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

- **operation:** document
- **citation:** 87 FR 20940
- **title:** Pipeline Safety: Requirement of Valve Installation and Minimum Rupture Detection Standards
- **source type:** rulemaking
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2022-04-08
- **effective on:** 2022-10-05
- **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.
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Federal Register, Volume 87 Issue 68 (Friday, April 8, 2022) [Federal Register Volume 87, Number 68 (Friday, April 8, 2022)] [Rules and Regulations] [Pages 20940-20992] From the Federal Register Online via the Government Publishing Office [ www.gpo.gov ] [FR Doc No: 2022-07133] [[Page 20939]] Vol. 87 Friday, No. 68 April 8, 2022 Part II Department of Transportation ----------------------------------------------------------------------- Pipeline and Hazardous Materials Safety Administration ----------------------------------------------------------------------- 49 CFR Parts 192 and 195 Pipeline Safety: Requirement of Valve Installation and Minimum Rupture Detection Standards; Final Rule Federal Register / Vol. 87 , No. 68 / Friday, April 8, 2022 / Rules and Regulations [[Page 20940]] ----------------------------------------------------------------------- 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 [[Page 20941]] pipeline rupture following the initial alarms received by the control room operators. Once Enbridge confirmed the rupture, the failed segment was immediately isolated using installed remote-control shut-off valves (RCV). --------------------------------------------------------------------------- \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 Sec. 192.903. \8\ Oak Ridge National Laboratory (ORNL), ORNL/TM-2012/411, ``Studies for the Requirements of Automatic and Remotely Controlled Shutoff Valves and Hazardous Liquids and Natural Gas Pipelines with Respect to Public and Environmental Safety'' (Oct. 31, 2012), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16701/finalvalvestudy.pdf . \9\ Kiefner and Associates, Inc., Report No. 12-173, ``Leak Detection Study--DTPH56-11-D-000001'' (Dec. 10, 2012), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16691/leak-detection-study.pdf . \10\ 85 FR 7162 (Feb. 6, 2020) (NPRM). --------------------------------------------------------------------------- B. Summary of the Major Provisions of the Regulatory Action This final rule prescribes installation and spacing requirements for ASVs and RCVs (collectively, rupture-mitigation valves, or RMVs) as well as for alternative equivalent technology. The requirements apply to most newly constructed, or entirely replaced, onshore pipelines with diameters of 6 inches or greater, including natural gas transmission pipelines, Type A gas gathering pipelines, and hazardous liquid pipelines (including certain regulated hazardous liquid gathering pipelines). In this final rule, PHMSA has defined an ``entirely replaced'' pipeline as a pipeline that has 2 or more miles being replaced with new pipe within any stretch of 5 contiguous miles within any 24-month period. The rule also defines ASVs and RCVs as RMVs. PHMSA did not identify specific technologies that operators might use as alternative equivalent technologies for the purposes of this rulemaking, but PHMSA is requiring that such alternative technologies meet the performance standard for RMVs, to include the ability to immediately enable isolation of a rupture--in 30 minutes or less, measured from an operator's identification of a rupture after notification of a potential rupture. Operators of pipelines subject to the requirements of this final rule may request to install alternative equivalent technologies if they can demonstrate within a notification for PHMSA review that site- specific installation of an alternative equivalent technology would provide an equivalent level of safety to an RMV. Those notifications must be submitted in advance of installation of that technology, and must demonstrate an equivalent level of safety by reference to technical and safety factors including, but not limited to, the following: Design, construction, maintenance, and operating procedures; technology design and operating characteristics such as operation times (closure times for manual valves); service reliability and life; accessibility to operator personnel; nearby population density; and potential consequences to the environment and the public. Further, should an operator request use of manual valves as an alternative equivalent technology, the notification submitted to PHMSA must also demonstrate the economic, technical, or operational infeasibility of installation of an RMV by reference to [[Page 20942]] factors such as access to communications and power; terrain; prohibitive cost; labor and component availability; ability to secure required land access rights and permits; and accessibility to operator personnel for installation and maintenance. For regulated rural hazardous liquid gathering pipelines,\11\ at this time, PHMSA is requiring the installation of RMVs or alternative equivalent technology only where such pipelines cross bodies of water more than 100 feet in width from high water mark to high water mark. For hazardous liquid pipelines in general, this final rule establishes valve spacing thresholds both within and outside of HCAs and provides valve spacing limits for highly volatile liquid (HVL) pipelines in populated areas. PHMSA has recently issued a final rule in a separate rulemaking that will update its regulations that affect all types of gas gathering pipelines.\12\ --------------------------------------------------------------------------- \11\ A regulated rural hazardous liquid gathering pipeline is defined in Sec. 195.11 as an onshore gathering line in a rural area that meets all of the following criteria: (1) A nominal diameter from 6\5/8\ to 8\5/8\ inches; (2) located in or within \1/4\ mile of an unusually sensitive area, as that term is defined in Sec. 195.6; and (3) operating at a maximum pressure established under Sec. 195.406 corresponding to a stress level greater than 20 percent of the specified minimum yield strength (SMYS) of the line pipe or, if the stress level is unknown or the pipeline is not constructed with steel pipe, a pressure of more than 125 psig. \12\ ``Pipeline Safety--Safety of Gas Gathering Pipelines: Extension of Reporting Requirements, Regulation of Large, High- Pressure Lines, and Other Related Amendments,'' 86 FR 63266 (Nov. 15, 2021) (``Gas Gathering final rule''). --------------------------------------------------------------------------- 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 Sec. 192.5, are determined depending on the number of dwellings within 220 yards on either side of a pipeline and reflect the population density around the pipeline. --------------------------------------------------------------------------- This final rule also establishes Federal minimum safety performance standards for the identification of ruptures, pipeline segment isolation, and other mitigative actions, for pipelines on which RMVs or alternative equivalent technology are installed pursuant to this rulemaking. Relevant new requirements include: (1) A definition of the term ``notification of potential rupture'' to identify signs of an uncontrolled release of a large volume of commodity observed by, or reported to, the operator; (2) establishing written procedures for identifying and responding to a rupture; (3) responding to an identified rupture by closing RMVs or alternative equivalent technology, to provide complete valve shut-off and segment isolation as soon as practicable, but no more than 30 minutes after rupture identification; (4) performing post-event reviews of any incidents/ accidents or other failure events involving the closure of RMVs or alternative equivalent technologies to ensure the performance objectives of this rule are met and to apply any lessons learned system-wide; (5) performing maintenance on RMVs and alternative equivalent technology, which includes drills for alternative equivalent technology that is manually or locally operated; and (6) remediation measures for repair or replacement of inoperable RMVs and alternative equivalent technologies, including an RMV or alternative equivalent technology that cannot maintain shut-off, as soon as practicable. This final rule also requires operators of all gas and hazardous liquid pipelines subject to the emergency planning requirements at Sec. Sec. 192.615 and 195.402, respectively, to update their emergency response plans to provide for immediate and direct notification of appropriate public safety answering points (9-1-1 emergency call centers) for the communities and jurisdictions in which a rupture is located following the notification of a potential rupture. Similarly, the final rule requires all gas and hazardous liquid pipelines subject to failure investigation requirements at Sec. Sec. 192.617 and 195.402, respectively, to conduct post-rupture investigations and reviews, and to incorporate lessons learned from such investigations and reviews into their personnel training and qualifications programs, and in design, construction, testing, maintenance, operations, and emergency procedure manuals and specifications. C. Costs and Benefits Consistent with Executive Order 12866 (``Regulatory Planning and Review''),\14\ PHMSA has prepared an assessment of the benefits and costs of this final rule, as well as reasonable alternatives. The Regulatory Impact Analysis (RIA) developed by PHMSA in support of this final rule, and which is available in the rulemaking docket, estimates the annual costs of the rule to be approximately $5.9 million, calculated using a 7 percent discount rate. In the RIA, costs are aggregated by compliance method to estimate total costs, by year, for the baseline and the final rule. The incremental effect of this rulemaking is estimated by taking the difference in total costs relative to the baseline. Costs are then aggregated across all years in the analysis period and annualized. The costs reflect the installation of valves on certain newly constructed and entirely replaced gas and hazardous liquid pipelines, as well as incremental programmatic changes that operators will need to make to incorporate the proposed rupture identification and response procedures. --------------------------------------------------------------------------- \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 [[Page 20943]] pertinent natural gas and hazardous liquid pipelines to take prompt identification, isolation, and mitigation actions with respect to unintentional or uncontrolled, large-volume releases of natural gas or hazardous liquids during a pipeline rupture. The safety enhancements in this final rule, therefore, are expected to improve public safety, reduce threats to the environment (including, but not limited to, reduction of greenhouse gas emissions released during ruptures of natural gas pipelines), and promote environmental justice for minority populations, low-income populations, or other underserved and disadvantaged communities. PHMSA has, therefore, determined that these (unquantified) public safety, environmental, and equity benefits of the final rule described in this final rule and its supporting RIA and Environmental Assessment justify the costs of the final rule. --------------------------------------------------------------------------- \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 [[Page 20944]] install ASVs or RCVs in HCAs and Class 3 and 4 locations, with the valve spacing based on risk analysis. --------------------------------------------------------------------------- \18\ See supra note 3. --------------------------------------------------------------------------- PHMSA determined that, although the NTSB directed these recommendations to a rupture on a gas transmission pipeline, certain aspects of these recommendations are also applicable to ruptures on gas gathering and hazardous liquid pipelines, including the regulated hazardous liquid gathering pipelines regulated under part 195. PHMSA took these recommendations into account when developing this final rule by requiring that RMVs and alternative equivalent technologies be capable of having their status controlled or monitored (directly, or indirectly via the upstream pressure, and the downstream pressure) remotely,\19\ and by requiring the installation of RMVs, or equivalent alternative technologies, at intervals of no more than 8 miles in Class 4 locations and 15 miles in Class 3 locations. --------------------------------------------------------------------------- \19\ As discussed later in this document, for ASVs, an operator does not need to monitor remotely a valve's status if the operator has the capability to monitor pressures or gas flow rate on the pipeline to identify and locate a rupture. Pipeline segments that use an alternative equivalent technology must have the capability to monitor pressures or gas flow rates on the pipeline to identify and locate a rupture. --------------------------------------------------------------------------- C. Advance Notices of Proposed Rulemaking PHMSA published two ANPRMs seeking comments regarding the revision of provisions in the Federal Pipeline Safety Regulations governing safety of hazardous liquid pipelines and natural gas pipelines.\20\ PHMSA responded to pertinent comments received on the ANPRMs in Section III of the NPRM preceding this final rule. PHMSA addressed other topics raised in the hazardous liquid and gas transmission ANPRMs within other rulemakings, as appropriate. --------------------------------------------------------------------------- \20\ 75 FR 63774 (Oct. 18, 2010) (pertaining to hazardous liquid pipelines within docket PHMSA-2010-0229), and 76 FR 53086 (Aug. 25, 2011 (pertaining to natural gas pipelines within docket PHMSA-2011- 0023). --------------------------------------------------------------------------- D. 2011 Pipeline Safety Act and Related Studies Sections 4 and 8 of the 2011 Pipeline Safety Act established statutory requirements relating directly to topics addressed in the ANPRMs discussed previously. This final rule responds to those statutory mandates. PHMSA also considered the GAO Report No. GAO-13- 168, ``Better Data and Guidance Needed to Improve Pipeline Operator Incident Response'' and ORNL Report/TM-2012/411, ``Studies for the Requirements of Automatic and Remotely Controlled Shutoff Valves on Hazardous Liquids and Natural Gas Pipelines With Respect to Public and Environmental Safety'' which were performed in response to the 2011 Pipeline Safety Act and are discussed further below. i. Section 4--Automatic and Remote-Controlled Shut-Off Valves Section 4 of the 2011 Pipeline Safety Act directs the Secretary of Transportation (Secretary), if appropriate, to require by regulation the use of ASVs or RCVs, or equivalent technology, where it is economically, technically, and operationally feasible, on hazardous liquid and gas transmission pipeline facilities that are constructed or entirely replaced after the date on which the Secretary issues the final rule containing such requirements. This final rule addresses this mandate by establishing minimum standards for the installation of RMVs or alternative equivalent technology on specified newly constructed or entirely replaced, onshore pipelines that have diameters of 6 inches or greater, including gas transmission pipelines, Type A gas gathering pipelines, hazardous liquid pipelines, and certain regulated hazardous liquid gathering lines. a. GAO Report GAO-13-168 Section 4 of the 2011 Pipeline Safety Act required the development of a study by the Comptroller General on the ability of pipeline operators to respond to a hazardous liquid or gas release from a pipeline segment located in an HCA. In this study, published in January 2013, the GAO recommended PHMSA take the following two actions: 1. Improve the reliability of incident response data to improve operators' incident response times, and use this data to evaluate whether to implement a performance-based framework for incident response times; and 2. Assist operators in determining whether to install automated valves by using PHMSA's existing information sharing mechanisms to alert all pipeline operators of inspection and enforcement guidance that provides additional information on how to interpret regulations on automated valves, and share approaches used by operators for making decisions on whether to install automated valves. The GAO report noted that defined performance-based goals, established with reliable data and sound agency assessments, could result in improved operator response to incidents, with ASV and RCV installation and use being one of the determining factors. The GAO further noted that PHMSA's then-current regulations for incident response and installation and use of ASVs and RCVs employed broadly- stated performance standards, requiring operators to respond to incidents in a ``prompt and effective manner,'' \21\ and requiring operators to install ASVs, RCVs, or emergency flow restricting devices (EFRD) if an operator determines, through risk analysis, such valves are necessary to protect HCAs.\22\ --------------------------------------------------------------------------- \21\ For natural gas and hazardous liquid pipelines, Sec. Sec. 192.615(a)(3) and 195.402(e)(2), respectively. \22\ Requirements for ASV and RCV installation on gas transmission pipelines are at Sec. 192.935(c), and requirements for EFRD installation for hazardous liquid pipelines are at Sec. 195.452(i)(4). --------------------------------------------------------------------------- More clearly defined goals can help operators identify actions that could improve their ability to respond to certain types of incidents consistently and promptly, though identical incident response actions are not appropriate for all circumstances due to variable locations, equipment needs, configurations, and operating conditions of pipeline facilities. PHMSA agrees with the GAO's conclusions that more precise performance-based standards, in conjunction with carefully selected requirements, could be more effective in improving incident response times, particularly when ruptures are involved. The GAO report also concluded that the primary advantage of installing and using automated valves is that operators can respond more quickly to isolate the affected pipeline segment and
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