# Pipeline Safety: Requirement of Valve Installation and Minimum Rupture Detection Standards > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2022-07133 ## Record - **Collection:** Federal Register - **Document type:** Rule - **Published:** April 8, 2022 - **Citation:** 87 FR 20940 ## Text DEPARTMENT OF TRANSPORTATION Pipeline and Hazardous Materials Safety Administration 49 CFR Parts 192 and 195 [Docket No. PHMSA-2013-0255; Amdt. Nos. 192-130; 195-105] RIN 2137-AF06 Pipeline Safety: Requirement of Valve Installation and Minimum Rupture Detection Standards AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA), DOT. ACTION: Final rule. SUMMARY: PHMSA is revising the Federal Pipeline Safety Regulations applicable to most newly constructed and entirely replaced onshore gas transmission, Type A gas gathering, and hazardous liquid pipelines with diameters of 6 inches or greater. In the revised regulations, PHMSA requires operators of these lines to install rupture-mitigation valves ( i.e., remote-control or automatic shut-off valves) or alternative equivalent technologies, and establishes minimum performance standards for those valves' operation to prevent or mitigate the public safety and environmental consequences of pipeline ruptures. This final rule establishes requirements for rupture-mitigation valve spacing, maintenance and inspection, and risk analysis. The final rule also requires operators of gas and hazardous liquid pipelines to contact 9-1-1 emergency call centers immediately upon notification of a potential rupture and conduct post-rupture investigations and reviews. Operators must also incorporate lessons learned from such investigations and reviews into operators' personnel training and qualifications programs, and in design, construction, testing, maintenance, operations, and emergency procedure manuals and specifications. PHMSA is promulgating these regulations in response to congressional directives following major pipeline incidents where there were significant environmental consequences or losses of human life. The revisions are intended to achieve better rupture identification, response, and mitigation of safety, greenhouse gas, and environmental justice impacts. DATES: The effective date of this final rule is October 5, 2022. FOR FURTHER INFORMATION CONTACT: Technical questions: Steve Nanney, Senior Technical Advisor, by telephone at 713-272-2855. General information: Robert Jagger, Senior Transportation Specialist, by telephone at 202-366-4361. SUPPLEMENTARY INFORMATION: I. Executive Summary A. Purpose of the Regulatory Action B. Summary of the Major Provisions of the Regulatory Action C. Costs and Benefits II. Background A. Pipeline Ruptures B. National Transportation Safety Board Recommendations C. Advance Notices of Proposed Rulemaking D. 2011 Pipeline Safety Act and Related Studies i. Section 4—Automatic and Remote-Controlled Shut-Off Valves a. GAO Report GAO-13-168 b. Studies for the Requirements of Automatic and Remotely Controlled Shutoff Valves and Hazardous Liquids and Natural Gas Pipelines With Respect to Public and Environmental Safety ii. Section 8—Leak Detection E. 2020 Valve Rule NPRM F. Subsequent Legislative Deadlines; Recent Executive Orders and Actions III. NPRM Comments, Pipeline Advisory Committee Recommendations, and PHMSA Responses A. General Comments, Scope, Applicability, and Cost-Benefit Issues B. Rupture Definition C. Rupture Identification Definition and Timeframe D. RMV Installation, RMV Closure Timeframe E. Valve Spacing & Location F. Valve Status Monitoring G. Class Location Changes H. Valve Maintenance I. Failure Investigations J. 9-1-1 Notification Requirements K. Other IV. Section-by-Section Analysis of Changes to 49 CFR Part 192 for Gas Pipelines V. Section-by-Section Analysis of Changes to 49 CFR Part 195 for Hazardous Liquid Pipelines VI. Regulatory Analyses and Notices I. Executive Summary A. Purpose of the Regulatory Action This final rule is the culmination of a decade-long PHMSA rulemaking effort responding to congressional mandates, National Transportation Safety Board (NTSB) recommendations, and Government Accountability Office (GAO) recommendations to revise the Federal Pipeline Safety Regulations at 49 Code of Federal Regulations (CFR) parts 192 and 195 to prevent the catastrophic loss of life, property damage, and environmental harm experienced from ruptures on large-diameter hazardous liquid and natural gas pipelines, such as those that occurred near Marshall, MI, and San Bruno, CA, in 2010. This final rule codifies a suite of design and performance standards prescribing the installation, operation, and spacing of rupture-mitigation valves (RMV) or alternative equivalent technologies on most new or entirely replaced, onshore, large-diameter (6 inches or greater), gas transmission, Type A gas gathering, and hazardous liquid pipelines. 1 The final rule also requires operators of all gas and hazardous liquid pipelines to modify their emergency plans to ensure immediate and direct contact of 9-1-1 emergency call centers, or coordinating government officials, on notification of a potential rupture. PHMSA expects this final rule's regulatory amendments will ensure operators of pertinent gas and hazardous liquid pipelines take prompt identification, isolation, and mitigation actions with respect to unintentional or uncontrolled, large-volume releases of gas or hazardous liquids during a pipeline rupture. The safety enhancements in this final rule, therefore, are expected to improve public safety, reduce threats to the environment (including, but not limited to, reduction of greenhouse gas (GHG) emissions released during ruptures of natural gas pipelines), and promote environmental justice for minority populations, low-income populations, or other underserved and disadvantaged communities. 1 For the purposes of this final rule, references to diameter are to the outside diameter of the pipe. Similarly, subsequent references in this final rule to gas transmission, Type A gas gathering, and hazardous liquid pipelines will, for brevity, generally omit the qualifications (onshore, 6-inch diameter) appearing in the statement of the final rule's scope above. Lastly, references within this final rule to “hazardous liquid pipelines” will, unless otherwise stipulated, include carbon dioxide pipelines because both hazardous liquid and carbon dioxide pipelines are subject to 49 CFR part 195 requirements. Recent pipeline ruptures with catastrophic consequences underscore the importance of prompt identification, isolation, and mitigation actions in reducing the amount of product released—and by extension, the loss of life, property damage, and environmental harm—from ruptures on hazardous liquid and natural gas pipelines. One such rupture occurred on July 25, 2010, in Marshall, MI, resulting in a release of approximately 800,000 gallons of crude oil into the Kalamazoo River and approximately $1 billion in property and environmental damages. 2 The operator, Enbridge Energy, LP (Enbridge), took 18 hours to confirm the pipeline rupture following the initial alarms received by the control room operators. Once Enbridge confirmed the rupture, the failed segment was immediately isolated using installed remote-control shut-off valves (RCV). 2 NTSB, Accident Report PAR-12/01, “Enbridge Incorporated: Hazardous Liquid Pipeline Rupture and Release; Marshall, MI: July 25, 2010” (July 10, 2012), https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1201.pdf. Another rupture occurred on September 9, 2010, in San Bruno, CA, when a gas transmission pipeline ruptured, causing an explosion that killed 8 people, sent 51 other people to the hospital, destroyed 38 homes and damaged 70 others, and caused the evacuation of approximately 300 homes. According to the NTSB report on that incident, 3 the initial 9-1-1 notification call by the public was made within one minute of the rupture, which occurred at 6:11 p.m. The response crew assembled to operate valves and isolate the rupture did not reach the first valve site until 7:20 p.m. According to the California Public Utilities Commission (CPUC) report on the incident, the operator, Pacific Gas and Electric (PG&E), did not confirm that the incident was a pipeline rupture until 7:25 p.m., when PG&E employees in the field, at dispatch, and in the company's supervisory control and data acquisition (SCADA) 4 center confirmed that a PG&E gas transmission line had failed. 5 After multiple valve closures, PG&E isolated the ruptured pipeline segment at 7:46 p.m., 95 minutes after the rupture initiated. 6 This delay in closing the valves allowed the fire to burn unabated and hampered emergency response efforts. 3 NTSB, Accident Report PAR-11/01, “Pacific Gas and Electric Company; Natural Gas Transmission Pipeline Rupture and Fire; San Bruno, CA; September 9, 2010” (Aug. 30, 2011), https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1101.pdf. 4 Most pipeline operators utilize a SCADA system to run their operations. These are computer-based systems used by a controller in a control room that collects and displays information about a pipeline facility and may have the ability to send commands back to the pipeline facility. See 49 CFR 192.3 and 195.2. 5 CPUC, “Sept. 9, 2010 PG&E Pipeline Rupture in San Bruno, CA” (Jan. 12, 2012), https://www.cpuc.ca.gov/uploadedFiles/CPUC_Public_website/Content/Safety/Natural_Gas_Pipeline/News/AgendaStaffReportreOIIPGESanBruno Explosion.pdf. 6 The CPUC also noted that the backfeed to the line and the gas feeds to a related distribution system were not closed until 7:52 p.m. and 11:32 p.m., respectively. These rupture events highlight the need for more robust protections in the Federal Pipeline Safety Regulations for identifying, isolating, and mitigating catastrophic pipeline failures. First, there is a need for better and more timely rupture isolation and mitigation equipment and methods. PG&E's failure to close isolation valves rapidly after the rupture at San Bruno diminished its ability to mitigate the consequences of the failure, allowing the fire to burn unabated for 95 minutes following the initial rupture, with firefighting operations continuing for an additional 2 days after the rupture occurred. Second, there is need for operators to identify promptly that a rupture has occurred and respond quickly to mitigate its consequences. Enbridge had remote-control isolation valves installed on its ruptured oil pipeline at the time the spill occurred near Marshall, MI, but its failure to confirm and respond to the rupture promptly rendered that technology essentially useless. After these spill events, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Pipeline Safety Act; Pub. L. 112-90) was enacted. The legislation contained several mandates to improve pipeline safety. In particular, PHMSA is required to issue regulations requiring the use of automatic shut-off valves (ASV) or RCVs, or equivalent technology, on newly constructed or replaced gas transmission and hazardous liquid pipeline facilities. See 49 U.S.C. 60102(n). That statutory mandate was subsequently revisited, establishing a new deadline for PHMSA to issue a final rule ( see 49 U.S.C. 60102 note). In developing this final rule, PHMSA considered NTSB safety recommendations following the PG&E incident; GAO recommendations on the ability of operators to respond to commodity releases in high-consequence areas (HCA); 7 technical reports commissioned by PHMSA on valves and leak detection; 8 9 comments received on related topics through advance notices of proposed rulemaking (ANPRM) and the notice of proposed rulemaking (NPRM) published in February 2020; 10 and feedback from members of the public, environmental advocacy organizations, State pipeline safety regulators, and industry representatives during Gas Pipeline Advisory Committee and Liquid Pipeline Advisory Committee meetings. 7 GAO, “Pipeline Safety: Better Data and Guidance Needed to Improve Pipeline Operator Incident Response” (Jan. 2013), https://www.gao.gov/assets/660/651408.pdf. An HCA, briefly, is an area with higher population density or contains an area of cultural significance or where people would congregate at a certain frequency ( e.g., churches, playgrounds, schools, hospitals, etc.). See § 192.903. 8 Oak Ridge National Laboratory (ORNL), ORNL/TM-2012/411, “Studies for the Requirements of Automatic and Remotely Controlled Shutoff Valves and Hazardous Liquids and Natural Gas Pipelines with Respect to Public and Environmental Safety” (Oct. 31, 2012), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16701/finalvalvestudy.pdf. 9 Kiefner and Associates, Inc., Report No. 12-173, “Leak Detection Study—DTPH56-11-D-000001” (Dec. 10, 2012), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16691/leak-detection-study.pdf. 10 85 FR 7162 (Feb. 6, 2020) (NPRM). B. Summary of the Major Provisions of the Regulatory Action This final rule prescribes installation and spacing requirements for ASVs and RCVs (collectively, rupture-mitigation valves, or RMVs) as well as for alternative equivalent technology. The requirements apply to most newly constructed, or entirely replaced, onshore pipelines with diameters of 6 inches or greater, including natural gas transmission pipelines, Type A gas gathering pipelines, and hazardous liquid pipelines (including certain regulated hazardous liquid gathering pipelines). In this final rule, PHMSA has defined an “entirely replaced” pipeline as a pipeline that has 2 or more miles being replaced with new pipe within any stretch of 5 contiguous miles within any 24-month period. The rule also defines ASVs and RCVs as RMVs. PHMSA did not identify specific technologies that operators might use as alternative equivalent technologies for the purposes of this rulemaking, but PHMSA is requiring that such alternative technologies meet the performance standard for RMVs, to include the ability to immediately enable isolation of a rupture—in 30 minutes or less, measured from an operator's identification of a rupture after notification of a potential rupture. Operators of pipelines subject to the requirements of this final rule may request to install alternative equivalent technologies if they can demonstrate within a notification for PHMSA review that site-specific installation of an alternative equivalent technology would provide an equivalent level of safety to an RMV. Those notifications must be submitted in advance of installation of that technology, and must demonstrate an equivalent level of safety by reference to technical and safety factors including, but not limited to, the following: Design, construction, maintenance, and operating procedures; technology design and operating characteristics such as operation times (closure times for manual valves); service reliability and life; accessibility to operator personnel; nearby population density; and potential consequences to the environment and the public. Further, should an operator request use of manual valves as an alternative equivalent technology, the notification submitted to PHMSA must also demonstrate the economic, technical, or operational infeasibility of installation of an RMV by reference to factors such as access to communications and power; terrain; prohibitive cost; labor and component availability; ability to secure required land access rights and permits; and accessibility to operator personnel for installation and maintenance. For regulated rural hazardous liquid gathering pipelines, 11 at this time, PHMSA is requiring the installation of RMVs or alternative equivalent technology only where such pipelines cross bodies of water more than 100 feet in width from high water mark to high water mark. For hazardous liquid pipelines in general, this final rule establishes valve spacing thresholds both within and outside of HCAs and provides valve spacing limits for highly volatile liquid (HVL) pipelines in populated areas. PHMSA has recently issued a final rule in a separate rulemaking that will update its regulations that affect all types of gas gathering pipelines. 12 11 A regulated rural hazardous liquid gathering pipeline is defined in § 195.11 as an onshore gathering line in a rural area that meets all of the following criteria: (1) A nominal diameter from 6 5/8 to 8 5/8 inches; (2) located in or within 1/4 mile of an unusually sensitive area, as that term is defined in § 195.6; and (3) operating at a maximum pressure established under § 195.406 corresponding to a stress level greater than 20 percent of the specified minimum yield strength (SMYS) of the line pipe or, if the stress level is unknown or the pipeline is not constructed with steel pipe, a pressure of more than 125 psig. 12 “Pipeline Safety—Safety of Gas Gathering Pipelines: Extension of Reporting Requirements, Regulation of Large, High-Pressure Lines, and Other Related Amendments,” 86 FR 63266 (Nov. 15, 2021) (“Gas Gathering final rule”). For gas transmission and Type A gas gathering pipelines, the RMV or alternative equivalent technology installation requirements will not apply if the pipeline segment is in a Class 1 or Class 2 location and has a potential impact radius (PIR) less than or equal to 150 feet. PHMSA understands that the lower operating pressures characteristic of Type B gas gathering pipelines involve risk profiles comparable to the Type A gas gathering pipelines exempted from the final rule's installation and operational requirements. Therefore, the final rule similarly exempts Type B gas gathering pipelines from the RMV or alternative equivalent technology installation requirements. The final rule also exempts Type C gas gathering lines from those requirements, as that designation was established by the Gas Gathering final rule—which was published well after the publication of the NPRM for this rulemaking. Additionally, for each gas pipeline whose operator, in response to a class location change, chooses to replace 2 or more miles of pipe within a contiguous 5-miles to meet the maximum allowable operating pressure (MAOP) requirements of the new class location, the operator would be required to install or otherwise modify existing valves as necessary to comply with the valve spacing requirements and rupture mitigation requirements of this final rule. 13 The final rule provides operators replacing smaller pipeline segments following a change in class location more flexibility: Operators replacing between 1,000 feet and 2 miles may either install RMVs, or they may automate existing valves with automatic or remote-control actuators and pressure sensors (with a maximum spacing of 20 miles). And the final rule's RMV installation and spacing requirements do not apply to those pipe replacements that amount to less than 1,000 feet within any single mile during any 24-month period. 13 Class locations, defined at § 192.5, are determined depending on the number of dwellings within 220 yards on either side of a pipeline and reflect the population density around the pipeline. This final rule also establishes Federal minimum safety performance standards for the identification of ruptures, pipeline segment isolation, and other mitigative actions, for pipelines on which RMVs or alternative equivalent technology are installed pursuant to this rulemaking. Relevant new requirements include: (1) A definition of the term “notification of potential rupture” to identify signs of an uncontrolled release of a large volume of commodity observed by, or reported to, the operator; (2) establishing written procedures for identifying and responding to a rupture; (3) responding to an identified rupture by closing RMVs or alternative equivalent technology, to provide complete valve shut-off and segment isolation as soon as practicable, but no more than 30 minutes after rupture identification; (4) performing post-event reviews of any incidents/accidents or other failure events involving the closure of RMVs or alternative equivalent technologies to ensure the performance objectives of this rule are met and to apply any lessons learned system-wide; (5) performing maintenance on RMVs and alternative equivalent technology, which includes drills for alternative equivalent technology that is manually or locally operated; and (6) remediation measures for repair or replacement of inoperable RMVs and alternative equivalent technologies, including an RMV or alternative equivalent technology that cannot maintain shut-off, as soon as practicable. This final rule also requires operators of all gas and hazardous liquid pipelines subject to the emergency planning requirements at §§ 192.615 and 195.402, respectively, to update their emergency response plans to provide for immediate and direct notification of appropriate public safety answering points (9-1-1 emergency call centers) for the communities and jurisdictions in which a rupture is located following the notification of a potential rupture. Similarly, the final rule requires all gas and hazardous liquid pipelines subject to failure investigation requirements at §§ 192.617 and 195.402, respectively, to conduct post-rupture investigations and reviews, and to incorporate lessons learned from such investigations and reviews into their personnel training and qualifications programs, and in design, construction, testing, maintenance, operations, and emergency procedure manuals and specifications. C. Costs and Benefits Consistent with Executive Order 12866 (“Regulatory Planning and Review”), 14 PHMSA has prepared an assessment of the benefits and costs of this final rule, as well as reasonable alternatives. The Regulatory Impact Analysis (RIA) developed by PHMSA in support of this final rule, and which is available in the rulemaking docket, estimates the annual costs of the rule to be approximately $5.9 million, calculated using a 7 percent discount rate. In the RIA, costs are aggregated by compliance method to estimate total costs, by year, for the baseline and the final rule. The incremental effect of this rulemaking is estimated by taking the difference in total costs relative to the baseline. Costs are then aggregated across all years in the analysis period and annualized. The costs reflect the installation of valves on certain newly constructed and entirely replaced gas and hazardous liquid pipelines, as well as incremental programmatic changes that operators will need to make to incorporate the proposed rupture identification and response procedures. 14 58 FR 51735 (Oct. 4, 1993). PHMSA provides a qualitative discussion of the benefits of this rulemaking in the RIA. 15 PHMSA expects this final rule's regulatory amendments will compel operators of pertinent natural gas and hazardous liquid pipelines to take prompt identification, isolation, and mitigation actions with respect to unintentional or uncontrolled, large-volume releases of natural gas or hazardous liquids during a pipeline rupture. The safety enhancements in this final rule, therefore, are expected to improve public safety, reduce threats to the environment (including, but not limited to, reduction of greenhouse gas emissions released during ruptures of natural gas pipelines), and promote environmental justice for minority populations, low-income populations, or other underserved and disadvantaged communities. PHMSA has, therefore, determined that these (unquantified) public safety, environmental, and equity benefits of the final rule described in this final rule and its supporting RIA and Environmental Assessment justify the costs of the final rule. 15 PHMSA explains in the RIA that, although the Environmental Assessment for this rulemaking provides illustrative quantifications of avoided greenhouse gas emissions from this final rule, PHMSA's evaluation of the greenhouse gas emissions within its cost-benefit analysis is on the basis of qualitative assessment of those avoided emissions. II. Background A. Pipeline Ruptures Although pipelines are generally considered to be an efficient and relatively safe means of transporting natural gas and hazardous liquids, 16 they can experience large-volume, uncontrolled releases that can have severe consequences. Such rupture events can be aggravated by some combination of: Missed opportunities by the operator to identify that a rupture has occurred; the failure of operating personnel to take appropriate actions once a rupture has been identified; delays in accessing and closing available pipeline segment isolation valves; and an inability quickly to close isolation valves that would have the most significant impact in mitigating the consequences of a rupture. Typically, these types of events where a significant amount of time passes between initiation and isolation of a rupture have been the most serious in terms of monetary and environmental damages and safety consequences. The Marshall, MI, and San Bruno, CA, incidents are examples of rapid failure events with large-volume releases on high-pressure, large-diameter pipelines with serious consequences exacerbated by delays in identification and isolation of the ruptures. 16 See PHMSA, Letter to Congress, Report on Shipping Crude Oil by Truck, Rail, and Pipeline at 2 (Oct. 2018), https://www7.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/news/70826/report-congress-shipping-crude-oil-truck-rail-and-pipeline-32019.pdf. The intent of this final rule is to require design and equipment elements and improved operational practices for quick and efficient identification of ruptures, that in turn will improve rupture mitigation and shorten rupture isolation times for certain gas transmission, gathering, and hazardous liquid pipelines. Rupture isolation time, as it is discussed in this final rule, is the time it takes an operator to identify a rupture after a notification of potential rupture, implement response procedures, and fully close the appropriate valves to terminate the uncontrolled flow of commodity from the ruptured pipeline segment. PHMSA and NTSB investigations of recent natural gas transmission and hazardous liquid pipeline ruptures have identified issues relating to the timeliness of rupture identification and the appropriateness and timeliness of operators' responses to identified ruptures. Typically, no single event contributes to the deficiencies in rupture identification and response. Instead, there are multiple contributing factors associated with the technology, design, equipment, procedures, or human elements that result in inadequate rupture identification and response efforts. In some rupture scenarios, certain aspects of an operator's rupture identification or response efforts appeared adequate, but other issues, such as delayed access to isolation valves, resulted in an inadequate response overall. For example, in the Enbridge accident near Marshall, MI, the pipeline operator had installed a leak detection system (LDS) and SCADA system that notified the operator of a potential rupture within minutes of the actual event, but issues related to the operator's procedures, training, and personnel response resulted in an 18-hour lapse before the operator confirmed the rupture and initiated mitigating actions. In the PG&E incident in San Bruno, CA, the operator effectively identified through its LDS or SCADA systems that there was in fact a rupture, but then took another 95 minutes to isolate it. This delay proved catastrophic due to the time required for confirming the existence of the rupture, assembling response personnel, traveling to the valve site, and closing the valve to isolate the pipeline segment—during which time a fire resulting from the rupture burned unabated. The NTSB's report on that incident noted that PG&E lacked a detailed and comprehensive procedure for responding to large-scale emergencies such as a transmission pipeline break, and that the use of ASVs or RCVs would have reduced the amount of time taken to stop the flow of gas. Prior to those rupture events, the NTSB noted similar issues related to rupture response in its report on an incident occurring on March 23, 1994, in Edison Township, NJ. 17 In the Edison incident, the operator took nearly 2 1/2 hours to stop the flow of natural gas from a ruptured pipeline in a highly-populated area. The fire that followed the rupture destroyed 8 buildings, caused the evacuation of approximately 1,500 apartment residents, and resulted in more than $25 million (approximately $40 million in 2020 dollars) worth of property damage. The NTSB report quotes the operator of that pipeline in saying that it could typically notify employees to close valves within 5 to 10 minutes after identifying a rupture, and that the time it took to close a manual valve depended on the employee's travel time to the valve site: Its employees could usually arrive at a valve site within 15 to 20 minutes, but in some instances it could take more than an hour for employees to arrive at certain valve locations after being dispatched. With this in mind, the NTSB concluded that the lack of automatic or remote-operated valves on the ruptured line prevented the operator from promptly stopping the flow of gas to the failed pipeline segment, which exacerbated damage to nearby property. Subsequently, the NTSB recommended to PHMSA's predecessor, the Research and Special Programs Administration, that it expedite establishing requirements for installing automatic or remote-operated valves on high-pressure pipelines in urban and environmentally sensitive areas to provide for rapid shutdown of failed pipeline systems. 17 NTSB, PAR-95-01, “Pipeline Accident Report; Texas Eastern Transmission Corporation Natural Gas Pipeline Explosion and Fire; Edison, New Jersey” (Jan. 18, 1995), https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR9501.pdf. B. National Transportation Safety Board Recommendations In its report on the PG&E gas transmission pipeline incident that occurred in San Bruno, CA, the NTSB issued safety recommendations P-11-8 through P-11-20 to PHMSA. 18 Pertaining to this rulemaking, NTSB safety recommendation P-11-10 recommended that PHMSA require operators to equip their SCADA systems with tools, including leak detection systems and appropriately spaced flow and pressure transmitters along covered transmission lines, to identify leaks (and ruptures); and NTSB safety recommendation P-11-11 recommended PHMSA require operators install ASVs or RCVs in HCAs and Class 3 and 4 locations, with the valve spacing based on risk analysis. 18 See supra note 3. PHMSA determined that, although the NTSB directed these recommendations to a rupture on a gas transmission pipeline, certain aspects of these recommendations are also applicable to ruptures on gas gathering and hazardous liquid pipelines, including the regulated hazardous liquid gathering pipelines regulated under part 195. PHMSA took these recommendations into account when developing this final rule by requiring that RMVs and alternative equivalent technologies be capable of having their status controlled or monitored (directly, or indirectly via the upstream pressure, and the downstream pressure) remotely, 19 and by requiring the installation of RMVs, or equivalent alternative technologies, at intervals of no more than 8 miles in Class 4 locations and 15 miles in Class 3 locations. 19 As discussed later in this document, for ASVs, an operator does not need to monitor remotely a valve's status if the operator has the capability to monitor pressures or gas flow rate on the pipeline to identify and locate a rupture. Pipeline segments that use an alternative equivalent technology must have the capability to monitor pressures or gas flow rates on the pipeline to identify and locate a rupture. C. Advance Notices of Proposed Rulemaking PHMSA published two ANPRMs seeking comments regarding the revision of provisions in the Federal Pipeline Safety Regulations governing safety of hazardous liquid pipelines and natural gas pipelines. 20 PHMSA responded to pertinent comments received on the ANPRMs in Section III of the NPRM preceding this final rule. PHMSA addressed other topics raised in the hazardous liquid and gas transmission ANPRMs within other rulemakings, as appropriate. 20 75 FR 63774 (Oct. 18, 2010) (pertaining to hazardous liquid pipelines within docket PHMSA-2010-0229), and 76 FR 53086 (Aug. 25, 2011 (pertaining to natural gas pipelines within docket PHMSA-2011-0023). D. 2011 Pipeline Safety Act and Related Studies Sections 4 and 8 of the 2011 Pipeline Safety Act established statutory requirements relating directly to topics addressed in the ANPRMs discussed previously. This final rule responds to those statutory mandates. PHMSA also considered the GAO Report No. GAO-13-168, “Better Data and Guidance Needed to Improve Pipeline Operator Incident Response” and ORNL Report/TM-2012/411, “Studies for the Requirements of Automatic and Remotely Controlled Shutoff Valves on Hazardous Liquids and Natural Gas Pipelines With Respect to Public and Environmental Safety” which were performed in response to the 2011 Pipeline Safety Act and are discussed further below. i. Section 4—Automatic and Remote-Controlled Shut-Off Valves Section 4 of the 2011 Pipeline Safety Act directs the Secretary of Transportation (Secretary), if appropriate, to require by regulation the use of ASVs or RCVs, or equivalent technology, where it is economically, technically, and operationally feasible, on hazardous liquid and gas transmission pipeline facilities that are constructed or entirely replaced after the date on which the Secretary issues the final rule containing such requirements. This final rule addresses this mandate by establishing minimum standards for the installation of RMVs or alternative equivalent technology on specified newly constructed or entirely replaced, onshore pipelines that have diameters of 6 inches or greater, including gas transmission pipelines, Type A gas gathering pipelines, hazardous liquid pipelines, and certain regulated hazardous liquid gathering lines. a. GAO Report GAO-13-168 Section 4 of the 2011 Pipeline Safety Act required the development of a study by the Comptroller General on the ability of pipeline operators to respond to a hazardous liquid or gas release from a pipeline segment located in an HCA. In this study, published in January 2013, the GAO recommended PHMSA take the following two actions: 1. Improve the reliability of incident response data to improve operators' incident response times, and use this data to evaluate whether to implement a performance-based framework for incident response times; and 2. Assist operators in determining whether to install automated valves by using PHMSA's existing information sharing mechanisms to alert all pipeline operators of inspection and enforcement guidance that provides additional information on how to interpret regulations on automated valves, and share approaches used by operators for making decisions on whether to install automated valves. The GAO report noted that defined performance-based goals, established with reliable data and sound agency assessments, could result in improved operator response to incidents, with ASV and RCV installation and use being one of the determining factors. The GAO further noted that PHMSA's then-current regulations for incident response and installation and use of ASVs and RCVs employed broadly-stated performance standards, requiring operators to respond to incidents in a “prompt and effective manner,” 21 and requiring operators to install ASVs, RCVs, or emergency flow restricting devices (EFRD) if an operator determines, through risk analysis, such valves are necessary to protect HCAs. 22 21 For natural gas and hazardous liquid pipelines, §§ 192.615(a)(3) and 195.402(e)(2), respectively. 22 Requirements for ASV and RCV installation on gas transmission pipelines are at § 192.935(c), and requirements for EFRD installation for hazardous liquid pipelines are at § 195.452(i)(4). More clearly defined goals can help operators identify actions that could improve their ability to respond to certain types of incidents consistently and promptly, though identical incident response actions are not appropriate for all circumstances due to variable locations, equipment needs, configurations, and operating conditions of pipeline facilities. PHMSA agrees with the GAO's conclusions that more precise performance-based standards, in conjunction with carefully selected requirements, could be more effective in improving incident response times, particularly when ruptures are involved. The GAO report also concluded that the primary advantage of installing and using automated valves is that operators can respond more quickly to isolate the affected pipeline segment and reduce the amount of commodity released. Although the report suggested that using automated valves can have certain disadvantages, including the potential for accidental closures, which makes it appropriate for operators to decide whether to install automated valves on a case-by-case basis, the report recognized that a faster incident response time could reduce the amount of property damage from secondary fires (after an initial pipeline rupture) by allowing fire departments to extinguish the fires sooner. For hazardous liquid pipelines, a faster incident response time could also result in lower costs for environmental remediation efforts and less commodity loss. PHMSA applied these principles and the GAO's findings and recommendations in developing the standards in this final rule. The amendments in this final rule also include specific post-event review requirements in §§ 192.617 and 195.402. Operators must make those post-event reviews available for PHMSA to inspect, and PHMSA would be able to use those reviews to inform future rulemakings and guidance documents. b. Studies for the Requirements of Automatic and Remotely Controlled Shutoff Valves and Hazardous Liquids and Natural Gas Pipelines With Respect to Public and Environmental Safety In March 2012, PHMSA commissioned a study to assess the effectiveness of timely operation of automatic and remote-controlled shut-off valves recommended by the NTSB in its report on the PG&E incident and mandated by section 4 of the 2011 Pipeline Safety Act for mitigating the public safety and environmental consequences of natural gas and hazardous liquid pipeline releases. That study, whose conclusions were memorialized in the above-captioned report, also evaluated the economic, technical and operational feasibility and potential benefits of installing ASVs and RCVs in newly constructed and entirely replaced pipelines. The study concluded that: 1. In general, installing ASVs and RCVs on newly constructed and entirely replaced natural gas transmission and hazardous liquid pipelines is technically feasible, provided sufficient space is available for the valve body, actuators, power source, sensors and related electronic equipment, and personnel required to install and maintain the valve; and is operationally feasible, provided the communication links between the RCV site and the control room are continuous and reliable. 2. There is evidence that it is economically feasible to install ASVs and RCVs on newly constructed and entirely replaced natural gas transmission and hazardous liquid pipelines, and the benefits would exceed the costs for the release scenarios (guillotine-type breaks on gas transmission pipelines with diameters of 12 and 42 inches in HCAs of all class locations, as well as on hazardous liquid pipelines with diameters of 8 and 30 inches in HCAs) considered in the study. However, the study noted that it is necessary to consider site-specific variables in determining whether installing ASVs or RCVs on newly constructed or entirely replaced pipelines is economically feasible for a particular situation and pipeline. 3. Installing ASVs and RCVs on newly constructed and entirely replaced natural gas and hazardous liquid pipelines can be an effective strategy for mitigating potential fire consequences resulting from a release and subsequent ignition. Adding automatic closure capability to valves on newly constructed or entirely replaced hazardous liquid pipelines can also be an effective strategy for mitigating potential socioeconomic and environmental damage resulting from a release that does not ignite. 4. For hazardous liquid pipelines, installing ASVs and RCVs can be an effective strategy for mitigating potential fire damage resulting from a pipe opening-type breaks 23 and subsequent ignition, provided the leak is detected and the appropriate ASVs and RCVs close completely so that the damaged pipeline segment is isolated within 15 minutes after the break. 23 A break in the pipeline that involves the opening of the pipe in either the circumferential or longitudinal direction. PHMSA used the conclusions of that report in developing this rulemaking and as a basis for implementing standards for valve installation per section 4 of the 2011 Pipeline Safety Act. ii. Section 8—Leak Detection Section 8 of the 2011 Pipeline Safety Act required the Secretary to submit to Congress a report on LDSs used by operators of hazardous liquid pipeline facilities, including transportation-related flow lines, and to establish technically, operationally, and economically feasible standards for the capability of LDSs to detect leaks. PHMSA responded to the 2011 Pipeline Safety Act's section 8 mandate by commissioning a leak detection study. 24 The study examined LDSs used by operators of hazardous liquid and natural gas transmission pipelines and included an analysis of the technical limitations of current LDSs, the ability of the systems to detect ruptures and small leaks that are ongoing or intermittent, and what can be done to foster development of better technologies. It also reviewed the practicality of establishing technically, operationally, and economically feasible standards for LDS capabilities. The study addressed five tasks defined by PHMSA: 24 See supra note 9. 1. Assess past incidents to determine if additional LDSs would have helped to reduce the consequences of the incident; 2. Review installed and currently available LDS technologies, along with their benefits, drawbacks, and ability to be retrofitted on existing pipelines; 3. Study current LDS operational practices used by the pipeline industry; 4. Perform a cost-benefit analysis of deploying LDSs on existing and new pipelines; and 5. Study existing LDS industry standards and international regulations to determine what gaps exist and if additional standards are needed to cover LDSs over a larger range of pipeline categories. The authors of the study were tasked only to report data and technical and cost aspects of LDSs. Although the study did not provide any specific conclusions or recommendations related to leak detection system standards, the study acknowledged that pressure/flow monitoring (leak detection techniques) will consistently and reliably catch large volume, uncontrolled release events such as ruptures. Consistent with the study findings, PHMSA has established regulations requiring RMVs and alternative equivalent technologies to be outfitted with equipment or other means to monitor valve status, commodity pressures, and flow rates. The study also noted that operator procedures may have allowed ignoring alarms, restarting pumps, or opening valves during large releases. PHMSA addresses this concern in this rulemaking by requiring operators to confirm that a rupture is occurring following any one of the criteria specified in a new regulatory definition for the “notification of [a] potential rupture.” The final rule also provides for post-incident reviews that can help operators determine how best to implement lessons learned system-wide and assist PHMSA in providing industry-wide guidance regarding overarching performance issues. E. 2020 Valve Rule NPRM On February 6, 2020, PHMSA published the NPRM seeking public comments on the revision of the Federal Pipeline Safety Regulations applicable to the safety of certain gas transmission, gas gathering, and hazardous liquid pipelines. Specifically, the proposed language created a RMV installation requirement for onshore, newly constructed and entirely replaced gas and hazardous liquid pipelines, including gathering pipelines, with diameters of 6 inches or greater. Additionally, PHMSA proposed to shorten pipeline segment isolation times in response to rupture events. PHMSA proposed a definition for “rupture” and outlined standards related to rupture identification and pipeline segment isolation, including establishing a 40-minute maximum RMV closure time and a 10-minute rupture identification threshold. In the NPRM, PHMSA also proposed requirements for RMV maintenance and inspection, spacing, risk analysis, post-incident investigation and review, and local 9-1-1 notification to help operators achieve better rupture response and mitigation. When developing the proposals in the NPRM, PHMSA considered the relevant comments it received on the ANPRMs, as well as the related NTSB recommendations, congressional mandates, and related studies. A summary of the NPRM proposals and topics, the comments received on those specific proposals, and PHMSA's response to the comments received is set forth in Section III. F. Subsequent Legislative Deadlines; Recent Executive Orders and Actions Congress has revisited the rulemaking mandate in the 2011 Pipeline Safety Act in subsequent legislation. Specifically, Congress directed PHMSA to issue a final rule no later than December 20, 2020 ( see 49 U.S.C. 60102 note). In addition, in the joint explanatory statement accompanying the Consolidated Appropriations Act for FY 2021 (Pub. L. 116-120; December 27, 2020), the conferees expressed “disappointment” that PHMSA had not met the December 20 deadline, and specified that PHMSA should issue a final rule within 180 days of enactment ( i.e., by June 25, 2021). 25 25 166 Cong. Rec. H8823 (daily ed. Dec. 21, 2020) (joint explanatory statement on Consolidated Appropriations Act of FY 2021). The President has also issued a series of Executive Orders emphasizing the importance of public safety, environmental protection, and GHG reduction in Federal policymaking. Executive Order 13990 (“Protecting Public Health and the Environment and Restoring Science To Tackle the Climate Crisis”) 26 announced the Administration's policy to, among other things, improve public health and protect the environment, reduce greenhouse gas emissions, and prioritize environmental justice. Executive Order 14008 (“Tackling the Climate Crisis at Home and Abroad”) 27 stated the Administration's policy that climate considerations will be an essential element of United States foreign policy and national security. The order also stated the Administration's policy to organize and deploy the full capacity of Federal agencies to combat the climate crisis, using a Government-wide approach. The President also announced a new target for reductions in national GHG emissions (a 50-52 percent reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030) to combat climate change, highlighting the importance of reducing emissions of greenhouse gases other than carbon dioxide, including methane, to deliver fast climate benefits. 28 Lastly, the Administration touted the GHG emissions reduction benefits of this rulemaking within the U.S. Methane Emissions Reduction Action Plan. 29 26 86 FR 7037 (Jan. 20, 2021). 27 86 FR 7619 (Feb. 1, 2021). 28 See, e.g., White House, “Fact Sheet: President Biden Sets 2030 Greenhouse Gas Pollution Reduction Target Aimed at Creating Good-Paying Union Jobs and Securing U.S. Leadership on Clean Energy Technologies” (Apr. 21, 2021), https://www.whitehouse.gov/briefing-room/statements-releases/2021/04/22/fact-sheet-president-biden-sets-2030-greenhouse-gas-pollution-reduction-target-aimed-at-creating-good-paying-union-jobs-and-securing-u-s-leadership-on-clean-energy-technologies/. 29 White House, “U.S. Methane Emissions Reduction Action Plan” at 7 (Nov. 2021), https://www.whitehouse.gov/wp-content/uploads/2021/11/US-Methane-Emissions-Reduction-Action-Plan-1.pdf. III. NPRM Comments, Pipeline Advisory Committee Recommendations, and PHMSA Responses The comment period for the NPRM ended on April 6, 2020. PHMSA received approximately 30 submissions to the docket commenting on the NPRM, including comments from major industry trade associations and others following advisory committee meetings as discussed below. PHMSA also accepted stakeholders' requests to discuss this rulemaking in meetings memorialized in the rulemaking docket. Consistent with § 190.323, PHMSA considered all of these comments given their relevance to the rulemaking and the absence of additional expense or delay resulting from considering any late-filed comments. Some of the comments PHMSA received in response to the NPRM were beyond the scope of the proposed regulations. In this final rule, PHMSA does not address the comments on pipeline safety issues that were beyond the scope of the NPRM; however, that does not mean that PHMSA determined the comments lack merit or do not support additional rules or amendments. Such issues may be the subject of other existing rulemaking proceedings or may be addressed in future rulemaking proceedings. The Technical Pipeline Safety Standards Committee (commonly known as the Gas Pipeline Advisory Committee, or the GPAC) and the Liquid Pipeline Advisory Committee (LPAC) are statutorily mandated (5 U.S.C. App. 1-16; 49 U.S.C. 60115) advisory committees tasked with advising and commenting on PHMSA's proposed safety standards, risk assessments, and safety policies for natural gas and hazardous liquid pipelines, respectively, prior to their final adoption. Each Committee consists of 15 members, with membership equally divided among Federal and State agencies, regulated industry, and the public. The committees consider the “technical feasibility, reasonableness, cost-effectiveness, and practicability” of each proposed pipeline safety standard and provide PHMSA with recommended actions pertaining to those proposals. On July 22 and 23, 2020, the GPAC and the LPAC (collectively, the “Committees”) met virtually to discuss this rulemaking. During the meetings, the Committees considered the specific regulatory proposals in the NPRM and discussed various comments submitted in the rulemaking docket on those proposals, including alternative regulatory language, from the pipeline industry, public interest groups, and government entities. Interested members of the public and other stakeholders were permitted to comment on the NPRM's proposals during the open portion of each meeting prior to the closed Committee discussions and voting. At the end of their closed discussions of each of the principal elements of the rulemaking, the Committees voted on whether to recommend PHMSA's adoption of the language proposed in the NPRM, or a variation thereon, as technically feasible, reasonable, cost-effective, and practicable. This section discusses the substantive comments on the NPRM that were submitted to the docket, the GPAC and LPAC recommendations, as well as any comments received from stakeholders in writing or during meetings with PHMSA personnel before issuance of this final rule. 30 They are organized by topic and include PHMSA's response to, and resolution of, those comments. 30 Those written comments, and summaries for the meetings, may be found in the rulemaking docket. PHMSA notes those comments and meeting summaries largely recapitulate positions submitted in written comments on the NPRM or during the GPAC/LPAC meetings. A. General Comments, Scope, Applicability, and Cost-Benefit Issues 1. Summary of Proposal In the NPRM, PHMSA proposed to make changes to parts 192 and 195 that applied to many regulated gas transmission, gas gathering, and hazardous liquid pipelines (including regulated rural hazardous liquid gathering pipelines). 2. Comments Received (i) General Support and Criticism Commenters largely supported the content and intent of the NPRM while also submitting more specific comments on individual topics and specific requests for revision, which are summarized in subsequent sections. Industry organizations were supportive of PHMSA's intent to enhance pipeline safety by improving rupture mitigation and shorten rupture isolation times for certain natural gas and hazardous liquid pipelines. The American Fuel and Petrochemical Manufacturers (AFPM) indicated that their members rely on an uninterrupted, affordable supply of crude oil and natural gas as feedstocks to maintain their competitiveness and economic activity, and that therefore, it is important to prevent pipeline safety incidents that can disrupt supply. The Kentucky Oil and Gas Association (KOGA) supported, in particular, the regulatory certainty provided by the rule, citing the importance of a clear framework to inform future business decisions. Additionally, the Clean Air Council and the National Association of Pipeline Safety Representatives (NAPSR) indicated support for the NPRM, the clarity it provides, and PHMSA's attention to human health and safety as well as the environment in regulating the transportation of gas and hazardous materials via pipeline across the United States. A broad, general criticism was that the same language, criteria, and requirements are unnecessarily restated in numerous sections of the NPRM, and that the NPRM could be improved by consolidating or removing duplicative language. Other criticisms included the scope of the rule and its applicability to gathering lines, as discussed in more detail in this section. (ii) Scope: General The NTSB stated that, although Safety Recommendation P-11-10 specifically called for PHMSA to require leak detection equipment on gas transmission and gas distribution pipelines, that recommendation is not included in the proposed rule. The NTSB noted that the criteria proposed for ruptures in the proposed rule do not specifically provide for leak detection, and the proposed requirements for installing RMVs exclude gas distribution systems, which are a particular concern of Safety Recommendation P-11-10. Other commenters echoed these concerns and stated that the rule should include leak- and rupture-detection requirements. The Clean Air Council stated that, because significant time is often lost during a pipeline incident in determining whether a rupture has occurred, the final rule should require operators install devices to detect ruptures. The Clean Air Council also noted that installing extra RMVs might be fruitless if an operator cannot detect the initial rupture, and went on to say that, in many rupture events, residents in the vicinity of the incident are those who discover a pipeline has ruptured, not the pipeline operators. Additionally, they noted that, in remote locations, the time between the rupture event occurring and when it is discovered is often so long that large amounts of product are lost, and the damage to the surrounding area is extreme. The Pipeline Safety Trust (PST) stated that it has been nearly 10 years since the NTSB recommended leak detection systems, via recommendation P-11-10, that meet regulatory performance standards on all transmission and distribution pipelines, and that PHMSA must do more to further the development and use of leak detection systems beyond participating in industry standards development. The PST and the Clean Air Council also asked that PHMSA consider extending the NPRM's proposed RMV requirements to existing pipelines consistent with the NTSB's recommendations. (iii) Scope: Distribution and Gathering Pipelines Regarding the scope related to gas distribution pipelines, INGAA et al. 31 recommended that PHMSA limit any new gas distribution system requirements, if they were intended in the proposal, to the 9-1-1 notification requirements and the incorporation of post-incident lessons learned. 31 The American Gas Association, American Petroleum Institute, American Public Gas Association, and Interstate Natural Gas Association of America (INGAA) jointly submitted comments to this rulemaking. Throughout this final rule, their joint comment is referred to as “INGAA et al.” Several commenters requested clarification regarding the provisions and their applicability to gathering pipelines, with the American Petroleum Institute and Association of Oil Pipe Lines (API/AOPL) and GPA Midstream Association (GPA Midstream), for example, recommending that PHMSA provide an exception for gathering pipelines from the RMV installation requirements. These entities stated that section 4 of the 2011 Pipeline Safety Act is limited to transmission pipelines, and also that requiring gathering pipeline operators to install RMVs is not economically, technically, or operationally feasible. KOGA and NAPSR noted that PHMSA initially stated that the NPRM would be applicable to transmission pipelines, however, both commenters noted that many of the provisions appeared to apply to gathering pipelines. NAPSR stated that, per § 192.9, Type A and B gathering pipelines must follow transmission regulations, and they requested that PHMSA clarify whether operators of gathering pipelines would have to install new valves as required by the NPRM for class location changes. Sander Resources stated that it was unclear whether PHMSA wanted to make the proposed regulations applicable to gathering pipelines or whether gathering pipelines were inadvertently included. Therefore, they noted that PHMSA must consider whether it would be appropriate to include provisions applicable to gathering pipelines in the final rule. Similarly, the Texas Pipeline Association (TPA) stated that the regulations should not be expanded beyond the scope of the congressional mandate, which applied to transmission pipeline facilities. (iv) Cost-Benefit Industry organizations stated that the NPRM dramatically understated the potential costs of the proposed valve installation and rupture detection standards, noting that PHMSA's Preliminary Regulatory Impact Assessment (PRIA) estimated the annual cost of implementing the proposed rule would be approximately $3.1 million. These organizations, however, said that an estimate prepared several decades ago showed that the cost of complying with similar valve installation standards would exceed $600 million. They stated the PRIA offered no explanation for the significant discrepancy between these two cost estimates and failed to account for the true costs for the changes required, noting that PHMSA may not propose a standard for adoption without making a “reasoned determination that the benefits of the intended standard justify its costs.” These commenters further stated that the alleged underreporting of incremental annual regulatory burdens in the PRIA is particularly impactful given the extraordinary economic conditions currently confronting the oil and gas industry due to the Covid-19 global pandemic. Furthermore, GPA Midstream and Sander Resources stated that the industry expects to add more than 35,000 miles of pipeline during 2020; therefore, they suggested that it may be unrealistic for PHMSA to estimate the total annualized cost amounts at $3.1 million. This would amount to just $88 per mile on an annualized basis. Further, these commenters noted that PHMSA's estimate did not cover repair or replacement projects that are ongoing. TC Energy Corporation commented that the cost estimates for adding actuators, controls, and telemetry to gas transmission pipelines would have added $250,000 to $375,000 per valve for a total of $4 to 6 million in additional annual costs. Based on their review of their class location projects completed in previous years, TC Energy estimated that the proposed language regarding class location replacements would add another $5 million in costs annually. An individual suggested that the cost-benefit analysis should consider the loss of power when gas transmission or gas distribution service is interrupted. They stated reductions in serious injuries and loss of life are the most significant economic consideration, but there are additional economic factors that PHMSA should consider. Among those economic costs mentioned were cost to end users associated with interruption of natural gas supply, as well as the additional delay and costs associated with recovery efforts ( e.g., re-lighting pilot lights) following a service interruption. The Clean Air Council commented that the economic feasibility of the proposed rule should not be a factor in implementing the regulations. They stated that the installation of the proposed rupture-detection and automatic-valve technology should be included in pipeline construction and repair costs and should not be considered “extra” infrastructure that would carry an incremental cost. They stated that, while in some cases, the necessary electricity and connectivity requirements may make RCVs and ASVs infeasible in very remote locations, in all other cases, this equipment should be considered mandatory as part of the cost of constructing or repairing a pipeline. They argued that the potential loss of life and economic costs from ruptures is enough to justify this change, and that the implementation cost is not even 1 percent of the amount of the damages the public and industry pays annually for pipeline incidents. 3. PHMSA Response PHMSA considered all the comments regarding the NPRM's readability and redundant language while drafting this final rule and believes that this final rule more clearly states the regulations and their intended effect. (i) Scope General. In response to the comments from the PST and the Clean Air Council that suggested PHMSA consider extending the NPRM's proposed RMV requirements to existing pipelines consistent with the NTSB's recommendations, PHMSA first notes that such a change is beyond the scope of the NPRM. As a result, such an expansion may merit additional process ( e.g., a supplemental notice and solicitation of additional comments), imposing a substantial delay to a rule that is already ten years in the making. Further, application of the rule's RMV and alternative equivalent technology installation requirements to existing pipeline infrastructure would entail installation activity ( e.g., blowdowns of existing pipelines prior to replacement, and work in pipeline rights-of-way) that could involve significant GHG emissions and other potential environmental harms. 32 32 PHMSA notes that the concerns discussed in this paragraph militate against, at the final rule stage, extending the rulemaking's scope to offshore gas and hazardous liquid pipelines. PHMSA is, however, evaluating extension in the future of the regulatory amendments in this final rule to pipeline facilities ( e.g., offshore pipelines, existing pipelines, additional gathering lines, and smaller-diameter pipelines) that were not within the scope of this rulemaking described in the NPRM. PHMSA notes that this does not mean that operators of existing pipelines do not have to address the risks of leaks or rupture events. All operators are required under the integrity management (IM) regulations at §§ 192.935 and 195.452 to conduct risk analyses to identify measures (including installing ASVs, RCVs, or EFRDs) as appropriate to enhance safety on pipeline segments that are in or which could affect HCAs. Further, this final rule requires operators of all gas and hazardous liquid pipelines subject to the emergency planning requirements at §§ 192.615 and 195.402, respectively, to update their emergency response plans to provide for immediate and direct notification of appropriate public safety answering points (9-1-1 emergency call centers) following the notification of a potential rupture. Similarly, the final rule requires all gas and hazardous liquid pipelines subject to failure investigation requirements at §§ 192.617 and 195.402, respectively, to conduct post-rupture investigations and reviews, and to incorporate lessons learned from such investigations and reviews into their training regimes and procedures. Regarding the provisions in this rulemaking related to leak detection, PHMSA is requiring pressure monitoring upstream and downstream of RMVs and alternative equivalent technology installed pursuant to this final rule. In doing so, PHMSA believes operators will be able to better detect and isolate ruptures, and operators can integrate the pressure monitoring equipment required by this rule into future, or current, leak detection systems and analyses. PHMSA also notes that the Federal Pipeline Safety Regulations reflect PHMSA's commitment to ensuring robust leak detection on PHMSA-jurisdictional pipelines. Since 2002, operators of hazardous liquid pipelines have been required to evaluate and install leak detection systems in HCAs, including on pipeline segments that could affect an HCA. 33 PHMSA also issued new regulations in October 2019 34 requiring that all hazardous liquid pipelines, even those outside of HCAs, have an effective system for detecting leaks. Further, hazardous liquid pipeline operators are required to inspect the surface conditions of their rights-of-way every 3 weeks. 35 Similarly, gas distribution pipeline operators are required by §§ 192.722 and 192.723 to conduct periodic patrols and leak surveys of their distribution systems at intervals. Gas transmission pipeline operators are obliged by § 192.705 to conduct periodic patrols of their pipelines, and by § 192.706 to conduct leak surveys twice per year in Class 3 locations and quarterly for Class 4 locations. 33 Design regulations for computational pipeline monitoring (CPM) leak detection systems are at § 195.134, and the operational requirements for CPM leak detection are at § 195.444. The requirement for operators of pipelines in HCAs and those that could affect HCAs to have an LDS are at § 195.452(i)(3). 34 84 FR 52260 (Oct. 1, 2019). 35 See § 195.412. PHMSA has also, in response to a mandate in section 120 of the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020 (Pub. L. 116-260; 2020 PIPES Act), initiated a rulemaking (under RIN 2137-AF51) to require operators of new and existing gas transmission, gas distribution, and (certain) regulated gas gathering lines implement leak detection and repair programs to achieve minimum performance standards reflecting the capabilities of commercially available advanced technologies. PHMSA will also continue to promote leak detection technology for pipelines through its research and development programs. Application to distribution and gas gathering lines. In the NPRM, PHMSA intended for the RMV and alternative equivalent technology installation requirements to apply to new and entirely replaced regulated gathering pipelines, both for gas and hazardous liquid operators. Section 192.9 states that operators of Type A gas gathering pipelines must comply with the requirements of part 192 applicable to gas transmission pipelines, and new and replaced Type B gas gathering pipelines must follow part 192 design, construction, installation, initial inspection, and initial testing requirements applicable to gas transmission pipelines. Nothing in the NPRM stated or suggested that the regulatory amendments proposed therein would not apply to new and entirely replaced gas gathering lines as provided by the plain meaning of § 192.9. However, in this final rule, PHMSA has decided to narrow the application of the valve installation requirements proposed in the NPRM to Type A gas gathering pipelines only; Type B gas gathering pipelines are explicitly exempted from those requirements. PHMSA adopts this limitation on the scope of the RMV and alternative equivalent technology installation requirements because of the distinguishable risk profiles associated with ruptures on Type A and Type B gas gathering pipelines. Type A gas gathering pipelines, per § 192.8, operate at higher pressures (correlating to hoop stress of 20 percent or more of specified minimum yield strength (SMYS), or pressures greater than 125 psig) and in areas of higher population density (specifically Class 2, Class 3, or Class 4 locations). As a result, ruptures on these pipelines will generally present a higher risk of public safety consequences, similar to gas transmission pipelines, warranting the additional protection that RMVs or alternative equivalent technology would provide. However, as explained in Section II. E of this final rule, PHMSA provides an exception from the valve installation requirements if an operator can demonstrate that a rupture on a new or entirely replaced Type A gas gathering pipelines in Class 2 locations would yield a PIR of 150 feet or less. Type B gas gathering pipelines, on the other hand, as defined at § 192.8, operate at lower pressures (involving hoop stress of less than 20 percent of SMYS). Ruptures on gas gathering pipelines operating within that same pressure range are likely to have a PIR comparable to the Type A gas gathering pipelines that PHMSA exempts from its RMV and alternative equivalent technology installation requirements. The final rule therefore exempts Type B gas gathering pipelines from those same requirements. Going forward, however, PHMSA will gather and consider additional data to inform application of these requirements to additional types of gas gathering pipelines. PHMSA has, in this final rule, further clarified that the Type C gas gathering lines established in the Gas Gathering final rule are, like Type B gas gathering lines, not subject to the RMV and alternative equivalent technology installation requirements. As explained above, the Type C gas gathering designation is new, created after publication of the NPRM and the LPAC and GPAC meetings on this rulemaking. PHMSA, therefore, declines to extend the valve installation requirements to that newly defined type of gas gathering lines in this final rule; PHMSA may, however, consider doing so in a subsequent rulemaking. Section § 195.1 similarly provides that part 195 applies to onshore hazardous liquid gathering pipelines that are: (1) Located in a non-rural area, (2) a regulated rural gathering line as that term is defined in § 195.11, or (3) located within an inlet of the Gulf of Mexico as provided in § 195.413. Further, operators of regulated rural gathering lines have to follow specific safety provisions set out in § 195.11, one of which is that steel regulated rural gathering lines must be designed, installed, constructed, initially inspected, and initially tested in compliance with part 195. Therefore, and similarly to Type A gas gathering pipelines, regulations proposed for design and construction standards for hazardous liquid pipelines will apply to regulated rural hazardous liquid gathering pipelines absent a specific statement that the regulations do not apply to regulated rural hazardous liquid gathering pipelines. Accordingly, in this final rule, operators of regulated hazardous liquid gathering lines must comply with the provisions of this rulemaking pertaining to hazardous liquid pipelines. Based on comments received on the NPRM and discussions at the LPAC meeting, however, PHMSA is requiring that operators of only certain regulated rural gathering lines—namely, lines that cross bodies of water greater than 100 feet wide, from high water mark to high water mark—install RMVs or alternative equivalent technologies in accordance with § 195.260(e). PHMSA has required extra valves near such water crossings for several decades under § 195.260, and similarly applies the requirements of this final rule to those lines. As for low-stress, rural hazardous liquid pipelines, as those are defined at § 195.12, PHMSA acknowledges that a hazardous liquid pipeline operating below 20 percent of SMYS is less likely to rupture than the same pipeline operating at higher pressures. However, a hazardous liquid pipeline can leak, without rupturing, and cause significant environmental damage; further, PHMSA accident report data yields that even low-stress hazardous liquid pipelines have failed. Accordingly, although the LPAC recommended that PHMSA consider an exception for low-stress, rural hazardous liquid pipelines in the final rule, PHMSA is instead requiring that all newly constructed and entirely replaced low-stress, rural hazardous liquid pipelines with diameter of six inches or greater, including low-stress hazardous liquid pipelines in rural areas, install RMVs pursuant to this rulemaking. PHMSA is also clarifying in this final rule that the requirements pertaining to RMVs or alternative equivalent technologies as outlined in the NPRM do not apply to gas distribution pipelines. The only requirements in this rule intended to apply to gas distribution pipelines are the requirements at § 192.615 for contacting 9-1-1 call centers and at § 192.617 pertaining to post-incident analysis and implementation of lessons learned. Although PHMSA acknowledges that there could be safety and environmental benefits from extending elements of this final rule to gas distribution pipelines, PHMSA declines to do so in this final rule as such an extension is beyond the scope of the NPRM and would require additional notice and public comment, and thus further delay issuance of this final rule. PHMSA will conduct further study and analysis evaluating which rupture response and mitigation measures (including, but not limited, those adopted in this final rule) are most appropriate for gas distribution pipelines. (iii) Cost-Benefit PHMSA analyzed the comments it received on the PRIA and cost-benefit issues and took them into account when drafting this final rule. PHMSA addresses those comments within the RIA in the rulemaking docket. B. Rupture Definition 1. Summary of Proposal In the NPRM, PHMSA proposed to introduce a new definition of “rupture” for gas pipelines at § 192.3 meaning any of the following events that involve an uncontrolled release of a large volume of gas: (1) A release of gas observed or reported to the operator by its field personnel, nearby pipeline or utility personnel, the public, local responders, or public authorities, and that may be representative of an unintentional and uncontrolled release event defined in paragraphs (2) or (3) of this definition; (2) An unanticipated or unplanned pressure loss of 10 percent or greater, occurring within a time interval of 15 minutes or less, unless the operator has documented in advance of the pressure loss the need for a higher pressure-change threshold due to pipeline flow dynamics that cause fluctuations in gas demand that are typically higher than a pressure loss of 10 percent in a time interval of 15 minutes or less; or (3) An unexplained flow rate change, pressure change, instrumentation indication, or equipment function that may be representative of an event defined in paragraph (2) of this definition. Similarly, for hazardous liquid pipelines, PHMSA proposed to introduce at § 195.2 a definition of “rupture” for hazardous liquid pipelines as any of the following events that involve an uncontrolled release of a large volume of hazardous liquid or carbon dioxide: (1) A release of hazardous liquid or carbon dioxide observed and reported to the operator by its field personnel, nearby pipeline or utility personnel, the public, local responders, or public authorities, and that may be representative of an unintentional and uncontrolled release event defined in paragraphs (2) or (3) of this definition; (2) An unanticipated or unplanned flow rate change of 10 percent or greater or a pressure loss of 10 percent or greater, occurring within a time interval of 15 minutes or less, unless the operator has documented in advance of the flow rate change or pressure loss the need for a higher flow rate change or higher pressure-change threshold due to pipeline flow dynamics and terrain elevation changes that cause fluctuations in hazardous liquid or carbon dioxide flow that are typically higher than a flow rate change or pressure loss of 10 percent in a time interval of 15 minutes or less; or (3) An unexplained flow rate change, pressure change, instrumentation indication or equipment function that may be representative of an event defined in paragraph (2) of this definition. For both definitions, PHMSA added a note stating that “rupture identification” was to occur when a rupture, as defined above, was first observed by, or reported to, pipeline operating personnel or a controller. 2. Comments Received For both gas and hazardous liquid pipelines, commenters stated that the proposed definitions are unclear in many respects and that the proposed definition of rupture emphasized the sources of information an operator might use to identify a rupture, like notifications to an operator, as opposed to establishing workable criteria for determining what qualifies as a rupture. Some commenters suggested that the release criteria PHMSA used to define a rupture were impractical and do not account for differences in pipeline system operation and monitoring capabilities. Some commenters further suggested that PHMSA proposed technically infeasible detection sensitivities. Individual operators and trade associations provided alternative definitions for “rupture” and “rupture identification” or provided editorial changes to the definitions. Other commenters, such as the NTSB, noted that elements of the definition, including the terms “large-volume” and “uncontrolled release,” could be interpreted in several ways and could benefit from clarification. Northern Natural Gas Company stated that the proposed definition of a rupture is too restrictive, noting that their pipeline system consists of pipelines with a series of branch or lateral lines which serve power plant or industrial customers that may change operating status several times per day with subsequent start-ups and shutdowns. They added that many of these start-ups and shutdowns would meet the proposed threshold defining a rupture, and for them to develop and maintain documentation in advance for all of these scenarios would be burdensome, extensive, time consuming, expensive, and would not result in improved pipeline safety. Therefore, they recommended that the language defining a rupture be changed to an unanticipated or unplanned flow rate change or pressure loss of 25 percent occurring within 30 minutes, or that the operator should be allowed to establish specific rupture criteria for each pipeline and maintain technical justification. TPA stated that there should be some recognition of the difficulty of determining a 30 percent pressure drop on certain transmission pipelines, such as where a natural gas-fueled electric generation plant is located on a segment. On pipeline segments such as these, they stated, significant swings in pressure are not uncommon as the generation plant starts up, and these swings in pressure can occur with little notice. Emerson Process Management Actuation Technologies, a manufacturer of pipeline valve operating systems and controls (including ASVs), noted that their clients typically use an actuation set point of a 20 to 30 psi pressure drop per minute with the goal of sensing a rupture but not being too sensitive to “risk a false valve closure.” This commenter proceeded to assert that the proposed definition could require ASV set points that are more sensitive to pressure changes than currently used within industry. Pertaining to hazardous liquid pipelines, AFPM stated that defining a rupture as a 10 percent pressure loss is not feasible for all locations, stating that the proposed language would force operators to consider pressure drops as ruptures when such pressure drops would likely not constitute an actual rupture event. They stated further that such a measure could lead to unnecessary incident reports, even in instances when no product is released, and suggested that a rupture is better defined as a percentage of flow leaving the pipeline, typically defined as 50 percent of receipt flows or higher. Magellan Midstream Partner, L.P. stated that the proposed rule is not clear regarding the impact of alarm persistence on determining whether a rupture is occurring and whether any momentary pressure change of 10 percent constitutes a rupture, or if the 10 percent drop would be sustained continuously over 15 minutes. Magellan also suggested that, since there are several scenarios in any given pipeline operation that could contribute to pressure drops and flow rates, a rupture should not be defined by a single variable, such as pressure or flow, but be inclusive of multiple indications that, evaluated collectively, would provide for a rupture signature. 36 36 Including pressure, temperature, meter flow, product characteristics, and geometry of the pipeline. OptaSense stated that operators should rely on monitoring systems that alert them of significant events with immediacy and actionable detail to mitigate the harmful consequences of a rupture rather than relying on third-party notification. On the other hand, TPA stated that the differences in the sophistication of various operators' pressure monitoring capabilities and differing granularity of monitored pressure points, combined with the short response times in the proposed rule, support some broadening of the definition of rupture to include notifications from first responders and the public. TPA added that these notifications would need some provision for operator confirmation. Magellan Midstream Partner, L.P. suggested that the proposed rule, as written, creates the potential for numerous false rupture alarms that could impact an operator's safety culture and desensitize an organization to the heightened awareness and urgent response that a rupture alarm should create. Commenters also suggested PHMSA consider allowing operators to establish specific rupture notification criteria for individual pipelines based on a pipeline's unique operating environment and parameters rather than establishing one-size-fits-all criteria. INGAA et al. stated that the proposed definition of rupture does not take into account that operators' natural gas systems and their customers' needs are unique and dynamic. INGAA et al. stated that the proposed definition arbitrarily establishes set points which require response and that PHMSA did not provide a technical basis for the 10-percent-over-15-minutes threshold in the proposed rule. INGAA et al. added that by unnecessarily triggering rupture response, PHMSA's proposed 10 percent over 15 minutes criteria may potentially compromise the reliability of service to customers. INGAA et al. stated that rather than prescribe a one-size-fits-all rupture criteria, they recommended that PHMSA direct operators to establish rupture-notification criteria for individual operating systems and to outline these criteria clearly within each operator's procedures. TC Energy recommended that if PHMSA includes a rate of pressure drop (ROPD) in the definition of a rupture, that operators should be allowed to establish their own ROPD that would indicate a rupture. They stated that the proposed definition of a rupture does not consider that operators' natural gas systems are unique and dynamic. Similarly, API/AOPL and GPA Midstream stated that the proposed definition of rupture relies on one-size-fits-all numerical thresholds for pressure loss and flow rates that would encompass many scenarios that are not in fact ruptures ( e.g., a power loss at a pump station). These entities added that PHMSA does not provide any technical justification for the proposed numeric thresholds and rigid application of the criteria that could lead to numerous false alarms and unnecessary valve closures. Commenters requested PHMSA clarify and distinguish between the meanings of the terms “rupture identification” and “notification of potential rupture” for both gas and hazardous liquid pipelines. INGAA et al. stated that the proposed definition of rupture does not address actual ruptures but rather the notification of potential ruptures, and PHMSA should therefore re-label this definition as the “notification of potential rupture,” which will also provide clarity in other sections of the rule. INGAA et al. and NAPSR also stated that PHMSA should limit the definition of “rupture” or “notification of potential rupture” to gas transmission pipelines, enabling PHMSA to use the terms “rupture” and “notification” as intended throughout the rulemaking without continuously qualifying whether the requirements are applicable to only potential ruptures on gas transmission lines or to both transmission line ruptures and rupture-like events on gas distribution lines, such as excavation damages. As noted previously, commenters, including API/AOPL and GPA Midstream, also suggested that PHMSA align the definition of rupture in this rulemaking with the definition of rupture used in PHMSA's incident report, noting the existing guidance currently used in the instructions for the part 195 accident reports state that a rupture occurs when a pipeline has “burst, split, or broken and the operation of the pipeline facility is immediately impaired,” resulting in an uncontrolled, large volume release of hazardous liquid or carbon dioxide. These industry commenters suggested that matching the definition in the reporting instructions would promote consistency, make the regulations easier to understand, and avoid unnecessary compliance burdens. The PST added that if the definition of rupture in the proposed rule is not the same as the definition of a rupture for incident and accident reporting purposes, it will make it impossible to track the effectiveness of this rule over time and to know whether this rule is driving safety. In response to these comments, PHMSA provided the Committees in advance of their July 22-23, 2020 meetings alternative language for consideration that would substitute the term “notification of potential rupture” for the definition of “rupture” proposed in the NPRM. The Committees unanimously recommended that PHMSA adopt this substitute language as presented and recommended by PHMSA staff at the meeting. However, the LPAC also recommended PHMSA remove from the second criterion under the part 195 definition of “notification of potential rupture” any reference to a specific pressure loss-rate threshold, instead recommending that this criterion refer only to operator observation of an unanticipated or unplanned pressure loss outside of a pipeline's normal operating parameters as defined in the operator's procedures. 3. PHMSA Response PHMSA acknowledges that having a clear definition is essential for successful implementation of the rule and considered the varying suggestions provided by commenters to clarify terms and improve understanding of, and compliance with, the final rule. Therefore, PHMSA has changed the proposed definition of “rupture” to a definition of “notification of potential rupture” as proposed to and recommended by the Committees. PHMSA intended for the definition of a “rupture” to provide operators with a standard to initiate rupture-mitigation measures consistently and promptly and notify emergency responders of a rupture event. PHMSA acknowledges, however, that operator response actions are more appropriately initiated on “notification of potential rupture” than on “rupture” as suggested by the NPRM. Indeed, the experience of the rupture events in San Bruno, CA, and Marshall, MI, underscore there can be a significant time lag between notification of indicia of a potential rupture and verification of a rupture. PHMSA has consequently, in this final rule, recharacterized the NPRM definition of “rupture” as a “notification of potential rupture.” PHMSA declines, however, to further modify the second criterion of the definition of “notification of potential rupture” to remove the NPRM's reference to a 10-percent-pressure-loss-within-15-minutes threshold as recommended by the LPAC. PHMSA's Accident Investigation Division has reviewed ruptures that have occurred the past several years that PHMSA has investigated and finds this to be an appropriate requirement. In certain cases, for example, operator pressure charts provided to PHMSA following pipeline ruptures showed pipelines operating at approximately 850 psig rapidly fall to approximately 100 psig. Another pipeline went from operating at 1,160 psig to 0 psig. In PHMSA's experience, unexpected pressure-loss events that are greater than 10 percent within 15 minutes are not routine events and are often indications a rupture has occurred. However, because PHMSA acknowledges that operators may have conditions or considerations that would cause pressure swings in excess of 10 percent within 15 minutes, PHMSA has introduced language permitting operators to document in their written procedures the need for alternative pressure-loss-rate thresholds due to the unique pipeline flow dynamics resulting from changes in demand. This final rule does not contemplate that operators must submit those written operating procedures to PHMSA in advance for notification or approval. PHMSA furthermore submits that operator concerns regarding the “one-size-fits-all” approach of this numerical threshold or the difficulty in predicting pressure drops given the diverse and variable demands on their systems may also be addressed by the qualifying language that any such pressure loss must be “unanticipated or unexplained.” PHMSA initially considered including the criteria for a “notification of potential rupture” within the definition sections of parts 192 and 195 (§§ 192.3 and 195.2, respectively) but found such an approach challenging. First, PHMSA found it unwieldy to include such detailed criteria in a definition section that has no enumerated paragraphs. Second, because the criteria also include requirements, PHMSA determined that the definition, including the criteria, would be more appropriately located in an operative section of the regulations. PHMSA understands the approach taken in this final rule provides improved clarity and enforceability. PHMSA used a similar approach when developing the definition of an “unusually sensitive area” in part 195. Therefore, in this final rule, PHMSA has established a definition for the term “notification of potential rupture” and has promulgated the criteria for that definition in §§ 192.635 and 195.417 for gas pipelines and hazardous liquid pipelines, respectively. PHMSA has also made editorial corrections clarifying the definitional criteria and identifying indicia—including explosions and fires in the immediate vicinity of a pipeline—discussed in the NPRM and during the Committee meetings as potential consequences (and therefore indicia) of a rupture. PHMSA acknowledges the value in aligning any regulatory definition of the term “rupture” with the definitions in its parts 192 and 195 incident/accident reporting forms. However, PHMSA has decided against codifying any regulatory definition of “rupture” in this final rule. Should PHMSA consider introducing a regulatory definition of “rupture” in a future rulemaking, it will endeavor to ensure consistency between any definition in the Federal Pipeline Safety Regulations and the incident and accident reporting forms. C. Rupture Identification Definition and Timeframe 1. Summary of Proposal In the NPRM, PHMSA proposed new provisions (§§ 192.634(c)(1) and 195.418(c)(1)) requiring operators installing RMVs or alternative equivalent technology to isolate a ruptured pipeline segment as soon as practicable, but within 40 minutes of rupture identification—defined in the NPRM (§§ 192.3 and 195.2) as the initial report to pipeline operators, or their initial observation, of a rupture. PHMSA also solicited comments on whether to oblige operators to have procedures to identify a rupture event within 10 minutes of the initial notification to the operator. These requirements would apply to both gas and hazardous liquid pipelines. 2. Summary of Comments Received API/AOPL, GPA Midstream, KOGA, Magellan Midstream Partner, L.P., and TC Energy Corporation stated that PHMSA should add a separate definition for the term “rupture identification” to specify that rupture identification occurs when a pipeline operator has sufficient information reasonably to determine that a rupture occurred. Some of these industry commenters provided alternative definitions or editorial suggestions to that end. API/AOPL stated that the rupture identification concept is highly important in establishing the extent of an operator's obligations under the new regulations. They suggested, along with GPA Midstream, that adding a separate definition for “rupture identification” that is based on a reasonableness standard is preferable to the NPRM's approach of defining a “rupture” by reference to a list of information that may be indicative, but not conclusive, of whether there is indeed a rupture. Northern Natural Gas Company stated that a 10-minute time limit for determining whether there is a rupture can create uncertainty in the initial actions that must be undertaken by natural gas transmission pipeline operators upon initial notification, and should be eliminated; Northern Natural Gas Company suggested that the final rule would be better focused on the time to commence shut-off of RMVs or alternative equivalent technology. Similarly, TC Energy Corporation called on PHMSA to remove the 10-minute rupture identification requirement entirely, and instead revise the regulatory text to mirror language in the NPRM preamble requiring operators to respond to a rupture as soon as practicable by closing rupture-mitigation valves, with complete valve shut-off and segment isolation within 40 minutes after rupture identification. INGAA et al. and TC Energy Corporation stated that PHMSA should eliminate the 10-minute identification requirement because the 40-minute response standard is sufficient to ensure safety in HCAs and Class 3 and Class 4 locations. INGAA et al. further stated that the decision to shut down a pipeline should not be rushed to meet an arbitrary 10-minute threshold because it risks significant service disruptions for natural gas customers. They added that operators should be provided the necessary time to determine whether a pipeline needs to be shut down. For hazardous liquid pipelines, API/AOPL stated that the feasibility of a 10-minute rupture identification requirement is highly dependent on the location of the pipeline. They further stated that imposing a 10-minute rupture identification requirement for pipelines in remote or difficult-to-access areas will effectively force operators of such pipelines to err on the side of being overly-conservative in responding to events as ruptures. Both API/AOPL and GPA Midstream stated that this requirement would disrupt operations, is too restrictive, and could lead to adverse consequences. API/AOPL requested that PHMSA eliminate the rupture identification timeframe or provide a longer period for rupture identification. Similar to comments made for gas transmission pipelines, GPA Midstream stated that, rather than providing a 10-minute deadline for rupture identification, PHMSA should provide operators with a 40-minute total response time for closing RMVs, manual valves, or equivalent technology following a rupture. TPA stated that the 10-minute requirement for identifying a rupture and contacting first responders is not feasible because of the need to determine the existence of a rupture as the trigger for the determination of the start of the response time. TPA stated that existing emergency procedures and damage prevention procedures at §§ 192.615 and 195.402 already contain requirements for the timely contact of emergency responders and calls to 9-1-1 numbers, so the 10-minute notification requirement in these provisions is duplicative and unnecessary, and recommended that this requirement be deleted from the proposed rule. An individual, on the other hand, agreed that the time to identify a rupture should be no more than 10 minutes, and that emergency services must be notified right away. At the Committee meetings on July 22 and 23, 2020, both the GPAC and the LPAC unanimously recommended that PHMSA eliminate the 10-minute rupture identification requirement because of the practical difficulties of prescribing a universal 10-minute rupture identification timeline notwithstanding the variety of pipeline locations and operational environments. In conjunction with this recommendation, the Committees also recommended that PHMSA require RMVs to be closed “as soon as practicable” within 30 minutes of “operator identification of a rupture” and that PHMSA require operators to document a method for rupture identification in their written procedures. 3. PHMSA Response PHMSA is adopting in this final rule at §§ 192.3 and 195.2 effectively identical regulatory definitions for “notification of potential rupture” that reflect editorial revisions to the definitions endorsed by the GPAC and LPAC. PHMSA notes that its decision to re-cast the NPRM definition of “rupture” as the term “notification of potential rupture” reflects that timely and effective rupture mitigation demands operators undertake certain actions on notification of common indicia of a rupture. Effective and timely rupture mitigation also demands operators take action on confirming, or identifying, that a rupture is in progress. The definition for “notification of potential rupture” allows an operator to consider the different pipeline operating characteristics, diverse potential rupture mechanisms, and information of varying quantity and quality in evaluating whether a rupture is, in fact, in progress, and whether additional mitigation measures are necessary. PHMSA believes this definition is flexible enough to help ensure operators reach an informed determination on whether a rupture is in progress. However, PHMSA has backstopped this flexibility by requiring within revisions to each of §§ 192.615 and 195.402 that each operator have written procedures specifying its methodology for identifying a rupture on receipt of a notification of a potential rupture. The communication of ruptures to 9-1-1 or other public safety officials was always meant to be broadly applicable to all pipeline operators—the provisions were placed in the emergency response section of the regulations applicable to all operators, and the GPAC and LPAC each recognized this intent when recommending that the proposed provisions for communicating with 9-1-1 applied to all ruptures, without exception. An operator cannot properly and promptly coordinate and share information with the appropriate public safety authorities regarding event location and planned and actual responses to an emergency if they do not have a procedure for identifying a rupture upon the notification of a potential rupture. Consistent with the Committees' recommendations, PHMSA has decided against including within this final rule the 10-minute global rupture identification time interval proposed in the NPRM. Although PHMSA understands that a 10-minute rupture identification timeline is achievable based on currently available technology, after reviewing the written comments submitted in this proceeding, and the discussions during the Committee meetings, PHMSA has concluded that the NPRM's one-size-fits-all approach to rupture identification could be challenging in light of the diversity of pipeline operational conditions and customer requirements. However, PHMSA remains concerned that, in the absence of a minimum rupture identification time interval, a scenario similar to those that played out during the Marshall, MI, and San Bruno, CA rupture events—in which there were extended delays in rupture identification and response despite multiple indicia of a potential rupture—could happen again. With that in mind, PHMSA had considered triggering this final rule's RMV operation response actions set forth in §§ 192.636 and 195.419 on notification of potential rupture rather than rupture identification. PHMSA has, however, declined to adopt such an approach in this final rule to avoid further procedural delays in realizing the safety benefits of a rulemaking that has been over a decade in the making here at PHMSA—which effort commenced over 40 years after the NTSB highlighted the public safety benefits from operators' installation of readily-available technologies such as RMVs on pipelines. 37 37 See Homendy, “San Bruno Victims and Their Families Deserve Long-Overdue Action” (Sept. 9, 2020), https://safetycompass.wordpress.com/category/infrastructure/ (last visited Nov. 8, 2021) ( referencing NTSB, PSS-71-1, Special Study of Effects of Delay in Shutting Down Failed Pipeline Systems and Methods of Providing Rapid Shutdown (Dec. 31, 1970), https://www.ntsb.gov/safety/safety-studies/Documents/PSS7101.pdf ). As a result, PHMSA may, in future rulemakings, consider whether it is appropriate to key operator RMV operation response actions to notification of potential rupture. In the interim, PHMSA has in this final rule codified at §§ 192.615(a)(12) and 195.402(e)(4) language within the NPRM expressing its expectation that operators will, upon notification of a potential rupture, identify whether there is indeed a rupture by reference to written procedures. Operators implementing this final rule should ensure those written procedures incorporate common-sense elements including, but not limited to, waiver of any requirements for specific pipeline personnel to conduct on-scene investigation of a potential rupture if an operator receives one or more of the following: Multiple or recurring instrument indications (pressure readings, alarms, etc.) of potential ruptures; pressure drops significantly in excess of the minimum thresholds in §§ 192.635(a)(1) and 195.417(a)(1); 38 and reports of rupture indicia from on-scene, credible sources ( e.g., on or off-duty pipeline operator personnel, sheriff or police officers, fire department personnel, or other emergency response personnel). PHMSA understands this reading of its revisions at §§ 192.615(a)(12) and 195.402(e)(4) to be consistent with operators' obligations elsewhere in §§ 192.615(a) and 195.402(e) (as revised) to take “necessary actions to minimize hazards of released [commodity] to life, property, or the environment.” PHMSA further notes that any risks to the public and the environment arising from delays in rupture identification for operators installing RMVs under this final rule would be further reduced by each of (1) language in §§ 192.615 and 195.402 requiring operators to ensure that their protocols identify ruptures “as soon as practicable” and (2) language at §§ 192.636 and 195.419 imposing demanding timelines—“as soon as practicable,” but not to exceed 30 minutes from rupture identification—for operation of RMVs following rupture identification. 38 PHMSA submits that operators may be able to leverage other provisions in this final rule (§§ 192.636(d)-(e) and 195.419(d)-(e)) pertaining to upstream/downstream pressure monitoring to support timely rupture identification without the need for on-scene investigation of a potential rupture. D. RMV Installation; RMV Closure Timeframe 1. Summary of Proposal In the NPRM, PHMSA proposed to require that all valves on newly constructed or entirely replaced onshore gas transmission and gathering pipelines that have diameters greater than or equal to 6 inches be RMVs or an alternative equivalent technology. Operators seeking to use an alternative equivalent technology in lieu of an RMV would have needed to submit a notification to PHMSA demonstrating that their preferred technology would provide an equivalent level of safety to an RMV. And should an operator seek to use a manual valve as an alternative equivalent technology, the operator would also have had to demonstrate that installation of an RMV would not be economically, technically, or operationally feasible. All valves installed per this proposal would meet the new rupture-mitigation standards proposed in § 192.634 and isolate a ruptured pipeline segment within 40 minutes of rupture identification. Similarly, for hazardous liquid pipelines, PHMSA similarly proposed to require that all valves on newly constructed and entirely replaced onshore hazardous liquid pipelines that have diameters greater than or equal to 6 inches be RMVs or alternative equivalent technology. Operators seeking to use an alternative equivalent technology in lieu of an RMV would have needed to submit a notification to PHMSA demonstrating that their preferred technology would provide an equivalent level of safety to an RMV. And should an operator seek to use a manual valve as an alternative equivalent technology, the operator would also have had to demonstrate that installation of an RMV would not be economically, technically, or operationally feasible. All valves installed under this proposal would meet the new rupture-mitigation standards proposed in § 195.418 and isolate a ruptured pipeline segment as soon as practicable, but within 40 minutes of rupture identification. 2. Comments Received The PST stated that the proposed rule did not provide sufficient rationale regarding how PHMSA arrived at a 40-minute shutdown requirement, other than a suggestion that it is “reasonable.” They stated that they have seen spill response plans for hazardous liquid pipelines claiming that failures isolated within 15 minutes constitute an operator's worst-case discharge. If those are accurately identified as the worst-case discharges, the PST noted, then valves must be able to close that fast or even more quickly. They stated that PHMSA's determination of the maximum allowable shut-off period should be justified by data relating to the speed with which automatic valves can shut, and if they can shut more quickly, then the maximum allowable valve closure period should be shortened to that length of time. Similarly, the NTSB suggested that the 40-minute valve closure time period is longer than expected for remote or automatic valves. The NTSB suggested that, if PHMSA determined that shut-off valves are not capable of isolating pipeline segments in less than 40 minutes, every facility response plan calculating the worst-case discharge based on a valve closure of less than 40 minutes after rupture identification should be re-evaluated. Conversely, Northern Natural Gas Company asserted that the requirement for closing a valve to isolate a rupture within 40 minutes does not allow adequate time for the pipeline controller to evaluate the nature of the pressure change, determine if there is an emergency, or identify the actions needed to mitigate the emergency. Therefore, Northern Natural Gas Company recommended PHMSA change the rupture identification and valve shut-off period to 60 minutes total. It stated that a 40-minute valve closure requirement could result in too-rapid decisions to shut-in pipeline segments, causing unnecessary outages, unanticipated pressure changes, and potential damage to the pipeline system. It also stated that, within the States where it operates, unplanned, sudden outages could cause major problems with prolonged loss of heat to residences, businesses, and government facilities as well as an interruption of electric power generation and industrial processes. INGAA et al. recommended that PHMSA apply the 40-minute valve closure time only to pipelines in HCAs and Class 3 and Class 4 locations to allow more flexibility in remote areas, noting specifically that achieving valve closure within 40 minutes is typically more challenging in remote areas. They noted that operators are likely to consider the use of manual valves in remote areas because an ASV, RCV, or equivalent technology would be economically, technically, or operationally infeasible, as it can be difficult to provide power or communications to automated valves in remote areas. INGAA et al., further noted that pipelines traverse a multitude of geographies, including locations that cannot safely be reached within 40 minutes, particularly during winter months. Similarly, AFPM and other commenters representing hazardous liquid pipeline operators also requested that PHMSA consider flexibility for response time in remote areas where manual valves are located, stating that, according to information submitted by AFPM members after a review of their respective systems, manual valve response times in certain scenarios would potentially exceed 40 or 60 minutes. AFPM stated that the increased response time is due to the location of field employees and their ability to reach remote locations, and that some valves may take up to 10 to 20 minutes to close once personnel are at the valve site. Therefore, these commenters stated that manual valves installed in accordance with the RMV installation requirements should not need to meet the proposed 40-minute valve closure standard. GPA Midstream, like other commenters, provided specific regulatory text for streamlining the requirements related to the valve closure period. GPA Midstream also recommended that operators be allowed to seek authorization from the Associate Administrator for Pipeline Safety to use an alternative shut-off time in appropriate cases, stating that there may be circumstances where an operator cannot meet the 40-minute shut-off time. INGAA et al. asserted that the 40-minute response time would not be practicable or appropriate to apply to existing pipelines, should PHMSA consider such a proposal in a future rulemaking. INGAA et al. claimed a 40-minute closure time is on the leading edge of what is practicable under currently-available technologies that could be applied to new and replaced pipelines. They noted that multiple PHMSA special permits contain a 60-minute valve closure time requirement, and operators have proactively taken steps to attain the 60-minute response target while the current rulemaking has been pending for almost a decade. Further, INGAA et al. stated that, even for new and replaced pipelines, attaining the 40-minute valve closure time will push the limit of what is currently technologically and operationally possible. They noted that for almost 60 percent of PHMSA-reportable ruptures from 2010 to 2019, the response time was greater than 40 minutes, which, they claimed, would indicate any response time shorter than 40 minutes for new and replaced pipelines would be infeasible. Similarly, Magellan Midstream Partners L.P. stated that 40 minutes is not a practical travel time to manual valves that have been installed in accordance with the RMV installation requirements. Commenters also suggested PHMSA should provide an allowance for scenarios where the operator and emergency responders agree not to shut an RMV following a rupture. At the Committee meetings on July 22 and 23, 2020, the Committees unanimously endorsed the NPRM's RMV closure requirements as “technically feasible, reasonable, cost effective and practicable” provided that PHMSA reduce the RMV closure time to 30 minutes in combination with eliminating the proposed 10-minute rupture identification standard. PHMSA understands that endorsement to reflect Committee discussions in which industry representatives focused their objections to the NPRM on the difficulty of meeting the 10-minute rupture identification timeline given differences in environmental conditions and operational requirements within their systems. Further, the GPAC recommended PHMSA review the issue of allowing certain valves to remain open during emergency situations based on the Committee discussion and public comments and ensure that the integrity of the rule was not compromised and would minimize environmental damage. The GPAC also recommended PHMSA allow, for natural gas pipelines, manual valves installed as alternative equivalent technology in non-HCA Class 1 locations to exceed the 30-minute closure time requirement only if the operator submits within its notification to install such valves as alternative equivalent technology a specific closure time for those manual valves. For hazardous liquid pipelines, the LPAC recommended a similar limitation apply to manual valves used as alternative equivalent technology in remote, non-HCA locations. 3. PHMSA Response As a part of developing the NPRM, PHMSA considered what would make it economically, technically, or operationally infeasible to install or use an ASV, RCV, or equivalent technology. For instance, PHMSA proposed to limit the installation of ASVs, RCVs, equivalent technologies (including, potentially manual valves) to pipelines of 6 inches and greater because, while rupture-mitigating technologies are commercially available for pipelines as small as 2 inches in diameter, PHMSA determined at the time that it is unlikely the safety and environmental benefits on those pipelines would justify the costs of installing the technology. While PHMSA applies these requirements to pipelines of 6 inches in this final rule, PHMSA may consider expansion of this application for smaller pipeline diameters in a future rulemaking. PHMSA would analyze the costs and potential safety and environmental benefits of an expansion in any such rulemaking. PHMSA also noted in the NPRM that examples of where it might be infeasible to install ASVs or RCVs included locations that may have issues with communication signals, power sources, space for actuators, or physical security. These locations can vary and are not limited to certain types of terrain. Certain urban areas, for example, might have access to power sources but might not have adequate physical space for the necessary valve actuators. Certain rural areas, on the other hand, might have issues with maintaining continuous communication signals or might have difficult-to-access valves. Other reasons that installation of RMV may be infeasible identified in written comments and during GPAC/LPAC meetings include difficulties in obtaining required access rights or permits. The COVID-19 global health emergency has also exacerbated labor and component constraints, drawing out procurement timelines and increasing costs. However, given that these valve installation requirements apply to new construction and replacement projects whose routes and components are planned out years in advance, PHMSA does not believe that there should be major economic, technical, or operational constraints impacting valve installation. Final Environmental Impact Statements for pipeline projects proposed after the passage of the Pipeline Safety Act of 2011 have shown that operators are committing to installing a substantial number of remotely operated and monitored valves. However, PHMSA does not want to preclude unforeseen challenges or conditions operators may face in installing valves pursuant to this rulemaking, and so developed an advance notification process at §§ 192.18 and 195.18, by which operators can (subject to PHMSA's review) make a site-specific case before installation of an alternative equivalent technology that (1) the technology would provide an equivalent level of safety to an RMV, and (2) if that proposed alternative equivalent technology is a manual valve, installation of an RMV would be economically, technically, or operationally infeasible. Similarly, PHMSA has in this final rule established procedural machinery allowing operators to request extensions of compliance timelines for installation of RMVs and alternative equivalent technology is such timelines are economically, technically, or operationally infeasible for near-term construction and replacement projects. PHMSA also considered what would make a technology “alternatively equivalent” to the ASVs and RCVs that the statute specifically listed. In developing the NPRM, and given the circumstances noted above, PHMSA wanted to provide operators with flexibility to install the appropriate valve or technology based on the unique circumstances at each site while still ensuring that such valves or technologies would close as soon as practicable. 39 In the NPRM, PHMSA also noted that, in the Marshall, MI incident, the rupture-mitigating valves the operator had equipped on the line were functionally useless until the operator was able to identify the rupture. Therefore, PHMSA believed that any proposed regulation would need to pair a valve installation requirement with a standard delineating when an operator must identify a rupture and actuate those valves. PHMSA did not consider it appropriate to assign different valve closure times to different rupture-mitigating valves or technologies, because doing so would have made compliance and enforcement difficult. 39 PHMSA notes that, as contemplated by the NPRM, such alternative technologies can include manual valves if an operator makes the requisite showings of safety equivalence and technical, operational, or economic infeasibility of RMV installation. See, e.g., 85 FR at 7178. PHMSA believed that, by setting a valve and technology closure standard for operators to meet, it would contribute to PHMSA's review of notifications contending that an alternative technology would provide an equivalent level of safety to an RMV. This approach allows operators to install the most appropriate valve or technology given site specifics, and it also prevents PHMSA from inadvertently restricting the development or use of promising rupture-mitigating technologies by imposing prescriptive requirements on the use of “equivalent technology,” which was not defined by the statute. As discussed throughout the NPRM and this final rule, PHMSA does expect operators to be able to close certain valves or technologies faster than others, and has included requirements for operators to close RMVs or alternative equivalent technologies “as soon as practicable” but within the required timeframe. PHMSA maintains that the proposed 40-minute RMV closure standard is achievable with current technology, and it would be a significant improvement over the 95 minutes it took PG&E to close the necessary valves during the incident at San Bruno, CA. As discussed in the NPRM, recent PHMSA-issued special permits for non-looped pipelines contemplate those lines will be equipped with isolation valves that can be closed in 30 minutes or less. PHMSA proposed a higher ceiling (40 minutes) in the NPRM because many gas and hazardous liquid systems have several incoming and outgoing product receipts and deliveries or tie-ins and, in some situations, multiple loop lines; establishing a one-size-fits-all requirement for valve closure times on all gas and hazardous liquid pipeline systems can be challenging based on the configuration of those systems. In the NPRM, PHMSA also noted that it considered valve closure times between 30 and 60 minutes based on comments on the ANPRMs and work on the “Alternative MAOP” rulemaking. 40 40 73 FR 62147 (Oct. 17, 2008). PHMSA notes that it developed the 40-minute RMV closure standard in the NPRM accounting for the potential need to include manual valves as alternative equivalent technology due to site-specific concerns; PHMSA assumed and expects ASVs and RCVs will be closed much faster. In the NPRM, PHMSA proposed to allow operators to use manual valves as an alternative equivalent technology, with a notification to PHMSA [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2022-07133. Public record. Not legal advice.