regulated gas pipeline facilities. PHMSA expects that
these proposed enhanced methane leakage and repair requirements would
improve public safety by allowing for timely identification and
remediation of potential ignition sources within part 193-regulated LNG
facilities, as well as reduce a key source of fugitive GHG emissions
from those facilities. Additionally, eliminating product losses results
in cost savings that improve the competitiveness of LNG storage and
export facilities, further increasing the net benefits of this
proposal. PHMSA also proposes that, consistent with its proposed
revisions to part 191 leak detection and repair reporting requirements
for part 192-regulated gas pipeline facilities, PHMSA would propose
conforming revisions to its annual report form for part 193-regulated
facilities \230\ to ensure meaningful reporting of all methane leaks
detected or repaired by operators pursuant to Sec. 193.2624.
---------------------------------------------------------------------------
\230\ PHMSA, Form 7300.1-3, ``Annual Report Form for Liquefied
Natural Gas Facilities (Oct. 2014). The instructions for Form
7300.1-3 states that ``a non-hazardous release that can be
eliminated by lubrication, adjustment, or tightening is not a
leak.'' PHMSA, Instructions for Form 7300.1-3 at 4 (Oct. 2014). That
historical understanding is inconsistent with PHMSA's understanding
of the PIPES Act of 2020 premise that all leaks of methane are
hazardous to the environment because they contribute to climate
change. PHMSA is not, however, proposing in this NPRM to modify the
historical reporting exception with respect to releases of other,
non-methane, hazardous materials within an LNG facility.
---------------------------------------------------------------------------
PHMSA expects its proposed leakage survey practices would be
reasonable, technically feasible, cost-effective, and practicable for
affected LNG facility operators. PHMSA notes that some LNG facility
operators may operate transmission pipelines supplying natural gas to
their facilities; those operators could use their existing leakage
survey practices as a foundation for development of leakage survey
requirements tailored to their LNG facilities. PHMSA further notes
that, insofar as leakage surveys using leak detection equipment are
widely understood to be essential tools in identifying and mitigating
threats to the integrity of pipelines transporting methane within any
gas pipelines, they are among the practices that reasonably prudent
operators would adopt in ordinary course to protect public safety and
the environment from releases of methane from equipment and components
in LNG facilities and minimize loss of a commercially valuable
commodity. Additionally, operators would have flexibility in choosing
between leakage detection equipment satisfying the performance standard
proposed in this NPRM for use in those leakage surveys. Viewed against
those considerations and the compliance costs estimated in the
Preliminary RIA, PHMSA expects its proposed amendments will be a cost-
effective approach to achieving the commercial, public safety, and
environmental benefits discussed in this NPRM and its supporting
documents. Lastly, the proposed compliance timelines--based on an
effective date of the proposed requirements six months after the
publication date of a final rule in this proceeding (which would
necessarily be in addition to the time since issuance of this NPRM)--
would provide operators ample time to implement requisite changes in
their leakage survey practices and manage any related compliance costs.
In order to avoid conflicting with existing regulatory requirements
and best practices in the National Fire Protection Association
standard, ``Standard for the Production, Storage, and Handling of
Liquefied Natural Gas (LNG)'' governing the requirements for LNG
facilities (NFPA 59A) and other standard practices, PHMSA has not
proposed in this NPRM for LNG facilities a comprehensive, advanced leak
detection and repair program framework along the lines of that
discussed below in section IV.B for part 192-regulated gas pipeline
facilities. For example, section 9.3 of the 2001 edition of NFPA
59A,\231\ which is incorporated by reference within PHMSA regulations
at Sec. 193.2801, requires continuous gas monitoring in the vicinity
of LNG process equipment, and section 12.4.2 requires an alarm at 25%
LEL or less. Additionally, certain equipment in LNG plants that are not
part of distribution systems may be subject to EPA leak detection and
repair requirements in 40 CFR part 60 depending on the purpose and
contents of the equipment. However, facilities storing or carrying
natural gas or LNG are typically subject to the standards for gas
production and transmission systems in 40 CFR part 60. The subpart OOOO
and OOOOa standards are described in greater detail in section IV.C.3
and include semiannual fugitive emissions monitoring surveys and repair
of all leaks visible with an OGI device or that produce an instrument
reading of 500 ppm or greater.\232\ For a subpart OOOOa facility, the
operator must attempt repair no later than 30 days after detecting the
fugitive emissions and must complete the repair within 30 days of the
first attempt or during the next scheduled shutdown.\233\ Finally,
detecting leaks on equipment such as at LNG plants is generally less
challenging than doing so on buried pipelines. PHMSA is pursuing a
parallel rulemaking (under RIN 2137-AF45) in which it could consider
leak monitoring, surveying, and patrolling requirements more
holistically.
---------------------------------------------------------------------------
\231\ NFPA, NFPA-59A: Standard for the Production, Storage, and
Handling of Liquefied Natural Gas (LNG)--2001 Edition (2001).
\232\ 40 CFR 60.5397a(a)(1) and (h).
\233\ 40 CFR 60.5397(h).
---------------------------------------------------------------------------
B. Advanced Leak Detection Programs--Sec. 192.763
Section 113 of the PIPES Act of 2020 requires PHMSA to issue
performance standards for operator leak detection and repair programs
reflecting the capabilities of commercially available, advanced leak
detection technologies
[[Page 31933]]
and practices. To satisfy this mandate, PHMSA proposes to introduce a
new Sec. 192.763 to require operators establish written Advanced Leak
Detection Programs (ALDPs) and to establish performance standards for
both the sensitivity of leak detection equipment and for the
effectiveness of those ALDPs. This new requirement would provide
benefits to both public safety and the environment by ensuring that
pipeline operators have programs in place to promptly detect and repair
leaks of all gas pipelines subject to part 192, thereby reducing harm
to public safety and the environment.
An ALDP represents a complementary set of mutually reinforcing
technologies and procedures (including analytics) that the operator
uses to detect all leaks. PHMSA proposes to require that an operator's
written ALDP include four main elements: leak detection equipment
employing commercially available advanced technology, leak detection
procedures, prescribed leakage survey frequencies, and program
evaluation. Note that grading and repairing leaks after investigation
is governed by the proposed Sec. 192.760 described in section IV.C of
this NPRM. The proposed requirements in this section would apply to
operators of all gas distribution lines, gas transmission lines,
offshore gathering, and Types A, B, and C regulated onshore gathering
pipelines.
PHMSA expects each of the proposed ALDP requirements discussed
below would be reasonable, technically feasible, cost-effective, and
practicable for all affected gas pipeline operators. PHMSA understands
that most operators of gas pipelines that would be subject to those
requirements may already employ one or more of its proposed ALDP
elements voluntarily because (inter alia) a reasonably prudent operator
would in ordinary course employ a systematic, defense-in-depth approach
to identifying leaks given the commercial value of, and potential risks
to public safety and the environment posed by, the commodities
transported (natural gas or flammable, toxic, or corrosive pressurized
gases). Alternatively, an operator may employ one of more of PHMSA's
proposed ALDP elements as a compliance strategy for existing PHMSA or
State leak detection or integrity management requirements. Regardless,
PHMSA's proposals build and on those existing practice by creating a
common, straightforward regulatory framework for addressing leak
detection across all part 192-regulated gas pipelines. Within that
common framework, moreover, operators would retain significant
flexibility to select (as appropriate for a pipeline's operational
needs and operating environment) a suite of mutually reinforcing leak
detection equipment, analytics, and practices, satisfying a baseline
leak detection performance standard derived from commercially available
advanced leak detection technology in a way that minimizes their
compliance costs. PHMSA's proposal even contemplates that some
operators of gas pipelines may employ (subject to PHMSA review) an
alternative performance standard as a function of location or gas
commodity being transported. Viewed against those considerations and
the compliance costs estimated in the Preliminary RIA, PHMSA expects
its proposed amendments will be a cost-effective approach to achieving
the commercial, public safety, and environmental benefits discussed in
this NPRM and its supporting documents. Lastly, the proposed compliance
timelines--based on an effective date of the proposed requirements six
months after the publication date of a final rule in this proceeding
(which would necessarily be in addition to the time since issuance of
this NPRM)--would provide operators ample time to implement requisite
protocols, obtain leak detection equipment, and manage any related
compliance costs.
1. Leak Detection Technology Standards--Sec. 192.763(a)(1)
The first element in an ALDP is the leak detection technology that
the operator would use to perform leakage surveys, investigate leaks,
and pinpoint leak locations. These technology requirements are proposed
in Sec. 192.763(a)(1). Each operator's ALDP would include a list of
leak detection equipment that the operator uses for leakage surveys,
leak investigations, and pinpointing leaks. Consistent with the mandate
in section 113 of the PIPES Act of 2020, PHMSA proposes to specify when
leak detection equipment would be required and when an operator may
rely on methods that rely on human or animal senses. Specifically, the
NPRM proposes to amend Sec. 192.723 to require that all leakage
surveys on gas distribution pipelines be performed with leak detection
equipment in light of the high risk to public safety from distribution
pipelines, which are often located in the vicinity of population
centers. Additionally, as described in section IV.A.2 of this NPRM, all
leakage surveys on onshore gas transmission and gathering pipelines
performed under Sec. 192.706 would require the use of leak detection
equipment, except when the operator of a gas transmission or gathering
pipeline in a Class 1 or Class 2 location determines that a survey
using human senses would be sufficient, subject to review by PHMSA, as
provided in Sec. 192.706(a)(1). This default requirement that ALDPs of
onshore regulated gas gathering, transmission, and distribution
operators use leak detection equipment in leakage surveys would enhance
operators' ability to identify and repair leaks on pipelines in a
timely manner, and therefore minimize releases and prevent leaks from
degrading. It would also serve to improve leak detection data to
improve the predictive power of leak management programs, integrity
management programs, and artificial intelligence services that can
identify systemic pipeline design or repair issues.
PHMSA further proposes that any leak detection equipment used must
have a minimum sensitivity of 5 ppm or less. A reading of 1% of the
lower-explosive limit of methane gas at atmosphere is approximately 500
ppm; a minimum sensitivity of 5 ppm would therefore provide a
protective threshold of detection sensitivity. That threshold is also
consistent with the performance of commercially available leak
detection equipment. Table 2 of the Appendix G-192-11 of the GPTC Guide
provides examples of commercially available methane detection
technologies and the sensitivity and detection ranges for those
technologies. That information is reproduced in the table below. In
addition to the devices listed below, OGI cameras, devices that are
capable of visualizing methane gas leaks and other fugitive emissions,
are commonly used for fugitive emissions monitoring at LNG plants,
compressor stations, and other facilities.
Methane Leak Detection Technologies and Performance
------------------------------------------------------------------------
Technology Sensitivity Range
------------------------------------------------------------------------
Semiconductor................... 1-100 ppm......... 0-100 ppm.
Flame Ionization................ 1 ppm............. 0-10,000 ppm.
[[Page 31934]]
Open Path Infrared (IR) Tunable 5 ppm-meter....... 0-100,000 ppm-
diode laser absorption meter.
spectroscopy.
Closed Path Bifringent IR....... 1 ppm............. 0-2,500 ppm.
Closed Path IR Laser............ 0.03-100 ppm...... 0-1000 ppm.
------------------------------------------------------------------------
Although each of the technologies listed above has advantages and
limitations that may make it more or less appropriate for leakage
surveys on particular gas pipelines or operating conditions, PHMSA's
proposed 5 ppm performance standard balances each of the following: a
methane sensitivity threshold consistent with the performance of state-
of-the-art, commercially-available technologies; robust margin to risk
of ignition; and flexibility for operators to choose from a baseline of
high-quality equipment for their unique needs. For example, PHMSA
understands that modern FID units and closed-path IR and laser-based
systems are capable of sub-ppm and parts-per-billion detection.
However, quality semiconductor sensors and open-path IR devices have
important applications despite comparatively lower-sensitivity.
Semiconductor sensors are typically much smaller than other detection
devices and therefore are useful in confined spaces and other
situations where a smaller tool is necessary to access the space.
Additionally, semiconductor sensors are often designed to incorporate
intrinsically safe features, which minimizes the risk of ignition in
situations where a flammable atmosphere may be present. Similarly, some
handheld open-path IR systems can have a sensitivity of 5 ppm-meter at
its maximum effective range \234\ but have the advantage of allowing a
surveyor to detect methane plumes from a distance. This allows operator
leakage surveyors to safely and efficiently survey facilities that may
otherwise be difficult or unsafe to access. However, the proposed leak
detection performance standard would generally exclude each of odorant
``sniffers'' used to test the adequacy of odorization, less-sensitive
combustible gas indicators, and most gas monitors intended for confined
space gas monitoring rather than methane leak detection--even as PHMSA
acknowledges such devices may nevertheless be useful in connection with
leak grading (pursuant to proposed Sec. 192.760), as tools
supplementing ALDP-compliant leak detection equipment, or as authorized
pursuant to proposed Sec. 192.763(c).
---------------------------------------------------------------------------
\234\ PPM-meter is a ``path integrated'' summation of measured
gas concentration used for open-path devices that sums gas
concentration per meter measured up to the effective range in front
of the device. Sensitivity may be higher at closer ranges depending
on the specific technology used.
---------------------------------------------------------------------------
As discussed throughout this section, other ALDP programmatic
requirements backstop any limitations on the ability of particular leak
detection technologies to contribute to the program-wide performance
standard at Sec. 192.763(b) that an ALDP detects all leaks of 5 ppm or
more when measured 5 feet from the pipeline. For example, PHMSA
acknowledges that an operator may determine, based on its operational
needs or the operating environment of a particular pipeline, that leak
detection equipment more sensitive than 5 ppm is necessary to meet the
ALDP programmatic performance standard at Sec. 192.763(b). For
example, an operator may determine that an efficient means of meeting
the ALDP performance standard at Sec. 192.763(b) would be to perform
leakage surveys by first using very sensitive (in the sub-ppm or low
ppb range) vehicle or aircraft mounted sensors, followed thereafter by
spot-checks using handheld devices with the minimum sensitivity of 5
ppm proposed at Sec. 192.763(a)(1)(ii). Similarly, an operator may
supplement any leak detection equipment meeting the minimum sensitivity
requirements proposed at Sec. 192.763(a)(1)(ii) with other techniques
for pinpointing leak location (e.g., soap bubble testing) or
technologies (e.g., devices for measuring release rate for
differentiating between leak grades) for grading identified leaks
pursuant to PHMSA's proposed Sec. 192.760.
PHMSA further notes that operators would be able to, pursuant to
the proposed Sec. 192.763(c), seek PHMSA review of use of an
alternative ALDP performance standard that may entail the use of
alternative (including less sensitive) leak detection technology than
that proposed under Sec. 192.763(a)(1). This process is available for
each of natural gas pipelines (other than distribution pipelines) in
Class 1 and 2 locations, and any part 192-regulated pipeline facility
transporting flammable, toxic, or corrosive gas other than natural
gas.\235\ PHMSA acknowledges the fast-evolving state-of-the-art in leak
detection technologies for methane and other gases and seeks comments
on whether and in what manner it could integrate within a final rule
requirements for technologies that may not have specified
sensitivities, including continuous pressure wave monitoring, fiber
optic sensing, OGI, and LIDAR based detection technologies, along with
the potential safety and environmental benefits and potential costs of
a particular approach (including whether that approach would be
technically feasible, cost-effective, and practicable). PHMSA expects
that it would consider the use of such technologies under the Sec.
192.763(c) process or as supplement to other equipment satisfying the
minimum sensitivity performance requirements proposed herein.
---------------------------------------------------------------------------
\235\ Although PHMSA's proposed 5 ppm default performance
standard for all part 192-regulated gas pipelines is based
principally on commercially available, advanced methane leak
detection technology for use with natural gas pipelines, PHMSA
understands that commercially available, advanced leak detection
technology for use with other part 192-regulated gas pipeline
facilities may (when considered either separately or within a suite
of mutually-reinforcing technologies) offer comparable leak
detection ability. Further, as explained in the paragraph above, the
NPRM contemplates operators of gas pipeline facilities transporting
gases other than natural gas (e.g., hydrogen) may request the use of
an alternative leak detection performance standard and supporting
leak detection equipment.
---------------------------------------------------------------------------
Apart from minimum sensitivity requirements described above, PHMSA
does not propose to require the use of any particular leak detection
equipment or technology for every operator or for each type of
pipeline. While the PIPES Act of 2020 directs PHMSA to require the use
of advanced leak detection technologies and practices, Congress defined
this requirement in terms of a performance standard for leak detection
and repair programs and described several possible approaches in the
statute. PHMSA therefore does not propose to narrowly define advanced
leak detection in terms of a particular technology, process,
manufacturer, or equipment. One type of technology may not always be
appropriate for every flammable, corrosive, or toxic gas, each type of
pipeline facility or even across
[[Page 31935]]
the range of operational/environmental conditions (e.g., seasonal
temperature, humidity, or precipitation patterns) within which a
particular pipeline operates. Rather than a technology standard, PHMSA
expects each of the periodic evaluation and improvement element of each
ALDP (proposed in Sec. 192.763(a)(4)), and the ALDP performance
requirement (proposed in Sec. 192.763(b), described later in this
section), would encourage operators to continually evaluate and
incorporate within their ALDPs such newly commercialized technologies
as appropriate for their systems over time. This flexible approach
would ensure that operators' leakage detection equipment keeps pace
with the state-of-the-art in leak detection technology. Additionally,
this NPRM proposes to require operators to select their leak detection
equipment based on a documented analysis that considers, at a minimum,
the gas being transported, the size, configuration, operating
parameters, and operating environment of the operator's system. An
operator would be required to choose leak detection technologies that
are best able to detect, investigate, and locate all leaks considering
these factors. For example, an advanced mobile leak detection system
could be an effective tool for detecting methane leaks in a suburban
distribution system but may not be optimal for surveying service lines
in an area with long setbacks or a transmission pipeline with poor road
access. PHMSA also proposes to require operators to analyze, at a
minimum, the appropriateness of the following examples of possible
advanced leak detection technologies and methods, some of which were
referenced in the PIPES Act of 2020: leakage surveys with optical,
infrared, or laser-based hand-held devices; continuous monitoring via
stationary gas sensors, pressure monitoring, or other means; mobile
surveys from vehicle, satellite, or aerial platforms; and systemic use
of other technologies capable of detecting and locating leaks
consistent with the proposed ALDP performance standard at Sec.
192.763. Operators would be required to maintain records of this
analysis for five years. Stationary gas detection systems are already
required on compressor stations under PHMSA's existing regulations at
Sec. 192.736. Likewise, section 16.4 of the 2001 edition of NFPA
59A,\236\ which is incorporated by reference into the federal safety
standards for LNG facilities in part 193, requires monitoring of
enclosed buildings and other areas that can have the presence of LNG or
other hazardous fluid (including natural gas), and specifies flammable
gas alarm settings in section 16.4.2. PHMSA invites comments on the
value of introducing requirements for continuous monitoring systems,
via stationary gas detection systems, pressure monitoring, or other
means (including requirements for the use of specific methods or
technologies), on other types of pipeline facilities (including whether
continuous monitoring would be most appropriate at any particular
facilities or locations, or in other particular conditions) within a
final rule in this rulemaking proceeding.\237\ Comments are especially
helpful to PHMSA when they are supported by research or operational
experience, along with the potential safety and environmental benefits
and potential costs of a particular approach (including whether that
approach would be technically feasible, cost-effective, and
practicable).
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\236\ NFPA, NFPA-59A: Standard for the Production, Storage, and
Handling of Liquefied Natural Gas (LNG)--2001 Edition (2001).
\237\ To the extent that a comment proposes to require
installation of such technologies on a pipeline, PHMSA also solicits
comment on the potential application of PHMSA's statutory
prohibition on retroactive design and installation standards. See 49
U.S.C. 60104(b).
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2. Leak Detection Practices--Sec. 192.763(a)(2)
The second program element in proposed Sec. 192.763(a)(2) consists
of the operator's procedures related to leak detection, investigation,
and location. Generally, this would involve supplementing or revising
existing procedures in the operator's manual of procedures. At a
minimum, the ALDP would include procedures for performing leakage
surveys as well as subsequent investigation and location of identified
leaks; operator procedures would provide instruction on whether and how
each type of leak detection equipment included in the ALDP would be
used in performing those tasks. To ensure that operators use procedures
appropriate for environmental conditions such as temperature, wind,
time of day, precipitation and humidity, the operator must define under
which conditions the procedure may and may not be used. Additionally,
the procedures must be consistent with any instructions and allowable
operating and environmental parameters issued by the leak detection
equipment manufacturer to ensure equipment effectiveness. For example,
some devices or systems may be unsuitable for use in certain weather or
atmospheric conditions, or at certain times of day, or in certain
temperatures. As noted in the discussion of leak detection practices in
section II.F, establishing and following procedures with parameters
appropriate for the leak detection technologies and practices is
critical for reliably detecting leaks, especially in challenging
conditions. This requirement also addresses the findings from the
NTSB's investigation of a 2018 gas explosion involving failed leakage
surveys (discussed in section II.H of this NPRM.) due to the operator's
improper use of leak detection equipment.\238\
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\238\ National Transportation Safety Board. ``Pipeline Accident
Report: Atmos Energy Corporation Natural Gas-Fueled Explosion:
Dallas, Texas: February 23, 2018.'' NTSB/PAR-21/01. Jan. 12, 2021.
Washington, DC https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR2101.pdf.
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PHMSA proposes to require that an operator's ALDP procedures
include investigating and pinpointing the location of all leak
indications. For onshore pipelines and offshore pipeline facilities
above the waterline, PHMSA proposes in Sec. 192.763(a)(2) to require
that pinpointing location be performed using handheld leak detection
equipment with a minimum sensitivity of 5 ppm. This proposed
requirement would complement PHMSA's proposed ALDP programmatic
performance standard in Sec. 192.763(b). If leak location is
pinpointed with handheld leak detection equipment during an initial
leakage survey, the initial survey would satisfy this requirement.
PHMSA proposes that pinpointing leak location on submerged offshore
pipelines (including riser piping up to the waterline) would not
require the use of leak detection equipment because submerged pipeline
leaks are visibly conspicuous.
To ensure the effectiveness of leak detection equipment, PHMSA
proposes to require at Sec. 192.763(a)(2)(iii) that an operator have
procedures for validating that a leak detection device meets the 5-ppm
minimum sensitivity requirement in Sec. 192.763(a)(1)(ii)prior to
initial use. This would consist of testing the equipment measurements
against a known concentration of gas. Operators would have to maintain
records that their leak detection equipment has been validated for five
years after the date each device ceases to be used in the operator's
ALDP. This is a one-time validation separate from the periodic
calibration required under proposed Sec. 192.763(a)(2)(iv) described
below. PHMSA also proposes to require that operators have procedures
for the maintenance and calibration of leak detection equipment--
including at least
[[Page 31936]]
any maintenance and calibration procedures recommended by the equipment
manufacturer--to ensure that equipment is functioning as intended
throughout its service life. Finally, PHMSA proposes to require that
operators recalibrate leak detection equipment following an indication
of malfunction.
3. Leakage Survey Frequency--Sec. 192.763(a)(3)
The third element that PHMSA proposes to require of an ALDP is the
frequency of leakage surveys, which is specified in proposed Sec.
192.763(a)(3). Minimum leakage survey frequencies are defined in Sec.
192.723 for gas distribution pipelines and in Sec. 192.706 for gas
transmission, offshore gathering, and Types A, B, and C gathering
pipelines. As noted in section IV.A, less sensitive survey equipment
may require more frequent surveys in order to provide an equivalent
degree of leak or emissions detection.\239\ If more frequent leakage
surveys are necessary to reliably meet the ALDP programmatic
performance standard in proposed Sec. 192.763(b), or as otherwise
specified by the operator, that must be noted in the operator's ALDP.
For example, more frequent leakage surveys may be appropriate for less
sensitive leak detection equipment authorized for use pursuant to
proposed Sec. 192.763(c), challenging survey conditions, or facilities
known to leak based on their material, design, or past operating and
maintenance history. As noted above in section IV.B.1, PHMSA invites
comments on the value of requiring continuous monitoring systems on
these types of facilities or any other pipeline facilities (for
potential inclusion within a final rule in this proceeding). Comments
are especially helpful to PHMSA when they are supported by research or
operational experience, along with the potential safety and
environmental benefits and potential costs of a particular approach
(including whether that approach would be technically feasible, cost-
effective, and practicable).
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\239\ Ravikumar, Arvind Ph.D. ``FEAST-Based Evaluation of
Methane Leak Detection and Repair Programs Using New Technologies.''
EPA Methane Detection Technology Workshop (August 24, 2021). https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/epa-methane-detection-technology-workshop. Day 2 at 1:33:50.
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4. Program Evaluation and Improvement--Sec. 192.763(a)(4)
The fourth and final element of an ALDP in Sec. 192.763(a)(4) is
program evaluation and improvement. At least annually, operators would
have to re-evaluate the elements of their ALDPs considering, at a
minimum, the performance of the leak detection equipment used, the
adequacy of their leakage survey procedures, advances in leak detection
technologies and practices, the number of leaks initially detected by
third parties, the number of leaks and incidents on the pipeline, and
estimated emissions from detected leaks. This proposal is similar in
principle to the existing continuous improvement requirements under IM
requirements in part 192, subparts O and P, as well as requirements for
certain operators to periodically review procedures under Sec.
192.605(b)(8) and (c)(4). PHMSA expects this proposal would ensure
operators periodically evaluate ways to improve their leak detection
programs based on leak detection performance data and advances in
technology. For example, if an operator finds evidence that their ALDP
fails to detect leaks during leakage surveys, or that it is finding
grade 1 or 2 leaks but does not find any grade 3 leaks, changes to
program elements may be necessary to ensure that the minimum
performance standard in Sec. 192.763(b) described below is met. This
provision would offer potential environmental benefits and could also
result in cost-savings to operators and shippers, by helping further
reduce product losses from pipeline facilities.
5. Advanced Leak Detection Performance Standard--Sec. 192.763(b)
The ultimate benchmark for the effectiveness of an operator's ALDP
would be a holistic, program-wide performance standard at Sec.
192.763(b). Specifically, PHMSA proposes to require that an ALDP must
be capable of detecting all leaks that produce a reading of 5 ppm or
greater of gas when measured from a distance of 5 feet from the
pipeline, or within a wall-to-wall paved area. As described in the
discussion of leak detection equipment above, the proposed 5 PPM
standard represents a protective, detection threshold achievable using
mainstream, commercially available, advanced leak detection equipment.
The Sec. 192.763(b) ALDP performance standard is consistent with that
minimum sensitivity for leak detection equipment, but it focuses on the
characteristics of the leak (in particular, whether the leak rate or
operating environment results in a reading of 5 ppm) rather than on the
sensitivity of the leak detection equipment employed by an operator.
For example, a walking survey conducted alongside a pipeline with
thorough, careful, procedures to ensure detection of all leaks could
achieve this standard with an FID or other handheld device with the 5
ppm sensitivity required by Sec. 192.763(a). But mobile leak detection
systems and aerial systems that use gas samplers or other sensors to
detect leaks at a greater distance may allow for more efficient leakage
surveying, but could require more sensitive (sensors in the ppb range)
leak detection equipment coupled with advanced analytics (followed by
the use of handheld leak detection equipment to pinpoint leak location)
to detect and locate the same leak. Similarly, leakage surveys
employing human or animal senses would have to employ leak detection
equipment to investigate and pinpoint the location of any leaks
detected during those non-instrumented surveys.
Some stakeholders attending the 2021 Public Meeting commented that
leak flow rate would be a more appropriate metric for leak detection
and ALDP program performance than PHMSA's proposed volumetric
sensitivity metric.\240\ However, as discussed above in section II.D.4,
most currently available methane leak detection technologies are
focused on calculating the concentration of gas in the air rather than
leak flow rate. Moreover, PHMSA's choice of leak concentration-based
performance standard for leak detection equipment was informed by the
goal of (as much as possible) identifying a single performance standard
that would be well-suited for leak detection on both aboveground and
buried natural gas pipelines. Additionally, consistent with the GPTC
Guide grading criteria and as acknowledged in the comments of AGA et
al. to the 2021 Public Meeting, a concentration-based metric is
especially useful for addressing explosion risks to public safety
(regardless of a leak's flow rate). To the extent that operators find
that leak rate measurements are helpful for identifying or grading
leaks or in calculating estimated emissions consistent with changes to
part 191 reporting requirements discussed elsewhere in this NPRM,
operators may incorporate leak flow rate metrics within their ALDPs to
supplement leak concentration metrics used in PHMSA's proposed leak
detection and ALDP performance standard. In particular, leak rate
measurements may help operators quickly grade certain leaks as grade 2
leaks based on a leak rate in excess of 10 CFH. Based on available
[[Page 31937]]
information, PHMSA's current assessment is that the proposed Sec.
192.763(b) ALDP performance standard represents a threshold of
detection demanding enough to ensure that operator ALDPs are capable of
detecting nearly all leaks on gas gathering, transmission, and
distribution pipelines. That said, PHMSA invites comment on whether and
how an alternative ALDP performance standard--such as a more demanding
volumetric standard, or a flowrate-based standard--should be adopted in
the final rule. Proposed alternatives are most helpful when they are
supported by a discussion of their value for public safety and
environmental protection, as well as their technical feasibility, cost-
effectiveness, and practicability.
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\240\ Written comments submitted before and after the meeting
are available in the rulemaking docket at Doc. No. PHMSA-2021-0039.
While some commenters observed that a leak flow rate performance
standard would be desirable, no commenter provided a suggestion for
how this could be implemented.
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6. Alternative Advanced Leak Detection Performance Standard--Sec.
192.763(c)
Lastly, because of the comparatively low emissions from natural gas
transmission pipeline leaks (relative to other gas transmission
pipeline facilities such as compressor stations),\241\ comparatively
lower potential safety risks to persons or property in remote areas,
and the continued development of methane leak detection technologies,
PHMSA proposes, at Sec. 192.763(c), to allow operators of each of gas
transmission, offshore gathering, and Types A, B, and C gathering
pipelines, located in Class 1 or 2 locations and outside of HCAs to
request an alternative ALDP performance standard (and use of supporting
leak detection equipment) pursuant to the notification and PHMSA review
procedures established in Sec. 192.18. PHMSA similarly proposes that
operators of any species of part 192-regulated gas pipelines
transporting flammable, toxic, or corrosive gases other than natural
gas may request use of an alternative ALDP performance standard (and
use of supporting leak detection equipment).
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\241\ See the discussion of GHGI data in section II.E. of this
NPRM.
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The operator must demonstrate, in the notification, that the
alternative performance standard is consistent with pipeline safety and
equivalent to the performance standard in Sec. 192.763(b) with respect
to reducing greenhouse gas emissions and other environmental hazards.
This flexibility can promote emerging technologies where they may be
most effective. For example, some aerial survey methods may not yet be
able to detect small but potentially hazardous, below-ground methane
leaks from a distribution pipeline system, but they could be an
efficient leakage survey method for leaks on below-ground onshore gas
transmission lines, which leaks are larger on average due to the higher
operating pressure. Similarly, an alternative performance standard may
be appropriate for flammable, toxic, or corrosive gases for which
commercially available, advanced leak detection technology either uses
different units of measure than that provided for in Sec. 192.763(a)
or is less sensitive than the default 5 ppm performance standard. PHMSA
proposes to require that notifications submitted under this provision
must include information about--among other things--the location and
material properties of the pipeline facility, the gas being
transported, a description of the proposed alternative performance
standard, and a description of the ALDP equipment and procedures that
would be used.
C. Leak Grading and Repair--Sec. Sec. 192.703, 192.760, and 192.769
As discussed in section II, gas pipeline operator leak grading and
repair practices are currently insufficient to meet the threats to the
environment and public safety from leaks on their systems. Current
requirements lack meaningful requirements for timely grading and repair
of leaks; only leaks that are ``hazardous'' (a term that is undefined)
are subject to explicit repair timelines and requirements, and PHMSA's
IM regulations in subparts O (transmission) and P (distribution)
largely defer to operator discretion regarding leak repair efforts for
the small portion of gas pipelines subject to those requirements. Only
a handful of States have imposed their own, more demanding leak repair
requirements than PHMSA's. Similarly, while some operators have
voluntarily adopted their own leak grading and repair practices, many
operators have no such requirements, and those that do may not apply
these requirements consistently across different types of pipeline
facilities.
PHMSA therefore proposes to address these regulatory gaps by
establishing requirements at Sec. Sec. 192.703, 192.760, and 192.769
for all part 192-regulated gas pipeline operators to ensure properly-
trained personnel grade and repair all leaks pursuant to a schedule for
each grade based on the severity of public safety and environmental
risks.\242\ PHMSA's proposal includes a leak grading framework informed
by the criteria of the GPTC Guide--which is familiar to industry and
State enforcement personnel--to facilitate compliance and regulatory
oversight. PHMSA's proposed leak grading framework in Sec. 192.760
would require the classification of every leak on any portion of a gas
pipeline (including components such as flanges, meters, regulators, and
ILI launchers and receivers) as either (in order of decreasing
priority) grade 1, grade 2, or grade 3 based on the magnitude and
probability of risks posed by that leak to the public and the
environment, prioritizing remediation of leaks presenting the most
serious hazards to people or the environment and setting minimum repair
timelines for each grade. Operators would be obliged to investigate
each leak discovered on their pipelines immediately and continuously
until a leak grade determination has been made to ensure that risks to
public safety and the environment from each leak are diligently
evaluated and repairs scheduled as appropriate to remedy any risks. The
NPRM also includes a number of enhancements to the GPTC Guide's three-
tiered framework to address gaps in safety and environmental
protection, including establishment of repair deadlines for grade 3
leaks and incentivizing replacement or remediation of pipe known to
leak. Operator personnel engaged in leakage survey, investigation for
grading purposes, and repair would be subject to baseline training
requirements. Lastly, PHMSA has proposed revision of the documentation
requirements at Sec. 192.605, consistent with statutory language in
section 114 of the PIPES Act of 2020, to oblige operators of gas
transmission, distribution, offshore gathering, and Types A, B, and C
gathering pipelines to update their procedures to provide for the
replacement or remediation of pipelines known to leak.
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\242\ These grading requirements apply to all commodities
transported under part 192, including petroleum gas, as all non-
natural gas commodities covered under part 192 are hazardous to
human health or the environment. See Sec. 192.3 (definition of
gas). Petroleum gas systems are subject to some specialized grading
criteria due to the unique hazards posed by this heavier-than-air
gas.
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PHMSA expects each of the proposed leak grading and repair
requirements discussed in this section IV.C would be reasonable,
technically feasible, cost-effective, and practicable for affected gas
pipeline operators. As explained above, some operators that would be
subject to this NPRM's proposed requirements have one or more pipelines
within their systems that are already subject to some leak repair
(either prescriptive or integrity management-based) requirements under
PHMSA or State regulatory regimes. Other operators may voluntarily
exceed minimum regulatory
[[Page 31938]]
requirements given the significant public safety and environmental
risks posed by releases of pressurized (natural, flammable, toxic, or
corrosive) gas from their pipelines, or to minimize loss of
commercially valuable commodity. PHMSA's proposal builds on those
existing practices by establishing for part 192-regulated gas pipelines
a common leak repair obligation leveraging the GPTC Guide's familiar
framework for classifying all leaks--not merely those thought to pose
imminent risks to public safety. PHMSA in turn calibrated its proposed
repair timelines for each leak grade based on the magnitude of public
safety and environmental risks; within those default repair timelines,
operators may be able to seek extensions or (with respect to compressor
stations) be relieved of obligations from potential overlapping
requirements from certain methane emissions requirements imposed by
other Federal and State regulatory authorities. Viewed against those
considerations and the compliance costs estimated in the Preliminary
RIA, PHMSA expects its proposed amendments will be a cost-effective
approach to achieving the commercial, public safety, and environmental
benefits discussed in this NPRM and its supporting documents. Lastly,
the NPRM's proposed compliance timelines--which are based on an
effective date of six months after the publication date of a final rule
in this proceeding (which would necessarily be in addition to the time
since issuance of this NPRM)--would provide operators ample time to
implement requisite leak grading and repair protocols (including, but
not limited to, those pertaining to procedure development, post-repair
inspection, and recordkeeping) and manage any related compliance costs.
1. Leak Repair Requirement--Sec. 192.703(c)
Consistent with the proposed new leak grading and repair
requirements at Sec. 192.760(c) discussed below, PHMSA proposes to
eliminate the current limitation of operators' repair obligation to
leaks that are ``hazardous'' to public safety. To accomplish this,
PHMSA proposes to revise Sec. 192.703(c) to require grading and repair
criteria for all detected leaks. Additionally, PHMSA proposes that its
expanded leak repair obligations would attach to all part-192 regulated
gas pipelines because any leak from those pipelines entails risks to
one or both of public safety and the environment. While any leak of
methane from a gas pipeline system necessarily entails environmental
harm proportional to the amount of methane released to the atmosphere,
PHMSA proposes introducing minimum sensitivity standards for leak
detection equipment at Sec. 192.763 (discussed below) in recognition
that some leaks are so small that the harm they present does not
warrant expending the resources necessary to detect and repair them,
particularly where the leak is approaching the limits of detection with
commercially available advanced technologies. This approach is
consistent with Congress's direction in the PIPES Act of 2020 for PHMSA
to require that operators repair or replace ``each leaking pipe, except
a pipe with a leak so small that it poses no potential hazard.'' Under
the proposed approach, some very small leaks which would escape
detection would not qualify as a ``leak or hazardous leak'' under Sec.
192.3, and thus would not be repaired.
2. Replacement of Pipelines Known to Leak--Sec. 192.605
Among the self-executing mandates within section 114 of the PIPES
Act of 2020 is a requirement that pipeline operators update their
procedures to provide for minimizing releases of natural gas;
eliminating hazardous leaks of natural gas and any other flammable,
toxic, or corrosive gas; and the replacement or remediation of
pipelines known to leak based on their material (including cast iron,
unprotected steel, wrought iron, and historic plastics with known
issues), design, or past operating and maintenance history. PHMSA
proposes to incorporate that self-executing statutory language within
Sec. 192.605's list of prescribed content for the operations,
maintenance, and emergency procedures of gas transmission,
distribution, offshore gathering, and Types A, B, and C gathering
pipelines. Affected operators may implement this proposed regulatory
amendment by updating (to the extent they have not done so already in
complying with the self-executing statutory mandate) their operating,
maintenance, and emergency procedures to contain protocols guiding
decision-making on whether replacement or remediation of a particular
pipeline or its components would be a more durable and effective
solution for remediating or preventing leaks that entail public safety
and the environmental harms. PHMSA submits that operator protocols
could (in addition to referencing the leak-prone materials identified
in section 114 language) reference authoritative resources (e.g., State
pipeline safety regulatory actions, PHMSA pipeline failure
investigation reports and advisory bulletins, NTSB findings, or
industry efforts) to assist in identifying pipelines known to leak and
evaluating whether replacement or remediation would be more appropriate
in each case, as discussed in the context of distribution pipeline
leakage surveys in section IV.A.1. PHMSA invites comment on the value
of either explicitly listing leak-prone materials (either within part
192 or within periodically-issued implementing guidance). Comments on
this question are especially helpful if they address the potential
safety and environmental benefits and potential costs of a particular
approach, including whether that approach would be technically
feasible, cost-effective, and practicable.
PHMSA's proposed revision to Sec. 192.605 addressing replacement
of pipelines known to leak would apply only to gas transmission,
distribution, and part 192-regulated gathering lines which are subject
to the self-executing statutory mandate. The more general requirement
from section 114 of the PIPES Act to have procedures addressing
minimizing releases of natural gas are proposed for part 192-regulated
gas pipeline facilities in Sec. 192.605, UNGSFs in Sec. 192.12, and
LNG facilities in Sec. Sec. 193.2503 and 193.2605. That proposal is
discussed in section IV.F. PHMSA solicits comment regarding whether any
final rule in this rulemaking proceeding should extend the proposed
revision addressing replacement of pipelines known to leak to gas
pipeline facilities other than piping systems (in particular, part 193
LNG facilities and UNGSFs). Comments on this question are especially
helpful if they address the potential safety and environmental benefits
and potential costs of a particular approach, including whether that
approach would be technically feasible, cost-effective, and
practicable.
3. Compressor Stations--Sec. 192.703(d)
As described in section II.B of this NPRM, EPA has imposed methane
emissions standards at 40 CFR part 60 for the oil and gas industry
establishing fugitive emissions monitoring and repair requirements for
gas transmission compressor stations and gas gathering boosting
stations constructed, reconstructed, or modified after September 18,
2015 (subpart OOOOa). EPA has also proposed (1) a new 40 CFR part 60,
subpart OOOOb that would update standards for gas transmission
compressor stations and gas gathering boosting stations installed,
reconstructed or modified after November 15, 2021, and (2) nationwide
emissions guidelines that would be
[[Page 31939]]
located at 40 CFR part 60, subpart OOOOc addressing methane emissions
from oil and gas existing sources including fugitive emission
components at existing gas transmission compression stations and gas
gathering boosting stations that would not be subject to its proposed
40 CFR part 60, subpart OOOOb standards.\243\
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\243\ See EPA SNPRM.
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Given EPA's existing and proposed robust methane emissions
standards, PHMSA proposes a narrow exception from some of the proposed
requirements for gas transmission and gas gathering compressor stations
that would already be subject to monitoring and repair requirements
within EPA's current 40 CFR part 60, subpart OOOOa regulations,
proposed subpart OOOOb updates and subpart OOOOc methane emissions
guidelines (as implemented through EPA-approved State plans with
standards at least as stringent as EPA's emission guidelines in subpart
OOOOc or implemented through a Federal plan).\244\ Specifically, PHMSA
proposes exception from each of its requirements pertaining to leak
repair (Sec. 192.703(c)), leakage survey and patrol (Sec. Sec.
192.705 and 192.706), leak grading and repair (Sec. 192.760), ALDPs
(Sec. 192.763) and qualification of leak detection personnel (Sec.
192.769). Operators would, notwithstanding the exception from other
elements of Sec. 192.760, remain obliged to retain records associated
with leak repairs pursuant to Sec. 192.760(i) to ensure appropriate
documentation of change and trend analysis on those facilities, as well
as adequate documentation to support regulatory oversight activity by
pertinent State and Federal regulatory authorities. To establish clear
boundaries for the exception, PHMSA proposes that the exception would
cover those components located within the first block valve entering or
exiting the facility (exclusive of that block valve)--which valves mark
the boundary of station overpressure protection pursuant to Sec.
192.167.
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\244\ Gas pipeline facilities that would be subject to this
proposed exception would remain PHMSA-jurisdictional gas pipeline
facilities otherwise subject to parts 191 and 192 requirements and
PHMSA regulatory oversight.
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EPA's proposed regime at 40 CFR part 60 for monitoring fugitive
methane emissions from gas transmission compression stations and gas
gathering boosting stations provides public safety and environmental
protection comparable to PHMSA's proposals in this NPRM.\245\ EPA
regulations at 40 CFR 60.5397a(g)(2) within subpart OOOOa require
quarterly \246\ methane emissions monitoring surveys of leaks from all
gas transmission compression and gas gathering boosting systems--more
frequent than PHMSA's proposed leakage survey revisions for all but
those facilities in HCAs within Class 4 locations. EPA requirements
require those surveys be performed using leak detection equipment--
either optical gas imaging or another ``instrument'' (such as FID) with
sensitivity of at least 500 ppm that complies with method DA in
appendix A-7 to 40 CFR part 60--standards that are similar to the leak
detection equipment contemplated by this NPRM. EPA regulations require
an operator first attempt repair of any fugitive emissions so detected
within 30 days and complete repairs within 30 days of that first
attempt--equivalent to the 30-day repair timeline for grade 2 gas
transmission pipeline leaks in HCAs and class 3 and class 4 locations
proposed in this NPRM but more aggressive than the proposed 6-month
timeline for repair of grade 2 leaks in non-HCA class 1 and class 2
locations. And although the EPA's repair timelines may be less
demanding than those proposed in this NPRM for grade 1 leaks, PHMSA
understands that EPA's more frequent required surveys would ensure
timely detection and remediation of leaks on gas transmission
compression stations and gas gathering boosting stations. Further,
allowing operators to direct compliance efforts toward EPA's regulatory
regime rather than proposing additional requirements for EPA-regulated
facilities ensures that operator resources are focused on methane
emissions reduction rather than overlapping compliance frameworks.
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\245\ EPA's updated methane emissions new source performance
standards in its proposed 40 CFR part 60, subpart OOOOb (new
sources) and accompanying methane emissions guidelines at subpart
OOOOc (existing sources) are not yet final; however, PHMSA considers
the monitoring and repair elements of those proposals to be at least
as protective of public safety and the environment as corresponding
existing requirements 40 CFR part 60, subpart OOOOa. However, should
proposed subparts OOOOb and OOOOc not be finalized, only gas
transmission compression and gas gathering boosting stations subject
to 40 CFR part 60, subpart OOOOa would be eligible for the exception
proposed in this NPRM.
\246\ While the final rule titled ``Oil and Natural Gas Sector:
Emissions Standards for New, Reconstructed, and Modified Sources
Review'' (85 FR 57018 (Sept. 14, 2020)) removed all methane
standards from 40 CFR part 60, subpart OOOOa, including the
quarterly monitoring and repair requirements for methane fugitive
emissions at compressor stations at 40 CFR 60.5397a(g)(2), Congress
subsequently disapproved that final rule by a joint resolution (Pub.
L. 117-23) enacted pursuant to the Congressional Review Act (Pub. L.
104-121). The president signed that joint resolution into law. As a
result, the EPA's September 2020 final rule is treated as if it had
never taken effect, and the methane standards in subpart OOOOa
promogulated in 2016 remain in effect. See EPA's Q&A for more
information. https://www.epa.gov/system/files/documents/2021-07/qa_cra_for_2020_oil_and_gas_policy_rule.6.30.2021.pdf.
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In the event that EPA's proposed regulations at subparts OOOOb and
OOOOc are not in effect because they have not yet been finalized or for
any other reason, the proposed exception would not apply and the leak
detection, grading, and repair requirements proposed herein would apply
to gas transmission and gas gathering compressor station facilities.
PHMSA invites comment on the appropriateness of this proposed
exception and the specific regulatory requirements within its proposed
scope (to include comments regarding any potential regulatory gaps that
may arise from this exception) for consideration in any final rule in
this proceeding. Should stakeholders submit proposed alternatives
content for this exception, those alternatives would be most helpful if
they are supported by evaluation of the safety or environmental
benefits, technical feasibility, cost-effectiveness, and
practicability.
4. Grade 1 Leaks--Sec. 192.760(b)
A grade 1 leak is the highest priority grade and represents an
existing or probable hazard to persons, property, or an existing, grave
hazard to the environment. A grade 1 leak is an urgent or emergency
situation--for this reason, PHMSA proposes that operators must be
required to take ``immediate and continuous'' action to eliminate the
hazards to public safety and the environment. As soon as an operator
determines a grade 1 leak exists, it must immediately dispatch
personnel to address hazards to people or the environment and undertake
other actions (including, but not limited to, those identified at
proposed Sec. 192.760(a)(2), most of which track requirements
elsewhere in PHMSA regulations) to minimize risks to public safety and
the environment. The appropriate ``immediate and continuous action[s]''
taken by an operator would necessarily depend on the nature of the leak
and pipeline operational and environmental conditions. For example, the
``immediate and continuous action[s]'' required of the operator of a
submerged, offshore pipeline in responding to a grade 1 leak on its
system may entail different engineering actions or considerations than
an operator of an onshore, non-buried, low-pressure pipeline with a
grade 1 leak.
[[Page 31940]]
PHMSA's proposed grade 1 leak criteria elaborate that, at a
minimum,\247\ a grade 1 leak includes any of the following
characteristics:
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\247\ Operators may decide to adopt additional grade 1 criteria
(or, for that matter, grade 2 criteria) supplementing the baseline
criteria PHMSA proposes herein.
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Any leak that, in the judgment of operating personnel at
the scene, is of sufficient magnitude to be an existing or probable
hazard to persons or property, or a grave hazard to the environment;
Any amount of escaping gas that has ignited;
Any indication that gas has migrated into a building,
under a building, or into a tunnel;
Any reading of gas at the outside wall of a building, or
areas where gas is likely to migrate to an outside wall of a building;
Any reading of 80% or greater of the LEL in a confined
space; \248\
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\248\ Several of the grading criteria reference gas readings and
are expressed as percent of the lower explosive limit (LEL). The LEL
is the minimum required concentration of gas necessary for the gas
to ignite when exposed to an ignition source. Percent LEL measures
how close measured gas concentration is to reaching a flammable
atmosphere. The LEL of natural gas is 5% gas by volume. However, the
LELs for other flammable gases vary (e.g., the LEL for hydrogen gas
is 4% gas by volume). A reading of 100% or more of LEL indicates
that a flammable atmosphere is present, provided there is a
sufficient concentration of oxygen present to support combustion and
the upper explosive limit (UEL) is not reached. The percent LEL is
typically measured during a leak investigation with a combustible
gas indicator.
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Any reading of 80% or greater of the LEL in a substructure
(including gas associated substructures of a gas pipeline or non-
associated gas pipelines), from which gas would likely migrate to the
outside wall of a building;
Any leak that can be seen, heard, or felt by human senses;
or
Any leak reportable as an incident as defined in Sec.
191.3.
PHMSA's proposed grade 1 leak criteria resemble those in the GPTC
Guide and, consistent with that framework, are intended to prioritize
for immediate repair those leaks that pose a significant hazard to
people and property. However, PHMSA proposes important differences
designed to address gaps in safety and environmental protection. First,
PHMSA proposes to characterize a grade 1 leak to include leaks with
grave environmental harms. Including such leaks in the grade 1 leak
criteria is consistent with the mandate for this NPRM in section 113 of
the PIPES Act of 2020 and would reduce public safety risks. Any leak of
methane from a gas pipeline system necessarily entails environmental
harm proportional to the total release volume by contributing to
climate change. PHMSA's proposed language therefore distinguishes
between public safety risks (which can be existing or contingent under
the historical GPTC Guide framework) and the certain environmental
harms from leaks of methane and other gas. PHMSA proposes grade 1
criteria scaled language (``grave hazard to the environment'') to
acknowledge the magnitude of that harm from methane or other gas
released from leaks can vary from one leak to the next. A leak
satisfying one or more of its proposed grade 1 criteria would be a
release of gas involving a risk of ignition that is sufficient to be an
existing or probable future hazard to public safety, or release of
sufficient volume that poses a grave hazard to the environment.
Proposed Sec. 192.760(b)(1)(vi) also classifies as a grade 1 leak
any reading of 80% LEL or greater in a substructure (subterranean
structures too small for a human to enter) from which gas would likely
migrate to the outside wall of a building. Unlike the GPTC Guide, the
proposed criteria would include substructures associated with the
operator's gas pipeline. A gas-associated substructure includes
facilities such as small valve boxes and other vaults not intended for
human entry. While it is not unusual for some gas to accumulate in gas-
associated substructure, a potentially explosive concentration of gas
with the potential to migrate to nearby buildings is an immediate
public safety hazard regardless of whether a substructure is associated
with a gas pipeline or not. PHMSA also proposes conforming revisions to
Sec. 192.3 to introduce definitions for the terms ``substructure,''
gas-associated substructure,'' and ``confined space'' to facilitate
operator compliance and PHMSA and State regulatory oversight.
Proposed Sec. 192.760(b)(1)(vii) would classify any leak that can
be seen, heard, or felt as a grade 1 leak. In comparison, Table (3a) in
the GPTC Guide limits this criterion to leaks that are in a location
that may endanger the public or property. Applying the seen, heard, or
felt criteria to leaks regardless of location ensures operator field
personnel have a standard for classifying leaks that potentially cause
significant environmental or safety consequences in the form of methane
emissions and other pollutants. The visible indications of a gas leak
may include for example, ground disturbances, a jet or vapor cloud of
condensation, or blowing debris. A gas leak can also emit a hissing
sound or, for larger leaks, sounds resembling a jet engine or train.
Tactile indications of a leak include force from a jet of gas or
vibrations in the pipe or soil. Each of these physical markers of a
pipeline leak are typically more apparent on higher-pressure, larger
volume leaks. PHMSA does not consider impacts to vegetation to be a
definitive indication of a grade 1 leak for these purposes. However, an
operator should consider if there are severe or widespread impacts to
vegetation during a leakage investigation. Additionally, a leak on an
offshore pipeline that is visible from the surface (i.e., bubbles or
condensate sheen) would be classified as a grade 1 leak under this
criterion.
Lastly, PHMSA proposes that any leak reportable as an incident
under part 191 would be classified as a grade 1 leak. The definition of
``incident'' in Sec. 191.3 would include any event involving the
release of gas from a pipeline that results in one or more of the
following consequences:
A death or personal injury necessitating in-patient
hospitalization;
Estimated property damage of $129,300, excluding the cost
of lost gas, (adjusted for inflation for calendar year 2022); or
Unintentional estimated gas release of 3 MMCF or more.
This criterion would address gaps in the GPTC Guide's current grade
1 leak criteria and would help ensure the repair of leaks that involve
very large release volumes, or which are known to result in significant
public safety and environmental harms. Further, if a previously
detected leak later results in an incident causing significant safety
and environmental consequences, then it almost certainly would have
been an ``existing or probable hazard'' to persons and the environment
at the time of detection and should have been graded and repaired
accordingly. PHMSA invites comments on other potential criteria for
identifying grade 1 leaks subject to immediate repair (for potential
inclusion within a final rule in this proceeding), including the
utility of adopting a quantified emissions rate criteria for grade 1
leaks or other characteristics indicative of a grave environmental
hazard, in addition to criteria proposed above. Comments are especially
helpful to PHMSA when they identify a specific quantified emissions
rate threshold or other specific characteristics supported by research
or operational experience, along with the potential safety and
environmental benefits and potential costs of a particular approach
(including whether that approach would be technically feasible, cost-
effective, and practicable).
[[Page 31941]]
5. Grade 2 Leaks--Sec. 192.760(c)
PHMSA also proposes to modify the GPTC Guide's characterization of
grade 2 leaks to introduce a reference to environmental harms from
those leaks: a grade 2 leak would be a leak which presents a probable
future hazard to public safety or a significant hazard to the
environment. PHMSA intends the proposed characterization of grade 2
leaks to include those leaks that are not as urgent a hazard to either
public safety or the environment as a grade 1 leak that it would
require immediate and continuous action to eliminate the hazard, but
which are significant enough to warrant timely repair.
PHMSA proposes to classify a grade 2 leak as any leak (other than a
grade 1 leak) with any of the following characteristics:
A reading of 40% or greater of the LEL under a sidewalk in
a wall-to-wall paved area that does not qualify as a grade 1 leak;
A reading of 100% of the LEL under a street in a wall-to-
wall paved area that does not qualify as a grade 1 leak;
A reading between 20% and 80% of the LEL in a confined
space;
A reading less than 80% of the LEL in a substructure
(other than gas associated substructures) from which gas could migrate;
A reading of 80% or greater of the LEL in a gas associated
substructure from which gas is not likely to migrate;
Any reading greater than 0% gas on a transmission or Types
A or C gas gathering pipeline that does not qualify as a grade 1 leak;
Any leak with a leakage rate of 10 CFH or more that does
not qualify as a grade 1 leak;
Any leak of LPG or hydrogen that does not qualify as a
grade 1 leak; or
Any leak that, in the judgment of operator personnel at
the scene, is of sufficient magnitude to justify scheduled repair
within 6 months or less.
The proposal has important differences from the GPTC Guide that are
designed to address gaps in safety and environmental protection.
Specifically, PHMSA proposes to delete qualifying language in grade 2
criteria to minimize ambiguity and ensure enforceability of the
proposed repair standards. For illustration, in example A.B.2. in Table
3b of the GPTC Guide, any reading of 100% LEL or greater under a street
in a wall-to-wall paved area ``that has significant gas migration''
that is not a grade 1 is considered a grade 2 leak, however what
constitutes ``significant'' gas migration is not defined or
straightforward to enforce. Instead, the NPRM proposes to apply this
standard to any such concentration of gas, which is itself hazardous to
public safety or the environment, with any migration. Similarly, PHMSA
does not propose to condition criteria for grade 2 leaks in
substructure on the likelihood that ``gas would likely migrate creating
a probable future hazard'' since a concentration of 80% or more of LEL,
near the explosive limit, within a substructure is itself a probable
future hazard to public safety. Additionally, PHMSA proposes to add a
new criterion for all leaks from LPG systems that do not qualify as a
grade 1 leak, consistent with an observation in the GPTC Guide that
since LPG is heavier than air and does not dissipate like natural gas,
``few [LPG] leaks can safely be classified as Grade 3.'' \249\
Likewise, PHMSA proposes that Grade 2 is the minimum priority grade for
leaks of gaseous hydrogen. PHMSA understands these heightened safety
requirements (compared to natural gas pipelines) are warranted because
hydrogen is itself a flammable gas with a lower explosive limit and
lower autoignition temperature than methane. And research summarized by
the National Renewable Energy Laboratory indicates that overpressure
blast risk in enclosed spaces and increases with the proportion of
hydrogen within hydrogen/natural gas blends (particularly for
concentrations above 50% hydrogen) and that, for transmission line
ruptures, fatal injury risk increases as either proximity to the
pipeline or the share of hydrogen in a natural gas blend
increases.\250\
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\249\ See Table 3 C in Appendix G-192-11A of the GPTC Guide.
\250\ Melania, et al., National Renewable Energy Laboratory
Technical Report TP-5600-51995, ``Blending Hydrogen into Natural Gas
Pipeline Networks: A Review of Key Issues'' at 16-17 (Mar. 2013),
https://www.nrel.gov/docs/fy13osti/51995.pdf.
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PHMSA also proposes to include a new emissions rate criterion for
grade 2 leaks: any leak with an emissions rate equal to or greater than
10 CFH would need to be classified as a grade 2 leak. PHMSA expects
this criterion would ensure prioritized repair of such environmentally
damaging leaks even if other grade 1 or grade 2 criteria are not met.
PHMSA further notes that this proposed 10 CFH criterion is the same
criterion used by PG&E's Super Emitter Program, which was based on data
showing that methane leaks larger than 10 CFH represented only 2% of
all leaks by number but over half of all emission volumes on PG&E's gas
distribution system.\251\ PHMSA's selection of a 10 CFH emissions rate
is consistent with the AGA et al. assertion that a significant share of
emissions from natural gas pipeline systems can be caused by a
relatively small proportion of leaks within each leak category.\252\ A
2016 analysis by Brandt, et.al., of 15,000 emissions measurements from
prior studies found that 5% of releases contributed to over half of
total emissions volumes.\253\ An emissions rate of 10 CFH correlates to
emissions of ca. 87,600 ft\3\ of methane (roughly 1,600 kg of methane)
if left unrepaired for a year.\254\
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\251\ Rongere, Francois. ``Lessons Learned from the First Year
of the Super Emitter Program.'' PG&E Nov. 5, 2019. https://www.epa.gov/sites/default/files/2019-12/documents/lessonslearnedfirstyearsuperemitterprogram_francoisrongere.pdf;
Lamb, Brian K., et al. ``Direct Measurements Show DECREASING Methane
Emissions from Natural Gas Local Distribution Systems in the United
States.'' Environmental Science & Technology, vol. 49, no. 8, 2015,
pp. 5161-5169., doi:10.1021/es505116p.
\252\ AGA et al. at 5.
\253\ Brandt AR, Heath GA, Cooley D. Methane Leaks from Natural
Gas Systems Follow Extreme Distributions. Environ Sci Technol. 2016
Nov 15;50(22):12512-12520. Doi: 10.1021/acs.est.6b04303. Epub 2016
Oct 26. PMID: 27740745.
\254\ The value here was calculated assuming a density of
methane of 0.01926 kg/ft\3\.
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PHMSA considered alternative approaches to its proposed emissions
rate criterion but is concerned about their practicability. PHMSA
invites comment on appropriate, alternative grade 2 emissions rate
criterion thresholds and calculation methodologies--particularly
considering the extent to which emissions from below ground leaks could
be incorporated. PHMSA considered an approach employed by the
Commonwealth of Massachusetts which categorizes methane leaks from
natural gas pipelines as ``environmentally significant'' grade 3 leaks
if they have a barhole reading of 50% gas in air or higher, or a
measured leak migration extent of 2,000 square feet or greater.\255\ In
Massachusetts, leaks with a migration extent from 2,000 to 10,000
square feet must be repaired within 2 years and leaks with a migration
extent greater than 10,000 square feet must be repaired within 12
months. This method--which measures the extent of below-ground
migration as a proxy for the release rate--could be a relatively
straightforward means to classify large-volume, below-ground leaks
(particularly for gas distribution systems). However, since gas
migration can be affected greatly by soil and weather conditions, the
2,000 square feet element of this approach may not be
[[Page 31942]]
appropriate for a nationwide standard applicable to natural gas
distribution, gathering and transmission pipelines across a diversity
of operational and environmental conditions, as well as other gases
transported in part 192-regulated gas pipelines. Variations in gas
migration due to operational and site-specific environmental
considerations may then result in missing or over-stating large-volume
leaks. PHMSA also considered a relative emissions criterion, such as
requiring an operator to repair leaks with an emissions quantity larger
than the median leak rate on the operator's system by release rate
(estimated with an advanced mobile leak detection technology, high-flow
sampler, or equivalent method) or measured gas concentration. While
that approach would be comparatively simple to implement, it could
result in inconsistent repair requirements across operators as well as
perverse consequences: an operator with a well-designed and maintained
system with few large-volume leaks would have the same proportion of
priority repairs as an operator with poor maintenance practices or
significant mileage of leak-prone pipe such that the latter operator
could defer repair of potentially large leaks.
---------------------------------------------------------------------------
\255\ 220 CMR 114.07(1)(a).
---------------------------------------------------------------------------
PHMSA invites comments on the proposed criteria for identifying
grade 2 leaks that constitute a significant hazard to the environment,
including the practicability of using a specified emissions rate
criterion (and whether 10 CFH is the appropriate emissions rate for
grade 2 leaks), for potential inclusion within a final rule in this
proceeding. Comments on this question are especially helpful if they
identify a specific emissions rate, gas concentration, or other
measurement supported by research or operational experience for
identifying leaks that should be subject to shorter repair timelines
due to their potential environmental impacts over time. PHMSA further
invites comments on how quantification of emissions rates are or could
be integrated into operator's leak survey, investigation, and
management procedures. Finally, PHMSA seeks comments on whether other
criteria could be used to identify leaks with significant environmental
harm. Comments on these questions are especially helpful to PHMSA when
they identify the potential safety and environmental benefits and
potential costs of a particular approach (including whether that
approach would be technically feasible, cost-effective, and
practicable).
PHMSA also proposes a minimum grade 2 classification for any leak
on a gas transmission or Type A or C gathering pipeline. The GPTC Guide
identifies leaks on pipelines operating at 30% SMYS or greater (i.e.,
most gas transmission lines) in Class 3 or Class 4 locations, other
than grade 1 leaks, as grade 2 leaks and assigns a six-month repair
requirement. This NPRM proposes to apply this repair timeline to all
gas transmission pipelines, and Types A and C gathering pipelines
because of the similar design and operating characteristics--and
therefore public safety and environmental risk profiles--of those
pipelines. In particular, transmission and Type A and Type C gathering
lines operate at a high stress level and therefore, as described in
section II.D.3, there is a correspondingly higher risk of a rupture if
the condition that caused the leak deteriorates further. PHMSA does not
propose a similar requirement for offshore gas gathering pipelines
because many of those pipelines operate far from the general public and
at lower pressures than gas transmission and Type A gathering pipelines
such that their public safety and environmental risks are
distinguishable.
PHMSA also proposes more timely repair of grade 2 leaks than
contemplated by the GPTC Guide, which requires operators to repair such
leaks within 12 months of detection. Specifically, PHMSA proposes a
default requirement for grade 2 leak repairs to be completed within the
earlier of six months of detection, or the repair timeline specified in
the operator's procedures or IM plan. The accelerated default repair
timeline would better address the significant public safety and
environmental risks grade 2 leaks entail. In addition, operators
subject to the six-month default repair timeline for grade 2 leaks
would be required to re-evaluate each grade 2 leak every 30 days until
the leak has been repaired, which is intended to ensure that those
leaks do not degrade into a grade 1 leak.
PHMSA proposes shorter repair deadlines for grade 2 leaks that are
known on or before the effective date of a subsequent final rule in
this proceeding. Further, PHMSA would require these leaks be repaired
within one year from the publication date, consistent with the 12-month
repair schedule in the GPTC Guide some operator practices may currently
reference. Additionally, due to the greater public safety risks of a
grade 2 leak from either a gas transmission or Type A gathering
pipeline, each within HCAs or densely populated Class 3 or Class 4
locations, PHMSA proposes to require that these leaks be repaired
within 30 days of detection, with an operator making continuous effort
to monitor and repair the leak and eliminate the potential hazard if
repairs cannot be completed within the prescribed timeline. As
previously discussed in section II.C., leaks on gas transmission line
pipe are less common than leaks on gas distribution pipeline pipe.
However, a leak on a gas transmission or Type A gathering pipeline will
likely result in greater release volumes and higher risk of ignition
than distribution or Type B gathering lines due to the higher operating
pressures and flow volumes typical of transmission and Type A gathering
pipelines. The higher operating stress level on gas transmission and
Type A gathering pipelines also entail a higher risk of rupture from
degradation of leaks over time.
Lastly, PHMSA proposes to require each operator's leak grading and
repair procedures to include a methodology for prioritizing grade 2
leak repairs, including criteria for determining leaks that must be
repaired within 30 days or less. PHMSA's proposed criteria are based on
calendar days rather than the working days under the GPTC Guide, which
is consistent with existing guidance in Table 3a of the GPTC Guide. The
operator's methodology must also include an analysis of the estimated
volume of leakage since detection or the date of the last survey
(whichever is earlier), migration of gas emissions, proximity of the
leaking gas to buildings and underground structures, the extent of
pavement, and soil types and conditions that affect the possibility for
hazardous gas migration, such as frost conditions or soil moisture.
This approach is consistent with the guidance in the GPTC Guide that
certain grade 2 leaks justify repair on an accelerated schedule, and
further mandates operators to consider safety and environmental
protection when prioritizing repair efforts.
6. Grade 3 Leaks--Sec. 192.760(d)
PHMSA proposes that any leak that does not meet the criteria for a
grade 1 or a grade 2 leak be classified as a grade 3 leak, which would
be the lowest priority leak category. PHMSA has provided a non-
exhaustive list of grade 3 criteria, including the following: a
positive reading of less than 80% LEL in gas-associated substructures
from which gas is unlikely to migrate, any positive reading under a
street in an area without wall-to-wall pavement where gas is unlikely
to migrate to the outside wall of nearby buildings, or a
[[Page 31943]]
gas reading less than 20% LEL in a confined space. These examples are
derived from the GPTC Guide, with additional clarifying language,
``from which gas is unlikely to migrate,'' consistent with PHMSA's
understanding of the purpose of the pertinent GPTC Guide example.
The GPTC Guide and most State requirements do not define leak
repair deadlines for grade 3 leaks. However, even a small leak can
result in significant emissions and harm to the environment and public
safety if it is allowed to release indefinitely without repair.
Moreover, even small leaks have the potential to progress to more
serious integrity incidents and failures, such that a grade 3 leak
could develop into a more hazardous condition if ignored indefinitely.
PHMSA therefore proposes a 24-month repair deadline for grade 3 leaks
detected after the effective date of any final rule in this proceeding;
this repair timeline would ensure timely repair of leaks while
facilitating operator prioritization of repairs of higher-risk grade 1
and 2 leaks. This proposed repair schedule is 12 months more aggressive
than the 36-month deadline adopted by the State of Texas, but
consistent with other standards such as the delayed repair permitted
for fugitive emissions monitoring in the EPA 40 CFR OOOOa standards for
repairs where immediate repair is not feasible.\256\ On the other hand,
some States have more aggressive timelines, suggesting that the
proposed timeline remains feasible for repair of buried pipeline
facilities. For example, Missouri requires repair of ``class 2 leaks''
\257\ within 45 days, unless the pipeline is scheduled for replacement
within 1 year.\258\ The 24-month repair deadline further ensures that
all leaks discovered during a leakage survey are repaired prior to the
next leakage survey (the longest proposed survey interval is once every
3 years for distribution pipelines outside of business districts, see
proposed Sec. 192.723), which would better prevent further growth in
the backlog of unrepaired leaks than a 36-month repair deadline. Due to
the likely large number of existing grade 3 leaks across the U.S.,
exemplified by the backlog of 10,000 unrepaired leaks on 11 New York
distribution systems described in section II.D.3,\259\ PHMSA proposes a
repair deadline of 3 years after the publication date of the final rule
for grade 3 leaks known to exist on or before the effective date of any
final rule. This repair deadline is intended to give operators time to
prioritize timely repair of higher-priority, previously-known-to-exist
grade 2 leaks, while still ensuring timely repair of grade 3 leaks
known to exist at the time a final rule publishes. Additionally, PHMSA
proposes to require that each grade 3 leak must be re-evaluated at
least once every six months until the repair of the leak is completed.
The re-evaluation is designed to assess if the leak or the leak
environment has changed in a way that may justify an upgrade to a grade
1 or grade 2 leak.
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\256\ 40 CFR 60.5397a(h)(3).
\257\ This term is unrelated to class 2 locations set forth in
49 CFR 192.5.
\258\ 20 [Missouri] Code of State Regulations 4240-
40.030(14)(C)(2).
\259\ State of New York Department of Public Service, Case 21-G-
0165, ``2020 Pipeline Safety Performance Measures Report'' at
Appendix K (June 17, 2021).
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Lastly, as previously discussed in section II.E of this NPRM
certain types of pipe materials cause a disproportionate number of
leaks. In particular, pipe and fittings made of cast iron, unprotected
steel, wrought iron, and historic plastics with known issues are more
likely to leak than coated and protected steel and modern plastics.
Replacing these pipelines and other pipelines known to leak can be an
effective, long-term solution to systematic leak susceptibility for
such pipelines. For example, in AGA's presentation at PHMSA's May 2021
public meeting on methane leak detection and repair, they noted that
operators cast iron and bare steel distribution pipelines accounted for
approximately 75 percent of reported leak repairs.\260\ These
replacement programs multiply benefits by eliminating both existing and
future leaks. To accommodate pipe replacement programs, particularly on
leak prone facilities, PHMSA proposes to allow that a grade 3 leak may
be monitored rather than repaired if the leaking pipeline is scheduled
for replacement or abandonment, and is in fact replaced or abandoned,
within five years from the date of detection of the leak. This five-
year timeline is intended to accommodate the time necessary for
planning, permitting, engineering, design, and construction of pipeline
replacement projects. This proposed timeline is consistent with PHMSA's
Natural Gas Distribution Infrastructure Safety and Modernization Grants
program, which permits applicants to elect a period of performance of
up to 5 years for pipe replacement projects.\261\ Due to the heightened
potential hazards to public safety and the environmental, PHMSA does
not propose a similar allowance for grade 1 and grade 2 leaks.
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\260\ Sames, Christina. ``Pipeline Leak Detection, Leak Repair,
and Methane Emissions.'' AGA. May 5, 2021. https://primis.phmsa.dot.gov/meetings/FilGet.mtg?fil=1139.
\261\ See PHMSA, ``Frequently Asked Questions: FY 2022 Natural
Gas Distribution Infrastructure Safety and Modernization Grant
Notice of Funding Opportunity (NOFO)'' (July 29, 2022). FAQ 67 at
page 16. https://www.phmsa.dot.gov/grants/pipeline/ngdism-nofo-faqs.
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PHMSA seeks comments on the proposed repair timelines for grade 3
leaks (for potential inclusion within a final rule in this proceeding),
including whether shorter repair timelines would be appropriate for
grade 3 leaks existing as of publication of a final rule, or for grade
3 leaks eliminated by pipeline replacement. Comments on these questions
are especially helpful when they provide specific suggestions supported
by research or operational experience, along with the potential safety
and environmental benefits and potential costs of a particular approach
(including whether that approach would be technically feasible, cost-
effective, and practicable).
7. Post-Repair Inspection--Sec. 192.760(e)
PHMSA proposes to specify that a leak repair may only be classified
as complete if the operator obtains during a post-repair inspection a
gas concentration reading of 0% gas by volume at the leak location. The
equipment used in leak investigations, including this post-repair
inspection, must meet the proposed 5 ppm sensitivity standards in Sec.
192.763(a)(1)(ii). This proposed inspection requirement ensures that
the repair was effective and provides a definite, final repair date for
operator records. For leaks that are eliminated by routine
maintenance--such as cleaning, lubrication, or adjustment--a post-
repair inspection would not be required for any leaks from aboveground
facilities or for grade 3 leaks from other facilities.
PHMSA proposes that an inspection must occur between 14 and 30 days
after the date of the repair. PHMSA intends the minimum interval before
the first repair inspection to help ensure that the inspection
accurately reflects the condition of the repair, since repairs may have
a 0% reading at the moment of repair, but gas may leak over time from
an incomplete repair or the repair may fail in a 14-day period. PHMSA
is proposing a 30-day maximum to align with its proposed 30-day
monitoring requirement for grade 2 leaks. If the operator is unable to
achieve a 0% reading and determines that a grade 1 or 2 condition
exists, PHMSA proposes that the operator must take immediate and
continuous action to re-evaluate and remediate the repair so as to
[[Page 31944]]
eliminate the leak. This proposed repair timeline could accelerate the
repair of some grade 2 leaks. An accelerated timeline may be warranted
because an incomplete or failed first attempt at leak repair could
inhibit subsequent efforts to properly repair the leak. The proposed
rule requires that if the post-repair inspection indicates a gas
reading of greater than 0% gas and a grade 1 or grade 2 condition does
not exist, the operator must remediate and re-inspect the repair every
30 days until it obtains a gas concentration reading of 0%. In this
situation, remediation of a repair of a grade 3 leak would be completed
before the initial repair deadline of 24 months from the date of
initial detection. If a grade 3 condition exists during a post-repair
inspection for a leak that was originally a grade 1 or grade 2 leak at
the time of detection, the operator may consider downgrading the leak
under proposed Sec. 192.760(g), in which case the repair deadline is
determined by the repair deadline proposed under Sec. 192.760(h).
8. Upgrading and Downgrading--Sec. 192.760 (f) and (g)
PHMSA proposes to establish requirements for when and how a leak
may be upgraded to a higher-priority grade or downgraded to a lower-
priority grade. Section 192.760(f) would require that if an operator
receives information that a higher-priority grade condition exists on a
previously graded leak, the operator must upgrade the leak to that new
grade. For a leak that is upgraded, the repair deadline is the earlier
of the remaining repair deadline for the original grade, or the repair
deadline under the new leak grade measured from the date the operator
receives the information that a higher-priority grade condition exists.
This proposed approach would provide certainty regarding the repair
deadline for an upgraded leak, while avoiding the perverse consequence
that upgrading a leak would allow a more permissive repair schedule.
PHMSA also proposes to allow downgrading a leak grade only if a
repair has been attempted. This approach would allow downgrading a leak
only if the operator performed a temporary repair or attempted a
permanent leak repair but did not obtain a 0% gas reading during the
post-repair inspection under proposed Sec. 192.760(e). This would
prevent practices such as downgrading a leak after venting until gas
concentration falls below a grade 1 or grade 2 criteria, without an
effort to repair the leak itself. If a leak is downgraded, PHMSA
proposes the time period for repair would be the remaining time allowed
for repair for the downgraded leak measured from the time the leak was
first detected--an approach PHMSA expects would incentivize timely
completion of downgraded repairs and prevent extension of repair
timelines through pretextual attempts at permanent repair.
9. Extension of leak repair--Sec. 192.760(h)
PHMSA proposes to allow an extension of the repair deadline
requirements for individual leaks on a case-by-case basis. Any
extension requires notification to, and review by, PHMSA pursuant to
the procedures in Sec. 192.18. Leak repair extensions under Sec.
192.760(h) may be requested only if (1) the leak repair pursuant to an
alternative schedule would not result in increased public safety risk,
and (2) the operator can demonstrate that the prescribed repair
schedule is impracticable, an alternative repair schedule is necessary
for safety, or remediation within the specified time frame would result
in the release of more gas to the environment than would otherwise
occur if the leak were allowed to continue. For example, an alternative
repair schedule may be warranted if remediation within the timeframe
proposed in this NPRM would result in the release of more gas to the
environment from blowdown--delayed repair could minimize emissions by
coordinating blowdowns with other maintenance activity, while offering
the safety benefit of fewer emissions that could ignite. PHMSA proposes
to limit the extensions to grade 3 leaks, which inherently pose lower
risks to public safety and the environment than grades 1 and 2 leaks.
The notification to PHMSA would need to include a description of the
leak, the leaking pipeline, the leak environment, any proposed
monitoring and extended repair schedule, the justification for an
extended repair schedule, and proposed emissions mitigation methods.
10. Recordkeeping--Sec. 192.760(i)
PHMSA proposes certain recordkeeping requirements for leak
detection, investigation, grading and repair activity. Section
192.760(i) would describe recordkeeping requirements associated with
leak grading and repair; PHMSA proposes that records documenting the
complete history of investigation and grading of each leak prior to
completion of the repair would need to be retained until five years
after the date of the final post-repair inspection performed under
proposed paragraph Sec. 192.760(e). Pertinent records would include
documentation of grading monitoring, inspections, upgrades, and
downgrades. PHMSA also proposes that records associated with the
detection, remediation, and repair of each leak must be maintained for
the life of the pipeline. This permanent recordkeeping would apply to
both piping and non-piping portions of the pipeline. Should leak
detection occur during a patrol, survey, inspection, or test, the
pertinent portion of documentation for that patrol, survey, inspection,
or test would need to be retained pursuant to proposed Sec.
192.760(i). These proposed documentation requirements would support
periodic evaluation and improvement of their ALDPs pursuant to proposed
Sec. 192.763(a)(4) as well as regulatory oversight activity by PHMSA
and its State partners.
D. Qualification of Leakage Survey, Investigation, and Repair
Personnel--Sec. 192.769
Proposed Sec. 192.769 would require that operator personnel
engaged in leakage surveys, and the investigation and repair of leaks
discovered on each of gas transmission, distribution, offshore
gathering, and Type A regulated onshore gathering \262\ pipelines are
subject to the personnel qualification requirements at part 192 in
performing those activities. PHMSA proposes to clarify that leakage
surveys, investigation, and repair activities are ``covered tasks''
under part 192, subpart N and therefore covered by operator
qualification requirements in that subpart. These operations and
maintenance functions are critical to ensuring the proper operation and
integrity of gas pipelines, and therefore meet the criteria for the
four-part test for defining covered tasks in Sec. 192.801(b) (tasks
that are performed on a pipeline facility; are operations or
maintenance tasks; are required by part 192; and affect the operation
or integrity of the pipeline). Therefore, the proposed revision would
help ensure baseline regulatory requirements for personnel
qualification are met when performing those activities.
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\262\ PHMSA regulations at Sec. 192.9(c) allow operators of
Type A gas gathering pipeline to employ less comprehensive programs
in satisfying subpart N personnel qualification requirements than
employed by certain other part 192-regulated gas pipelines. PHMSA is
not proposing a different approach for personnel qualifications with
respect to personnel conducting leakage surveys and investigation
and repair of leaks on Type A gas gathering pipelines.
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PHMSA understands that the proposed personnel qualification
requirements discussed above would be reasonable, technically feasible,
cost-effective, and practicable for affected gas pipeline operators.
PHMSA understands
[[Page 31945]]
that some affected operators may already have adopted (either
voluntarily or in response to State or Federal requirements) compliant
training and personnel practices, or would be able to adapt existing
practices with minimal effort--particularly as ensuring personnel
employed in conducting leakage surveys, inspection, and repair
activities is a practice that reasonably prudent operators would adopt
in ordinary course to protect public safety and the environment from
release of pressurized (natural, flammable, corrosive, and toxic) gases
transported in their pipelines and minimize loss of commercially
valuable commodity. Viewed against those considerations and the
compliance costs estimated in the Preliminary RIA, PHMSA expects its
proposed amendments will be a cost-effective approach to achieving the
commercial, public safety, and environmental benefits discussed in this
NPRM and its supporting documents. Lastly, the NPRM's proposed
compliance timelines--which are based on an effective date of six
months after the publication date of a final rule in this proceeding
(which would necessarily be in addition to the time since issuance of
this NPRM)--would provide operators ample time to develop and provide
the requisite training for their personnel (or otherwise obtain access
to qualified personnel) and manage any related compliance costs. PHMSA
seeks comments on whether, within a final rule in this proceeding, it
would be appropriate to apply the proposed operator qualification
requirements in Sec. 192.769 to Type B and Type C regulated onshore
gas gathering lines or UNGSFs, which are not currently required to
comply with subpart N. Comments on this question are especially helpful
if they address the potential safety and environmental benefits and
potential costs of that approach, including whether that approach would
be technically feasible, cost-effective, and practicable. For gas
gathering pipelines, this could entail subjecting Type B and applicable
Type C gathering pipelines to simplified subpart N requirements similar
to Type A lines in Class 1 locations and could either apply generally
to all covered tasks, or only for leak detection, grading, and repair
activities.
E. Reporting and National Pipeline Mapping System--Sec. Sec. 191.3,
191.9, 191.11, 191.17, 191.19, 191.23, and 191.29
PHMSA proposes new and revised reporting requirements to collect
more data on pipeline leaks and other emissions. The most significant
proposed revisions would create a large-volume gas release report to
supplement existing incident reporting requirements. As is the case for
incident reports, this requirement would apply to any gas pipeline
facility covered under part 191, including jurisdictional storage and
part 193 LNG facilities. Additionally, PHMSA proposes to revise the gas
transmission, offshore gathering, and Types A, B, and C gathering, and
distribution annual report forms to include each of (1) estimated
aggregate emissions from all leaks existing on the system within the
calendar year by grade (including emissions within the calendar year
from leaks discovered in prior years), (2) other methane emissions by
source category, and (3) the number of leaks detected and repaired by
grade. PHMSA solicits comments on the potential utility of requiring
operators to report more granular leak data, such as individual leak
location, individual leak emissions, or individual leak repair timing,
in addition to the information described above. Comments on this
question are especially helpful if they address the potential safety
and environmental benefits and potential costs of a particular
approach, including whether that approach would be technically
feasible, cost-effective, and practicable.
Existing Sec. 191.3 defines an incident as a release from a gas
pipeline facility that results in death or serious injury, property
damage of $122,000 \263\ or more in calendar year 2021, or an
unintentional release of 3 MMCF or more of gas. While incident reports
provide valuable information on major emissions events with critical
safety consequences, existing incident reporting criteria and the
exclusion of intentional releases from reporting requirements means the
current reporting scheme does not capture data on many significant
emissions events.
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\263\ Adjusted for inflation on an annual basis.
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PHMSA therefore proposes at Sec. 191.19 to require a new report
for intentional and unintentional releases with a volume of 1 MMCF or
greater, excluding certain events that had been reported as incidents
under Sec. Sec. 191.9 or 191.15. For illustration, routine leaks with
an emissions rate of 10 CFH consistent with the proposed grade 2
emissions criteria at Sec. 192.760, would not be reported individually
under this section if they are repaired within the proposed repair
schedule (note that a count of all leaks would be reported on annual
reports), but larger leaks exceeding 100 kg/hr. ``super-emitter''
criteria contemplated by the EPA in their December 6, 2022 supplemental
notice of proposed rulemaking \264\ would be reported if they were not
promptly repaired such that their aggregate emissions were below the 1
MMCF threshold. Blowdowns of high-pressure lines without mitigation
measures such as those proposed in Sec. 192.770 may also meet the 1
MMCF threshold depending on the pressure and volume of the blowdown
segment. Operators would be required to submit a report within 30 days
from the date that a release known at detection to be 1 MMCF or more
was detected, or 30 days from the date that a previously detected
release became reportable. If the time the leak started is unknown,
operators should base the calculation based on estimated release volume
from the date of the most recent leakage survey. PHMSA proposes an
exception from Sec. 191.23 safety-related condition reporting
requirements for events that are reported as large-volume gas releases.
This proposed exception for large-volume incident reports would be
consistent with the existing exception at Sec. 191.23(b) for events
reported as incidents.
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\264\ EPA, ``Standards of Performance for New, Reconstructed,
and Modified Sources and Emissions Guidelines for Existing Sources:
Oil and Natural Gas Sector Climate Review,'' 87 FR 74702, 74707
(Dec. 6, 2022).
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These new, large-volume gas release reports would provide valuable
information on the primary sources and causes of vented emissions and
the causes of large-volume leaks that do not qualify as incidents,
addressing information gaps in the current incident reporting
requirements. First, information on vented emissions is not currently
collected on incident or annual report forms. The new report would
provide PHMSA and other interested stakeholders information on the
causes, consequences, and frequency of intentional, large-volume,
vented emissions to provide both regulators and operators the
information necessary to prevent reoccurrence. That information would
be also particularly useful for PHMSA and State regulatory authorities
in ensuring operator compliance with the self-executing mandate within
section 114 of the PIPES Act of 2020 for operators to update their
inspection and maintenance procedures to provide for minimization of
releases of gas from their pipeline facilities. Second, PHMSA's
proposed 1 MMCF threshold for the new large-volume gas release report
is significantly lower than the 3 MMCF threshold required under the
current incident reporting regulations, allowing PHMSA to collect
detailed
[[Page 31946]]
cause and consequence information on large-volume, intentional and
unintentional releases that may not be collected on incident reports.
PHMSA solicits comment on whether alternative reporting thresholds for
either large volume gas releases or incidents, including thresholds
below 1 MMCF, would provide higher-quality information than PHMSA's
proposed 1 MMCF threshold. Comments on this question are especially
helpful if they address the potential safety and environmental benefits
and potential costs of a particular approach, including whether that
approach would be technically feasible, cost-effective, and
practicable.
PHMSA proposes to include the above information on a new report
rather than by revising the incident definition at Sec. 191.3 to
collect focused information on fugitive and vented emissions that do
not satisfy incident reporting criteria. Operators of all gas pipeline
facilities would remain required to submit incident reports if
unintentional releases reported under this new requirement subsequently
satisfy incident reporting criteria. Operators who have already
submitted an incident report would not need to file a large-volume gas
release report under Sec. 191.19 for the same event so long as the
release volume in the incident report is within 10 percent of the total
release volume on cessation of the release. PHMSA intends for the
large-volume gas release reporting requirement to extend to Type R gas
gathering pipelines to inform PHMSA's consideration of whether fugitive
and vented emissions from those pipeline facilities warrant extension
of part 192 requirements.
PHMSA proposes to clarify what is considered property damage for
the purpose of determining whether a release is reportable as an
incident pursuant to Sec. Sec. 191.9 or 191.15. Specifically, PHMSA
proposes revision of the definition of ``incident'' at Sec. 191.3 to
exclude, when calculating estimated property damage, costs associated
with each of obtaining permits and removal or replacement of
infrastructure undamaged by the event (e.g., pavement needed for access
and repair activity) in connection with an event. This change would
respond to NAPSR Resolution 2021-01, ``A Resolution Seeking a
Modification of PHMSA's Instructions for Incident Reporting for Gas
Distribution, Gas Transmission, and Gas Gathering Systems,'' \265\
which concerns how to classify overall secondary damage beyond the
primary damage from an incident. Operators would still report these
costs as incident consequences on the applicable incident report forms;
however, they should not be included in the calculation of property
damage for determining whether a release is reportable as an incident.
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\265\ http://www.napsr.org/resolutions.html.
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PHMSA also proposes changes to the gas distribution, transmission,
offshore gathering, and regulated onshore gas gathering annual reports
required by Sec. Sec. 191.11 and 191.17, consistent with other
proposed changes regarding leak grading and repair on those facilities
and to collect information on estimated total emissions from each of
(1) leaks existing on the operator's system during the calendar year by
grade and (2), other emissions by source category. The source
categories generally mirror the categories in the GHGI, as summarized
in section II.C.2. While existing annual report forms include limited
data on leaks repaired in the preceding year, they lack other data--
including the number and grade of leaks detected in the preceding year,
the grade of leaks repaired in the preceding year, and estimated
release volumes from those leaks--important for PHMSA and State
regulators to understand the frequency of leaks, the significance for
public safety and the environment from those leaks, and adequacy of
operator leak detection and repair programs. PHMSA therefore proposes
to revise the annual report forms for operators of gas distribution,
offshore gathering, regulated onshore gathering, and transmission
pipeline facilities to collect data on each of the following: the
number of leaks detected and repaired by grade (see proposed Sec.
192.760); the estimated aggregate emissions from all existing leaks
(whether detected in the reporting year or not) by grade, and estimated
emissions from other sources by source categories. PHMSA further
proposes that, because this NPRM does not provide for leak grading
requirements for LNG facilities, operators of those facilities would
need to report data on each of the number of methane leaks detected and
repaired during the annual reporting period pursuant to proposed Sec.
193.2624, the number of unrepaired leaks at the end of the annual
reporting period, and estimated fugitive methane emissions (each by EPA
GHGRP source category) from all methane leaks identified pursuant to
proposed Sec. 193.2624. PHMSA is not proposing similar enhanced annual
reporting requirements for Type R gathering pipelines because those
facilities would not be subject to the leak grading and repair
requirements at Sec. 192.760. However, PHMSA sees value in reviewing
the results of recently-adopted incident and annual reporting
requirements for those pipelines under the Gas Gathering Final Rule, as
well as the large-volume gas release reporting requirements proposed
herein, to inform a path forward regarding expanding annual reporting
requirements for Type R pipelines.
For emissions reporting, PHMSA proposes operators provide aggregate
emissions estimate for leaks by grade. PHMSA also proposes to collect
estimated annual emissions by source category, which includes both
leaks, incidents, and vented emissions. The source categories generally
mirror the categories in the GHGI and as summarized in section II.C.2.
This approach would ensure that both EPA and PHMSA have high-quality
leak emissions data to support their distinguishable, but mutually-
reinforcing, regulatory responsibilities. For PHMSA aggregate emissions
data provided on a per-leak grade basis would be particularly useful in
informing future decision-making calibrating part 192 safety
requirements based on an evolving understanding of the safety and
environmental hazards posed by different grades of leaks. Similarly,
information on other emissions would better inform Federal, State, and
operator efforts to minimize avoidable vented emissions, which is
required under section 114 of the PIPES Act of 2020. PHMSA would
require that, in developing aggregate emissions estimates, operators
would employ direct measurement and/or top-down methodologies along the
lines of those discussed in section III.C.2 above.\266\
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\266\ PHMSA would also consider estimated emissions
methodologies employed by EPA-qualified third-party notifiers in
reporting leaks under EPA's super-emitter response program proposals
within its supplemental notice of proposed rulemaking issued under
RIN 2060-AV16. See EPA SNPRM.
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PHMSA also proposes to require operators to submit geospatial data
about offshore gas gathering and Type A, Type B, and Type C gathering
pipelines to the NPMS. The NPMS is a geographic information system
(GIS) that contains the locations and related attribute data for a
variety of pipeline facilities. The NPMS was established via a self-
executing requirement codified in 49 U.S.C. 60132; while that statutory
mandate excluded distribution and gathering lines, PHMSA has authority
elsewhere in the Federal Pipeline Safety Laws at 49 U.S.C. 60117(c) to
collect safety data for gathering pipelines to inform whether and how
to provide
[[Page 31947]]
regulatory oversight of those facilities. Pipeline safety
stakeholders--including journalists, operators, emergency responders,
excavators, elected officials, public interest advocates, and PHMSA and
State regulators--use the NPMS to obtain important pipeline-safety
related information, including the locations of pipelines and related
infrastructure, the names and contact information of pipeline
operators, and other attributes of pipelines such as commodities
transported and diameter.\267\ In particular, access to gathering
pipeline geospatial data on NPMS would reinforce damage prevention
programs required under Sec. 192.614. Emergency responders often use
the NPMS to identify pipelines in the vicinity of reported leaks and
contact relevant operators. Emergency responders and pipeline operators
also use the NPMS while conducting drills and exercises to support
operators' emergency response plans. The requirement to submit data to
the NPMS would also reinforce operators' efforts in developing and
maintaining adequate maps and records of their systems.
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\267\ PHMSA acknowledges that stakeholders do not have uniform
access to information within NPMS.
---------------------------------------------------------------------------
In addition to the benefits detailed above, PHMSA expects that its
proposed amendments to NPMS requirements may also improve operators'
leak detection programs. First, it would ensure that operators know the
location of their pipelines; accurate location information can improve
the accuracy of leakage surveys and patrols for buried pipelines,
especially for leakage surveys performed with handheld equipment.
Second, if a pipeline is in the NPMS, it is easier for third parties
such as other operators, researchers, or the public to report leaks,
ruptures, and other unsafe conditions to the operator. Public interest
groups and aerial survey technology providers have noted that they have
had difficulty identifying the operator of a facility where a leak
indication was detected. PHMSA solicits comment on whether, within a
final rule in this proceeding, it would be appropriate to require NPMS
participation for Type R gathering pipelines not regulated under part
192. Comments on this question are especially helpful if they address
the potential safety and environmental benefits and potential costs of
that particular approach, including whether that approach would be
technically feasible, cost-effective, and practicable.
While operators may engage third parties as part of their efforts
to comply with the requirements proposed herein (for example, by
contracting with vendors of technologies such as those discussed in
section II.D.4 above), PHMSA has not proposed in this NPRM any formal
role for third parties in the detection or reporting of leaks or
intentional emissions. PHMSA invites comment on whether PHMSA should
revise Sec. 192.605 to address operators' procedures for responding to
third-party reports of gas releases or otherwise incorporate elements
from or leverage EPA's super-emitter response program proposed in the
EPA SNPRM for third party leak reporting \268\ as a backstop to support
the reporting requirements proposed herein (for potential inclusion
within a final rule in this proceeding), including whether data from
such third party leak reporting should be included in operator reports
to PHMSA (including aggregate emissions estimates by grade). PHMSA
further invites comment on whether to facilitate third party reporting
of operator non-compliance with the proposed requirements in this
rulemaking (or any other provision of PHMSA regulations) to the
attention of PHMSA enforcement personnel or State partners. Comments on
these questions are especially helpful to PHMSA when they identify
specific proposals supported by research or operational experience,
along with the potential safety and environmental benefits and
potential costs of a particular approach (including whether that
approach would be technically feasible, cost-effective, and
practicable).
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\268\ See EPA SNPRM, 87 FR at 74746.
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PHMSA understands that the proposed enhanced reporting and NPMS
requirements discussed above would be reasonable, technically feasible,
cost-effective, and practicable for affected gas pipeline operators.
The contents of PHMSA's proposed new large-volume gas release report
will resemble longstanding incident reporting requirements applicable
to unintentional releases from part 192-regulated gas pipelines.
Meanwhile, PHMSA's proposed enhanced annual reporting requirements for
leak and repair activity would largely consist of reporting of
information obtained from operator efforts in complying with the
enhanced leak detection and repair requirements proposed elsewhere in
this NPRM. Meanwhile, PHMSA's proposal to extend NPMS requirements to
all part 192-regulated gas gathering lines would merely require those
operators to submit information (including the precise location of
their pipelines, the commodity transported, etc.) that reasonably
prudent operators would maintain in ordinary course to protect public
safety and the environment from the pressurized (natural flammable,
corrosive, or toxic) gases transported in their pipelines. Viewed
against those considerations and the compliance costs estimated in the
Preliminary RIA, PHMSA expects its proposed amendments to part 191
reporting requirements will be a cost-effective approach to obtaining
enhanced data on intentional and unintentional releases of methane and
other part 192-regulated gases necessary to inform PHMSA enforcement,
policy development, and incident avoidance and response efforts.
Lastly, the NPRM's proposed compliance timelines with those proposed
reporting requirements--which are based on an effective date of six
months after the publication date of a final rule in this proceeding
(which would necessarily be in addition to the time since issuance of
this NPRM)--would provide operators ample time to design and implement
requisite protocols and manage any related compliance costs.
F. Mitigating Vented and Other Emissions From Gas Pipeline Facilities--
Sec. Sec. 192.9, 192.12, 192.605, 192.770, 193.2503, 193.2523 and
193.2605
In light of the significant methane emissions associated with
blowdowns and other vented gas emissions from PHMSA-jurisdictional gas
pipeline facilities, and to facilitate operator implementation of the
self-executing mandate in section 114 of the PIPES Act of 2020, PHMSA
proposes to incorporate that statutory language within the Pipeline
Safety Regulations.\269\ Specifically, PHMSA proposes to incorporate an
explicit requirement to eliminate leaks of all flammable, toxic, or
corrosive gases, as well as minimize releases of natural gas, within
provisions prescribing the content of operating, emergency, and
maintenance manuals for gas transmission, distribution, Type A
gathering and offshore gathering pipelines (Sec. 192.605 via current
Sec. 192.9), Types B and C gathering pipelines (Sec. 192.605 via a
revised Sec. 192.9(d) and (e)), UNGSFs (Sec. 191.12(c)), and part 193
LNG facilities (Sec. Sec. 193.2503 and 193.2605). The proposed broad-
based incorporation of the PIPES Act of 2020 section 114 mandate would
promote operator compliance efforts by aligning
[[Page 31948]]
PHMSA's regulatory requirements with the statutory mandate and helping
to ensure that leak elimination and natural gas release mitigation
inform the spectrum of operator activities. The proposed regulatory
text would reinforce other operator obligations (including, but not
limited to, repair criteria and IM requirements) throughout PHMSA
regulations that improve safety, environmental protection, and U.S.
competitiveness.
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\269\ PHMSA has, pursuant to section 114 of the PIPES Act of
2020, initiated a study on the best available technology or
practices to reduce methane emissions associated with design,
construction, operations, and maintenance of pipeline facilities,
and will initiate a rulemaking based on the results of that study.
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PHMSA proposes that operators of gas transmission, offshore
gathering, Type A gathering, and part 193 LNG facilities would have to
adopt specific requirements for minimizing the release of gas during
non-emergency blowdowns, LNG tank boil-offs, and other vented emissions
events. According to GHGI data described in section II.C of this NPRM,
approximately one-fourth of annual methane emissions from U.S. natural
gas transmission pipelines are from vented emissions, including
blowdowns. For LNG facilities, blowdowns represented around 48% of
methane emissions, and as much as 80% of methane emissions from storage
appurtenant to LNG facilities. PHMSA also notes that boil-offs of LNG
storage tanks at part 193 LNG facilities to accommodate maintenance
activity are similar in function to blowdowns on part 192 pipeline
facilities--and similarly can be significant contributors of methane
emissions if released to atmosphere.\270\ Mitigation of non-emergency
vented emissions as an important opportunity for reducing methane
emissions. The EPA Natural Gas STAR program listed blowdown volume
mitigation among several cost-effective and recommended technologies
for reducing methane emissions from operations, maintenance, and
construction.\271\Additionally, the ``Best Management Practice''
commitment option for EPA's voluntary Methane Challenge program
identifies various methods of reducing or eliminating blowdown
emissions volumes similar to those proposed in this NPRM.\272\ The PST
has identified similar mitigation options in public comments to
rulemaking actions dating from 2016, and INGAA included minimizing
blowdown volume in a list of commitments that member companies are
making to address methane emissions.\273\
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\270\ Vented and other releases of cryogenic LNG to the
atmosphere also present unique safety hazards and can cause
flammable vapor clouds, jet or pool fires in the presence of an
ignition source, or a sudden and explosive phase change if LNG
encounters a warm surface such as water. When spilled directly onto
water, LNG can rapidly convert from liquid to gaseous phase,
releasing enough energy to cause a physical explosion without any
combustion or chemical reaction. See World Bank Group,
Environmental, Health, and Safety Guidelines: Liquefied Natural Gas
Facilities (2017). In addition, vented releases of unprocessed gas
results in the release of VOCs and HAPs that entail distinguishable
environmental and public safety harms.
\271\ See PRO Fact Sheets Nos. 401, https://www.epa.gov/sites/default/files/2016-06/documents/injectblowdowngas.pdf.
\272\ EPA, ``Natural Gas STAR Methane Challenge Program: BPM
Commitment Option Technical Document'' (May 2022), https://www.epa.gov/system/files/documents/2022-05/MC_BMP_TechnicalDocument_2022-05.pdf (last accessed Dec. 20, 2022).
\273\ https://www.ingaa.org/File.aspx?id=38582; https://www.regulations.gov/comment/PHMSA-2011-0023-0272.
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PHMSA therefore proposes to amend its regulations pertaining to
each of gas transmission, regulated offshore gathering, and Type A
gathering pipelines (Sec. 192.770) and part 193 LNG facilities (Sec.
193.2523) to identify a menu of proven options--many of them featuring
prominently in the voluntary initiatives described in the preceding
paragraph that operators must choose from to mitigate methane releases
during blowdowns, tank boil-offs, and other vented emissions.
Proposed Sec. Sec. 192.770(a) and 193.2523(a) include an option to
install and use valves or control fittings to reduce the volume of gas
that must be removed from pipeline facility segments. Instead of
blowing down a pipeline facility between mainline block valves or
compressor stations, the operator would isolate a shorter segment of
pipe, resulting in lower release volumes. In addition to the emissions
abatement benefits from isolating shorter segments for maintenance
tasks, this approach can have operational benefits from reducing or
eliminating downtime by bypassing the shut-in segment. A second
proposed method is routing vented gas to a flare stack to be ignited or
to other equipment to be collected for later use. Burning gas rather
than releasing it into the atmosphere significantly reduces the climate
change impacts of vented emissions by converting methane gas to carbon
dioxide and water via combustion. Under favorable conditions a well-
designed and maintained flare stack can combust gas with almost 100%
efficiency, however leaks and unlit or incomplete flaring (due to poor
maintenance, design, or operation practices) can reduce the methane
reduction efficiency on a field-level basis to approximately 90%.\274\
Leaks and releases from flaring equipment would be subject to the
proposed amendments in this NPRM as components of a ``pipeline'' as
defined in parts 191 and 192. Routing or recovering gas for use as a
fuel source is similar in principle to flaring. The third, fourth, and
fifth approaches identified in proposed Sec. Sec. 192.770(a) and
193.2523 involve reducing pressure (or, in the case of LNG tank boil-
off, LNG volumes) of a pipeline segment prior to venting, thereby
reducing total emissions volume. In the third approach, an operator
would isolate the pipeline segment upstream of the vented segment and
use the downstream compressor station to reduce the pressure of the
affected segment. The fourth approach is similar except instead of the
compressor station, an operator would use a mobile compressor unit to
reduce the pressure of the segment by compressing gas, or diverting
LNG, into adjacent facilities or a storage vessel. The fifth approach--
transferring gas or LNG to a lower-pressure pipeline segment--is like
the fourth, except it may be performed without compression in certain
circumstances. PHMSA seeks comment on whether it is appropriate to
specify a minimum pressure or pressure reduction in the vented segment
for pressure reduction methods and any other mitigation measures
operators should consider. Lastly, PHMSA proposes that operators be
able to employ alternative approaches not listed in Sec. Sec.
192.770(a) and 193.2523(a) for release volume mitigation, provided that
the operator can demonstrate that a proposed approach reduces the
volume of released gas by at least 50% compared with taking no
mitigative action. This is consistent with the approach used in the
EPA's Methane Challenge \275\ program and would provide operators with
flexibility to employ techniques and technologies appropriate for the
unique operating and environmental conditions of their facilities and
would accommodate future advancements in release mitigation
technologies and practices. PHMSA invites comment on whether, for any
(or all) of the release volume mitigation approaches proposed in
Sec. Sec. 192.770(a)(1) through (5) and 193.2523(a)(1) through (3),
operators should be required to demonstrate that a particular approach
reduces the
[[Page 31949]]
volume of released gas by at least 50% compared with taking no action
(consistent with the EPA's Methane Challenge program) (for potential
inclusion within a final rule in this proceeding). PHMSA further
invites comment on whether a different minimum percentage reduction
(higher or lower than 50%) would instead be more appropriate for any
(or all) of the release volume mitigation approaches proposed in
Sec. Sec. 192.770(a) and 193.2523(a) (for potential inclusion within a
final rule in this proceeding). Comments on each of these questions are
especially helpful when they are supported by research or operational
experience, along with the potential safety and environmental benefits
and potential costs of a particular approach (including whether that
approach would be technically feasible, cost-effective, and
practicable).
---------------------------------------------------------------------------
\274\ Duren, Riley and Deborah Gordon. ``Tackling unlit and
inefficient gas flaring,'' Science. Vol. 337 Issue 6614. (2022):
1486-1487. https://www.science.org/doi/full/10.1126/science.ade2315.
\275\ See EPA, ``Methane Challenge Program BMP Commitment Option
Technical Document'' at pg. 21 (May 2022), https://www.epa.gov/system/files/documents/2022-05/MC_BMP_TechnicalDocument_2022-05.pdf
(last accessed March 16, 2023).
---------------------------------------------------------------------------
PHMSA further proposes in Sec. Sec. 192.770(c) and 193.2523(c)
that those operators develop documentation describing the suite of
actions undertaken--including, but not limited to, their choice from
among the blowdown mitigation method(s) identified in either Sec. Sec.
192.770(a) or 193.2523(a)--to minimize vented emissions from their
systems. PHMSA does not propose to require mitigation for emergency
blowdowns pursuant to an emergency plan under Sec. Sec. 192.615(a)(3)
or 193.2509 so as to ensure that emissions mitigation will not come at
the expense of public safety and other environmental resources;
however, PHMSA proposes at Sec. Sec. 192.770(b) and 193.2523(b) to
require that operators document such events, including the
justification for not taking mitigative action.\276\
---------------------------------------------------------------------------
\276\ Note that a blowdown that is not mitigated may also be
reportable under the proposed large-volume gas release report.
---------------------------------------------------------------------------
PHMSA understands that its proposed requirements for minimizing
vented and other releases from certain gas pipeline facilities
discussed above would be reasonable, technically feasible, cost-
effective, and practicable for affected gas pipeline operators. PHMSA
understands that some affected operators may already have adopted
protocols for minimizing vented emissions and eliminating leaks from
their facilities either voluntarily (e.g., to minimize loss of a
commercially valuable--and hazardous--commodity) or in response to
State or Federal requirements (including, but not limited to, the self-
executing mandate in section 114 of the PIPES Act of 2020). The NPRM
reinforces those efforts by codifying that self-executing statutory
mandate in the pipeline safety regulations. Similarly, PHMSA's
proposals accommodate a variety of compliance strategies; the text of
pertinent regulatory provisions contains a non-exclusive menu of
compliant approaches from which operators can choose as appropriate for
their needs and their facilities' operational characteristics and
environment. Viewed against those considerations and the compliance
costs estimated in the Preliminary RIA, PHMSA expects its proposed
amendments will be a cost-effective approach to achieving the
commercial, public safety, and environmental benefits discussed in this
NPRM and its supporting documents. Lastly, the NPRM's proposed
compliance timelines--which are based on an effective date of six
months after the publication date of a final rule in this proceeding
(which would necessarily be in addition to the time since issuance of
this NPRM)--would provide operators ample time to develop and implement
compliance protocols and manage any related compliance costs.
Although the NPRM does not include a similar prescribed menu of
required blowdown emissions mitigation approaches for gas distribution
or Types B and C gathering pipelines due to the comparatively smaller
blowdown volumes of some of those systems, PHMSA seeks comment on
whether, within a final rule in this proceeding, it would be
appropriate to require use of some of the methods for mitigating
transmission pipeline and LNG facility blowdown emissions proposed
herein for use on gas distribution or Types B and C gathering
pipelines. PHMSA also seeks comment on whether it is appropriate to
restrict the use of flaring to instances where other mitigation
measures are impracticable. Comments on these questions are especially
helpful if they address the potential safety and environmental benefits
and potential costs of a particular approach, including whether that
approach would be technically feasible, cost-effective, and
practicable.
The proposals described in this section are intended to codify
section 114(a) and (b) of the PIPES Act of 2020 and address a subset of
operations and maintenance-related emissions sources. PHMSA has a
separate Congressional mandate under section 114(d) of the PIPES Act of
2020 to promulgate pipeline design, operations, and maintenance
requirements to ``prevent or minimize, without compromising pipeline
safety, the release of natural gas'' in connection with intentional
operator releases. PHMSA will address this mandate in a future
rulemaking action following the completion of a report to Congress
discussing the best available technologies, practices, and designs to
prevent or minimize such releases (per section 114(d)(1) of the PIPES
Act of 2020).\277\ Specifically, the report must evaluate pipeline
facility designs that mitigate the need to intentionally vent natural
gas (without compromising pipeline safety) as well as the best
available technologies or practices to prevent or minimize (without
compromising pipeline safety) the release of natural gas when making
planned repairs, replacements, or maintenance to a pipeline facility
and when the operator intentionally vents or releases natural gas,
including blowdowns. As of the date of issuance of this final rule,
PHMSA is in the process of developing the best available technologies
and practices report referenced in section 114(d)(1).
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\277\ Section 114(d)(2) of the PIPES Act of 2020 requires the
Secretary to update the Pipeline Safety Regulations that the
Secretary has determined are necessary to protect the environment
without compromising safety within 180 days after submitting the
section 114(d)(1) report.
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G. Design, Configuration, and Maintenance of Pressure Relief Devices--
Sec. Sec. 192.9, 192.199 and 192.773
PHMSA proposes to minimize emissions caused by malfunctioning
pressure relief devices and other unnecessary releases from poorly
designed or configured pressure relief devices. A pressure relief
device vents gas to the atmosphere (or to a flare) when the pressure in
the system satisfies either design or configuration actuation
criteria,\278\ to protect the integrity of the facility from an
overpressure condition. A pressure relief device may malfunction by not
releasing gas as required by those criteria, risking an overpressure
condition that can induce a loss of system integrity and release of gas
to atmosphere. Alternatively, a pressure relief may malfunction by
operating before those criteria have been satisfied, which results in
unnecessary releases of gas to the atmosphere. Similarly, a pressure
relief device with design or configuration actuation criteria more
conservative than necessary to provide
[[Page 31950]]
adequate margin to an overpressure condition can also result in
unnecessary gas releases. Additionally, a pressure relief device whose
design or materials are ill-suited for use in a pipeline facility's
particular operating and environmental conditions may fail or leak.
---------------------------------------------------------------------------
\278\ PHMSA here draws a distinction between design actuation
criteria set by a device manufacturer (which generally cannot be
changed by an operator) and configuration actuation criteria (which
in some cases could be changed by an operator post-manufacture and
installation). PHMSA further notes that by ``actuation criteria'' it
means the suite of setpoints (e.g., pressure) and other conditions
(e.g., programmable logic) that must be satisfied for a pressure
relief device to actuate and cease actuation. For example, actuation
criteria may consist of a pressure setpoint at which a pressure
relief valve may open, as well as a setpoint for that same valve to
close.
---------------------------------------------------------------------------
PHMSA often receives reports of major releases from pressure relief
device failures: since 2010, operators have submitted 112 incident
reports for releases from pressure relief devices on gas transmission
and regulated gas gathering pipelines from 2010 through the end of
2022, reporting an average release volume of 12.5 MMCF from each event.
The largest relief device failure reported to PHMSA occurred on
November 22, 2014, when an 8-inch relief valve on a 34-inch gas
transmission pipeline operated by Pacific Gas and Electric (PG&E)
malfunctioned, which released 119 MMCF of natural gas into the
atmosphere until operating personnel were able to bypass the valve.
Following the incident, PG&E contractors performed a root cause
analysis and made unspecified changes to the pressure limiting station
pending a future redesign.\279\
---------------------------------------------------------------------------
\279\ PHMSA, ``Pipeline Incident Flagged Files'', https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-flagged-files (last accessed Dec. 20, 2022) (memorialized within
Report ID No. 20140148).
---------------------------------------------------------------------------
Out of these incident reports 84 were caused by a malfunction of
the relief device or other pressure control equipment.
Gas Transmission and Regulated Gas Gathering Pressure Relief Device
Incidents
------------------------------------------------------------------------
Incidents 2010-
Primary cause and sub-cause 2022
------------------------------------------------------------------------
Equipment failure: malfunction of control/relief 84
equipment..............................................
Equipment failure: other equipment failure.............. 5
Equipment failure: threaded connection/coupling failure. 2
Equipment failure: defective of loose tubing/fitting.... 1
Incorrect operation: other incorrect operation.......... 8
Incorrect operation: pipeline/equipment over pressurized 3
Incorrect operation: incorrect valve position........... 2
Incorrect operation: incorrect equipment................ 1
Natural force damage: temperature....................... 4
Miscellaneous........................................... 2
---------------
Total............................................... 112
------------------------------------------------------------------------
The most common causes of these failures according to narratives in
part G6 or H of operator's gas transmission incident reports are
mechanical failures of the relief device, including failures to reseat
or reseal after activation, and failures caused when liquid
contaminants cause a relief device to freeze open or closed in cold
weather conditions. Other reported incidents have resulted from the use
of pressure relief devices whose design and material were inappropriate
for the pipelines on which they were installed and expected operating
conditions. For example, incidents were attributed to improper
calibration, design issue with the location of the sensing line,
pressure programming or setting issues, improper setpoint,
construction, or programming issues, an oversized or undersized
pressure relief device and inlet piping, high pipeline flow conditions,
and setpoint drift.
Other data sources suggest these incident report figures may
undercount relief device emissions that could be prevented through
better design, configuration, and maintenance. For example, PHMSA
receives inquiries from media sources based on satellite documentation
of significant methane releases. Additionally, PHMSA is notified of
National Response Center reports on releases involving pressure relief
devices in accordance with Sec. 191.5 approximately once a week, with
39 NRC reports referencing relief valves in the description in calendar
year 2021.\280\ Operators report such releases to the National Response
Center more frequently than they file incident reports pursuant to
Sec. Sec. 191.9 or 191.15, which suggests that operators may--after
reporting them to the National Response Center immediately after
discovery of a release--subsequently designate some emissions from
relief devices as ``intentional'' emissions that are not required to be
reported to PHMSA as incidents.\281\
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\280\ United States Coast Guard, National Response Center,
https://nrc.uscg.mil/ (last accessed Dec. 20, 2022).
\281\ The discrepancy between events reported to the National
Response Center pursuant to Sec. 191.5 and those ultimately
reported as incidents pursuant to Sec. Sec. 191.9 or 191.15
reflects a difference in timing between these two reporting
requirements: the Sec. 191.5 reporting requirement obliges
operators to notify the National Response Center at ``the earliest
practicable'' moment--which in practice can mean before a formal
decision has been made by the operator to designate an event as an
``incident'' reported to PHMSA some time (as many as 30 days later)
pursuant to Sec. Sec. 191.9 or 191.15.
---------------------------------------------------------------------------
Overpressurization is a critical safety issue and can result in a
pipeline incident or rupture with grave public safety and environmental
consequences. However, inadequate design and configuration of pressure
relief devices may result in potentially very large releases beyond
that necessary to provide overpressure protection. Additionally, relief
device malfunctions due to inadequate maintenance or other issues can
result in a failure to provide reliable overpressure protection if it
fails to operate or significant emissions if the device leaks or
operates unintentionally. PHMSA has observed through inspections and
other regulatory oversight activities, that operator procedures,
including the choice of design and configuration actuation criteria,
may not be optimized to reduce emissions associated with pressure
relief device malfunctions or operations beyond what is necessary to
provide overpressure protection. For example, some operators take an
overly conservative approach to avoiding overpressure conditions and
employ design and configuration actuation criteria such that those
pressure relief valves will release gas to the atmosphere either more
frequently or in greater quantities than necessary to protect against
an overpressure condition.
PHMSA proposes to revise Sec. 192.199 to require operators of all
new and replaced, relocated, or otherwise changed gas transmission,
distribution, and part 192-regulated gathering pipelines be designed
and configured, as demonstrated by documented engineering analysis, to
minimize unnecessary releases of gas. Section 192.199 would prescribe a
series of elements that operators must demonstrate would minimize
emissions using engineering analysis. These elements include the choice
of design material and function, configuration actuation conditions,
pressure relief device piping characteristics, presence of isolation
valves to facilitate testing and maintenance, and compatibility of
material and design with use. In addition, PHMSA proposes a new Sec.
192.773 that, coupled with proposed revisions to Sec. 192.9, would
require operators of all gas transmission, distribution, and part 192-
regulated gathering pipelines to develop procedures to assess the
proper function of pressure relief devices on their facilities and
remediate or replace any
[[Page 31951]]
malfunctioning devices. This change ensures that operator's maintenance
procedures ensure reliable overpressure protection and the minimization
of emission from malfunctioning pressure relief devices. PHMSA's
proposed language also identifies specific action operators would have
to take on operation of a malfunctioning pressure relief device. PHMSA
proposes to require a relief device be repaired or replaced immediately
if it operates above the pressure limits in Sec. 192.201(a) or Sec.
192.739, fails to operate, or otherwise fails to provide reliable
overpressure protection due to the potential consequences of
overpressurizing the pipeline.
On the other hand, a relief device that activates below the
intended set pressure poses a hazard to the environment, especially if
it releases gas at normal operating pressure. Therefore, PHMSA also
proposes that if a relief device activates below the set pressure
range, the operator must take immediate and continuous action to stop
the release of gas and ensure operation with an adequate margin to
overpressure conditions. The device must then be repaired or replaced
as soon as practicable, and within 30 days. Action to stop the flow of
gas should be defined in an operator's abnormal operating procedures
and could include reconfiguring the relief device.
In either case the operators would be obliged to maintain records
documenting the proper operation and any remediation/replacement of
pressure relief devices for the service life of their facilities.
PHMSA understands that its proposed requirements for design,
configuration, and maintenance of pressure relief valves discussed
above would be reasonable, technically feasible, cost-effective, and
practicable for affected gas pipeline operators. PHMSA understands that
some affected operators may already have adopted protocols ensuring
that the design and configuration of pressure relief devices minimizes
emissions of pressurized (natural, toxic, corrosive, or flammable)
gases, either voluntarily (to minimize loss of commercially valuable
commodities) or in response to State or Federal requirements. The NPRM
would backstop those existing practices by enshrining them in
regulation by prescribing release mitigation as a mandatory factor in
the design and selection of new pressure relief devices; the NPRM
contemplates operators would have flexibility within that broad
objective to develop their precise implementation strategy for a
particular (new) pressure relief device. Similarly, existing pressure
relief device configurations would need to be tweaked to minimize
releases as well, but only so far as such configurations can be
changed; operators whose pressure relief devices do not admit changes
in configuration would not have to effectuate any changes. Viewed
against those considerations and the compliance costs estimated in the
Preliminary RIA, PHMSA expects its proposed amendments will be a cost-
effective approach to achieving the commercial, public safety, and
environmental benefits discussed in this NPRM and its supporting
documents. Lastly, the NPRM's proposed compliance timelines--which are
based on an effective date of six months after the publication date of
a final rule in this proceeding (which would necessarily be in addition
to the time since issuance of this NPRM)--would provide operators ample
time to develop and implement compliance protocols and manage any
related compliance costs.
H. Investigation of Failures--Sec. 192.617
Understanding the causes of pipeline leaks and reasons for
malfunction of pressure relief devices is essential for identifying
systemic threats to pipeline integrity and preventing similar failures
in the future. Although PHMSA regulations at Sec. 192.617 require
operators of gas distribution, transmission, offshore gathering, and
Type A gathering pipelines to have procedures for analyzing the causes
of ``failures and incidents,'' \282\ those requirements are limited in
application (they do not apply to Types B and C gathering pipelines),
and ``failure'' is not defined in part 192. With respect to the meaning
of the term ``failure'', operators have applied the definition in the
instructions for the Gas Transmission and Gas Gathering Pipeline System
Annual Report,\283\ which references the broad, functional definition
in ASME B31.8, ``Gas Transmission and Distribution Piping Systems.''
ASME B31.8 defines a failure as the following:
---------------------------------------------------------------------------
\282\ PHMSA's discussion of Sec. 192.617 describes the text of
that provision as it will be amended on the October 5, 2022,
effective date of the Valve Installation and Rupture Detection Final
Rule.
\283\ PHMSA Form F 7100.2-1 (revision 10-2021), Instruction
Revision (10-2021). https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2021-10/Current%20GT%20GG%20Annual%20Instructions%20-%20PHMSA%20F%207100%202-1%20Approved%2010-2021%20for%20CY%202021%20and%20Beyond.pdf.
failure: a general term used to imply that a part in service has
become completely inoperable; is still operable but is incapable of
satisfactorily performing its intended function; or has deteriorated
seriously, to the point that it has become unreliable or unsafe for
---------------------------------------------------------------------------
continued use.
Although PHMSA has issued interpretations suggesting that leaks
caused by certain mechanisms (in particular, those resulting from
corrosion) would require investigation pursuant to Sec. 192.617,\284\
PHMSA regulations do not require investigation of all failures that
result in leaks. This limitation could prevent investigations that can
identify systemic integrity threats to their pipelines--as well as
denies PHMSA and State regulators information necessary to protect
public safety and the environment.
---------------------------------------------------------------------------
\284\ PHMSA, Interpretation Response Letter No. PI-92-033 (Jul.
16, 1992).
---------------------------------------------------------------------------
PHMSA therefore proposes to address the lack of specificity of the
definition of a failure by revising Sec. 192.617 to define the term
``failure'' for the purposes of that section using language similar to
that in ASME B31.8. This approach would facilitate compliance by
leveraging elements of a consensus industry standard with which
operators are familiar, and portions of which are incorporated by
reference elsewhere in PHMSA regulations. Additionally, PHMSA already
references ASME B31.8's functional definition of a failure in the
instructions for gas transmission and regulated gathering pipeline
annual reports. Since a leaking pipe has failed to contain gas, a
failure that results in a leak would be required to be investigated in
accordance with Sec. 192.617. The proposed definition clarifying that
all leaks on pertinent gas pipelines require investigation under Sec.
192.617 would improve safety. The proposed changes are intended to
complement the leak grading and repair requirements in this NPRM (as
well as repair criteria and IM requirements elsewhere in PHMSA
regulations) and equip operators, PHMSA, and State regulators with the
information needed in developing proactive initiatives to avoid future
pipeline failures. Viewed against those considerations and the
compliance costs estimated in the Preliminary RIA, PHMSA expects this
proposed amendment will be a cost-effective approach to achieving the
commercial, public safety, and environmental benefits discussed in this
NPRM and its supporting documents. Lastly, the NPRM's proposed
compliance timelines--which are based on an effective date of six
months after the publication date of a final rule in this proceeding
(which would necessarily be in addition to the time since issuance of
this NPRM)--would provide operators ample time to develop
[[Page 31952]]
and implement compliance protocols and manage any related compliance
costs.
Although PHMSA proposes to limit the scope of application of this
revised definition of ``failure'' to Sec. 192.617, it acknowledges
that term is used elsewhere in PHMSA regulations. PHMSA therefore
invites comment on whether the proposed definition of ``failure''
should instead be located within the broadly applicable definitions at
Sec. 192.3 (for potential inclusion within a final rule in this
proceeding). Comments on this question are especially helpful if they
address the potential safety and environmental benefits and potential
costs of that approach, including whether that approach would be
technically feasible, cost-effective, and practicable.
I. Type B and Type C Gathering Pipelines--Sec. 192.9
Types B and C gathering pipelines are not currently subject to all
of the part 192 safety requirements broadly applicable to other part
192-regulated gas pipelines, including those pertaining to procedural
manuals for operations, maintenance, and emergency response procedures
(Sec. 192.605), patrolling (Sec. 192.705), and certain recordkeeping
(Sec. 192.709); Type B gathering pipelines are also not subject to
emergency planning requirements set forth in Sec. 192.615. Further,
because Types B and C gathering pipelines are not subject to Sec.
192.605, some stakeholders have questioned whether those pipelines are
excepted from the self-executing requirements within section 114 of the
PIPES Act of 2020 for operators to have procedures to eliminate leaks,
minimize releases of natural gas, and repair or remediate pipelines
known to leak.\285\ Additionally, most Type C gathering pipelines are,
pursuant to Sec. 192.9(f)(1), not even subject to PHMSA's minimal
existing requirements for leakage surveys (Sec. 192.706) and repair of
hazardous leaks (Sec. 192.703(c)).\286\
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\285\ See, e.g., GPA Midstream and American Petroleum Institute,
``Joint Comments re Docket No. PHMSA-2021-0039, Pipeline Leak
Detection, Leak Repair and Methane Emission Reductions Public
Meeting'' at 4-5 (May 24, 2021).
\286\ PHMSA's RIA for the Gas Gathering Final Rule estimated
only ca. 20,000 miles (of the ca. 90,000 total miles of Type C
pipelines) would be subject to Sec. Sec. 192.703 and 192.705. See
Gas Gathering RIA at 15.
---------------------------------------------------------------------------
These limitations contribute to public safety and environmental
risks. PHMSA has historically imposed each of the requirements listed
in the preceding paragraph on gas transmission and Type A gathering
pipelines precisely because of the self-evident, appreciable public
safety benefits they entail.\287\ Although PHMSA previously declined to
extend those minimal requirements to Types B and C gathering pipelines
(representing the majority of part 192-regulated gathering pipeline
mileage),\288\ the notable public safety and environmental risks from
Types B and C gathering pipelines discussed throughout this NPRM
warrant removal of those historic regulatory gaps. As described above
in section II.C.2, incidents and leaks occur on Type B and Type C
gathering pipelines just as they occur on Type A pipelines. For Type B
lines, the public safety risks of any incident are evident due to the
location of those pipelines in densely-populated Class 2, 3 and 4
locations, while the high operating pressures and large diameters of
Type C pipelines entail risks to public safety similar to those posed
by Type A pipelines (notwithstanding Type C lines' location in more
sparsely-populated Class 1 areas than Type A lines).\289\ And as
explained above, leaks from any type of natural gas gathering pipeline
contains VOCs and HAPs, exacerbating public safety and environmental
risk. Leaks of unprocessed natural gas also contain corrosive materials
that can accelerate leak degradation.\290\ The public safety and
environmental risks associated with releases (whether leaks or more
serious incidents) from gas gathering pipelines also support extension
of emergency planning requirements to Type B gas gathering pipelines,
which are located in the vicinity of buildings intended for human
occupancy; the emergency planning requirements at Sec. 192.615 will
ensure that those operators have in place a robust framework for
proactive measures to mitigate the public consequences of any emergency
on their systems. Lastly, increasing appreciation for the outsized
contribution to climate change of fugitive and vented emissions from
all natural gas gathering pipelines underscores the importance of
minimizing those greenhouse emissions from Types B and C regulated
gathering pipelines.
---------------------------------------------------------------------------
\287\ PHMSA, ``Gas Gathering Line Definition; Alternative
Definition for Onshore Lines and New Safety Standards,'' 71 FR
13289, 13292 (Mar. 15, 2006).
\288\ See Gas Gathering RIA at 15 (noting a total of ca. 90,000
miles of Type C gathering pipelines) and 30 (noting a total of ca.
11,000 miles of Types A and B gathering pipelines).
\289\ See Gas Gathering Final Rule at 63267.
\290\ Leaks from part 192-regulated gathering lines transporting
flammable, toxic, or corrosive gases other than natural gas also
entail their own safety and environmental risks.
---------------------------------------------------------------------------
This NPRM therefore proposes a series of regulatory amendments
representing a first step in mitigating the anomalous treatment of
Types B and C gathering pipelines in PHMSA regulations. Specifically,
PHMSA proposes to revise Sec. 192.9 to add to the list of part 192
requirements applicable to Types B and C pipelines each of its proposed
requirements for pressure relief device design and maintenance
(Sec. Sec. 192.199 and 192.773),\291\ certain recordkeeping (Sec.
192.709) and procedural manual requirements for operations,
maintenance, and emergency response (Sec. 192.605), and--for Type B
gathering pipelines--the emergency planning requirements at Sec.
192.615. Each of these requirements have proven utility in minimizing
public safety and environmental risks from gas transmission and Type A
gathering pipelines and exemplify common-sense programmatic elements
that any responsible business owning facilities known to transport
pressurized, hazardous commodities would maintain in ordinary course
(even in the absence of explicit regulatory requirements) to protect
public safety and the environment. Extension of the procedural manual
requirements at Sec. 192.605 and recordkeeping requirements at Sec.
192.709, moreover, would facilitate regulatory oversight of Types B and
C gathering facilities by PHMSA and State inspectors by aligning
documentation requirements with existing substantive requirements under
Sec. 192.9. It would also dispel any uncertainty among stakeholders
regarding application to Types B and C gathering pipelines of the self-
executing obligations under section 114 of the PIPES Act of 2020 to
eliminate leaks, minimize emissions, and repair or remediate pipelines
known to leak based on their material, design, or operating and
maintenance history. Extension of the emergency planning requirements
in Sec. 192.615 to Type B gathering pipelines would also improve
public awareness of pipeline safety and emergency response to incidents
on Type B gathering pipelines, bringing requirements for such pipelines
in line with existing requirements for all other part 192-regulated gas
pipelines. Effective emergency response requirements are critical to
ensure the safety of the public, emergency responders, and operator
personnel during gas pipeline emergencies on Type B gathering lines,
which are located in Class 2, 3, and 4
[[Page 31953]]
locations.\292\ Section 192.615 includes requirements to ensure
effective emergency preparedness, including a coordinated operator and
community response to pipeline emergencies. Moreover, this requirement
would ensure that operators of Type B gathering lines are prepared to
take appropriate immediate and continuous actions in response to a
grade 1 leak, which could require activation of an emergency response
plan. PHMSA further proposes (as discussed above) to extend the suite
of enhanced leak detection and repair-related proposals elsewhere in
this NPRM to certain Types B and C gathering pipelines (including
Sec. Sec. 192.703(c) and (d), 192.705, 192.706, 192.709, 192.760,
192.763, and 192.769). Similarly, PHMSA also proposes to extend
requirements for this NPRM's elements pressure relief device
maintenance (Sec. 192.773) to Types B and C gathering pipelines to
further reduce emissions and public safety and environmental risks
associated with Types B and C gathering pipelines.
---------------------------------------------------------------------------
\291\ As explained elsewhere, PHMSA's proposed Sec. 192.199
requirements would only apply to new, replaced, relocated, or
changed Type C gathering pipelines.
\292\ Type B gathering pipelines are defined in Sec. 192.8 as
those gathering pipelines located in Class 4, Class 3, and certain
Class 2 locations with the operating characteristics specified in
Table 1 to Sec. 192.8(c)(2).
---------------------------------------------------------------------------
PHMSA expects the above proposed first steps toward improving
alignment of regulatory requirements for Types B and C gas gathering
pipelines with those applicable to other part 192-regulated pipelines
would be reasonable, technically feasible, cost-effective, and
practicable. The specific regulatory requirements PHMSA proposes to
extend are common-sense, widely-employed approaches adopted by
reasonably prudent operators in ordinary course to minimize losses of
commercially valuable commodities and risks to public safety and the
environment from the operation of pipelines transporting pressurized
(natural, corrosive, toxic, or flammable) gases. Precisely for that
reason, PHMSA expects that some Types B and C gas gathering pipeline
operators may already voluntarily comply with those proposed
requirements. Those and other operators of Types B and C gas gathering
pipelines (some of which operators may also operate either gas
transmission or Type A gathering pipelines) may also have pipelines
within their systems subject to similar procedural manual,
recordkeeping, and pressure relief device requirements under Federal or
State law; those existing procedural manuals and (recordkeeping and
pressure relief device design and configuration) protocols could be
extended and adapted to Types B and C gas gathering pipelines. Viewed
against those considerations and the compliance costs estimated in the
Preliminary RIA, PHMSA expects its proposed amendments will be a cost-
effective approach to achieving the commercial, public safety, and
environmental benefits discussed in this NPRM and its supporting
documents. Lastly, the proposed compliance timelines--based on an
effective date of the proposed requirements six months after the
publication date of a final rule in this proceeding (which would
necessarily be in addition to the time since issuance of this NPRM)--
would provide operators ample time to implement requisite changes to
existing procedural manuals and protocols (and conduct any accompanying
personnel training) and manage any related compliance costs.
PHMSA solicits comment on additional opportunities to harmonize
part 192 treatment of regulated gathering pipelines for potential
inclusion within a final rule in this or a subsequent rulemaking
proceeding. Comments on this question are especially helpful if they
address the potential safety and environmental benefits and potential
costs of a particular approach, including whether that approach would
be technically feasible, cost-effective, and practicable.
J. Miscellaneous Changes in Parts 191 and 192 To Reflect Codification
in Federal Regulation of the Congressional Mandate To Address
Environmental Hazards of Leak From Gas Pipelines
As discussed above in section II.D, current PHMSA regulations
reflect an ambiguous distinction between ``hazardous'' and other leaks
that reflects PHMSA's historical prioritization of public safety
hazards. PHMSA's regulations at parts 191 and 192 consequently contain
numerous references to ``potentially hazardous'' gas releases, or to
``hazards'' expressed principally in terms of public safety risks. As
discussed above in sections II.D.3, III.C.1, and III.C.6, all ``leaks''
are necessarily hazardous to the environment, and even a small leak can
be hazardous to public safety, especially if it is allowed to continue
indefinitely without repair and potentially degrade into a more serious
leak or incident. PHMSA therefore proposes miscellaneous conforming
revisions to various provisions of parts 191 and 192 consistent with
the PIPES Act of 2020's direction. PHMSA proposes to define ``hazardous
leak or leak'' in Sec. 192.3 and apply it to those subparts of part
192 other than the IM regulations under subparts O and P. That proposed
definition would make ``hazardous leak'' synonymous to ``leak.'' PHMSA
also proposes to delete language in several places in part 192
suggesting contingency (for example, references to ``potentially
hazardous'' releases) at each of Sec. Sec. 192.503(a)(2), 192.507(a),
192.509(a), 192.513(b), 192.553(a)(2), 192.557(b)(2), and 192.751(a))
regarding hazards posed by releases from gas pipelines.\293\ For other
provisions (specifically, Sec. Sec. 192.605(b)(9), 192.613(b),
192.615(a), 192.615(a) introduction, 192.616(d)(2) and (j)(2), and
192.703(c)), existing language referring to ``hazard'' and ``hazardous
leak'' is elastic enough to accommodate PHMSA's proposed expansion of
the ``hazard'' concept to encompass environmental hazards without
revision of regulatory text. Although the expansion of the ``hazard''
concept may require some operators to modify procedures and practices,
PHMSA expects any compliance burdens would be de minimis because a
reasonably prudent operator would employ practices and procedures
addressing the need to minimize releases of natural gas and other
environmental harms from their activities. In addition, the mechanism
for public safety and environmental harms (the release of gas from a
pipeline) is the same.
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\293\ PHMSA will also propose conforming revisions to the part
191 annual report forms and instructions for each of gas
transmission, offshore gathering and Types A, B, and C gathering
pipelines (F7100.2-1), Type R gas gathering pipelines (F7100.2-3),
and gas distribution pipelines (F7100.1-1) to eliminate distinctions
made or suggested in those documents between hazardous leaks, other
leaks, or other gas releases allegedly too small to merit reporting.
---------------------------------------------------------------------------
This proposed expansion of ``hazardous leaks'' to encompass hazards
to the environment and public safety could lead operators to modify
testing practices. For example, PHMSA's proposed changes to subpart J
testing requirements (specifically, Sec. Sec. 192.503(a)(2),
192.507(a), 192.509(a), 192.513(b)) to limit placement into service of
any new, replaced, relocated or otherwise changed gas transmission,
distribution, offshore gathering, Types A, B, and C gathering pipeline
segments with any leak could make testing and qualification of new,
replaced, relocated, or changed pipelines more difficult in that it
would require conforming revisions to operator acceptance criteria.
However, PHMSA expects the impact of those proposed revisions would be
de minimis, as reasonably prudent operators would not place new,
replaced, relocated, or changed pipeline segments into service
[[Page 31954]]
if they had observed any leak during initial testing. The same logic
would extend to its proposed amendment of uprating requirements (at
Sec. Sec. 192.553(a)(2), 192.557(b)(2)) applicable to gas
transmission, distribution, offshore gathering, and Type A gathering
pipelines.
PHMSA does not propose to expand every reference to ``hazard'' or
``hazardous leak'' in PHMSA's part 191 and 192 regulations to encompass
environmental hazards. First, PHMSA proposes to exclude the IM
regulations at subparts O and P from application of the new definition
of ``leak or hazardous leak'' at Sec. 192.3 to keep operator IM
plans--and operators' limited resources implementing those plans--
focused on identification and management of public safety risks.\294\
PHMSA is proposing to revise Sec. 192.1007 to delete a reference to
Sec. 192.703(c) that would be rendered obsolete by the limited
application of PHMSA's proposed definition of ``leak or hazardous
leak'' at Sec. 192.3. Second, PHMSA is not proposing to refer to
``hazards'' or leaks ``hazardous to public safety'' where an explicit
reference to environmental hazards would either be unnecessary (e.g.,
because other subparagraphs within the same provision would address any
environmental hazards) or inapposite to the pertinent requirement. This
applies to Sec. Sec. 192.605(c)(1)(v), 192.605(a)(6) and (7),
192.615(c), and 192.721. Similarly, PHMSA proposes to revise other
references to (unqualified) ``hazards'' to preserve those provisions'
historical and appropriate focus on public safety, rather than
environmental, hazards. Generally, those proposed regulatory amendments
would consist of addition of qualifying language (``hazard(s) to public
safety'') where an explicit reference to environmental hazards would
either be unnecessary (e.g., because other, related provisions or
paragraphs would address any environmental hazards) or inapposite to
the pertinent requirement. PHMSA proposes these conforming amendments
for Sec. Sec. 191.23(a)(9), 192.167(a)(2), 192.169(b), 192.179(c),
192.199(e), 192.361(f)(3), 192.363(c), 192.629(a) and (b), 192.727(b)
and (c) and 192.751. Third, even though PHMSA does not propose to
expand the concept of ``hazard'' uniformly across its regulations,
operators nevertheless may voluntarily supplement the baseline
requirements of PHMSA regulations by explicitly incorporating
environmental harms from releases of gas from their pipelines
throughout their policies, procedures, and practices.
---------------------------------------------------------------------------
\294\ Similarly, this proposed definition would not apply to IM
programs for UNGSFs, which are not subject to any requirements of
part 192 aside from Sec. 192.12(d).
---------------------------------------------------------------------------
PHMSA expects no material impact on operators' existing practices
from the above proposed new definition (along with the limited,
conforming revisions specified above), which supports a conclusion that
those proposed amendments would be reasonable, technically feasible,
cost-effective, and practicable. PHMSA invites comment by stakeholders
on the appropriateness of each of its above proposed revisions to, or
preservation of, existing regulatory references to ``hazards'' and
``hazardous leaks'' for potential modification of its above proposed
amendments in any final rule issued in this proceeding. PHMSA also
solicits comment on whether any provisions not addressed above would
also benefit from conforming revision. Should stakeholders proffer
alternative or additional regulatory amendments, they should support
those proposals by reference to each of any expected safety and
environmental benefits, as well as the cost-effectiveness,
practicability, and technical feasibility.
V. Section-By-Section Analysis
Sec. 191.3 Definitions
PHMSA proposes to revise Sec. 191.3 to add a definition for large-
volume gas releases that must be reported, per the new Sec. 191.19.
PHMSA proposes to define a ``large-volume gas release'' as an
intentional or unintentional release of gas of 1 MMCF or more. This new
large-volume gas release reporting requirement would be applicable to
all gas pipeline facility operators, including (but not limited to)
operators of jurisdictional underground storage and LNG facilities, as
well as Type R gas gathering pipelines.
PHMSA also proposes revision of the property damage criterion
within the definition of ``incident'' to exclude certain indirect costs
associated with the cost incurred by operators in conducting repair
activity. In particular, the revised definition excludes the cost of
preparing and obtaining permits, as well as the removal and replacement
of third-party infrastructure that was not itself damaged by the event.
For example, if a release from a pipeline beneath a street did not
damage a roadway, but pavement must be temporarily removed to repair
the pipeline, the costs of the roadway repair and associated permits
would not be included in the definition of property damage.
Sec. 191.11 Distribution System: Annual Report
PHMSA proposes to change Form F7100.1-1 and its instructions to
collect data on leaks detected and repaired by grade in the annual
reporting period and the number (by grade) of unrepaired leaks at the
conclusion of the annual reporting period. PHMSA also proposes to
change the gas distribution annual report form to include estimated
aggregate emissions from leaks by grade and other emissions categorized
by source category (similar to those in the tables in section II.C) on
an operator's system over the annual reporting period. PHMSA also
proposes to revise miscellaneous sections of those annual reports and
their instructions to remove statements expressing or suggesting that
releases that can be eliminated by routine maintenance (such as
lubrication, tightening, or adjustment) need not be reported as leaks.
Such leaks and leak repairs would instead be recorded as a separate
line item similar to the existing collection related to mechanical
fitting failures to ensure a complete accounting of the number of
releases from gas distribution pipelines.
Sec. 191.17 Transmission Systems; Gathering Systems; Liquefied Natural
Gas Facilities; and Underground Natural Gas Storage Facilities; Annual
Report
PHMSA proposes to change the gas transmission and regulated
gathering annual report form (Form F7100.2-1) and its instructions to
collect data on leaks detected and repaired by grade during the annual
reporting period. This form change is applicable to gas transmission,
offshore gas gathering, and Type A, B, and C regulated onshore gas
gathering pipelines. PHMSA also proposes to change Form F7100.2-1 to
include estimated aggregate emissions from leaks by grade and other
emissions by source category from an operator's system over the annual
reporting period. PHMSA does not propose changes to the Type R annual
report form (Form F7100.2-3). Lastly, PHMSA proposes to revise
miscellaneous sections of the annual reports (and accompanying
instructions) for each of gas transmission, offshore gathering, and
regulated onshore gathering pipelines (Form F7100.2-1), Type R
gathering pipelines (Form F7100.2-3) and LNG facilities (Form F7100.3-
1) to remove statements expressing or suggesting that releases that can
be eliminated by routine maintenance (such as lubrication, tightening,
or adjustment) need not be reported as leaks. A count of leaks
eliminated by routine
[[Page 31955]]
maintenance would instead be reported as a separate line item on the
annual report form.
Sec. 191.19 Large-Volume Gas Release Reports
PHMSA proposes to create a new Sec. 191.19 requiring operators to
submit reports of large-volume gas releases. Like incident reports,
this requirement would be applicable to all operators of PHMSA-
jurisdictional gas pipeline facilities, including operators of
jurisdictional underground storage and LNG facilities, as well as Type
R gas gathering pipelines. The term ``large-volume gas release'' is
defined in proposed amendments to Sec. 191.3, as described above. The
report would be required for releases that become reportable on or
after the effective date of a final rule.
The new proposed report would require pertinent operators to report
both intentional and unintentional releases of 1 MMCF or more of gas.
This new form would capture both unintentional, fugitive emissions
(e.g., from leaks) as well as blowdowns, maintenance related venting,
pressure relief device actuations, and other intentional, vented
emissions. Operators would be required to submit a report within 30
days from the date that a release known at detection to be 1 MMCF or
more was detected, or 30 days from the date that a previously detected
release became reportable. If the time the leak started is unknown,
operators should base the calculation based on estimated release volume
from the date of the most recent leakage survey.
PHMSA also notes that events reported as incidents under Sec. Sec.
191.9 or 191.15 would not also need to be reported pursuant to the
proposed Sec. 191.19 unless the total release volume at cessation
exceeds 10% of the volume estimated in the incident report. If an
unintentional release reported as a large-volume gas release report
subsequently becomes reportable as an incident due to updated release
volume estimates or consequences (or for any other reason), the
operator would have to resubmit it as an incident report appropriate
for the facility type.
Sec. 191.23 Reporting Safety-Related Conditions
Consistent with PHMSA's current treatment of releases reportable as
incidents, PHMSA proposes to except large-volume gas releases as
defined in proposed Sec. 191.3 from the requirement to submit a
safety-related condition report pursuant to Sec. 191.23. PHMSA also
proposes to amend Sec. 191.23(a)(9) to explicitly limit that safety-
related condition reporting requirement to imminent hazards to public
safety.
Sec. 191.29 National Pipeline Mapping System
PHMSA proposed to delete the current exemption for offshore gas
gathering, and Types A, B, and C gathering pipelines from NPMS
reporting requirements at Sec. 191.29(a), thereby obliging operators
of those pipelines to submit geospatial pipeline location data to NPMS.
PHMSA does not propose to require operators of Type R, reporting-only,
gas gathering lines to participate in the NPMS.
Sec. 192.3 Definitions
Section 192.3 defines a number of terms that are referenced in part
192. PHMSA proposes to add a few definitions, primarily those
associated with leak detection and repair. These are primarily
referenced in proposed Sec. 192.760 for the purposes of leak grading
and repair requirements.
PHMSA proposes to define a ``confined space'' as any subsurface
structure, other than a building, of sufficient size to accommodate a
person, and in which gas could accumulate or migrate. These would
include vaults, catch basins, and manholes. Unlike a building, a
confined space is not ordinarily occupied for residential, commercial,
or industrial uses. The difference between a confined space and a
substructure is that a confined space is large enough to accommodate a
person, while a substructure is not. Consistent with the GPTC Guide,
this definition differs from the definition of a ``confined space''
used by OSHA at 29 CFR 1910.146(b).
PHMSA proposes to define a ``gas-associated substructure'' as a
substructure that is part of an operator's pipeline facility but that
is not itself designed to convey or store gas. These would typically
consist of small vaults for devices, such as valves, meters,
regulators, or other equipment.
PHMSA proposes to define a ``substructure'' as any subsurface
structure that is not large enough for a person to enter and in which
gas could accumulate or migrate. Substructures would include telephone
and electrical service boxes and associated ducts and conduits, valve
boxes, and meter boxes.
PHMSA proposes to define, for the purposes of all subparts of part
192 other than IM requirements in Sec. 192.12(d) and subparts O and P,
a ``leak or hazardous leak'' as any release of gas from a pipeline that
is uncontrolled at the time of discovery and is an existing, probable,
or future hazard to persons (including operating personnel), property,
or the environment, or any uncontrolled release of gas from a pipeline
that is detectable via equipment, sight, sound, smell, or touch. PHMSA
proposes to require that each leak must be investigated, graded, and
repaired in accordance with proposed Sec. 192.760. This includes leaks
that are identified by the public or emergency personnel. Leaks include
unintended releases through intended release pathways. For example, a
pressure relief device or emergency shutdown device that fails and
releases gas through a vent or flare is a leak.
PHMSA proposes to define the ``lower explosive limit (LEL)'' as the
minimum concentration of vapor in air below which propagation of a
flame does not occur in the presence of an ignition source at ambient
temperature and pressure. The LEL of natural gas is 5% methane in air
by volume. The LEL for propane is 2.1% propane in air by volume. The
LEL for hydrogen gas is 4% hydrogen by volume.
PHMSA proposes to define a ``tunnel'' as a subsurface passageway
large enough for a person to enter and in which gas could accumulate or
migrate. Compared with a confined space, a tunnel is intended for
regular or occasional human occupancy.
PHMSA proposes to define a ``wall-to-wall paved area'' as an area
where the ground surface between the curb of a paved street and the
front wall of a building is continuously paved with hard top surface
impermeable to gas, excluding non-continuous landscaping such as tree
plots.
Sec. 192.9 What requirements apply to gathering lines?
The NPRM proposes a series of amendments to Sec. 192.9 to improve
protection of public safety and the environment from leaks and
incidents on all part 192-regulated onshore and offshore gathering
lines, and to improve alignment between the part 192 safety
requirements applicable to each of Types A, B, and C gathering
pipelines.
Requirements for Type A gathering pipelines are defined in Sec.
192.9(c), which requires that a Type A pipeline comply with the
requirements of part 192 for transmission lines, subject to specific
exceptions listed in that paragraph. PHMSA proposes no change to that
paragraph. All Type A gathering pipelines would therefore be subject to
the proposals introduced within the NPRM for transmission lines,
including each of the following: revised definitions, to include a
definition of ``leak or hazardous leak'' to account for environmental
hazards in connection
[[Page 31956]]
with non-IM subparts of part 192 (Sec. 192.3); engineering analyses
for the design of pressure relief devices (Sec. 192.199); modification
of initial testing requirements to account for environmental hazards
(Sec. Sec. 192.503, 192.507, 192.509, and 192.513); modification of
procedural manuals to provide for elimination of leaks and minimize
releases of gas as well as remediation or replacement of pipelines
known to leak (Sec. 192.605); revision of failure investigation
procedures for investigation of leaks (Sec. 192.617); enhanced
patrolling requirements (Sec. 192.705); enhanced leakage survey
requirements (Sec. 192.706); new leak grading, repair, and
documentation requirements (Sec. Sec. 192.703(c) and (d), 192.709,
192.760 and 192.763); new limitations on uprating pipelines (Sec. Sec.
192.553 and 192.557); new leak detection personnel qualification
requirements (Sec. 192.769); specific requirements for minimization of
blowdown emissions (Sec. 192.770), and new pressure relief device
maintenance requirements (Sec. 192.773). PHMSA also proposes that Type
A gathering pipeline operators would be able to submit for PHMSA review
a notification pursuant to Sec. 192.18 for flexibility with respect to
each of the following: use of alternative leak detection equipment in
non-HCA, Class 2 locations in complying with Sec. 192.706; use of an
alternative performance standard in Class 2 locations in complying with
Sec. 192.763; and extension of leak repair timelines set forth in
Sec. 192.760.
Part 192 requirements for Type B gathering pipelines are listed in
Sec. 192.9(d); part 192 requirements not listed in Sec. 192.9(d) are
generally inapplicable to Type B gathering pipelines. With respect to
new, relocated, replaced, or otherwise changed Type B gathering lines,
PHMSA proposes (consistent with its proposals for other regulated
gathering lines) each of the following: a new Sec. 192.199 prescribing
engineering analyses for the design of pressure relief devices; and
modification of initial testing requirements to account for
environmental hazards (Sec. Sec. 192.503, 192.507, 192.509, and
192.513). PHMSA also proposes to revise Sec. 192.9(d) to add to the
list of part 192 operations (subpart L) and maintenance (subpart M)
requirements applicable to all Type B gathering pipelines a number of
requirements for enhancing Type B operator leak detection, grading and
repair programs, including the following: revised definitions, to
include a definition of ``leak or hazardous leak'' to account for
environmental hazards in connection with non-IM subparts of part 192
(Sec. 192.3); introduction of procedural manuals providing for, among
other things, the elimination of leaks and minimizing releases of gas
as well as remediation or replacement of pipelines known to leak (Sec.
192.605); patrolling requirements (Sec. 192.705); enhanced leakage
survey requirements (Sec. 192.706); new leak grading, repair, and
documentation requirements (Sec. Sec. 192.703(c) and (d), 192.709,
192.760 and 192.763); and new pressure relief device maintenance
requirements (Sec. 192.773). PHMSA has not proposed that operators of
Type B gathering pipelines would be subject to new vented emissions
mitigation requirements at proposed Sec. 192.770. Further, PHMSA's
proposed revision referencing Sec. 192.605 procedural manual
requirements would dispel any stakeholder confusion regarding whether
Type B gathering pipelines are subject to the self-executing
requirements at section 114 of the PIPES Act of 2020 to eliminate
leaks, minimize releases of natural gas, and remediate or replace
pipelines known to leak. PHMSA also proposes that Type B gathering
pipelines would be subject to emergency response manual documentation
requirements at Sec. 192.605 and emergency planning requirements at
Sec. 192.615. Under Sec. 192.605(b)(1) and (b)(2), operators must
include procedures for compliance with the subpart M and subpart I
requirements applicable to the Type B lines in accordance with Sec.
192.9, but they are not required to have procedures for other subparts
M and I requirements. Similarly, operators of Type B gathering lines
are not required to have procedures for complying with Sec. 192.631
control room management requirements referenced in Sec.
192.605(b)(12), nor for the continuing surveillance and accident
investigation requirements referenced in Sec. 192.605(e).
Additionally, PHMSA proposes that Type B gathering pipeline operators
would be able to submit for PHMSA review a notification pursuant to
Sec. 192.18 for flexibility with respect to each of the following: use
of alternative leak detection equipment in non-HCA, Class 2 locations
in complying with Sec. 192.706; extension of leak repair timelines set
forth in Sec. 192.760; and use of an alternative performance standard
in Class 2 locations in complying with Sec. 192.763.
PHMSA also proposes a number of revisions to Sec. 192.9 paragraphs
identifying specific part 192 requirements applicable to Type C
gathering pipelines to promote alignment with regulatory requirements
applicable to other regulated onshore gathering pipelines and reduce
fugitive and vented emissions. Specifically, PHMSA proposes to revise
Sec. 192.9(e) to expand the list of part 192 operations (subpart L)
and maintenance (subpart M) requirements applicable to all Type C
gathering pipelines to include a number of requirements to enhance Type
C operator leak detection, grading and repair programs, including the
following: revised definitions, to include a definition of ``leak or
hazardous leak'' to account for environmental hazards in connection
with non-IM subparts of part 192 (Sec. 192.3); procedural manuals
providing for, among other things, elimination of leaks and minimize
releases of natural gas as well as remediation or replacement of
pipelines known to leak (Sec. 192.605); patrolling requirements (Sec.
192.705); enhanced leakage survey requirements (Sec. 192.706); new
leak grading, repair, and documentation requirements (Sec. Sec.
192.703(c) and (d), 192.709, 192.760 and 192.763); and pressure relief
device maintenance requirements (Sec. 192.773). PHMSA also proposes
that new, replaced, relocated, or changed Type C gathering lines would
be subject to the pressure relief device design and configuration
requirements at Sec. 192.199, as well as modification of initial
testing requirements to account for environmental hazards (Sec. Sec.
192.503, 192.507, 192.509, and 192.513). PHMSA has not proposed that
operators of Type C gathering pipelines would be subject to its
proposed new limitations on uprating pipelines at Sec. Sec. 192.553
and 192.557, or the vented emissions mitigation requirements at
proposed Sec. 192.770. PHMSA also proposes revision to Sec.
192.9(f)(1) to narrow the exceptions identified in that subparagraph to
ensure that all Type C gathering pipelines are subject to leakage
survey and repair requirements. Further, PHMSA's proposed revision
referencing Sec. 192.605 procedural manual documentation requirements
would dispel any stakeholder confusion regarding whether Type C
gathering pipelines must have emergency response manuals, or are
subject to the self-executing requirements at section 114 of the PIPES
Act of 2020 to eliminate leaks, minimize releases of natural gas, and
replace or remediate pipelines known to leak. Under Sec. 192.605(b)(1)
and (b)(2), operators must include procedures for compliance with the
subpart M and subpart I requirements applicable to the Type C
[[Page 31957]]
pipeline in accordance with Sec. 192.9, but they are not required to
have procedures for other subparts M and I requirements. Similarly,
operators are only required to have procedures for submitting safety-
related condition reports on Type C gathering lines if the pipeline is
subject to the safety-related condition reporting requirement in Sec.
191.23 (i.e., the pipeline is required to have an MAOP). Further,
operators of Type C gathering lines are not required to have procedures
for complying with Sec. 192.631 control room management requirements
referenced in Sec. 192.605(b)(12), nor for the continuing surveillance
and accident investigation requirements referenced in Sec. 192.605(e).
PHMSA also proposes that Type C gathering pipeline operators would be
able to submit for PHMSA review a notification pursuant to Sec. 192.18
for flexibility in each of the following: use of alternative leak
detection equipment in non-HCA, Class 1 locations in complying with
Sec. 192.706; use of an alternative performance standard in Class 1
locations in complying with Sec. 192.763; and extension of leak repair
timelines set forth in Sec. 192.760.
Lastly, PHMSA proposes minor changes to the language in Sec.
192.9(b) listing part 192 requirement to which offshore gas gathering
pipelines are exempt: specifically, PHMSA has added language stating
explicitly that offshore gas gathering pipelines would be exempt from
the default grade 2 classification requirement and at Sec.
192.763(c)(1)(vi) and the 30-day repair requirement at Sec.
192.763(c)(3). PHMSA has not otherwise proposed to modify Sec.
192.9(b). However, because PHMSA is proposing a number of revisions to
part 192 requirements applicable to gas transmission lines, those
proposed requirements would apply to offshore gathering pipelines as
well pursuant to Sec. 192.9(b). Specific proposals that would apply to
offshore gathering pipelines include each of the following: revised
definitions, to include a definition of ``leak or hazardous leak'' to
account for environmental hazards in connection with non-IM subparts of
part 192 (Sec. 192.3); engineering analyses for the design of pressure
relief devices (Sec. 192.199); modification of initial testing
requirements to account for environmental hazards (Sec. Sec. 192.503,
192.507, 192.509, and 192.513); new limitations on uprating pipelines
(Sec. Sec. 192.553 and 192.557); modification of procedural manuals to
provide for elimination of leaks and minimize releases of gas as well
as remediation or replacement of pipelines known to leak (Sec.
192.605); revision of failure investigation procedures for
investigation of leaks (Sec. 192.617); enhanced patrolling
requirements (Sec. 192.705); enhanced leakage survey requirements
(Sec. 192.706); new leak grading, repair, and documentation
requirements (Sec. Sec. 192.703(c) and (d), 192.709, 192.760 and
192.763); new leak detection personnel qualification requirements
(Sec. 192.769); specific requirements for minimization of blowdown
emissions (Sec. 192.770), and new pressure relief device maintenance
requirements (Sec. 192.773). PHMSA also proposes that offshore gas
gathering pipeline operators would be able to submit for PHMSA review a
notification pursuant to Sec. 192.18 for flexibility with respect to
each of the following: use of an alternative ALDP performance standard
in complying with Sec. 192.763; and extension of leak repair timelines
set forth in Sec. 192.760. PHMSA has not proposed that offshore gas
gathering pipelines would be subject to its proposed default
requirement within Sec. 192.763 for any leak be considered a grade 2
leak at a minimum.
Sec. 192.12 Underground Natural Gas Storage Facilities
Section 192.12(c) obliges operators of underground natural gas
storage facilities to have and follow written procedures for
operations, maintenance, and emergency response activities. PHMSA
proposes to revise the regulatory language in this provision to
incorporate within its regulations the section 114 of the PIPES Act of
2020 self-executing mandate that operators update their procedures to
provide for the elimination of leaks and minimize release of gas from
pipeline facilities.
Sec. 192.18 How To Notify PHMSA
PHMSA proposes to revise Sec. 192.18(c) to cross reference
proposed amendments in the NPRM that allow an operator flexibility in
complying with certain part 192 requirements. Specifically, the NPRM
proposes to allow operators to use alternative compliance approaches
with advance notification to PHMSA in connection with the following
requirements: use of leak detection equipment for leakage surveys on
onshore gas transmission and certain regulated gathering pipelines
(Sec. 192.706(a)(2)); for each of natural gas transmission and
gathering operators with pipelines in Class 1 or 2 locations, as well
as operators of any part 192-regulated gas pipeline transporting gas
other than natural gas, implementation of an alternative ALDP
performance standard as well as alternative leak detection equipment
(Sec. 192.763(c)); and minimum leak repair schedules (Sec.
192.760(h)). Each of these flexibilities is described separately under
its respective discussion in this section V. As specified in existing
Sec. 192.18, an operator must notify PHMSA 90 days in advance of using
an alternative compliance approach and may begin to use that
alternative approach if they do not receive a letter after 90 days
objecting to that alternative compliance approach from PHMSA.
Sec. 192.167 Compressor Stations: Emergency Shutdown
PHMSA proposes to revise Sec. 192.167(a)(2) governing on new,
replaced, relocated, or otherwise changed compressor stations on gas
transmission and part 192-regulated onshore gas gathering pipelines to
state that blowdowns of those facilities during emergency shutdowns
must be directed toward locations where the released gas would not
create a hazard to public safety specifically.
Sec. 192.169 Compressor Stations: Pressure Limiting Devices
PHMSA proposes to revise Sec. 192.169(b) governing on new,
replaced, relocated, or otherwise changed gas compression stations on
gas transmission pipelines and boosting stations on part 192-regulated
gathering pipelines to state that vent lines from pressure relief
devices must exhaust gas to locations that would not create a hazard to
public safety specifically.
Sec. 192.179 Transmission Line Valves
PHMSA proposes to revise Sec. 192.179(c) governing blowdown valves
on new, replaced, relocated, or otherwise changed gas transmission and
Types A, B, and C gathering pipelines to state that the discharges from
those valves must be located such that blowdowns to atmosphere would
not create a hazard to public safety specifically.
Sec. 192.199 Requirements for Design and Configuration of Pressure
Relief and Limiting Devices
PHMSA proposes to revise Sec. 192.199 to require that all new,
replaced, relocated, or otherwise changed overpressure protection
devices be designed and configured to minimize unnecessary releases of
gas to the atmosphere. Since Sec. 192.199 is a generally applicable
design requirement, this proposed amendment would apply to all
facilities regulated under part 192, including gas transmission,
distribution, offshore gas gathering, and Types A, B, and C onshore gas
gathering pipelines. This requirement would not be retroactive,
[[Page 31958]]
and thus would not apply to any pressure relief device on pipelines
existing on or before the effective date of the rule unless the
pipeline is subsequently replaced, relocated, or otherwise changed.
To comply with this proposed requirement, each pressure relief
device must be designed and configured based on a documented
engineering analysis demonstrating that the set and reset conditions of
the device, as well as the size and configuration of it and its
associated piping, are appropriate for providing adequate overpressure
protection. Additionally, the design and materials used for the relief
device must be compatible with the composition of the gas being
transported and be suitable for the anticipated operating and
environmental conditions. The design of the relief device would need to
include isolation valves to support testing and maintenance.
Lastly, PHMSA proposes revision of Sec. 192.199(e) to require that
all new, replaced, relocated, or otherwise changed pressure relief and
limiting devices on gas transmission, distribution, offshore gas
gathering, and Types A, B, and C gas gathering pipelines would need to
have discharge stacks, vents, or outlet ports located where gas can be
discharged into the atmosphere without undue hazards to public safety
specifically.
Sec. 192.361 Service Lines: Installation
PHMSA proposes revision of Sec. 192.631(f)(3) governing new,
replaced, relocated, or otherwise changed underground service lines
installed under buildings to provide that vents from service line
annular spaces must be to locations that would not create a hazard to
public safety specifically.
Sec. 192.363 Service Lines: Valve Requirements
PHMSA proposes revision of Sec. 192.363(c) governing design and
construction requirements for valves on high-pressure service lines to
limit that requirement to, among other things, certain high-pressure
service lines installed in areas where blowdowns of gas would be
hazardous to public safety specifically.
Sec. 192.503 General Requirements
PHMSA proposes to revise Sec. 192.503(a)(2) governing initial
testing requirements on new, replaced, relocated, or otherwise changed
gas transmission, distribution, and part 192-regulated gathering
pipelines to delete the qualification ``potentially'' modifying
``hazardous leak'' in recognition of the certainty of environmental
harms from any released natural gas, flammable gas, toxic gas, or
corrosive gas.
Sec. 192.507 Test Requirements for Pipelines To Operate at a Hoop
Stress Less Than 30 Percent of SMYS and at or Above 100 p.s.i. (689
kPa) Gage
PHMSA proposes to revise Sec. 192.507(a) governing certain initial
testing requirements on new, replaced, relocated, or otherwise changed
gas transmission, distribution, and part 192-regulated gathering
pipelines to delete the qualification ``potentially'' modifying
``hazardous leak'' in recognition of the certainty of environmental
harms from any released gas.
Sec. 192.509 Test Requirements for Pipelines To Operate Below 100
p.s.i. (689 kPa) Gage
PHMSA proposes to revise Sec. 192.509(a) governing initial testing
requirements on new, replaced, relocated, or otherwise changed gas
transmission, distribution, and part 192-regulated gathering pipelines
(other than service and plastic pipelines) to delete the qualification
``potentially'' modifying ``hazardous leak'' in recognition of the
certainty of environmental harms from any released gas.
Sec. 192.513 Test Requirements for Plastic Pipelines
PHMSA proposes to revise Sec. 192.513(b) governing initial testing
requirements on new, replaced, relocated, or otherwise changed plastic
gas transmission, distribution, and part 192-regulated gathering
pipelines to delete the qualification ``potentially'' modifying
``hazardous leak'' in recognition of the certainty of environmental
harms from any released gas. PHMSA also proposes an editorial
correction of the word ``insure'' to ``ensure.''
Sec. 192.553 General Requirements
PHMSA proposes to revise the general requirements for uprating to
clarify that any hazardous leaks detected during the uprating process
on gas transmission, distribution, offshore gathering, and Type A
gathering lines must be repaired prior to further increasing the
pressure of the pipeline during the incremental pressure increase
procedure in Sec. 192.553(a). This requirement would apply to any gas
transmission, distribution, or Type A gathering pipeline subjected to
an incremental increase in operating pressure as described in Sec.
192.553.
Sec. 192.557 Uprating: Steel Pipelines to a Pressure That Will Produce
a Hoop Stress Less Than 30 Percent of SMYS: Plastic, Cast Iron, and
Ductile Iron Pipelines
PHMSA proposes to revise Sec. 192.557(b)(2) to require that
operators of gas transmission, distribution, offshore gathering, and
Type A gathering pipelines repair any hazardous leaks (note that PHMSA
proposes to define leaks and hazardous leaks identically in Sec.
192.3) that are found prior to uprating a pipeline that will operate at
an MAOP producing a hoop stress less than 30 percent of SMYS, or that
is made of plastic, cast iron, or ductile iron. A pipeline with an
active leak would therefore not be permitted to be uprated to a higher
MAOP until each leak repair was complete.
Sec. 192.605 Procedural Manual for Operations, Maintenance, and
Emergencies
Existing Sec. 192.605 requires each operator of an onshore or
offshore gas transmission pipeline, gas distribution pipeline, offshore
gas gathering pipeline, or Type A gas gathering pipeline to prepare and
follow a written procedure manual for operations, maintenance, and
emergency response activities. PHMSA proposes to revise Sec. 192.9 to
extend those procedural documentation requirements to Types B and C gas
gathering pipelines, excluding requirements for procedures that are not
applicable to such pipelines. PHMSA also proposes to revise Sec.
192.605 to incorporate the self-executing mandate at section 114 of the
PIPES Act of 2020 that the maintenance and operating procedures for
part 192-regulated gas pipelines must include procedures for each of
the elimination of leaks and for minimizing releases of gas from
pipelines, as well as the remediation or replacement of pipelines known
to leak based on their material, design, or past maintenance and
operating history. These proposed amendments to Sec. Sec. 192.9 and
192.605 would dispel any stakeholder uncertainty regarding application
of the self-executing requirements in section 114 of the PIPES Act of
2020.
Sec. 192.617 Investigation of Failures
For the purposes of the existing requirement to investigate
failures, PHMSA proposes to define the term ``failure'' for the
purposes of Sec. 192.617 to mean ``when any portion of a pipeline
becomes inoperable, is incapable of safely performing its intended
function, or has become
[[Page 31959]]
unreliable or unsafe for continued use.'' PHMSA considers any leaking
gas pipeline as having failed to perform its intended function. This
proposed regulatory amendment would apply to gas distribution, gas
transmission, offshore gas gathering, and Type A regulated onshore gas
gathering pipelines.
Sec. 192.629 Purging of Pipelines
PHMSA proposes to revise its provisions governing the purging of
gas from each of gas transmission, distribution, offshore gathering and
Type A gathering pipelines to clarify that this provision remains
focused on addressing risks to public safety associated with purging of
gas from those pipelines. PHMSA also proposes editorial amendments
replacing the term ``released'' with ``introduced'' to more accurately
reflect that gas is being injected into the pipeline and replacing the
term ``line'' with ``pipeline.''
Sec. 192.703 General
As discussed above and below, PHMSA is proposing to delete the
historical reference to ``hazardous leak'' in Sec. 192.703 (which
qualification limited the general repair requirement in that provision)
and replace it with a reference to PHMSA's proposed Sec. 192.760 leak
grading and repair requirements. PHMSA's proposed revisions to
Sec. Sec. 192.703 (when coupled with proposed amendments to Sec.
192.9) would extend the scope of the Sec. 192.703 general leak repair
requirement to all part-192 regulated gas pipelines.
PHMSA also proposes an exception from proposed requirements listed
in Sec. 192.703(d) for gas transmission compression and gathering
boosting stations subject to EPA methane emissions monitoring and
repair requirements within current 40 CFR part 60, subpart OOOOa
regulations; proposed subpart OOOOb updates and subpart OOOOc methane
emissions guidelines (as implemented through EPA-approved State plans
with standards at least as stringent as EPA's emission guidelines in
subpart OOOOc or implemented through a Federal plan).\295\ Specific
proposed requirements from which eligible stations would be excepted
include the following: leak repair (Sec. 192.703(c)), leakage survey
and patrol (Sec. Sec. 192.705 and 192.706), leak grading and repair
(Sec. 192.760), ALDPs (Sec. 192.763), and qualification of leak
detection personnel (Sec. 192.769).
---------------------------------------------------------------------------
\295\ EPA, ``Standards of Performance for New, Reconstructed,
and Modified Sources and Emissions Guidelines for Existing Sources:
Oil and Natural Gas Sector Climate Review,'' 87 FR 74702 (Dec. 6,
2022).
---------------------------------------------------------------------------
Sec. 192.705 Transmission Lines: Patrolling
Visual right-of-way patrols with or without the use of leak
detection equipment are required by Sec. 192.705 on gas transmission
lines and are an important supplement to leakage surveys. PHMSA
proposes to increase the minimum required frequency of right-of-way
patrols on gas transmission, offshore gathering, and Type A gathering
pipelines to at least 12 times each calendar year, with intervals
between patrols not exceeding 45 days, regardless of location. PHMSA
also proposes to revise Sec. 192.9 to require operators perform
patrols of Type B and Type C regulated onshore gas gathering pipelines
on the same interval. An operator may combine a patrol pursuant to
Sec. 192.705 with a leakage survey pursuant to Sec. 192.706, provided
their procedures include both a visual survey of the right-of-way and a
leakage survey with leak detection equipment.
Sec. 192.706 Transmission Lines: Leakage Surveys
PHMSA proposes to revise Sec. 192.706 to increase the minimum
frequency for performing leakage surveys of gas transmission, offshore
gas gathering, and Types A, B, and C gathering pipelines, each located
in HCAs in Class 1, Class 2, and Class 3 locations, to twice each
calendar year at intervals not exceeding 7\1/2\ months. PHMSA also
proposes revision of Sec. 192.9 to extend Sec. 192.706 leak survey
requirements to all Type C gathering pipelines. Further, PHMSA proposes
to increase the minimum frequency for performing leakage surveys of gas
transmission and Types A and B gathering pipelines located in HCAs in
Class 4 locations to four times each calendar year at intervals not
exceeding 4\1/2\ months.
PHMSA proposes to require each leakage survey on an onshore gas
transmission pipeline or Type A, B, or C gathering pipeline to be
performed using leak detection equipment and methods that meet the ALDP
performance standard in the proposed Sec. 192.763. This proposed
change would eliminate the existing automatic, generically available
exception at Sec. 192.625 from requirements to use leak detection
equipment for gas transmission and Types A and B gathering pipelines in
Class 1 and Class 2 locations and odorized pipelines in Class 3 and
Class 4 locations. Leakage surveys for onshore gas transmission and
Types A, B, and C gathering pipelines would only be performed without
the use of leak detection equipment (i.e., solely with the use of human
or animal senses) with prior notification and review by PHMSA in
accordance with Sec. 192.18, and may only be approved in non-HCA,
Class 1, and Class 2 locations. Leakage surveys for offshore gas
transmission and offshore gathering pipelines would not require the use
of leak detection equipment. PHMSA has not proposed changes to the
requirements for leakage surveys for gas transmission and gathering
pipelines located outside of HCAs, or for gas transmission and
gathering pipelines operating without an odor or odorant.
PHMSA also proposes more frequent leakage surveys for all valves,
flanges, tie-ins with valves and flanges, ILI launcher and receiver
facilities on gas transmission, offshore gathering, and Types A, B, and
C gathering lines. PHMSA similarly proposes more frequent leakage
surveys for those gas transmissions, offshore gathering, and Types A,
B, and C gathering pipelines known to leak based on material, design,
or past operating and maintenance history. Each such facilities
identified in this paragraph located in Class 1, Class 2, and Class 3
locations must be surveyed twice each calendar year, and those in Class
4 locations must be surveyed at least four times each calendar year.
Sec. 192.723 Distribution: Leakage Surveys
PHMSA proposes defining minimum standards for leak survey practices
and equipment on gas distribution pipelines through reference to the
proposed ALDP performance standard in Sec. 192.763. This proposal
would replace the existing requirement at Sec. 192.723 to use leak
detection equipment and is described in more detail under the
discussion of that section below.
PHMSA also proposes to increase the frequency of leakage surveys on
most gas distribution pipelines outside of business districts to once
every 3 calendar years, with an interval between surveys not to exceed
39 months. Operators whose procedures or DIMP call for more frequent
leakage surveys would be obliged to conduct leakage surveys
accordingly. And distribution pipelines outside of business districts
at a high risk of leakage would generally be obliged to conduct leakage
surveys more frequently: once each calendar year, with the interval
between surveys not to exceed 15 months. The following distribution
pipelines outside of business districts would be subject to PHMSA's
proposed new annual survey requirement:
[[Page 31960]]
1. Cathodically unprotected pipelines on which electrical surveys
are impracticable. This would typically cover bare and unprotected
distribution lines;
2. Pipelines known to leak based on their material (including, but
not limited to, cast iron, unprotected steel, wrought iron, and
historic plastics with known issues), design, or past operating and
maintenance history; and
3. Any distribution pipeline protected by a distributed anode
system where the cathodic protections survey under Sec. 195.463 showed
a deficient reading during the most recent cathodic protection survey.
In determining whether a plastic pipeline is made of a ``historic
plastic with known issues'' operators should consider PHMSA and State
regulatory actions and industry technical resources identifying
systemic integrity issues from plastic pipe that is either comprised of
particular materials; or manufactured at particular times, by
particular companies, or pursuant to particular processes.
In addition to the above, PHMSA proposes to require, as soon as
practicable following ground freezing, heavy rain, flooding, or other
environmental conditions that may affect the venting of gas or cause
gas migration to nearby buildings, reinvestigation of known leaks
(including conducting a leakage survey for possible gas migration).
This investigation is to determine whether changes to gas migration or
to the facility itself have created a hazard that requires upgrading
the leak. Generally, any surface freezing or frost and any flooding
near the leak location is likely to affect gas venting and migration
through the soil. When determining if heavy rain is likely to affect
the venting or migration of leaking gas through the soil, operators
should consider the estimated flow rate of the leak, rate of rainfall,
local soil conditions, drainage, the presence of other nearby buried
structures, and whether the area has a history of flooding.
PHMSA also proposes to require leakage surveys of a distribution
pipeline soon (initiated within 72 hours) after the cessation of
extreme weather events or land movement that could damage that pipeline
segment. PHMSA defines the cessation of the event as either the time
that the facility becomes safely accessible to operator personnel, or
alternatively the time that the pipeline facility is placed back into
service.
Sec. 192.727 Abandonment or Deactivation of Facilities
PHMSA proposes to revise Sec. 192.727(b) and (c) governing
abandonment of gas transmission, distribution, offshore gathering, and
Type A gathering pipelines to provide that the existing exception for
small gas purge volumes in those paragraphs would be available if
purging would not create a risk to public safety specifically.
Sec. 192.751 Prevention of Accidental Ignition
PHMSA proposes to revise Sec. 192.751(a) governing gas
transmission, offshore gathering, and Type A gathering pipelines to
clarify that the hazards being addressed in that provision are hazards
to public safety specifically. PHMSA also proposes an editorial
amendment clarifying that a fire extinguisher must be present, rather
than provided, during venting of gas.
Sec. 192.760 Leak Grading and Repair
PHMSA proposes to create a new Sec. 192.760 addressing
requirements for grading and repairing leaks on gas distribution,
transmission, offshore gathering, and Types A, B, and C gathering
pipelines. The leak grading concept and many of the leak grading
criteria are similar to those in the GPTC Guide, which has been adopted
in some operator procedures and State pipeline safety requirements.
Sec. 192.760(a): General
Section 192.760(a) would require operators to have and carry out
written procedures for grading and repairing leaks that meet or exceed
the minimum requirements of Sec. 192.760. PHMSA's proposed
requirements in this paragraph also clarify that Sec. 192.760 would
apply to any leak detected by the operator and applies to all
components of pipelines (including, but not limited to, pipeline pipe,
valves, flanges, meters, regulators, tie-ins, launchers, and
receivers). Operators must investigate any leaks discovered immediately
and continuously until a leak grade determination has been made.
Sec. 192.760(b): Grade 1 Leaks
PHMSA proposes to characterize a grade 1 leak as an existing or
probable hazard to persons and property or grave hazard to the
environment. A grade 1 leak is an urgent or emergency situation and
this NPRM proposes to require an operator take immediate and continuous
action to eliminate any hazard to public safety and the environment and
to promptly complete repair. PHMSA's proposed paragraph (b)(2) includes
a list of actions the operator may take to address any hazard pending
repair. These steps include activating the operator's emergency plan
under Sec. 192.615, evacuating or blocking off the vicinity of the
leak, rerouting traffic, eliminating ignition sources, ventilating the
leak area to disperse hazardous accumulations of gas, stopping the flow
of gas in the facility, or notifying emergency responders. While some
of these actions, such as bar holing near the leak, may reduce gas
concentration, proposed Sec. 192.760(e) would not allow downgrading a
leak to a lower-priority leak grade unless a repair has been made. The
operator would have to promptly complete repair even if gas
concentration falls to grade 2 or grade 3 levels after the leak
location has been vented.
Paragraph (b)(1) provides minimum criteria for grade 1 leaks that
would need to be included in operators' leak grading procedures as they
demonstrate that a leak poses an existing or probable hazard to public
safety or grave hazard to the environment. Operator procedures may
supplement those proposed minimum grade 1 criteria as desired. Specific
criteria include the following: any leak that operating personnel at
the scene determine is an existing or probable hazard to public safety
or a grave hazard to the environment; any leak that has ignited; any
indication of potential for ignition of accumulated gas resulting from
gas migrating into a building, under a building, or into a tunnel; any
indication of potential for ignition due to accumulated gas due to
migration of gas to the outside wall of a building or to an area from
which migration to the outside wall of a building could occur; gas
concentration readings approaching LEL within either of a confined
space or a substructure from which gas could migrate to the outside of
a building; any leak that can be seen, heard, or felt; and any leak
that is an incident pursuant to Sec. 191.3.
Sec. 192.760(c): Grade 2 Leaks
PHMSA proposes to characterize a grade 2 leak as a leak with a
probable future hazard to public safety or a significant hazard to the
environment. There are currently no explicit Federal pipeline safety
requirements to repair such leaks; however, some States and operators
have adopted the GPTC Guide, which requires operators to repair such
leaks within 12 months of detection. PHMSA proposes to require a grade
2 leak repair be completed within six months in most circumstances,
however certain leaks would have shorter repair deadlines.
[[Page 31961]]
The proposed minimum criteria for grade 2 leaks reflect gas
readings suggesting that a leak has a probable, future hazard to public
safety or a significant hazard to the environment, but there is not an
existing or probable hazard to public safety or a grave hazard to the
environment as a grade 1 leak entails. Operator procedures may
supplement those proposed minimum grade 2 criteria as desired. Among
PHMSA's proposed minimum criteria are leaks, other than grade 1 leaks,
producing a gas reading of 40% LEL or greater under a sidewalk in a
wall-to-wall paved area, or a reading of 100% or greater under a street
in a wall-to-wall paved area with gas migration that is not a grade 1
leak. Similar to the grade 1 criteria, the grade 2 criteria include
criteria based on readings within confined spaces and substructures. A
leak reading between 20% LEL and 80% of LEL in a confined space is a
grade 2 leak. Unlike the grade 1 criteria, however, the grade 2
criteria make a distinction between gas readings in gas-associated and
non-gas associated substructures. A leak must be classified as grade 2
if it produces a reading less than 80% LEL in a non-gas associated
substructure from which gas could migrate. A leak with a reading of 80%
LEL or greater in a gas associated substructure from which gas could
migrate must be classified as a grade 2 leak. Like the grade 1
criteria, this NPRM proposes to require that operators' procedures
allow operating personnel at the scene to decide that a leak justifies
repair on a grade 2 schedule.
Similar to the discussion of grade 1 leaks, there are differences
between the grade 2 criteria proposed in this NPRM and the grade 2
criteria in the GPTC Guide. To ensure timely repair of leaks with
relatively large emissions, PHMSA proposes to require that any leak
other than a grade 1 leak with a leakage rate of 10 CFH) or more be
classified as a grade 2 leak. Additionally, in the NPRM, grade 2 is the
minimum grade for any leak on a gas transmission pipeline or Type A or
C gathering pipeline, or any leak of LPG or hydrogen that does not
qualify as grade 1 leak.
PHMSA proposes to require that operators repair grade 2 leaks
within 6 months of detection, or any alternative timeline identified in
an operator's procedures or IM plan, whichever is earlier. Operators
must reevaluate each grade 2 leak once every 30 days until the leak
repair is completed or the leak is cleared (or, if a grade 2 leak must
be repaired within 30 days, every 2 weeks until the repair has been
completed). However, PHMSA proposes to require operators to prioritize
repair of some grade 2 leaks based on their higher potential for public
safety and environmental consequences. For example, PHMSA proposes to
require any leak on a gas transmission or Type A gathering pipeline,
each in an HCA or a Class 3 or Class 4 location (and that is not a
grade 1 leak) to be repaired within 30 days of detection, or the
operator must take continuous action to monitor and repair the leak.
Additionally, PHMSA proposes to require each operator's leak grading
and repair procedures to include a methodology for prioritizing grade 2
leak repairs, including criteria for leaks that must be repaired within
30 days or less. The operator's methodology must include an analysis of
the volume and migration of gas emissions, the proximity of gas to
buildings and subsurface structures, the extent of pavement, and soil
type and conditions that affect the possibility for gas migration such
as frost conditions or soil moisture. This NPRM also proposes to
require an operator complete repair of an existing grade 2 leak or take
other immediate and continuous action to complete repairs and eliminate
hazards when changing environmental conditions that may affect the
venting or migration of gas that could allow gas to migrate to the
outside wall of a building. Environmental changes that could contribute
to gas migration include ground freezing, heavy rains or flooding, or
the installation of new pavement.
Finally, PHMSA proposes to require that operators complete repairs
of grade 2 leaks known to exist on or before the effective date of the
rule within 1 year from the date of publication of the final rule.
Sec. 192.760(d): Grade 3 Leaks
PHMSA proposes to characterize a grade 3 leak as any leak that does
not meet its minimum proposed grade 1 or grade 2 criteria. Like grade 2
leaks, there is no current Federal standard requiring repair of such
leaks, and the GPTC Guide does not require a minimum repair schedule.
Illustrative examples of grade 3 leaks as contemplated by this NPRM
include (but are not limited to) leaks with a reading of less than 80%
LEL in gas-associated substructures from which gas is unlikely to
migrate, any reading of gas under pavement outside of wall-to-wall
paved areas where it is unlikely that gas could migrate to the outside
wall of a building, or a reading of less than 20% LEL in a confined
space.
PHMSA proposes to require an operator to complete repair of each
grade 3 leak within 24 months of the date the leak was detected and
require each grade 3 leak be re-evaluated once every six months until
the leak repair has been completed. However, PHMSA proposes to allow an
operator to continue to monitor a grade 3 leak provided the pipeline
segment containing the leak is scheduled for replacement and is in fact
replaced, within five years of the date the leak was detected. Finally,
PHMSA proposes to require a grade 3 leak known to exist on or before
the effective date of the rule be repaired within 3 years from the date
of publication of the final rule, unless the pipeline is scheduled for
replacement within five years from the effective date of the rule.
Sec. 192.760(e): Post-Repair Inspection
PHMSA in proposed Sec. 192.760(e) defines requirements for
determining and documenting that a complete and effective repair of a
leak has been accomplished. PHMSA proposes to require that, in order
for a leak repair to be complete, an operator must perform a permanent
repair and obtain, during a post-repair inspection, a gas concentration
reading of 0% gas at the leak location. A temporary repair may be used
to downgrade a leak in accordance with proposed Sec. 192.760(g).
Proposed Sec. 192.760(e)(2) would require that the first post-repair
inspection be completed no sooner than 14 days but no later than 30
days after the date of repair.
Proposed Sec. 192.760(e)(3) provides for enhanced repair and
monitoring requirements if a post-repair inspection yields a gas
reading greater than 0% gas. Specifically, if a post-repair inspection
indicates that a grade 1 or 2 condition exists, the operator would need
to reevaluate the repair and take immediate and continuous action to
eliminate the hazard and complete the repair. If a grade 1 or grade 2
condition did not exist, the operator would need both to re-inspect the
leak every 30 days and complete the repair within either of the repair
deadline for a grade 3 leak under Sec. 192.760(d)(2) or (for a leak
that was downgraded after the initial repair) a new repair deadline
established under Sec. 192.760(g). Lastly, proposed Sec.
192.760(e)(4) would provide that post-repair inspection would not be
necessary if leak remediation was completed via routine maintenance
activities such as cleaning, lubrication, or adjustment.
Sec. 192.760(f) and (g): Upgrading and Downgrading
Proposed Sec. 192.760(f) and (g) describe the repair deadlines and
requirements for leaks that are upgraded or
[[Page 31962]]
downgraded to higher or lower -priority grades. Operators who receive
information that a higher-priority grade condition exists on a
previously graded leak would need to upgrade that leak to a higher-
priority grade. For a leak that is upgraded, PHMSA proposes to require
that the deadline for the repair would be the earlier of either the
remaining time based on the original leak grade, or the time allowed
for repair for the upgraded leak measured from the time the operator
receives information that a higher-priority grade condition exists. In
other words, an operator would not be permitted to extend the repair
deadline by upgrading a leak.
PHMSA also proposes to prohibit downgrading of a leak unless a
temporary repair has been made or a permanent repair to the pipeline
has been attempted but gas was detected during the post-repair
inspection required by proposed Sec. 192.760(e). For example, a leak
may not be downgraded simply by venting the leak location until gas
measurements fall to grade 3 levels, with no action taken to
permanently remediate the leak. A leak may be downgraded if the
facility was the subject of an attempt at permanent repair, but a non-
zero reading was measured during the post-repair inspection described
in the discussion of Sec. 192.760(e). If a leak were downgraded after
the attempted permanent repair, the time period for completion of
repair would be the remaining time allowed for repair under its new
grade, measured from the time the leak was initially detected.
Sec. 192.760(h) Extension of Leak Repair
PHMSA proposes to allow an extension of the repair deadline
requirements for individual grade 3 leaks only on a case-by-case basis.
This extension requires notification to, and review by, PHMSA pursuant
to the procedures in Sec. 192.18. An operator may request an extension
if the delayed repair timeline would not result in increased risks to
public safety, and the operator can demonstrate either that the
prescribed repair schedule is impracticable, an alternative repair
schedule is necessary for safety, or remediation within the specified
time frame would result in the release of more gas to the environment
than would otherwise occur if the leak were allowed to continue. For
example, if the repair of a grade 3 leak would require significant
emissions to blowdown the facility, delaying repair to coordinate with
other maintenance requiring shutdown (and thereby minimizing the total
number of blowdowns) may be appropriate. PHMSA proposes to require that
a notification under this paragraph include descriptions of the leak,
the leaking facility, the leak environment, the proposed extended
repair schedule, the justification for an extended repair schedule and
proposed emissions mitigation methods.
Sec. 192.760(i): Recordkeeping
Proposed Sec. 192.760(i) describes recordkeeping requirements
associated with leak grading and repair. Beginning on the effective
date of the rule, PHMSA proposes that records documenting the complete
history of investigation and grading of each leak prior to completion
of the repair would need to be retained until five years after the date
of the final post-repair inspection performed under proposed paragraph
Sec. 192.760(e). These records include documentation of grading
monitoring, inspections, upgrades, and downgrades. PHMSA also proposes
that records associated with the detection, remediation, and repair of
each leak must be maintained for the life of the pipeline. Permanent
recordkeeping would apply to both piping and non-piping portions of the
pipeline. Complete records of the location and timing of leaks and
repairs is necessary for an adequate leak management program.
Sec. 192.763 Advanced Leak Detection Program
PHMSA proposes to create Sec. 192.763 that would require operators
of gas distribution, transmission, offshore gathering, and Types A, B,
and C gathering pipelines establish a written Advanced Leak Detection
Program (ALDP) and establish performance standards for both the
sensitivity of leak detection equipment and for the effectiveness of
operators' ALDPs. The ALDP represents a comprehensive set of
technologies and procedures that an operator would use to detect all
leaks consistent with the proposed ALDP performance standard at Sec.
192.763(b). PHMSA proposes to require that an operator's written ALDP
include four main elements: leak detection equipment, leak detection
procedures, prescribed leakage survey frequencies, and program
evaluation.
The first element in an ALDP is the leak detection equipment that
operators would use to perform leakage surveys, pinpoint leak
locations, and investigate leaks. These equipment requirements are
proposed in Sec. 192.763(a)(1). Operator ALDPs would include a list of
leak detection technologies that the operator would use for leakage
surveys, pinpointing leak location, and leak investigations. Leak
detection equipment is not required for surveys of offshore gas
transmission and offshore gathering pipelines because offshore leaks
are visibly conspicuous. PHMSA further proposes that any leak detection
equipment must have a minimum sensitivity of 5 ppm (Sec.
192.763(a)(1)(ii)) to ensure detection of leaks consistent with the
proposed ALDP performance standard at Sec. 192.763(b). An operator may
need to use more sensitive equipment than required by Sec.
192.763(a)(1)(ii)--or supplemental equipment or techniques (e.g., soap
bubble testing)--to meet that ALDP performance standard depending on
the leak detection procedures used and the operating characteristics
and environment of the pipeline. Alternatively, operators of each of
(1) natural gas transmission and part 192-regulated gathering
pipelines, each of which are located either offshore or in Class 1 or 2
locations, and (2) any gas pipeline transporting flammable, toxic, or
corrosive gas other than natural gas, may (pursuant to Sec.
192.763(c)) request use of alternative leak detection equipment by
submitting a Sec. 192.18 notification for PHMSA review.
PHMSA proposes to require operators select leak detection equipment
within their ALDPs based on a documented analysis that reflects the
state of commercially available advanced leak detection technologies
and practices, and considers at a minimum the size, configuration,
operating parameters, and operating environment of the operator's
system (Sec. 192.763(a)(1)(iii)). PHMSA further proposes an operator's
analysis consider the appropriateness of specified examples of possible
advanced leak detection technologies, including each of the following:
handheld equipment, including optical, infrared, or laser-based
devices; continuous monitoring via stationary gas detectors, pressure
monitoring or other means; mobile surveys from vehicle or aerial
platforms; or systemic use of any other commercially available advanced
technology capable of meeting the program performance standard in Sec.
192.763(b).
The second program element in proposed Sec. 192.763(a)(2) consists
of the operator's written procedures related to leak detection. PHMSA
proposes that, at a minimum, the ALDP must include procedures for
performing compliant leakage surveys for each of the leak detection
equipment included in an operator's ALDP. To ensure that operators use
procedures appropriate for environmental conditions such as
temperature, wind, time of day, precipitation and humidity, the
operator must define under which conditions the
[[Page 31963]]
procedure may and may not be used. Additionally, those procedures must
be consistent with any instructions of the leak detection equipment
manufacturer regarding environmental and operational conditions
parameters for use.
PHMSA proposes to require that an operator's procedures must
provide for pinpointing the location of all leak indications with the
use of handheld leak detection equipment (Sec. 192.763(a)(2)(ii)). As
described above, any equipment used for pinpointing leaks must
generally (for onshore gas transmission, Types A, B, and C gathering,
and distribution pipelines) have a minimum sensitivity of 5 ppm or
less. If a leak location was pinpointed with handheld leak detection
equipment meeting this standard during the initial survey, PHMSA would
not expect an operator to re-survey the area to meet the requirement of
this paragraph.
To ensure the quality of leak detection equipment, PHMSA also
proposes at Sec. 192.763(a)(2)(iii) to require that an operator have
procedures for validating that a leak detection device used in its ALDP
meets the 5-ppm sensitivity requirement in Sec. 192.763(a)(1)(ii)
prior to initial use. This consists of testing the equipment
measurements against a known concentration of gas. The operator must
maintain records that the leak detection equipment has been validated
for five years after the date that the device ceases to be used in the
operator's ALDP. Separate from the one-time validation requirement,
PHMSA also proposes to require that operators have procedures for the
maintenance and calibration of leak detection equipment (Sec.
192.763(a)(2)(iv)). At a minimum the operator must follow the
maintenance and calibration procedures recommended by the equipment
manufacturer. PHMSA further proposes to require that an operator
recalibrate leak detection equipment following an indication of
malfunction.
The third required element of an ALDP in proposed Sec.
192.763(a)(3) is the frequency of leakage surveys. As discussed above,
PHMSA proposes to define minimum leakage survey frequencies in Sec.
192.723 for gas distribution pipelines and in Sec. 192.706 for gas
transmission, offshore gathering, and Types A, B, and C gathering
pipelines. However, PHMSA also proposes that if more frequent leakage
surveys are necessary to meet the ALDP performance standard in proposed
Sec. 192.763(b) or otherwise specified by the operator, those
frequencies must be noted in the operator's ALDP. More frequent leakage
surveys may be required for less sensitive leak detection equipment,
challenging survey conditions, or facilities with a high leakage
frequency.
The final element of an ALDP consists of proposed requirements in
Sec. 192.763(a)(4) for operator procedures governing program
evaluation and improvement. At least annually, operators must re-
evaluate the elements of their ALDP considering, at a minimum, each of
the following: the performance of leak detection equipment used,
advances in leak detection technologies and practices, the number of
leaks initially detected by third parties, the number of leaks and
incidents overall, and estimated emissions from leaks. This is similar
in principle to the existing continuous improvement requirements under
IM requirements in part 192, subparts O and P, as well as requirements
for certain operators to periodically review procedures under Sec.
192.605(b)(8) and (c)(4). If an operator finds evidence that their ALDP
fails to detect leaks during leakage surveys as required by the ALDP
performance standard at Sec. 192.763(b), it must make changes to
program elements to ensure that the minimum performance standard in
Sec. 192.763(b) is met. Operators must consider ways to improve their
leak detection programs based on leak detection performance data and
advances in technology.
PHMSA's proposed ALDP performance standard at Sec. 192.763(b)
includes a holistic, program-wide performance standard for the ALDP
elements listed in Sec. 192.763(a). PHMSA proposes to require that an
ALDP for gas transmission, distribution, offshore gathering, and Types
A, B, and C gathering pipelines must be capable of detecting all leaks
that produce a reading of 5 ppm of gas or greater when measured from a
distance of 5 feet from the pipeline, or from within a wall-to-wall
paved area. The performance standard of detecting leaks of a size large
enough to produce a reading of 5 ppm is a measurement of minimum
detectible leak size rather than the sensitivity of equipment itself.
PHMSA further proposes that each ALDP must be validated and documented
with engineering tests and analyses, and that such records should be
maintained for five years after the date that ALDP is no longer used by
the operator.
Lastly, PHMSA proposes at Sec. 192.763(c) the ability for certain
operators (specifically, each of (1) natural gas transmission, offshore
gathering, and Types A, B, and C gathering pipelines located in Class 1
or 2 locations and (2) any gas pipeline transporting flammable, toxic,
or corrosive gas other than natural gas) to request use of an
alternative performance standard, pursuant to the notification and
PHMSA review procedures established in Sec. 192.18. PHMSA proposes to
require that any notifications submitted under this provision must
include, among other things, information about the location, design,
gas being transported, operational parameters, environmental
conditions, and material properties and history of the pipeline, the
proposed alternative performance standard, and a description of any
leak detection equipment and procedures that would be used.
Sec. 192.769 Qualification of Leakage Survey, Investigation, and
Grading Personnel
PHMSA proposes to clarify at Sec. 192.769 training and
qualification requirements for personnel that conduct leakage surveys,
investigation, and leak grading on gas transmission, distribution,
offshore gathering, and Types A gathering pipelines. Section 192.769
proposes to require that all such personnel must be qualified under
subpart N and have documented work history or training in conducting
leakage surveys, investigation, and grading. This requirement clarifies
that surveying, investigating, grading, and repairing leaks are covered
tasks under subpart N.
Sec. 192.770 Minimizing Emissions From Gas Transmission Pipeline
Blowdowns
PHMSA in a new Sec. 192.770 proposes to require gas transmission,
offshore gathering, and Type A gathering pipeline operators minimize
the release of gas to the environment from intentional, vented
emissions (including for repairs, construction, operations, or
maintenance). PHMSA does not, however, propose to require mitigation
for emergency releases (e.g., emergency blowdowns) associated with the
activation of an operator's emergency plan under Sec. 192.615(a)(3).
However, an operator must document when an emergency release occurs,
and the justification for not taking mitigative action.
The proposed regulatory text provides examples of approved
mitigation methods from which pertinent operators may choose to prevent
or mitigate vented emissions. The first method is installing and using
valves or control fittings to reduce the volume of gas that must be
removed from the pipeline. The second method listed is routing vented
gas to a flare stack to be ignited or to other equipment for
consumption. The third, fourth, and fifth methods each involve reducing
the pressure of a
[[Page 31964]]
pipeline segment prior to venting, reducing total emissions volume. In
the third example, an operator isolates the pipeline segment upstream
of the venting segment and uses the downstream compressor station to
reduce the pressure of the affected segment. The fourth example is
similar except instead of the compressor station, an operator uses a
mobile compressor unit to reduce the pressure of the venting segment by
compressing gas into adjacent facilities or a storage vessel. The fifth
example is like the fourth, except it may be performed without
compression. PHMSA also proposes that operators may request, pursuant
to the notification procedure at Sec. 192.18, use of alternative
approaches for mitigating vented emissions not listed in the proposed
regulatory text, but which would provide reduce emissions by at least
50% compared with venting gas to the atmosphere without mitigative
action.
Lastly, PHMSA proposes that operators document the methodology used
in their procedures, including by documenting an analysis on how its
selected method minimizes the release of natural gas to the
environment.
Sec. 192.773 Pressure Relief Device Maintenance and Adjustment of
Configuration
PHMSA in a new Sec. 192.773 proposes to require operators of all
gas distribution, transmission, offshore gathering, and Types A, B, and
C gathering pipelines to have written operating and maintenance
procedures for assessment of the proper function of pressure relief
devices. PHMSA's proposed regulatory text would require operators to
assess and either repair or replace malfunctioning pressure relief
devices. PHMSA's proposed language also identifies specific action
operators would have to take on operation of a malfunctioning pressure
relief device, to include immediate repair or replacement of relief
devices that fail to provide adequate overpressure protection. If a
relief device activates and releases gas below the set pressure ranges
defined in the operator's operations and maintenance manual, the
operator must take immediate and continuous action to stop further
releases of gas and ensure adequate overpressure protection. In the
latter case, the device must be repaired or replaced as soon as
practicable but within 30 days of actuation. PHMSA further notes that
operators would be obliged to maintain records documenting the proper
operation and any remediation/replacement of pressure relief devices
for the service life of their facilities.
Sec. 192.1007 What are the required elements of an integrity
management plan?
PHMSA proposes to revise Sec. 192.1007(e)(1)(i) and (v) to delete
existing references to Sec. 192.703(c) that would be rendered
inapposite by PHMSA's proposed adoption of a different meaning for
``hazardous leak'' applicable to Sec. 192.703(c) than would be
applicable within its integrity management regulations at subparts O
and P.
Sec. 193.2503 Operating Procedures
Section 193.2503(c) obliges operators of part 193-regulated LNG
facilities to have and follow written procedures for normal and
abnormal operations. PHMSA proposes to revise the regulatory language
in this provision to incorporate within its regulations the section 114
of the PIPES Act of 2020 self-executing mandate that operators update
their procedures to provide for the elimination of leaks and minimize
release of gas from pipeline facilities.
Sec. 193.2523 Minimizing Emissions From Blowdowns and Boiloff
PHMSA proposes to add a new Sec. 193.2523 to require operators of
part 193-regulated LNG facilities to mitigate methane emissions from
non-emergency, vented releases such as blowdowns and tank boiloff.
PHMSA's proposed mitigation and documentation requirements in Sec.
193.2523 largely mirror those described in the section V discussion of
proposed Sec. 192.770.
Sec. 193.2605 Maintenance Procedures
Section 193.2605(b) obliges operators of part 193-regulated LNG
facilities to have and follow written maintenance procedures. PHMSA
proposes to revise the regulatory language in this provision to
incorporate within its regulations the section 114 of the PIPES Act of
2020 self-executing mandate that operators update their procedures to
provide for the elimination of leaks and minimize release of gas from
pipeline facilities.
Sec. 193.2624 Leakage Surveys
PHMSA proposes to create a new section requiring operators of LNG
facilities to perform periodic methane leakage surveys on methane or
LNG-containing components and equipment at least four times each
calendar year, with a maximum interval between surveys not to exceed
4\1/2\ months. This requirement would apply to part 193-regulated LNG
facilities. The methane leakage surveys would need to be performed with
leak detection equipment satisfying the 5-ppm minimum sensitivity
standard proposed for part 192-regulated gas pipelines elsewhere in
this NPRM. Methane leaks and other conditions discovered during the
surveys would need to be remediated in accordance with the operators'
maintenance or abnormal operating conditions procedures, to include any
repair schedules within those procedures. Leakage survey records,
including records of equipment validation and calibration, must be
maintained for 5 years after the leakage survey is completed.
VI. Regulatory Analysis and Notices
A. Legal Authority for This Rulemaking
This proposed rule is published under the authority of the
Secretary of Transportation delegated to the PHMSA Administrator
pursuant to 49 CFR 1.97. Among the statutory authorities delegated to
PHMSA are those set forth in the Federal Pipeline Safety Statutes (49
U.S.C. 60101 et seq.) (authorizing, inter alia, issuance of regulations
governing design, installation, inspection, emergency plans and
procedures, testing, construction, extension, operation, replacement,
and maintenance of pipeline facilities) and section 28 of the Mineral
Leasing Act, as amended (30 U.S.C. 185(w)(3)). For a complete listing
of authorities, see 49 CFR 1.97.
This NPRM proposes to implement several provisions of the PIPES Act
of 2020, including sections 113 (codified at 49 U.S.C. 60102(q)), 114
(codified at 49 U.S.C. 60108(a)), and 118 (codified at 49 U.S.C.
60102(b)(5)). While section 113 of the PIPES Act of 2020 does not
mandate that PHMSA issue leak detection and repair program requirements
for Type C gas gathering pipelines in Class 1 locations, 49 U.S.C.
60101(b) and 60102 grant authorities to issue standards for the
transportation of gas via any part 192-regulated gathering pipelines to
protect public safety and the environment, which include Type C gas
gathering pipelines. As explained in section II.E of this NPRM,
fugitive emissions from all gas gathering pipelines (including Type C
gas gathering pipelines in Class 1 locations) are a significant source
of methane emissions which directly harm the environment by
contributing to climate change--which (as explained in section II.B of
this NPRM) itself entails public safety and environmental risks.
Further, as explained in section II.D.3 of this NPRM and discussed in
further detail in the Preliminary RIA, releases of natural gas
(particularly unprocessed natural
[[Page 31965]]
gas from Type C and other gas gathering pipelines) contain HAPs and
VOCs are particularly harmful to public safety and the environment.
Further, 49 U.S.C. 60117(c) authorizes PHMSA to require owners and
operators of gas gathering, transmission, and distribution pipelines
and other pipeline facilities to submit information (including, as
appropriate, each of annual reports, incident reports, and intentional
release reports, and NPMS information as proposed in this NPRM)
required for regulation of those pipeline facilities under the Federal
Pipeline Safety Statutes. Further, section 60117(c) authorizes the
Secretary to require owners and operators of Type R gas gathering
pipelines to submit the same information to support future decision
making regarding whether and to what extent to impose requirements in
49 CFR part 192 on those gas gathering pipelines.
B. Executive Order 12866 and DOT Regulatory Policies and Procedures
E.O. 12866 (``Regulatory Planning and Review''),\296\ as amended by
E.O. 14094 (``Modernizing Regulatory Review''),\297\ 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, E.O. 12866
requires that ``agencies should select those [regulatory] approaches
that 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.
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\296\ 58 FR 51735 (Oct. 4, 1993).
\297\ 88 FR 21879 (April 11, 2023).
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E.O. 12866, as amended, and DOT Order 2100.6A require that PHMSA
submit ``significant regulatory actions'' to the Office of Management
and Budget (OMB) for review. This action has been determined to be
significant under E.O. 12866, as amended. It is also considered
significant under DOT Order 2100.6A because of significant
congressional, State, industry, and public interest in pipeline safety.
The proposed rule has been reviewed by OMB in accordance with E.O.
12866 and is consistent with the requirements of E.O. 12866, as
amended, and DOT Order 2100.6A.
E.O. 12866, as amended, and DOT Order 2100.6A also require PHMSA to
provide a meaningful opportunity for public participation, which
reinforces requirements for notice and comment in the Administrative
Procedure Act (APA, 5 U.S.C. 551 et seq.). In accord with the
requirement, PHMSA seeks public comment on the proposals in the NPRM
(including preliminary cost and cost savings analyses pertaining to
those proposals set forth in the preliminary RIA, as well as
discussions of the public safety, environmental, and equity benefits in
that document and the draft Environmental Assessment), as well as any
information that could assist in evaluating the benefits and costs of
this NPRM.\298\
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\298\ PHMSA also participated in OMB-led E.O. 12866 meetings
requested by public stakeholders during interagency regulatory
review of this NPRM, including EDF (March 9, 2023), PST (March 17,
2023), and Boundary Stone Partners/Aclima, Inc. (March 20, 2023).
Summaries of each E.O. 12866 meeting are available in the rulemaking
docket at Doc. No. PHMSA-2021-0039.
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The quantified benefits of the final rule consist of the climate
benefits of avoided methane emissions and the market value of avoided
natural gas losses. PHMSA expects additional, unquantified benefits
including safety benefits from early detection of leaks before they can
evolve into incidents and detection of integrity threats on gas
transmission and gathering pipelines from right-of-way patrols. PHMSA
also expects additional unquantified environmental and public health
benefits associated with preventing releases of natural gas, and other
flammable, toxic or corrosive gases, and expects these benefits to be
important given the types of health effects resulting from exposure to
air pollutants (e.g., asthma and other respiratory effects, cancer).
PHMSA invites commenters to provide additional information that would
enable quantification of the additional health and safety benefits of
the rule.
The table below summarizes the annualized quantified costs and
benefits for the provisions in the final rule at a 3 percent and a 7
percent discount rate (discussed in further detail in the Preliminary
RIA for this NPRM, available in the rulemaking docket):
Annualized Monetized Costs and Benefits
[Million 2020$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Distribution Total \1\
---------------------------------------------------------------
Discount rate (%) Item Gathering Transmission Lamb et al. Weller et al.
(2015) (2020) Low High
--------------------------------------------------------------------------------------------------------------------------------------------------------
3 Benefits..................... $553 $12 $515 $1,754 $1,081 $2,320
Costs........................ 211 15 514 654 740 880
Net benefits................. 343 -3 1 1,100 341 1,440
7% \2\ Benefits..................... 549 12 512 1,743 1,073 2,304
Costs........................ 209 15 530 677 753 900
Net benefits................. 340 -3 -18 1,067 320 1,404
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Total costs and benefits are presented as a range to reflect different assumptions regarding leak incidence and methane emissions rate across pipe
materials. The low estimate reflects distribution costs based on Lamb et al. (2015) whereas the high estimate reflects distribution costs based on
Weller et al. (2020).
\2\ Costs and benefits of natural gas losses are discounted at 7 percent, whereas climate benefits are based on the average SC-CH4 at 3 percent
discount. See section 5 of the Preliminary RIA for estimated climate benefits using other discount rates.
Source: PHMSA analysis.
Benefits of the final rule would depend on, among other things, the
degree to which compliance actions result in additional safety and gas
release avoidance and mitigation measures, relative to the baseline,
and
[[Page 31966]]
the effectiveness of these measures in preventing or mitigating future
releases or incidents from gas pipeline facilities subject to this
NPRM.
C. Executive Order 13132: Federalism
PHMSA analyzed this NPRM in accordance with the principles and
criteria contained in E.O. 13132 (``Federalism'') \299\ and the
Presidential Memorandum (''Preemption'') published in the Federal
Register on May 22, 2009.\300\ E.O. 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.''
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\299\ 64 FR 43255 (Aug. 10, 1999).
\300\ 74 FR 24693 (May 22, 2009).
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This NPRM is not expected to have a substantial direct effect on
State and local governments, the relationship between the National
Government and the States, or the distribution of power and
responsibilities among the various levels of government. This NPRM is
not expected to impose substantial direct compliance costs on State and
local governments.
While the NPRM may operate to preempt some State requirements, it
would not impose any regulation that has substantial direct effects on
the States, the relationship between the National Government and the
States, or the distribution of power and responsibilities among the
various levels of government. Section 60104(c) of Federal Pipeline
Safety Laws prohibits certain State safety regulation of interstate
pipelines. Under Federal Pipeline Safety Laws, States that have
submitted a current certification under section 60105(a) can augment
Federal 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. In this instance, the
preemptive effect of the regulatory amendments in this NPRM would be
limited to the minimum level necessary to achieve the objectives of the
Federal Pipeline Safety Laws. Therefore, the consultation and funding
requirements of E.O. 13132 do not apply.
D. Regulatory Flexibility Act
The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) requires
Federal agencies to conduct an initial Regulatory Flexibility Analysis
(IRFA) for a proposed rule subject to notice-and-comment rulemaking
under the APA unless the agency head certifies that the proposed rule
will not have a significant economic impact on a substantial number of
small entities. E.O. 13272 (``Proper Consideration of Small Entities in
Agency Rulemaking'') \301\ obliges agencies to establish procedures
promoting compliance with the Regulatory Flexibility Act. The DOT posts
its implementing guidance on a dedicated web page.\302\ This NPRM was
developed in accordance with E.O. 13272 and DOT guidance 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.
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\301\ 67 FR 53461 (Aug. 16, 2002).
\302\ DOT, ``Rulemaking Requirements Related to Small
Entities,'' https://www.transportation.gov/regulations/rulemaking-requirements-concerning-small-entities (last accessed June 17,
2021).
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PHMSA conducted an IRFA, which has been made available in the
docket within the Preliminary RIA for this rulemaking. PHMSA has
preliminarily determined that the proposed rule could result in a
significant economic impact on a substantial number of small entities,
depending on the degree to which operators are able to pass-through
costs. PHMSA seeks comment on whether the proposed rule, if adopted,
would have a significant economic impact on a significant number of
small entities.
E. National Environmental Policy Act
The National Environmental Policy Act (NEPA, 42 U.S.C. 4321 et.
seq.) 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 analyzed this NPRM in accordance with NEPA, NEPA implementing
regulations, and DOT Order 5610.1C. PHMSA has prepared a draft
environmental assessment (DEA) and preliminarily determined this action
will not significantly affect the quality of the human environment. To
the extent that the NPRM has impacts on the environment, these are
primarily beneficial ecological and human health impacts from early
detection of gas leaks and minimizing emissions of methane, a powerful
GHG that contributes to climate change. A copy of the draft EA for this
action is available in the docket. PHMSA invites comment on the
environmental impacts of this NPRM.
F. Environmental Justice
E.O. 12898 (``Federal Actions to Address Environmental Justice in
Minority Populations and Low-Income Populations''),\303\ as
supplemented by the E.O. entitled ``Revitalizing Our Nation's
Commitment to Environmental Justice for All'' (April 21, 2023),\304\
directs Federal agencies to take appropriate and necessary steps to
identify and address disproportionately high and adverse effects of
Federal actions on the health or environment of minority and low-income
populations ``[t]o the greatest extent practicable and permitted by
law.'' DOT Order 5610.2C (``U.S. Department of Transportation Actions
to Address Environmental Justice in Minority Populations and Low-Income
Populations'') establishes departmental procedures for effectuating
E.O. 12898 promoting the principles of environmental justice through
full consideration of environmental justice principles throughout
planning and decision-making processes in the development of programs,
policies, and activities, including PHMSA rulemaking.
---------------------------------------------------------------------------
\303\ 59 FR 7629 (Feb. 16, 1994).
\304\ E.O. number and Federal Register citation forthcoming. See
White House, ``Executive Order on Revitalizing Our Nation's
Commitment to Environmental Justice for All'' (April 21, 2023),
https://www.whitehouse.gov/briefing-room/presidential-actions/2023/
04/21/executive-order-on-revitalizing-our-nations-commitment-to-
environmental-justice-for-all/
#:~:text=We%20must%20advance%20environmental%20justice,human%20health
%20and%20the%20environment.
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PHMSA has evaluated this NPRM under DOT Order 5610.2C and E.O.
12898 and has preliminarily determined it will not cause
disproportionately high and adverse human health and environmental
effects on minority and low-income populations. The NPRM is facially
neutral and national in scope; it is neither directed toward a
particular population, region, or community, nor
[[Page 31967]]
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 gas gathering,
transmission, and distribution lines, many of which are located in the
vicinity of environmental justice communities,\305\ PHMSA does not
expect the regulatory amendments introduced by this final rule would
entail disproportionately high adverse risks for minority or low-income
populations in the vicinity of those pipelines. Lastly, as explained in
the draft environmental assessment, PHMSA expects that its proposed
regulatory amendments will yield GHG emissions reductions, thereby
reducing the risks posed by anthropogenic climate change to minority
and low-income populations.
---------------------------------------------------------------------------
\305\ 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).
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G. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
PHMSA analyzed this NPRM according to the principles and criteria
in E.O. 13175 (``Consultation and Coordination with Indian Tribal
Governments'') \306\ and DOT Order 5301.1 (``Department of
Transportation Programs, Polices, and Procedures Affecting American
Indians, Alaska Natives, and Tribes''). E.O. 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.
---------------------------------------------------------------------------
\306\ 65 FR 67249 (Nov. 9, 2000).
---------------------------------------------------------------------------
PHMSA assessed the impact of the NPRM and has preliminarily
determined that it will not significantly or uniquely affect Tribal
communities or Indian Tribal governments. The rulemaking's regulatory
amendments are facially neutral and would have broad, national scope;
PHMSA, therefore, does not expect this NPRM to significantly or
uniquely affect Tribal communities, much less impose substantial
compliance costs on Native American Tribal governments or mandate
Tribal action. Insofar as PHMSA expects the rulemaking will improve
safety and reduce public safety and environmental risks associated with
gas pipelines, PHMSA believes it will not entail disproportionately
high adverse risks for Tribal communities. While PHMSA is not aware of
specific Tribal-owned business entities that operate part 192-regulated
gas pipelines, any such business entities could be subject to direct
compliance costs as a result of this proposed rule. Because PHMSA does
not anticipate that this proposed rule would have tribal implications,
the funding and consultation requirements of E.O. 13175 would not
apply. PHMSA seeks comment on the applicability of E.O. 13175 to this
proposed rule and the existence of any Tribal-owned business entities
operating pipelines affected by the proposed rule (along with the
extent of such potential impacts).
H. Executive Order 13211
E.O. 13211 (``Actions Concerning Regulations That Significantly
Affect Energy Supply, Distribution, or Use'') \307\ requires Federal
agencies to prepare a Statement of Energy Effects for any ``significant
energy action.'' E.O. 13211 defines a ``significant energy action'' is
defined 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 (including a notice of inquiry, ANPRM,
and NPRM) that (1)(i) is a significant regulatory action under E.O.
12866 or any successor order and (ii) is likely to have a significant
adverse effect on the supply, distribution, or use of energy; or (2) is
designated by the Administrator of the Office of Information and
Regulatory Affairs as a significant energy action.
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\307\ 66 FR 28355 (May 22, 2001).
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This NPRM is a significant action under E.O. 12866, as amended;
however, it is not likely to have a significant adverse effect on
supply, distribution, or energy use, as further discussed in the
Preliminary RIA. Further, OIRA has not designated this NPRM as a
significant energy action.
I. Paperwork Reduction Act
Pursuant to 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. The proposals in the Pipeline Safety: Gas Pipeline Leak
Detection and Repair NPRM would trigger new reporting and notification
requirements for operators of natural gas transmission, distribution,
and gathering pipelines. PHMSA proposes new and revised reporting
requirements intended to improve the quality of the data available
concerning pipeline leaks and other sources of emissions.
Reporting Releases of Gas
PHMSA proposes to require pipeline operators to submit data on
intentional and unintentional releases of gas with a volume of 1 MMCF
or greater excluding certain events that had been reported as incidents
under Sec. Sec. 191.9 or 191.15. To collect this data, PHMSA proposes
the creation of a new large-volume emissions report to parallel
existing incident reporting requirements. Operators would be required
to submit this data upon each occurrence of a release that meets the
reporting requirement within 30 days from the date of detection or 30
days from the date that a previously detected release became
reportable. These new large-volume gas release reports would provide
valuable information on the primary sources and causes of vented
emissions and the causes of large-volume leaks that do not qualify as
incidents. This data would address information gaps in the current
incident reporting requirements with respect to intentional releases
and environmentally hazardous unintentional releases with release
volumes between 1 MMCF and 3 MMCF. PHMSA estimates that it would
receive 373 reports on average each year (239 and 134 reports for
gathering and transmission, respectively), with each report estimated
to require 4 hours to prepare.
Annual Report Revisions
PHMSA also proposes revisions to the existing gas transmission,
gathering, and distribution annual report forms to include reporting of
leaks discovered and repaired by grade, estimated leak emissions by
grade, and estimated annual emissions from other sources by source
category. Currently, these forms include data on leak repair, however
they lack data on leaks discovered and data on emissions generally.
Safety-Related Condition Reporting
PHMSA proposes an exception from Sec. 191.23 safety-related
condition reporting requirements for events that are reported as large-
volume gas releases. The proposed exception for large-volume incident
reports would be consistent with the existing exception at Sec.
191.23(b) for events reported as incidents. Because large-volume gas
release reports would have roughly equivalent detail to an incident
report,
[[Page 31968]]
a less detailed safety-related condition report would not be necessary.
PHMSA expects the burden for this information collection to decrease
because of this change.
National Pipeline Mapping System Reporting
This NPRM proposes to extend the reporting requirements at Sec.
191.29 for the NPMS to offshore gathering pipelines as well as Types A,
B, and C regulated onshore gas gathering pipelines. Currently only gas
transmission pipelines are required to provide geospatial data on their
pipeline systems in accordance with the NPMS requirements at 49 U.S.C.
60132 and 49 CFR 191.29. The collection of geospatial data from gas
gathering pipelines would provide PHMSA critical knowledge about the
location and operating characteristics of these pipelines to assist in
the identification and remediation of leaks.
Notification Requirements
PHMSA requires operators to make notifications in accordance with
Sec. 192.18 90 days in advance of using an alternative technology or
assessment method. Operators may proceed only if they do not receive a
letter objecting to the proposed use of other technology and/or
methods.
PHMSA proposes, in Sec. 192.706(a), to allow operators to request
the use of human senses, in lieu of leak detection equipment, when
conducting a leak survey if the operator provides advance notification
to PHMSA in accordance with Sec. 192.18.
In Sec. 192.763(c), PHMSA proposes to allow operators to request
to use an alternative advanced leak detection performance standard if
the operator notifies PHMSA, in accordance with Sec. 192.18. For gas
transmission, offshore gathering, and Types A, B, and C gathering
pipelines located in Class 1 or Class 2 locations, an operator may use
an alternative performance standard with prior notification to, and
review by PHMSA in accordance with Sec. 192.18. The notification must
include: mileage by system type, known material properties, location,
HCAs, operating parameters, environmental conditions, leak history, and
design specifications, including coating, cathodic protection status,
and pipe welding or joining method, the proposed performance standard,
any safety conditions such as increased survey frequency, the leak
detection equipment, procedures, and leakage survey frequencies the
operator proposes to employ, data on the sensitivity and the leak
detection performance of the proposed alternative ALDP standard, and
the gas transported by the pipeline.
In this proposed rule, an operator may request an extension of the
leak repair deadline requirements for an individual grade 3 leak with
advance notification to, and review by, PHMSA pursuant to Sec. 192.18.
The operator's notification must show that the delayed repair timeline
would not result in an increased risk to public safety, as well as that
either the required repair deadline is impracticable, or that
remediation within the specified time frame would result in the release
of more gas to the environment than would occur with continued
monitoring. The notification must include: a description of the leaking
facility including the location, material properties, the type of
equipment that is leaking, and the operating pressure; a description of
the leak and the leak environment, including gas concentration
readings, leak rate if known, class location, nearby buildings, weather
conditions, soil conditions, and other conditions that could affect gas
migration, such as pavement; a description of the alternative repair
schedule and a justification for the same; and proposed emissions
mitigation methods and monitoring and repair schedule. PHMSA estimates
that it may receive 508 requests to extend the deadline for remedying
leaks on average per year (341 from gas gathering operators and 167
from gas transmission operators), and that each of these requests would
require approximately 8 hours to prepare.
Recordkeeping Requirements
PHMSA proposes to require operators to develop and maintain various
records in conjunction with the proposed requirements in this NPRM.
Among those requirements, operators must develop written procedures for
grading and repairing leaks according to Sec. 192.760(a)(1); operators
must document post-repair evaluations according to Sec. 192.760(e);
operators must record the history of each leak, including leak
discovery, grading, monitoring, remediation, upgrades, and downgrades,
and maintain these records for a period of 5 years (records of repairs
must be maintained for the life of the pipeline) pursuant to Sec.
192.760(i)(1) and (2); operators must document the leak detection
equipment choice analysis required in Sec. 192.763(f); operators must
also record leak detection equipment calibration (and re-calibration)
and maintain these records for the life of the equipment pursuant to
Sec. 192.763(h)(2); and operators must record the repair or
replacement of a pressure relief device and maintain these records for
the life of the pipeline according to Sec. 192.773(c). PHMSA estimates
that it would take operators, on average, 80 hours annually to develop
these records. PHMSA estimates that it would take operators 20 hours
annually to maintain these records. This burden would be incurred by
the total reporting community.
PHMSA will submit the following information collection requests to
OMB for approval based on the requirements in this proposed rule. These
information collections are contained in the pipeline safety
regulations, 49 CFR parts 190 through 199. The following information is
provided for each information collection: (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 burden for the following information
collections are estimated to be revised as follows:
1. Title: Incident and Annual Reports for Gas Pipeline Operators.
OMB Control Number: 2137-0522.
Current Expiration Date: 03/31/2025.
Abstract: This mandatory information collection covers the
collection of data from operators of natural gas pipelines, UNGSFs, and
LNG facilities for annual reports. 49 CFR 191.17 requires operators of
UNGSFs, gas transmission systems, and gas gathering systems to submit
an annual report by March 15, for the preceding calendar year. This
information collection also covers the collection of immediate notice
of incident report data from Gas pipeline operators.
PHMSA proposes to revise this information collection in conjunction
with proposed regulatory changes made in the Pipeline Safety: Gas
Pipeline Leak Detection and Repair NPRM. The requested revision would
revise form F7100.2-1, the ``Natural and Other Gas Transmission and
Gathering Pipeline Systems Annual Report'' form, to collect the total
number of leaks identified within a calendar year.
PHMSA currently estimates that 1,810 operators spend, on average,
47 hours completing form PHMSA F7100.2-1. PHMSA expects these operators
to spend an additional 6 hours reporting the newly requested data on
the total number of leaks identified and estimated emissions within the
calendar year. This would increase the burden, per operator, from 47.5
hours annually to 53.5 hours annually to complete form PHMSA F7100.2-1.
This revision would
[[Page 31969]]
result in an additional reporting burden of 10,860 hours annually
bringing the overall burden for completing form F7100.2-1 to 96,835
hours (53.5 hours x 1,810 responses).
Affected Public: All gas pipeline operators.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 3,321.
Total Annual Burden Hours: 106,671 hours.
Frequency of Collection: Annual.
2. Title: Annual Report for Gas Distribution Operators.
OMB Control Number: 2137-0629.
Current Expiration Date: 05/31/2024.
Abstract: This information collection request would require
operators of gas distribution pipeline systems to submit annual report
data to the Office of Pipeline Safety in accordance with the
regulations stipulated in 49 CFR part 191 by way of form PHMSA F
7100.1-1. The form is to be submitted once for each calendar year. The
annual report form collects data about the pipe material, size, and
age. The form also collects data on leaks from these systems as well as
excavation damages. PHMSA uses the information to track the extent of
gas distribution systems and normalize incident and leak rates. PHMSA
proposes to revise this information collection in conjunction with
proposed regulatory changes made in the Pipeline Safety: Gas Pipeline
Leak Detection and Repair NPRM. The requested revision would revise
form PHMSA F7100.1-1, the Gas Distribution Annual Report, to collect
the total number of leaks identified within a calendar year, emissions
from leaks by grade, and estimated emissions from other sources by
source categories.
PHMSA estimates that, currently, 1,446 operators spend 17.5 hours
completing the Gas Distribution Annual report each year. PHMSA expects
these operators to spend an additional 6 hours reporting the newly
requested data on the total number of leaks identified and estimated
emissions within the calendar year. Because of this, PHMSA expects the
burden for completing form PHMSA F7100.1-1 to increase to 23.5 (17.5+6)
hours per report adding a total of 8,676 (6 hours x 1,446 operators)
hours to the overall burden for this information collection.
Affected Public: Gas Distribution operators.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 1,446.
Total Annual Burden Hours: 33,981.
Frequency of Collection: Annual.
3. Title: Reporting Safety-Related Conditions on Gas, Hazardous
Liquid, and Carbon Dioxide Pipelines and Liquefied Natural Gas
Facilities.
OMB Control Number: 2137-0578.
Current Expiration Date: 01/31/2023.
Abstract: 9 U.S.C. 60102 requires each operator of a pipeline
facility (except master meter operators) to submit to DOT a written
report on any safety-related condition that causes or has caused a
significant change or restriction in the operation of a pipeline
facility or a condition that is a hazard to life, property, or the
environment. PHMSA proposes to adjust the burden associated with this
information collection in conjunction with proposed regulatory changes
made in the Pipeline Safety: Gas Pipeline Leak Detection and Repair
NPRM which exempts large-volume gas releases from safety-related
condition reporting. The requested revision would reduce the burden for
this information collection by 3 responses and 18 burden hours
annually. PHMSA is not proposing to collect any additional data at this
time.
Affected Public: All gas pipeline operators.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 171.
Total Annual Burden Hours: 1,026.
Frequency of Collection: Annual.
4. Title: Incident and Annual Reports for Gas Pipeline Operators.
OMB Control Number: 2137-0635.
Current Expiration Date: 01/31/2023.
Abstract: Operators of natural gas pipelines and LNG facilities are
required to report incidents, on occasion, to PHMSA per the
requirements in 49 CFR part 191. This mandatory information collection
covers the collection of incident report data from natural gas pipeline
operators. The reports contained within this information collection
support the Department of Transportation's strategic goal of safety.
This information is an essential part of PHMSA's overall effort to
minimize natural gas transmission, gathering, and distribution pipeline
failures. PHMSA proposes to revise this information in conjunction with
proposed regulatory changes made in the Pipeline Safety: Gas Pipeline
Leak Detection and Repair NPRM to include a new form, (PHMSA F 7100.5)
designed to collect data on intentional and unintentional releases of
gas with a volume of 1 MMCF or greater.
PHMSA estimates that it would receive 593 of these new reports on
average each year (139 gas transmission, 254 gas gathering, and 200 gas
distribution), with each report estimated to require 12 hours to
prepare. This would result in an additional 593 responses and 7,116
burden hours for this information collection.
Affected Public: All gas pipeline operators.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 1,592.
Total Annual Burden Hours: 11,572.
Frequency of Collection: On Occasion.
5. Title: National Pipeline Mapping System Program.
OMB Control Number: 2137-0596.
Expiration Date: 1/31/2023.
Type of Request: Revision of a previously approved information
collection.
Abstract: The Pipeline Safety Improvement Act of 2002 (Pub. L. 107-
355), 49 U.S.C. 60132, ``National Pipeline Mapping System,'' requires
the operator of a pipeline facility (except distribution lines and
gathering lines) to provide information to PHMSA. Each operator is
required to submit geospatial data appropriate for use in the NPMS or
data in a format that can be readily converted to geospatial data; the
name and address of the person with primary operational control (to be
known as its operator), and a means for a member of the public to
contact the operator for additional information about the pipeline
facilities it operates. Operators would submit the requested data
elements once and make annual updates to the data if necessary. These
data elements strengthen the effectiveness of PHMSA's risk rankings and
evaluations, which are used as a factor in determining pipeline
inspection priority and frequency; allow for more effective assistance
to emergency responders by providing them with a more reliable,
complete data set of pipelines and facilities; and provide better
support to PHMSA's inspectors by providing more accurate pipeline
locations and additional pipeline-related geospatial data that can be
linked to tabular data in PHMSA's inspection database.
PHMSA proposes to revise this information in conjunction with
proposed regulatory changes made in the Pipeline Safety: Gas Pipeline
Leak Detection and Repair NPRM to require gas gathering operators to be
subject to NPMS reporting. PHMSA estimates that gas transmission
operators currently spend approximately 120 hours each year submitting
geospatial data through the NPMS. PHMSA estimates that, due to the
changes in this NPRM, 378 Type A, B, and C operators would be added to
the NPMS reporting community. This addition would increase the number
of responses for this information collection by 378 and increase the
overall reporting burden by 45,360 hours.
[[Page 31970]]
Respondents: Operators of gas transmission, hazardous liquid, or
LNG pipeline facilities.
Annual Reporting and Recordkeeping Burden:
Estimated Number of Responses: 1,724 responses.
Estimated Total Annual Burden: 207,761 hours.
Frequency of Collection: Annually.
6. Title: Notification Requirements for Leak Detection and Repair.
OMB Control Number: PHMSA will request a new OMB Control No.
Current Expiration Date: TBD.
Abstract: A person owning or operating a natural gas pipeline
facility is required to provide information to the Secretary of
Transportation at the Secretary's request according to 49 U.S.C. 60117.
The Pipeline Safety regulations contained within 49 CFR part 192
require operators to make various notifications upon the occurrence of
certain events. The provisions covered under this ICR involve
notification requirements for operators who utilize alternative or
expanded technologies and methods when conducting leak detection and
repair activities. These notification requirements are necessary to
ensure safe operation of pipelines and ascertain compliance with gas
pipeline safety regulations. These mandatory notifications help PHMSA
to stay abreast of issues related to the health and safety of the
nation's pipeline infrastructure.
PHMSA proposes to create this information in conjunction with
proposed regulatory changes made in the Pipeline Safety: Gas Pipeline
Leak Detection and Repair NPRM which requires operators to notify PHMSA
in various instances pertaining to leak detection and repair
activities. PHMSA expects all gas pipeline operators to be subject to
these notification requirements. PHMSA estimates that it may receive
1,000 requests on average per year from gas distribution operators to
extend the deadline for remedying leaks, with each of these requests
requiring approximately 8 hours to prepare.
Affected Public: All gas pipeline operators.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 1,000.
Total Annual Burden Hours: 8,000.
Frequency of Collection: On Occasion.
7. Title: Recordkeeping Requirements for Gas Pipeline Operators.
OMB Control Number: 2137-0049.
Current Expiration Date: 3/31/2025.
Abstract: A person owning or operating a natural gas pipeline
facility is required to maintain records, make reports, and provide
information to the Secretary of Transportation at the Secretary's
request. This mandatory information collection request would require
owners and/or operators of gas pipeline systems to make and maintain
records in accordance with the requirements prescribed in 49 CFR part
192 and to provide information to the Secretary of Transportation at
the Secretary's request. Certain records are maintained for a specific
length of time while others are required to be maintained for the life
of the pipeline. PHMSA uses these records to verify compliance with
regulated safety standards and to inform the agency on possible safety
risks.
PHMSA proposes to revise this information in conjunction with
proposed regulatory changes made in the Pipeline Safety: Gas Pipeline
Leak Detection and Repair NPRM which includes various recordkeeping
requirements for operators pertaining to leak detection and remediation
activities.
Affected Public: All gas pipeline operators.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 3,867,101 responses.
Total Annual Burden Hours: 1,904,157 hours.
Frequency of Collection: On Occasion.
Requests for copies of these information collections should be
directed to Angela Hill at [email protected]. Comments are invited
on:
(a) The need for the proposed collection of information for the
proper performance of the functions of the agency, including whether
the information will have practical utility;
(b) The accuracy of the agency's estimate of the burden of the
revised collection of information, including the validity of the
methodology and assumptions used;
(c) Ways to enhance the quality, utility, and clarity of the
information to be collected; and
(d) Ways to minimize the burden of the collection of information on
those who are to respond, including the use of appropriate automated,
electronic, mechanical, or other technological collection techniques.
Send comments directly to the Office of Management and Budget,
Office of Information and Regulatory Affairs, Attn: Desk Officer for
the Department of Transportation, 725 17th Street NW, Washington, DC
20503. Comments should be submitted on or prior to July 17, 2023.
J. Unfunded Mandates Reform Act of 1995
The Unfunded Mandates Reform Act (UMRA, 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 of $100 million or more (in 1996 dollars) in any given year,
the agency must prepare, amongst other things, a written statement that
qualitatively and quantitatively assesses the costs and benefits of the
Federal mandate.
PHMSA expects this NPRM would impose compliance costs of $100
million or more (in 1996 dollars) on private sector entities. PHMSA has
conducted an assessment (within the Preliminary RIA in the rulemaking
docket) of the NPRM and has preliminarily concluded that the NPRM's
proposed regulatory amendments will yield an appropriate balancing of
costs and benefits.
K. Privacy Act Statement
In accordance with 5 U.S.C. 553(c), PHMSA solicits comments from
the public to better inform its rulemaking process. PHMSA posts these
comments, without edit, including any personal information the
commenter provides, to www.regulations.gov, as described in the system
of records notice (DOT/ALL-14 FDMS), which can be reviewed at
www.dot.gov/privacy.
L. Executive Order 13609 and International Trade Analysis
E.O. 13609 (``Promoting International Regulatory Cooperation'')
\308\ 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.
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\308\ 77 FR 26413 (May 4, 2012).
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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
[[Page 31971]]
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 engages with international standards setting bodies to
protect the safety of the American public. PHMSA has assessed the
effects of the NPRM and has preliminarily determined that its proposed
regulatory amendments would not cause unnecessary obstacles to foreign
trade.
M. Cybersecurity and Executive Order 14082
E.O. 14082 (``Improving the Nation's Cybersecurity'') \309\
expressed the Administration policy that ``the prevention, detection,
assessment, and remediation of cyber incidents is a top priority and
essential to national and economic security.'' E.O. 14082 directed the
Federal Government to improve its efforts to identify, deter, and
respond to ``persistent and increasingly sophisticated malicious cyber
campaigns.'' In keeping with these policies and directives, PHMSA has
assessed the effects of this NPRM to determine what impact the proposed
regulatory amendments may have on cybersecurity risks for pipeline
facilities.
---------------------------------------------------------------------------
\309\ 86 FR 26633 (May 17, 2021).
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PHMSA's proposed requirements would not require pipeline operators
to generate new security-sensitive records. Most of the pipeline
facilities for which PHMSA proposes leak detection and repair
requirements (and associated recordkeeping requirements) are already
subject to such requirements--this NPRM simply proposes to enhance and
expand those requirements. While computerized continuous or remote
monitoring systems for pipeline facilities could be more vulnerable to
cyber-attack than other technologies, the NPRM does not prescribe the
use of any particular leak detection technology within operator
advanced leak detection programs. PHMSA proposes to require operators
to evaluate remote and real-time leak detection technologies as one
potential approach when operators are designing the portfolio of
technologies to be used to satisfy the proposed ALDP requirements, but
ultimately operators can choose to adopt or decline such technologies.
One proposal that may present relatively more cybersecurity risk is
the proposed requirement for offshore gas gathering pipelines and Types
A, B, and C gas gathering pipelines to provide geospatial data for
NPMS. If hacked by a bad actor, this information could provide
particularly sensitive information regarding the location of gas
gathering infrastructure nationwide. However, the risk associated with
hacking of NPMS data on gas gathering infrastructure appears relatively
low compared to the risks associated with unauthorized release of NPMS
data on gas transmission infrastructure. Data on gas transmission
infrastructure has long been stored in NPMS and would likely be
considered a more attractive target for bad actors given the greater
importance of transmission lines in the U.S. interstate gas supply
network.
Operators affected by these proposed requirements may also be
subject to cybersecurity requirements and guidance under Transportation
Security Administration (TSA) Security Directives,\310\ as well as any
new requirements resulting from ongoing TSA efforts to strengthen
cybersecurity and resiliency in the pipeline sector, as discussed
within an advance notice of proposed rulemaking published in November
2022.\311\ The Cybersecurity & Infrastructure Security Agency (CISA)
and the Pipeline Cybersecurity Initiative (PCI) of the U.S. Department
of Homeland Security also conduct ongoing activities to address
cybersecurity risks to U.S. pipeline infrastructure and may introduce
other cybersecurity requirements and guidance for gas pipeline
operators.\312\
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\310\ E.g., TSA, ``Ratification of Security Directive,'' 86 FR
38209 (July 20, 2021) (ratifying TSA Security Directive Pipeline-
2012-01, which requires certain pipeline owners and operators to
conduct actions to enhance pipeline cybersecurity).
\311\ TSA, ``Enhancing Surface Cyber Risk Management,'' 87 FR
74702 (Nov. 30, 2022).
\312\ See, e.g., CISA, National Cyber Awareness System Alerts,
https://www.cisa.gov/uscert/ncas/alerts (last accessed Feb. 1,
2023).
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PHMSA has considered the effects of the NPRM and has preliminarily
determined that its proposed regulatory amendments would not materially
affect the cybersecurity risk profile for pipeline facilities within
the scope of the proposed amendments. PHMSA seeks comment on any other
potential cybersecurity impacts of the proposed amendments beyond the
considerations discussed here.
N. Severability
The purpose of this proposed rule is to operate holistically in
addressing a panoply of issues related to safety and environmental
hazards on regulated pipelines, with a focus on detection, grading, and
repair of leaks. However, PHMSA recognizes that certain provisions
focus on unique topics. Therefore, PHMSA preliminarily finds that the
various provisions of this proposed rule are severable and able to
function independently if severed from each other, and thus, in the
event a court were to invalidate one or more of this proposed rule's
unique provisions, the remaining provisions should stand and continue
in effect. PHMSA seeks comment on which portions of this proposed rule
should or should not be severable.
List of Subjects
49 CFR Part 191
Natural gas, Pipeline safety, Reporting and recordkeeping
requirements.
49 CFR Part 192
Natural gas, Pipeline safety, Safety.
49 CFR Part 193
Pipeline safety, Reporting and recordkeeping requirements.
In consideration of the foregoing, PHMSA proposes to amend 49 CFR
parts 191, 192, and 193 as follows:
PART 191--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE;
ANNUAL, INCIDENT, AND OTHER REPORTING
0
1. The authority citation for part 191 continues to read as follows:
Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5121, 60101 et. seq.,
and 49 CFR 1.97.
0
2. In Sec. 191.3:
0
a. Revise paragraph (1)(ii) in the definition of ``Incident''; and
0
b. Add the definition of ``Large-volume gas release'' in alphabetical
order.
The revision and addition read as follows:
Sec. 191.3 Definitions.
* * * * *
Incident * * *
(1) * * *
(ii) Estimated property damage of $122,000 or more, including loss
to the operator and others, or both, but excluding each of the cost of
gas lost, the cost to acquire permits, and the cost to remove and
replace non-operator infrastructure that was not damaged by the
release. For adjustments for inflation
[[Page 31972]]
observed in calendar year 2021 onwards, changes to the reporting
threshold will be posted on PHMSA's website. These changes will be
determined in accordance with the procedures in appendix A to part 191.
* * * * *
Large-volume gas release means an intentional or unintentional
release of 1 million cubic feet or more of gas from a gas pipeline
facility as that term is defined in Sec. 192.3.
* * * * *
0
3. Add Sec. 191.19 to read as follows:
Sec. 191.19 Large-volume gas release report.
Each operator of a gas pipeline facility must report a large-volume
gas release on DOT Form PHMSA-F7100.5. Each report must be submitted
within 30 days after detection of a large-volume gas release. A large-
volume gas release report is not required if an incident report has
already been submitted under this part for the same event and the
release volume identified in the incident report is within 10 percent
of the total release volume on cessation of the release.
0
4. In Sec. 191.23, revise paragraphs (a)(9) and (b)(2) to read as
follows:
Sec. 191.23 Reporting safety-related conditions.
(a) * * *
(9) Any safety-related condition that could lead to an imminent
hazard to public safety and causes (either directly or indirectly by
remedial action of the operator), for purposes other than abandonment,
a 20% or more reduction in operating pressure or shutdown of operation
of a pipeline, UNGSF, or an LNG facility that contains or processes gas
or LNG.
* * * * *
(b) * * *
(2) Is an incident or large-volume gas release, or results in an
incident or large-volume gas release before the deadline for filing the
safety-related condition report;
* * * * *
0
5. In Sec. 191.29, revise paragraph (a) introductory text, and remove
paragraph (c) to read as follows:
Sec. 191.29 National Pipeline Mapping System.
(a) Each operator of a gas transmission pipeline, offshore
gathering, Type A, Type B, or Type C regulated onshore gathering
pipeline as determined in Sec. 192.8 of this subchapter, or liquefied
natural gas facility must provide the following geospatial data to
PHMSA for that pipeline or facility:
* * * * *
PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE:
MINIMUM FEDERAL SAFETY STANDARDS
0
6. 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
7. In Sec. 192.3, add the definitions of ``Confined space,'' ``Gas-
associated substructure,'' ``Leak or hazardous leak,'' ``Lower
explosive limit (LEL),'' ``Substructure,'' ``Tunnel,'' and ``Wall-to-
wall paved area'' in alphabetical order to read as follows:
Sec. 192.3 Definitions.
* * * * *
Confined space means any subsurface structure, other than a
building, of sufficient size to accommodate a person, and in which gas
could accumulate or migrate. These include, vaults, certain tunnels,
catch basins, and manholes.
* * * * *
Gas-associated substructure means a substructure that is part of an
operator's pipeline but that is not itself designed to contain gas.
* * * * *
Leak or hazardous leak means, for the purposes of all subparts of
part 192 except Sec. 192.12(d) and subparts O and P, any release of
gas from a pipeline that is uncontrolled at the time of discovery and
is an existing, probable, or future hazard to persons, property, or the
environment, or any uncontrolled release of gas from a pipeline that is
or can be discovered using equipment, sight, sound, smell, or touch.
* * * * *
Lower explosive limit (LEL) means the minimum concentration of gas
or vapor in air below which propagation of a flame does not occur in
the presence of an ignition source at ambient pressure and temperature.
* * * * *
Substructure means any subsurface structure that is not large
enough for a person to enter and in which gas could accumulate or
migrate. Substructures include, but are not limited to, telephone and
electrical ducts, and conduit, gas and water valve boxes, and meter
boxes.
* * * * *
Tunnel is a subsurface passageway large enough for a person to
enter and in which gas could accumulate or migrate.
* * * * *
Wall-to-wall paved area means an area where the ground surface
between the curb of a paved street and the front wall of a building is
continuously paved, excluding intermittent landscaping, such as tree
plots.
* * * * *
0
8. In Sec. 192.9:
0
a. Revise paragraph (b);
0
b. Redesignate paragraphs (d)(4) through (8) as paragraphs (d)(6)
through (10);
0
c. Add new paragraphs (d)(4) and (5);
0
d. Remove the word ``and'' from the end of paragraph (d)(9);
0
e. Revise newly redesignated paragraph (d)(10), and add paragraphs
(d)(11) through (13);
0
f. Redesignate paragraphs (e)(1)(iii) through (vii) as paragraphs
(e)(1)(iv) through (viii);
0
g. Add new paragraph (e)(1)(iii);
0
h. Remove the word ``and'' at the end of paragraph (e)(1)(vii);
0
i. Revise newly redesignated paragraph (e)(1)(viii);
0
j. Add paragraphs (e)(1)(ix) through (xi); and
0
k. Revise paragraph (f).
The revisions and additions read as follows:
Sec. 192.9 What requirements apply to gathering pipelines?
* * * * *
(b) Offshore lines. An operator of an offshore gathering line must
comply with requirements of this part applicable to transmission lines,
except the requirements in Sec. Sec. 192.13(d), 192.150, 192.285(e),
192.319(d) through (g), 192.461(f) through (i), 192.465(d) and (f),
192.473(c), 192.478, 192.485(c), 192.493, 192.506, 192.607, 192.613(c),
192.619(e), 192.624, 192.710, 192.712, 192.714, 192.763(c)(1)(vi) and
(c)(3), and in subpart O of this part.
* * * * *
(d) * * *
(4) Prepare, update, and follow a manual of written procedures for
conducting operations, maintenance, and emergency response in
accordance with Sec. 192.605. Compliance with the requirements
referenced in Sec. 192.605(b)(1), (b)(2), (b)(12), and (e) is only
required for pipeline facilities that are made subject to such
requirements under this section or Sec. 191.23;
(5) Develop and implement procedures for emergency plans in
accordance with Sec. 192.615;
* * * * *
(10) Conduct leakage surveys in accordance with Sec. 192.706
within an advanced leak detection program in accordance with Sec.
192.763;
(11) Investigate, grade, repair, and document leaks and leak
repairs in accordance with Sec. Sec. 192.703(c) through (d), 192.709,
and 192.760;
[[Page 31973]]
(12) Conduct patrols in accordance with Sec. 192.705; and
(13) Maintain and configure pressure relief devices to ensure
proper device operation and minimize release of gas in accordance with
Sec. 192.773.
(e) * * *
(1) * * *
(iii) Prepare, update, and follow a manual of written procedures
for conducting operations, maintenance, and emergency response in
accordance with Sec. 192.605. Compliance with the requirements
referenced in Sec. 192.605(b)(1), (2) and (12), (d), and (e) is only
required for pipeline facilities that are made subject to such
requirements under this section or Sec. 191.23;
* * * * *
(viii) Conduct leakage surveys in accordance with Sec. Sec.
192.706 within an advanced leak detection program in accordance with
Sec. 192.763;
(ix) Grade, investigate, repair, and document leaks and leak
repairs in accordance with Sec. Sec. 192.703(c) and (d), 192.709, and
192.760;
(x) Conduct patrols in accordance with Sec. 192.705; and
(xi) Maintain and configure pressure relief devices to ensure
proper device operation and minimize release of gas in accordance with
Sec. 192.773.
* * * * *
(f) Exceptions. (1) Compliance with paragraphs (e)(1)(ii), (vi),
and (vii), and (e)(2)(i) and (ii) of this section is not required for
pipeline segments that are 16 inches or less in outside diameter if one
of the following criteria are met:
* * * * *
0
9. In Sec. 192.12, revise paragraph (c) to read as follows:
Sec. 192.12 Underground natural gas storage facilities.
* * * * *
(c) Procedural manuals. Each operator of an UNGSF must prepare and
follow for each facility one or more manuals of written procedures for
conducting operations, maintenance, and emergency preparedness and
response activities under paragraphs (a) and (b) of this section. Such
manuals must include procedures for eliminating leaks and minimizing
releases of gas. Each operator must keep records necessary to
administer such procedures and review and update these manuals at
intervals not exceeding 15 months, but at least once each calendar
year. Each operator must keep the appropriate parts of these manuals
accessible at locations where UNGSF work is being performed. Each
operator must have written procedures in place before commencing
operations or beginning an activity not yet implemented.
* * * * *
0
10. In Sec. 192.18, revise paragraph (c) to read as follows:
Sec. 192.18 How to notify PHMSA.
* * * * *
(c) Unless otherwise specified, if an operator submits, pursuant to
Sec. 192.8, 192.9, 192.13, 192.179, 192.319, 192.461, 192.506(b),
192.607(e)(4), 192.607(e)(5), 192.619, 192.624(c)(2)(iii),
192.624(c)(6),192.632(b)(3), 192.634, 192.636, 192.703(d)(4),
192.706(a)(2), 192.710(c)(7), 192.712(d)(3)(iv), 192.712(e)(2)(i)(E),
192.714, 192.745, 192.760(h), 192.763(c), 192.917, 192.921(a)(7),
192.927, 192.933, or 192.937(c)(7) a notification for use of a
different integrity assessment method, analytical method, compliance
period, sampling approach, pipeline material, 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 PHMSA informing the operator that PHMSA objects to the
proposal or that PHMSA requires additional time and/or more information
to conduct its review.
* * * * *
0
11. In Sec. 192.167, revise paragraph (a)(2) to read as follows:
Sec. 192.167 Compressor stations: Emergency shutdown.
(a) * * *
(2) It must discharge gas from the blowdown piping at a location
where the gas will not create a hazard to public safety;
* * * * *
0
12. In Sec. 192.169, revise paragraph (b) as follows:
Sec. 192.169 Compressor stations: Pressure limiting devices.
* * * * *
(b) Each vent line that exhausts gas from the pressure relief
valves of a compressor station must extend to a location where the gas
may be discharged without hazard to public safety.
* * * * *
0
13. In Sec. 192.179, revise paragraph (c) to read as follows:
Sec. 192.179 Transmission line valves.
* * * * *
(c) Each section of a transmission line, other than offshore
segments, between main line valves must have a blowdown valve with
enough capacity to allow the transmission line to be blown down as
rapidly as practicable. Each blowdown discharge must be located so the
gas can be blown to the atmosphere without hazard to public safety and,
if the transmission line is adjacent to an overhead electric line, so
that the gas is directed away from the electrical conductors.
* * * * *
0
14. In Sec. 192.199, revise the section heading and paragraph (e), and
add paragraph (i) to read as follows:
Sec. 192.199 Requirements for design and configuration of pressure
relief and limiting devices.
* * * * *
(e) Have discharge stacks, vents, or outlet ports designed to
prevent accumulation of water, ice, or snow, located where gas can be
discharged into the atmosphere without undue hazard to public safety;
* * * * *
(i) All new, replaced, relocated, or otherwise changed pressure
relief and limiting devices must be designed and configured, as
demonstrated by a documented engineering analysis, to minimize
unnecessary releases of gas by ensuring each of the following:
(1) The set and reset actuation pressure of the pressure relief
device and where pressures are taken must minimize release volumes
beyond what is necessary to provide adequate overpressure protection;
(2) The design (including sizing and material) and configuration of
the pressure relief device and its associated piping must be
appropriate for its set and reset actuation pressure to minimize
pressure choking, compatible with the composition of transported gas,
and suitable for reliable operation in expected operating and
environmental conditions; and
(3) Installation of the pressure relief device must include
upstream and downstream isolation valves to facilitate testing and
maintenance.
0
15. In Sec. 192.361, revise paragraph (f)(3) to read as follows:
Sec. 192.361 Service lines: Installation.
* * * * *
(f) * * *
(3) The space between the conduit and the service line must be
sealed to prevent gas leakage into the building and, if the conduit is
sealed at both ends, a vent line from the annular space must extend to
a point where gas would not be a hazard to public safety, and
[[Page 31974]]
extend above grade, terminating in a rain and insect resistant fitting.
* * * * *
0
16. In Sec. 192.363, revise paragraph (c) to read as follows:
Sec. 192.363 Service lines: Valve requirements.
* * * * *
(c) Each service-line valve on a high-pressure service line,
installed above ground or in an area where the blowing of gas would be
hazardous to public safety, must be designed and constructed to
minimize the possibility of the removal of the core of the valve with
other than specialized tools.
0
17. In Sec. 192.503 revise paragraph (a)(2) to read as follows:
Sec. 192.503 General requirements.
(a) * * *
(2) Each hazardous leak has been located and eliminated.
* * * * *
0
18. In Sec. 192.507, revise paragraph (a) to read as follows:
Sec. 192.507 Test requirements for pipelines to operate at a hoop
stress less than 30 percent of SMYS and at or above 100 p.s.i. (689
kPa) gage.
* * * * *
(a) The pipeline operator must use a test procedure that will
ensure discovery of all hazardous leaks in the segment being tested.
* * * * *
0
19. In Sec. 192.509, revise paragraph (a) to read as follows:
Sec. 192.509 Test requirements for pipelines to operate below 100
p.s.i. (689 kPa) gage.
* * * * *
(a) The test procedure used must ensure discovery of all hazardous
leaks in the segment being tested.
* * * * *
0
20. In Sec. 192.513, revise paragraph (b) to read as follows:
Sec. 192.513 Test requirements for plastic pipelines.
* * * * *
(b) The test procedure must ensure discovery of all hazardous leaks
in the segment being tested.
* * * * *
0
21. In Sec. 192.553, revise paragraph (a)(2) to read as follows:
Sec. 192.553 General requirements.
* * * * *
(a) * * *
(2) Each leak detected must be repaired before a further pressure
increase is made.
* * * * *
0
22. In Sec. 192.557, revise paragraph (b)(2) to read as follows:
Sec. 192.557 Uprating: Steel pipelines to a pressure that will
produce a hoop stress less than 30 percent of SMYS: plastic, cast iron,
and ductile iron pipelines.
* * * * *
(b) * * *
(2) Make a leakage survey (if it has been more than 1 year since
the last survey) and repair any leaks that are found.
* * * * *
0
23. In Sec. 192.605, add paragraph (b)(13) to read as follows:
Sec. 192.605 Procedural manual for operations, maintenance, and
emergencies.
* * * * *
(b) * * *
(13) Eliminating leaks and minimizing releases of gas from
pipelines, as well as remediating or replacing pipelines known to leak
based on their material, design, or past operating and maintenance
history.
* * * * *
0
24. In Sec. 192.617, add paragraph (e) to read as follows:
Sec. 192.617 Investigation of failures and incidents.
* * * * *
(e) Failure defined. For the purposes of this section, the term
failure means when any portion of a pipeline becomes inoperable, is
incapable of safely performing its intended function, or has become
unreliable or unsafe for continued use.
0
25. In Sec. 192.629, revise paragraphs (a) and (b) to read as follows:
Sec. 192.629 Purging of pipelines.
(a) When a pipeline is being purged of air by use of gas, the gas
must be introduced into one end of the pipeline in a moderately rapid
and continuous flow. If gas cannot be supplied in sufficient quantity
to prevent the formation of a mixture of gas and air hazardous to
public safety, a slug of inert gas must be introduced into the pipeline
before the gas.
(b) When a pipeline is being purged of gas by use of air, the air
must be introduced into one end of the line in a moderately rapid and
continuous flow. If air cannot be supplied in sufficient quantity to
prevent the formation of a mixture of gas and air hazardous to public
safety, a slug of inert gas must be released into the line before the
air.
0
26. In Sec. 192.703, revise paragraph (c), and add paragraph (d) to
read as follows:
Sec. 192.703 General.
* * * * *
(c) Leaks must be graded and repaired in accordance with the
requirements in Sec. 192.760.
(d) Compliance with Sec. Sec. 192.703(c), 192.705 for patrols,
192.706 for leakage surveys, 192.760(a) through (h) for leak grading
and repair, 192.763 for advanced leak detection programs, and 192.769
for qualification of leakage survey personnel, is not required for a
compressor station on a gas transmission or gathering pipeline if:
(1) The facility is subject to methane emission monitoring and
repair requirements under either:
(i) 40 CFR part 60, subparts OOOOa or OOOOb; or
(ii) an EPA-approved State plan or Federal plan which includes
relevant standards at least as stringent as EPA's finalized emissions
guidelines in 40 CFR part 60, subpart OOOOc;
(2) The facility is within the first block valve entering or
exiting the compressor station covered by the emergency shutdown system
as required in Sec. 192.167 for station isolation from the pipeline;
and
(3) Repair records are maintained for the life of the facility in
accordance with Sec. 192.760(i).
0
27. In Sec. 192.705, revise paragraph (b) to read as follows:
Sec. 192.705 Transmission lines: Patrolling.
* * * * *
(b) Operators must conduct patrols at least 12 times each calendar
year at intervals not exceeding 45 days.
* * * * *
0
28. Revise Sec. 192.706 to read as follows:
Sec. 192.706 Transmission lines: Leakage surveys.
(a) General. Each operator must perform periodic leakage surveys in
accordance with this section. Each leakage survey must be conducted
according to the advanced leak detection program requirements in Sec.
192.763, except that human or animal senses may be used in lieu of leak
detection equipment only in the following circumstances:
(1) An offshore gas transmission pipeline below the waterline or
offshore gathering pipeline below the waterline; or
(2) An onshore transmission line outside of an HCA or a gathering
pipeline, each either in a Class 1 or Class 2 location, with advance
notification to PHMSA in accordance with Sec. 192.18. The notification
must include tests or analyses demonstrating that the survey method
would meet the ALDP performance standard in Sec. 192.763(b) or (c) (as
applicable).
[[Page 31975]]
(b) Frequency of surveys. Except as provided in paragraphs (c) and
(d) of this section, leakage surveys must be performed at the following
intervals:
(1) Pipelines outside of HCAs must be surveyed at least once per
calendar year, but with an interval between surveys not to exceed 15
months; and
(2) Pipelines in HCAs must be surveyed as follows:
(i) In Class 1, Class 2, and Class 3 locations, at least twice each
calendar year, with intervals not exceeding 7\1/2\ months;
(ii) In Class 4 locations, at least four times each calendar year,
with intervals not exceeding 4\1/2\ months.
(c) Non-odorized pipelines. Leakage surveys for pipelines
transporting gas in conformity with Sec. 192.625 without an odor or
odorant, must perform leakage surveys using leak detection equipment at
the following intervals:
(1) In Class 3 locations, at least twice each calendar year, at
intervals not exceeding 7\1/2\ months.
(2) In Class 4 locations, at least four times each calendar year,
at intervals not exceeding 4\1/2\ months.
(d) Valves, flanges and certain other facilities. Leakage surveys
of all valves, flanges, pipeline tie-ins with valves and flanges, ILI
launcher and ILI receiver facilities, and pipelines known to leak based
on material (including, cast iron, unprotected steel, wrought iron, and
historic plastics with known issues), design, or past operating and
maintenance history, must be performed at the following intervals:
(1) In Class 1, Class 2, and Class 3 locations, at least twice each
calendar year, at intervals not exceeding 7\1/2\ months.
(2) In Class 4 locations, at least four times each calendar year,
at intervals not exceeding 4\1/2\ months.
0
29. Revise Sec. 192.723 to read as follows:
Sec. 192.723 Distribution systems: Leakage surveys.
(a) General. Each operator of a gas distribution pipeline must
conduct periodic leakage surveys with leak detection equipment in
accordance with this section. All leakage surveys performed pursuant to
this section must use leak detection equipment that meets the
requirements of Sec. 192.763.
(b) Business districts. Leakage surveys must be conducted at least
once each calendar year, at intervals not exceeding 15 months,
consisting of atmospheric tests at each gas, electric, telephone,
sewer, water, or other system manhole; crack in the pavement and
sidewalks; and any other location that provides an opportunity for
finding gas leaks.
(c) Non-business districts. Leakage surveys must be conducted at
least once every 3 calendar years, at intervals not exceeding 39
months, unless a shorter inspection interval is required either by
paragraph (d) of this section, the operator's operations and
maintenance procedures, or the operator's integrity management plans
under part 192, subpart P.
(d) Frequency of regular leakage surveys. Leakage surveys must be
conducted at least once every calendar year, at intervals not exceeding
15 months, for:
(1) Cathodically unprotected distribution pipelines subject to
Sec. 192.465(e);
(2) Pipelines known to leak based on their material (including cast
iron, unprotected steel, wrought iron, and historic plastics with known
issues), design, or past operating and maintenance history; and
(3) Gas distribution pipeline systems protected by a distributed
anode system, in the area of deficient readings identified during a
cathodic protection survey pursuant to Sec. 195.463 and appendix D,
until the cathodic protection deficiency is remediated.
(e) Investigating known leaks after environmental changes. An
operator must investigate a known leak, including conducting a leakage
survey for possible gas migration, as soon as practicable when freezing
ground, heavy rain, flooding, or other changes to the environment occur
that could affect the venting of gas or could cause migration of gas to
the outside wall of a building.
(f) Extreme Weather Surveys. Leakage surveys must be performed
after extreme weather events and land movement with the likelihood to
cause damage to the affected pipeline segment. The survey must be
initiated within 72 hours after the cessation of the event, defined as
either the point in time when the affected area can be safely accessed
by the personnel and equipment required to perform the leakage survey
or when the facility has been returned to service.
0
30. In Sec. 192.727, revise paragraphs (b) and (c) to read as follows:
Sec. 192.727 Abandonment or deactivation of facilities.
* * * * *
(b) Each pipeline abandoned in place must be disconnected from all
sources and supplies of gas; purged of gas; in the case of offshore
pipelines, filled with water or inert materials; and sealed at the
ends. However, the pipeline need not be purged when the volume of gas
is so small that there is no potential hazard to public safety.
(c) Except for service lines, each inactive pipeline that is not
being maintained under this part must be disconnected from all sources
and supplies of gas; purged of gas; in the case of offshore pipelines,
filled with water or inert materials; and sealed at the ends. However,
the pipeline need not be purged when the volume of gas is so small that
there is no potential hazard to public safety.
* * * * *
0
31. In Sec. 192.751, revise paragraph (a) to read as follows:
Sec. 192.751 Prevention of accidental ignition.
* * * * *
(a) When an amount of gas potentially hazardous to public safety is
being vented into open air, each potential source of ignition must be
removed from the area and a fire extinguisher must be present.
* * * * *
0
32. Add Sec. 192.760 to read as follows:
Sec. 192.760 Leak grading and repair.
(a) General. Each operator must have and follow written procedures
for grading and repairing leaks that meet or exceed the requirements of
this section.
(1) These requirements are applicable to leaks on all portions of a
gas pipeline including, but not limited to, line pipe, valves, flanges,
meters, regulators, tie-ins, launchers, and receivers.
(2) The leak grading and repair procedure must prioritize leaks by
the hazard to public safety and the environment.
(3) Each leak must be investigated immediately and continuously
until a leak grade determination has been made.
(b) Grade 1 leaks. (1) A grade 1 leak is any leak that constitutes
an existing or probable hazard to persons or property or a grave hazard
to the environment. A grade 1 leak includes a leak with any of
following characteristics:
(i) Any leak that, in the judgment of operating personnel at the
scene is regarded as an existing or probable hazard to public safety or
a grave hazard to the environment;
(ii) Any amount of escaping gas has ignited;
(iii) Any indication that gas has migrated into a building, under a
building, or into a tunnel;
(iv) Any reading of gas at the outside wall of a building, or areas
where gas could migrate to an outside wall of a building;
(v) Any reading of 80% or greater of the LEL (60% for LPG systems)
in a confined space;
[[Page 31976]]
(vi) Any reading of 80% or greater of the LEL (60% for LPG systems)
in a substructure, (including gas associated substructures) from which
any gas could migrate to the outside wall of a building;
(vii) Any leak that can be seen, heard, or felt; or
(viii) Any leak defined as an incident in Sec. 191.3.
(2) An operator must promptly repair a grade 1 leak and eliminate
the hazardous conditions by taking immediate and continuous action by
operator personnel at the scene. Immediate action means the operator
will begin instant efforts to remediate and repair the leak upon
detection and to eliminate any hazardous conditions caused by the leak.
Continuous means that the operator must maintain on-site remediation
efforts until the leak repair has been completed. This may require one
or more of, but not limited to, the following actions be taken without
delay:
(i) Implementing an emergency plan pursuant to Sec. 192.615;
(ii) Evacuating premises;
(iii) Blocking off an area;
(iv) Rerouting traffic;
(v) Eliminating sources of ignition;
(vi) Venting the area by removing manhole covers, bar holing,
installing vent holes, or other means;
(vii) Stopping the flow of gas by closing valves or other means; or
(viii) Notifying emergency responders.
(c) Grade 2 leaks. (1) A grade 2 leak constitutes a probable future
hazard to persons or property or a significant hazard to the
environment, and includes any leak (other than a grade 1 leak) with any
the following characteristics:
(i) A reading of 40% or greater of the LEL under a sidewalk in a
wall-to-wall paved area that does not qualify as a grade 1 leak;
(ii) A reading at or above 100% of LEL under a street in a wall-to-
wall paved area that has gas migration and does not qualify as a grade
1 leak;
(iii) A reading between 20% and 80% of the LEL in a confined space;
(iv) A reading less than 80% of the LEL in a substructure (other
than gas associated substructures) from which gas could migrate;
(v) A reading of 80% or greater of the LEL in a gas associated
substructure from which gas could not migrate;
(vi) Any reading of gas that does not qualify as a grade 1 leak
that occurs on a transmission pipeline or a Type A or Type C regulated
gas gathering line;
(vii) Any leak with a leakage rate of 10 cubic feet per hour (CFH)
or more that does not qualify as a grade 1 leak;
(viii) Any leak of LPG or hydrogen gas that does not qualify as a
grade 1 leak; or
(ix) Any leak that, in the judgment of operating personnel at the
scene, is of sufficient magnitude to justify scheduled repair within
six months or less.
(2) An operator must schedule repair based on the severity or
likelihood of hazard to persons, property, or the environment. A grade
2 leak must be repaired within six months of detection, unless a
shorter repair deadline is required by the operator's procedures,
integrity management program, or paragraphs (c)(3) through (6) of this
section. The operator must re-evaluate each grade 2 leak at least once
every 30 days until it is repaired.
(3) The operator must complete repair of any grade 2 leak on a gas
transmission or Type A gathering pipeline, each located in an HCA,
Class 3 or Class 4 location, within 30 days of detection. If repair
cannot be completed within 30 days due to permitting requirements or
parts availability, the operator must take continuous action to monitor
and repair the leak.
(4) Each operator's operations and maintenance procedure must
include a methodology for prioritizing the repair of grade 2 leaks,
including criteria for leaks that warrant repair within 30 days of
detection pursuant to Sec. 192.760(c). Grade 2 leaks with a repair
deadline of less than 30 days must be re-evaluated at least once every
2 weeks until the repair is complete. This methodology must include an
analysis of, at a minimum, each of the following parameters:
(i) The volume and migration of gas emissions;
(ii) The proximity of gas to buildings and subsurface structures;
(iii) The extent of pavement; and
(iv) Soil type and conditions, such as frost cap, moisture, and
natural venting.
(5) Each operator must take immediate and continuous action to
complete repair of a grade 2 leak and eliminate the hazard when
freezing ground, heavy rain, flooding, new pavement, or other changes
to the environment are anticipated or occur near an existing grade 2
leak that may affect the venting or migration of gas and could allow
gas to migrate to the outside wall of a building.
(6) An operator must complete repair of known grade 2 leaks
existing on or before [effective date of the final rule] before [date 1
year after the publication date of the final rule].
(d) Grade 3 leaks. (1) A grade 3 leak is any leak that does not
meet the criteria of a grade 1 or grade 2 leak. In order to qualify as
a grade 3 leak, none of the criteria for grade 1 or 2 leaks must be
present. Grade 3 leaks may include, but are not limited to, leaks with
the following characteristics:
(i) A reading of less than 80% of the LEL in gas associated
substructures from which gas is unlikely to migrate; or
(ii) Any reading of gas under pavement outside of a wall-to-wall
paved area where gas is unlikely to migrate to the outside wall of a
building; or
(iii) A reading of less than 20% of the LEL in a confined space.
(2) A grade 3 leak must be repaired within 24 months of detection,
except as described below:
(i) A grade 3 leak known to exist on or before [effective date of
the final rule] must be repaired prior to [date 3 years after the
publication date of the final rule].
(ii) A grade 3 leak may be evaluated in accordance with paragraph
(d)(3) of this section and repairs postponed if the segment containing
the leak is scheduled for replacement, and is replaced, within five
years of detection of the leak.
(3) Each operator must re-evaluate each grade 3 leak at least once
every six months until repair of the leak is complete.
(e) Post-repair inspection. (1) A leak repair is considered to be
complete when an operator obtains a gas concentration reading of 0% gas
at the leak location after a permanent repair.
(2) An operator must conduct a post-repair leak inspection at least
14 days after but no later than 30 days after the date of the repair to
determine if the repair was complete.
(3) If a post-repair inspection shows a gas concentration reading
greater than 0% gas, the repair is not complete, and operator must take
the following actions:
(i) If the post repair inspection finds gas concentrations or
migration indicating that the potential for a grade 1 or grade 2
condition leak exists, the operator must re-inspect the repair and take
immediate and continuous action to eliminate the hazard and complete
repair;
(ii) If the operator's post repair inspection does not find a gas
concentration reading of 0% at the leak location, and a grade 1 or
grade 2 condition does not exist, then the operator must remediate the
repair and re-inspect the leak within 30 days and continue reevaluating
the leak at least once every 30 days until there is a gas concentration
reading of 0%. Leak repair must be complete within the repair deadline
for a grade 3 leak under Sec. 192.760(d)(2), or for a downgraded leak,
the repair deadline under Sec. 192.760(g).
[[Page 31977]]
(4) A post repair inspection is not required for any leak that is
eliminated by routine maintenance work--such as adjustment or
lubrication of above-ground valves, or tightening of packing nuts on
valves with seal leaks--and is a grade 3 leak or occurs on an
aboveground pipeline facility.
(f) Upgrading leak grades. If at any time an operator receives
information that a higher-priority grade condition exists in connection
with a previously-graded leak, the operator must upgrade that leak to
the higher-priority grade. When an operator upgrades a leak to a
higher-priority grade, the time period to complete the repair is the
earlier of either the remaining time based on its original leak grade
or the time allowed for repair under its new leak grade measured from
the time the operator received the information that a higher-priority
grade condition exists.
(g) Downgrading leak grades. A leak may not be downgraded to a
lower-priority leak grade unless a temporary repair to the pipeline has
been made or a permanent repair was attempted but gas was detected
during the post-repair inspection under paragraph (e) of this section.
In this case, the time period for repair is the remaining time allowed
for repair under its new grade measured from the time the leak was
detected.
(h) Extension of leak repair. An operator may request an extension
of the leak repair deadline requirements for an individual grade 3 leak
with advance notification to and no objection from PHMSA pursuant to
Sec. 192.18. The operator's notification must show that the delayed
repair timeline would not result in an increased risk to public safety,
as well as that either the required repair deadline is impracticable,
or that remediation within the specified time frame would result in the
release of more gas to the environment than would occur with continued
monitoring. The notification must include the following:
(1) A description of the leaking facility including the location,
material properties, the type of equipment that is leaking, and the
operating pressure;
(2) A description of the leak and the leak environment, including
gas concentration readings, leak rate if known, class location, nearby
buildings, weather conditions, soil conditions, and other conditions
that could affect gas migration, such as pavement;
(3) A description of the alternative repair schedule and a
justification for the same; and
(4) Proposed emissions mitigation methods, monitoring, and repair
schedule.
(i) Recordkeeping. (1) Records of the complete history of the
investigation and grading of each leak must be retained for 5 years
after the final post-repair inspection is completed under paragraph (e)
of this section. These records include all records documenting leak
grading, monitoring, inspections, upgrades, and downgrades.
(2) Records of the detection, remediation, and repair of the leak
must be retained for the life of the pipeline. This must include the
date, location, and description of each leak detected, and repair or
remediation of the same, made on the pipeline.
0
33. Add Sec. 192.763 to read as follows:
Sec. 192.763 Advanced Leak Detection Program.
(a) Advanced Leak Detection Program (ALDP) elements. Each operator
must have and follow a written ALDP that includes the following
elements:
(1) Leak detection equipment. (i) The ALDP must include a list of
leak detection equipment used in operator leakage surveys, pinpointing
leak locations, and investigating leaks.
(ii) Leak detection equipment used for leakage surveys, pinpointing
leak locations, investigating, and inspecting leaks must have a minimum
sensitivity of 5 parts per million for each gas being surveyed. The
operator must validate the sensitivity of this equipment before using
the device in a leakage survey by testing with a known concentration of
gas.
(iii) Leak detection equipment must be selected based on a
documented analysis considering, at a minimum, the state of
commercially available leak detection technologies and practices, the
size and configuration of the pipeline system, and system operating
parameters and environment. At a minimum, operators must analyze the
effectiveness of the following technologies for their systems:
(A) The use of handheld leak detection equipment capable of
detecting and locating all leaks of 5 parts per million or more when
measured within 5 feet of the pipeline or within a wall-to-wall paved
area, in conjunction with locating equipment to verify the tools are
sampling the area within 5 feet of the buried pipeline. The procedure
must include sampling the atmosphere near cracks, vaults, or any other
surface feature where gas could migrate;
(B) Periodic surveys performed with leak detection equipment
mounted on mobile, aerial, or satellite-based platforms that, in
conjunction with confirmation by hand-held equipment, is capable of
detecting and pinpointing all leaks of 5 parts per million or more when
measured within 5 feet of the pipeline, or within a wall-to-wall paved
area;
(C) Periodic surveys performed with optical, infrared, or laser-
based leak detection equipment that can sample or inspect the area
within 5 feet of the pipeline, or within a wall-to-wall paved area,
capable of detecting and pinpointing all leaks of 5 parts per million
or more;
(D) Continuous monitoring for leaks via stationary sensors,
pressure monitoring, or other means that provide alarms or alerts and
that, in conjunction with confirmation by hand-held equipment, is
capable of detecting and pinpointing all leaks of 5 parts per million
or more when measured within 5 feet of the pipeline, or within a wall-
to-wall paved area; and
(E) Systematic use of other commercially available technology
capable of detecting and pinpointing all leaks producing a reading of 5
parts per million or more within 5 feet of the pipeline, or within a
wall-to-wall paved area.
(2) Leak detection practices. At a minimum, an operator must have
and follow written procedures for:
(i) Performing leakage surveys. Operators must have procedures for
performing leakage surveys required for Sec. Sec. 192.706 and 192.723
using each selected leak detection technology as described in paragraph
Sec. 192.763(a)(1). The procedures must define environmental and
operational conditions for which each leak detection technology is and
is not permissible. The operator's procedures must follow the leak
detection equipment manufacturer's instructions for survey methods and
allowable environmental and operational parameters.
(ii) Pinpointing and investigating leaks. The location of the
source of each leak indication on an onshore pipeline or any portion of
an offshore pipeline above the waterline must be pinpointed and
investigated with handheld leak detection equipment. Leak indications
on offshore pipelines below the waterline may be pinpointed with human
senses.
(iii) Validating performance. Operators must have procedures
validating that leak detection equipment meets the requirement of
paragraph (a)(1)(ii) of this section. The operator must have procedures
for validating the sensitivity of the equipment before initial use by
testing with a known concentration of gas and at the required offset
conditions of 5 feet. Records validating equipment performance must be
maintained for five years after the
[[Page 31978]]
date the device is no longer used by the operator.
(iv) Maintaining and calibrating leak detection equipment. At a
minimum, procedures must follow the equipment manufacturer's
instructions for calibration and maintenance. Leak detection equipment
must be recalibrated or replaced following any indication of
malfunction. Records validating equipment calibration and failures
indicating recalibration is necessary must be maintained for 5 years
after the date the individual device is retired by the operator.
(3) Leakage survey frequency. Leakage survey frequency must be
sufficient to detect all leaks that have a sufficient release rate to
produce a reading of 5 parts per million or more of gas when measured
from a distance of 5 feet or less from the pipeline, or within a wall-
to-wall paved area, but may be no less frequent than required in
Sec. Sec. 192.706 and 192.723. Less sensitive equipment, challenging
survey conditions, or facilities known to leak based on their material,
design, or past operating and maintenance history may require more
frequent surveys to detect leaks consistent with paragraph (b) of this
section.
(4) Periodic evaluation and improvement. The ALDP must include
procedures and records showing the operator is meeting all of the
program requirements.
(i) The operator must evaluate the ALDP at least once each calendar
year but with a maximum interval not to exceed 15 months.
(ii) The operator must make changes to any program elements
necessary to locate and eliminate leaks and minimize releases of gas.
(iii) When considering changes to program elements, operators must
analyze, at a minimum, the performance of the leak detection equipment
used, the adequacy of the leakage survey procedures, advances in leak
detection technologies and practices, the number of leaks that are
initially detected by the public, the number of leaks and incidents,
and estimated emissions from leaks detected pursuant to this section.
(iv) The operator must document any improvements needed to the
program.
(b) Advanced leak detection performance standard. Each operator's
ALDP described in paragraph (a) of this section must be capable of
detecting all leaks that have a sufficient release rate to produce a
reading of 5 parts per million or more of gas when measured from a
distance of 5 feet or less from the pipeline, or within a wall-to-wall
paved area.
(1) The performance of the ALDP must be validated and documented
with engineering tests and analyses.
(2) Records validating that the ALDP meets the performance standard
must be maintained for at least 5 years after the date that ALDP is no
longer used by the operator.
(c) Alternative advanced leak detection performance standard. For
gas pipelines other than natural gas pipelines, and for natural gas
transmission, offshore gathering, and Types A, B, and C gathering
pipelines located in Class 1 or Class 2 locations, an operator may use
an alternative ALDP performance standard (and supporting leak detection
equipment) with prior notification to, and with no objection from,
PHMSA in accordance with Sec. 192.18. PHMSA will only approve a
notification if operator, in the notification, demonstrates that the
alternative performance standard is consistent with pipeline safety and
equivalent to the standard in paragraph (b) of this section for
reducing greenhouse gas emissions and other environmental hazards. The
notification must include:
(1) Mileage by system type;
(2) Known material properties, location, HCAs, operating
parameters, environmental conditions, leak history, and design
specifications, including coating, cathodic protection status, and pipe
welding or joining method;
(3) The proposed performance standard;
(4) Any safety conditions, such as increased survey frequency;
(5) The leak detection equipment, procedures, and leakage survey
frequencies the operator proposes to employ;
(6) Data on the sensitivity and the leak detection performance of
the proposed alternative ALDP standard; and
(7) The gas transported by the pipeline.
0
34. Add Sec. 192.769 to read as follows:
Sec. 192.769 Qualification of leakage survey, investigation, grading,
and repair personnel.
Only individuals qualified under subpart N of this part may conduct
leakage survey, investigation, grading, and repair. Individuals
qualified under subpart N must also possess training, experience, and
knowledge in the field of leakage survey, leak investigation, and leak
grading, including documented work history or training associated with
those activities.
0
35. Add Sec. 192.770 to read as follows:
Sec. 192.770 Minimizing emissions from gas transmission pipeline
blowdowns.
(a) Except as provided in paragraph (b) of this section, when an
operator performs any intentional release of gas (including blowdowns
or venting for scheduled repairs, construction, operations, or
maintenance) from a gas transmission pipeline, the operator must
prevent or minimize the release of gas to the environment through one
or more of the following methods:
(1) Isolating the smallest section of the pipeline necessary to
complete the task by use of valves or the installation of control
fittings;
(2) Routing gas released from the pipeline from the nearest
isolation valves or control fittings to a flare or to other equipment
as fuel gas;
(3) Reducing pressure by use of in-line compression;
(4) Reducing pressure by use of mobile compression to a segment or
storage vessel adjacent to the nearest isolation valves;
(5) Transferring the gas to a segment of a lower pressure pipeline
system adjacent to the nearest isolation valves; or
(6) Employing an alternative method demonstrated to result in a
release volume reduction of at least 50% compared to venting gas
directly to the atmosphere without mitigative action.
(b) An operator is not required to comply with the provisions of
paragraph (a) of this section during an event that activates its
emergency plan under Sec. 192.615(a)(3) when such minimization would
delay emergency response or result in a safety risk during pipeline
assessments or maintenance. Each emergency release conducted without
mitigation must be documented, including the justification for release
without mitigation.
(c) Operators must document the methodologies used in paragraph (a)
of this section and describe how the methodologies minimize the release
of gas to the environment.
0
36. Add Sec. 192.773 to read as follows:
Sec. 192.773 Pressure relief device maintenance and adjustment of
configuration.
(a) Each operator must develop, maintain, and follow written
operations and maintenance procedures to assess the proper function of
pressure limiting or relief device and to repair or replace each failed
pressure limiting or relief device. When a pressure limiting or relief
device fails to operate or allows gas to release to the atmosphere at
an operating pressure above or below the set actuation pressure range
defined for the device in the operator's operations
[[Page 31979]]
and maintenance procedure, the operator must:
(1) Assess the pilot, springs, seats, pressure gauges, and other
components to ensure proper functioning, sensing, and set/reset
actuation pressures are within actuation pressure tolerances;
(2) Assess the inlet and outlet piping for piping that restricts
the inlet or outlet gas flow, piping that restricts the sensing
pressure, debris, and other restrictions that could impede the
operation or restrict the capacity to relieve overpressure conditions;
(3) Repair or replace the device to eliminate the malfunction as
follows:
(i) If a pressure relief device activates above its set pressure
and above the pressure limits in Sec. 192.201(a) or 192.739 as
applicable, fails to operate, or otherwise fails to provide
overpressure protection, the operator must repair or replace the device
or pressure sensing equipment immediately.
(ii) If a pressure relief device allows gas to release to the
atmosphere at an operating pressure below the set actuation pressure
range, the operator must take immediate and continuous action with on-
site personnel to stop the release until the device is repaired or
replaced. The relief device or pressure sensing equipment must be
repaired or replaced as soon as practicable but within 30 days.
(b) Each operator must develop, maintain, and follow written
operations and maintenance procedures to ensure that a pressure relief
device configuration, as demonstrated by a documented engineering
analysis, employs set and reset actuation pressures ensuring
minimization of release volumes while providing adequate overpressure
protection.
(c) Records under this section must be maintained as follows:
(1) Records of relief devices malfunctions must be maintained for 5
years after repair or replacement.
(2) Records pertaining to repair, replacement, or reconfiguration
(including any engineering analyses) of a pressure relief device must
be maintained for the life of the pipeline.
0
37. In Sec. 192.1007, revise paragraphs (e)(1)(i) and (v) as follows:
Sec. 192.1007 What are the required elements of an integrity
management plan?
* * * * *
(e) * * *
(1) * * *
(i) Number of hazardous leaks either eliminated or repaired (or
total number of leaks if all leaks are repaired when found),
categorized by cause;
* * * * *
(v) Number of hazardous leaks either eliminated or repaired (or
total number of leaks if all leaks are repaired when found),
categorized by material; and
* * * * *
PART 193--LIQUEFIED NATURAL GAS FACILITIES: FEDERAL SAFETY
STANDARDS
0
38. The authority citation for part 193 continues to read as follows:
Authority: 49 U.S.C. 5103, 60102, 60103, 60104, 60108, 60109,
60110, 60113, 60118; and 49 CFR 1.53.
0
39. In Sec. 193.2503, add paragraph (h) to read as follows:
Sec. 193.2503 Operating procedures.
* * * * *
(h) Eliminating leaks and minimizing releases of gas.
0
40. Add Sec. 193.2523 to read as follows:
Sec. 193.2523 Minimizing emissions from blowdowns and boiloff.
(a) Except as provided in paragraph (b) of this section, an
operator of an LNG facility must minimize intentional emissions of
natural gas from LNG facilities, including tank boiloff or blowdowns
for repairs, construction, operations, or maintenance. The operator
must minimize the release of natural gas to the environment by use of
one or more of the following methods:
(1) Isolating a smaller section of the piping segments by use of
valves or the installation of control fittings;
(2) Routing gas released from the facility to a flare, or to other
equipment for use as fuel gas;
(3) Transferring gas or LNG to a storage tank or local pressure
vessel; or
(4) Employing an alternative method demonstrated to result in
release volume reductions of at least 50% compared to venting gas
directly to the atmosphere without mitigative action.
(b) An operator is not required to comply with the provisions of
paragraph (a) of this section during an emergency resulting in the
activation of their emergency procedures under Sec. 193.2509. An
operator must document each emergency release without mitigation
described in paragraph (b) of this section, including the justification
for release without mitigation.
(c) The operator must document the method or methods used and
describe how those methods minimize the release of natural gas to the
environment.
0
41. In Sec. 193.2605, add paragraph (b)(3) to read as follows:
Sec. 193.2605 Maintenance procedures.
* * * * *
(b) * * *
(3) Procedures for eliminating leaks and minimizing releases of
gas.
* * * * *
0
42. Add Sec. 193.2624 to read as follows:
Sec. 193.2624 Leakage surveys.
(a) Each operator of an LNG facility, including mobile, temporary,
and satellite facilities must conduct periodic methane leakage surveys,
on equipment and components within their facilities containing methane
or LNG, at least four times each calendar year, with a maximum interval
between surveys not exceeding 4\1/2\ months, using leak detection
equipment. Leak detection equipment must be capable of detecting and
locating all methane leaks producing a reading of 5 parts per million
or more of within 5 feet of the component or equipment surveyed.
(b) Operators must have written procedures providing for each of
the following:
(1) Validating the leakage survey equipment and performing leakage
surveys consistent with the equipment manufacturer's instructions for
survey methods and allowable environmental and operational parameters;
(2) Validating the sensitivity of this equipment by the operator
before initial use by testing with a known concentration of gas at a
required offset condition of 5 feet; and
(3) Calibrating the equipment consistent with the equipment
manufacturer's instructions for calibration and maintenance. Leak
detection equipment must be recalibrated or replaced following any
indication of malfunction.
(c) Each operator must maintain records of the leak survey and
equipment sensitivity validation and calibration for five years after
the leakage survey.
(d) Operators must review the results of the methane leakage
surveys and address any methane leaks and abnormal operating conditions
in accordance with their written maintenance procedures or abnormal
operating procedures.
Issued in Washington, DC, on May 4, 2023, under authority
delegated in 49 CFR 1.97.
Alan K. Mayberry,
Associate Administrator for Pipeline Safety.
[FR Doc. 2023-09918 Filed 5-17-23; 8:45 am]
BILLING CODE 4910-60-P