{"operation":"document","citation":"85 FR 7162","title":"Pipeline Safety: Valve Installation and Minimum Rupture Detection Standards","source_type":"rulemaking","agency":"Pipeline and Hazardous Materials Safety Administration","status":"proposed","official":true,"published_on":"2020-02-06","effective_on":null,"summary":"PHMSA is proposing to revise the Pipeline Safety Regulations applicable to newly constructed and entirely replaced onshore natural gas transmission and hazardous liquid pipelines to mitigate ruptures. Additionally, PHMSA is revising the regulations regarding rupture detection to shorten pipeline segment isolation times. These proposals address congressional mandates, incorporate recommendations from the National Transportation Safety Board, and are necessary to reduce the consequences of large-volume, uncontrolled releases of natural gas and hazardous liquid pipeline ruptures.","machine_formats":{"json":"https://regulus.evalyn.ai/document/federal-register-2020-01459.json","markdown":"https://regulus.evalyn.ai/document/federal-register-2020-01459.md"},"app_url":"https://regulus.evalyn.ai/document/federal-register-2020-01459","source_url":"https://www.federalregister.gov/documents/2020/02/06/2020-01459/pipeline-safety-valve-installation-and-minimum-rupture-detection-standards","body":"Federal Register, Volume 85 Issue 25 (Thursday, February 6, 2020) [Federal Register Volume 85, Number 25 (Thursday, February 6, 2020)] [Proposed Rules] [Pages 7162-7189] From the Federal Register Online via the Government Publishing Office [ www.gpo.gov ] [FR Doc No: 2020-01459] [[Page 7161]] Vol. 85 Thursday, No. 25 February 6, 2020 Part IV Department of Transportation ----------------------------------------------------------------------- Pipeline and Hazardous Materials Safety Administration ----------------------------------------------------------------------- 49 CFR Parts 192 and 195 Pipeline Safety: Valve Installation and Minimum Rupture Detection Standards; Proposed Rule Federal Register / Vol. 85, No. 25 / Thursday, February 6, 2020 / Proposed Rules [[Page 7162]] ----------------------------------------------------------------------- DEPARTMENT OF TRANSPORTATION Pipeline and Hazardous Materials Safety Administration 49 CFR Parts 192 and 195 [Docket No. PHMSA-2013-0255] RIN 2137-AF06 Pipeline Safety: Valve Installation and Minimum Rupture Detection Standards AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA), DOT. ACTION: Notice of proposed rulemaking. ----------------------------------------------------------------------- SUMMARY: PHMSA is proposing to revise the Pipeline Safety Regulations applicable to newly constructed and entirely replaced onshore natural gas transmission and hazardous liquid pipelines to mitigate ruptures. Additionally, PHMSA is revising the regulations regarding rupture detection to shorten pipeline segment isolation times. These proposals address congressional mandates, incorporate recommendations from the National Transportation Safety Board, and are necessary to reduce the consequences of large-volume, uncontrolled releases of natural gas and hazardous liquid pipeline ruptures. DATES: Persons interested in submitting written comments on this NPRM must do so by April 6, 2020. ADDRESSES: You may submit comments identified by the docket number PHMSA-2013-0255 by any of the following methods: Comments should reference Docket No. PHMSA-2013-0255 and may be submitted in the following ways: Federal eRulemaking Portal: http://www.regulations.gov . This site allows the public to enter comments on any Federal Register notice issued by any agency. Follow the online instructions for submitting comments. Fax: 1-202-493-2251. Mail: U.S. DOT Docket Operations Facility (M-30), West Building, 1200 New Jersey Avenue SE, Washington, DC 20590. Hand Delivery: DOT Docket Operations Facility, West Building, Room W12-140, 1200 New Jersey Avenue SE, Washington, DC 20590 between 9:00 a.m. and 5:00 p.m., Monday through Friday, except Federal holidays. Instructions: Identify the docket number, PHMSA-2013-0255, at the beginning of your comments. If you mail your comments, submit two copies. To confirm receipt of your comments, include a self-addressed, stamped postcard. Note: All comments are posted electronically in their original form, without changes or edits, including any personal information. Privacy Act Statement In accordance with 5 U.S.C. 553(c), DOT solicits comments from the public to better inform its rulemaking process. DOT posts these comments, without edit, including any personal information the commenter provides, to www.regulations.gov , as described in the system of records notice (DOT/ALL-14 FDMS), which can be reviewed at www.dot.gov/privacy . Confidential Business Information Confidential Business Information (CBI) is commercial or financial information that is both customarily and actually treated as private by its owner. Under the Freedom of Information Act (FOIA) (5 U.S.C. 552), CBI is exempt from public disclosure. If your comments responsive to this notice contain commercial or financial information that is customarily treated as private, that you actually treat as private, and that is relevant or responsive to this notice, it is important that you clearly designate the submitted comments as CBI. Pursuant to 49 CFR 190.343, you may ask PHMSA to give confidential treatment to information you give to the agency by taking the following steps: (1) Mark each page of the original document submission containing CBI as ``Confidential''; (2) send PHMSA, along with the original document, a second copy of the original document with the CBI deleted; and (3) explain why the information you are submitting is CBI. Unless you are notified otherwise, PHMSA will treat such marked submissions as confidential under the Freedom of Information Act, and they will not be placed in the public docket of this notice. Submissions containing CBI should be sent to Robert Jagger at U.S. DOT, PHMSA, PHP-30, 1200 New Jersey Avenue SE, PHP-30, Washington, DC 20590-0001. Any commentary PHMSA receives that is not specifically designated as CBI will be placed in the public docket for this matter. FOR FURTHER INFORMATION CONTACT: Technical questions: Steve Nanney, Project Manager, 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 Regulatory Action B. Summary of the Major Provisions of the Regulatory Action C. Costs and Benefits II. Background A. General Authority B. Major Pipeline Accidents C. National Transportation Safety Board Recommendations D. Advance Notices of Proposed Rulemaking (ANPRM) E. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and Related Studies i. Section 4--Automatic and Remote-Controlled Shut-Off Valves a. GAO Report GAO-13-168 b. ORNL Report ORNL/TM-2012/411 ii. Section 8--Leak Detection F. PHMSA 2012 R&D Forum, ``Leak Detection and Mitigation'' III. Proposed Rupture Detection and Mitigation Actions and Analysis of ANPRM Comments A. Definition of Rupture B. Accident Response and Mitigation Measures i. Installing Remote Control Valves (RCVs) and Automatic Shutoff Valves (ASVs) ii. Standards for Rupture Identification and Response Times iii. Using RCVs and ASVs in All Cases C. Drills to Validate Valve Closure Capability D. Maximum Valve Spacing Distance i. Gas Transmission Pipelines ii. Valve Spacing in Response to Class Location Changes iii. Hazardous Liquid Pipelines E. Protection of High Consequence Areas (HCAs) i. Gas Transmission Pipelines ii. Hazardous Liquid Pipelines F. Failure Investigations IV. Section-by-Section Analysis of Changes to 49 CFR Part 192 for Gas Transmission 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 PHMSA seeks notice and comment on proposed revisions to the Pipeline Safety Regulations for both gas transmission and hazardous liquid pipelines. PHMSA is proposing regulations to meet a congressional mandate calling for the installation of remote-control valves (RCV), automatic shutoff valves (ASV), or equivalent technology, on all newly constructed and fully replaced gas transmission and hazardous liquid lines. However, consistent with the mandate, PHMSA recognizes that there may be locations where it is not economically, technically, or operationally feasible to install RCVs, ASVs, or equivalent technology. Therefore, PHMSA is proposing to allow operators to install manual valves at these locations, provided operators have a sufficient justification for using a manual valve instead of an RCV, an ASV, or [[Page 7163]] equivalent technology, and provided that operators appropriately station personnel to ensure that a manual valve can be closed within the same 40-minute timeframe PHMSA is proposing in this rulemaking for RCVs, ASVs, and equivalent technology. This will help to ensure that a consistent level of safety is provided whether operators use manual valves, RCVs, ASVs, or equivalent technology. This rulemaking (NPRM) is proposing to apply this installation requirement to those newly constructed or fully replaced pipelines that are greater-than-or-equal-to 6 inches in nominal diameter. PHMSA is also proposing regulations to improve pipeline operators' responses to large-volume, uncontrolled release events that may occur during the operation of certain onshore gas transmission, hazardous liquid, and carbon dioxide pipelines of particular diameters and in specific locations.\\1\\ This NPRM would define a ``rupture'' event through certain metrics or observations, require operators of applicable lines to meet new regulatory standards to identify ruptures more quickly, respond to them more effectively, and mitigate their impacts. PHMSA's existing regulations require that operators take several steps to reduce the risk of potential leaks and failures, including testing and assessments, continuous monitoring of operations, and physical surveys and patrols of their pipelines' right-of-ways. Based on congressional direction, National Transportation Safety Board (NTSB) safety recommendations from accident investigations, recommendations from the Government Accountability Office (GAO), and PHMSA's analysis of incidents and evolving technology, this rule proposes to define large- volume, uncontrolled releases of both natural gas and hazardous liquids as pipeline ``ruptures'' and proposes standards to mitigate those ruptures. --------------------------------------------------------------------------- \\1\\ For brevity, reference to ``hazardous liquid pipelines'' through the remainder of this NPRM will include carbon dioxide pipelines as well, unless otherwise stipulated. --------------------------------------------------------------------------- One such rupture occurred on July 25, 2010, in Marshall, Michigan, resulting in the spill of approximately 800,000 gallons of crude oil into the Kalamazoo River and approximately $1 billion in damages. The operator took 18 hours to confirm the pipeline rupture. Following confirmation of the rupture, the failed segment of the pipeline was immediately isolated using remote-controlled valves. Another incident occurred on September 9, 2010, in San Bruno, California, when a gas pipeline ruptured, causing a fire. This incident involved the uncontrolled release of natural gas for 95 minutes, severely hampering firefighting efforts, before the operator closed the mainline valves. The incident resulted in 8 deaths, 51 injuries requiring hospitalization, the destruction of 38 homes, damage to 70 other homes, and the evacuation of approximately 300 houses. These two incidents are examples of release events where consequences can be significantly aggravated by some combination of missed opportunities by operators, including: (1) Identifying that a rupture has occurred; (2) failing to take appropriate and prompt action(s) once a rupture has been identified, including calling 911 following the rupture, activating emergency response protocols, and notifying first responders and public officials; and (3) failing to promptly access and close available segment isolation valves that would be most beneficial for mitigating the impact of the rupture. Following those incidents, Congress issued the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Pipeline Safety Act), which contained several mandates to improve pipeline safety. Section 4 of the 2011 Pipeline Safety Act requires PHMSA to issue regulations, if appropriate, requiring the use of automatic or remote-controlled shut-off valves, or equivalent technology, on newly constructed or replaced natural gas or hazardous liquid pipeline facilities. PHMSA is proposing these regulations to improve operational practices related to rupture mitigation and to shorten rupture-segment isolation times by requiring operators of applicable lines to identify a rupture quickly, implement response procedures, and fully close pipeline mainline valves to terminate the uncontrolled release of commodity as soon as practicable. PHMSA is also requiring operators to install automatic shutoff, remote-controlled, or equivalent valves on newly constructed and entirely replaced pipelines to meet the section 4 mandate. PHMSA seeks comment from the public on these proposals. Enbridge, the pipeline operator responsible for the incident near Marshall, MI, had remote-control technology installed on the ruptured pipeline. However, a failure to identify the rupture within a short amount of time rendered the technology essentially useless. Therefore, PHMSA believes a regulation requiring the installation of rupture- mitigating valves should be paired with a standard delineating when an operator must identify a rupture and actuate those valves. PHMSA also believes that this standard will be most cost-effective when applied to onshore hazardous liquid and natural gas transmission pipelines of certain diameters in high-consequence areas (HCA), areas that could affect HCAs (for hazardous liquid pipelines), and Class 3 and 4 locations (for natural gas transmission pipelines),\\2\\ where a release could have the most significant adverse consequences on public safety or the environment. --------------------------------------------------------------------------- \\2\\ A gas pipeline's class location broadly indicates the level of potential consequences for a pipeline release based upon population density along the pipeline. Class locations are determined as specified at Sec. 192.5(a) by using a ``sliding mile'' that extends 220 yards on both sides of the centerline of a pipeline. The number of buildings within this sliding mile at any point during the mile's movement determines the class location for the entire mile of pipeline contained within the sliding mile. Class 1 locations contain 10 or fewer buildings intended for human occupancy, Class 2 locations contain 11 to 45 buildings, Class 3 locations contain 46 or more buildings, and Class 4 locations have a prevalence of 4-or-more-story buildings. --------------------------------------------------------------------------- In developing these proposed regulations, PHMSA considered other mandates in the 2011 Pipeline Safety Act, as well as NTSB safety recommendations that followed the San Bruno incident; \\3\\ GAO recommendations on the ability of operators to respond to commodity releases in HCAs; \\4\\ technical reports commissioned by PHMSA on valves and leak detection from Oak Ridge National Laboratory (ORNL) and Kiefner and Associates, respectively; 5 6 comments received on related topics through advance notices of proposed rulemaking (ANPRM); and information gathered at public meetings and workshops. --------------------------------------------------------------------------- \\3\\ ``Pacific Gas and Electric Company; Natural Gas Transmission Pipeline Rupture and Fire; San Bruno, CA; September 9, 2010; NTSB Accident Report PAR-11/01; Adopted August 30, 2011. https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1101.pdf . \\4\\ ``Pipeline Safety: Better Data and Guidance Needed to Improve Pipeline Operator Incident Response,'' Government Accountability Office Report to Congressional Committees, January 2013. https://www.gao.gov/assets/660/651408.pdf . \\5\\ ``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;'' Oak Ridge National Laboratory; ORNL/TM-2012/411; October 31, 2012. https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16701/finalvalvestudy.pdf . \\6\\ ``Leak Detection Study--DTPH56-11-D-000001;'' Kiefner and Associates, Inc.; Final Report No. 12-173; December 10, 2012. https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16691/leak-detection-study.pdf . --------------------------------------------------------------------------- PHMSA believes this approach, as detailed in this NPRM, will help reduce the consequences of ruptures through [[Page 7164]] improving both rupture identification and rupture mitigation, including more rapid and effective isolation of failed pipeline segments. B. Summary of the Major Provisions of the Proposed Regulatory Action This NPRM will require the installation of automatic shutoff valves, remote-control valves, or equivalent technology, on all newly constructed or entirely replaced natural gas transmission and hazardous liquid pipelines that have nominal diameters of 6 inches or greater.\\7\\ For the purposes of this NPRM, PHMSA considers pipelines to be ``entirely replaced'' when 2 or more contiguous miles are being replaced with new pipe. PHMSA requests comments on this definition of ``entirely replaced'' in the context of the Section 4 valve installation mandate and whether it is reasonable or should be modified in the future. Additionally, for gas transmission pipelines, when a pipeline's class location changes and results in pipe replacement to meet the maximum allowable operating pressure (MAOP) requirements of the new class location, an operator would be required to install or otherwise modify valves as necessary to comply with valve spacing requirements and the proposed rupture identification and mitigation requirements. --------------------------------------------------------------------------- \\7\\ ``Nominal'' pipe size is the standard size used to refer to pipe in non-specific terms and identifies the approximate inner diameter of the pipe with a non-dimensional number. --------------------------------------------------------------------------- The NPRM also would establish Federal minimum standards for the identification of ruptures and the initiation of pipeline shutdowns, segment isolation, and other mitigative actions, which are designed to reduce the volume of commodity released due to a pipeline rupture and thereby minimize potential adverse safety and environmental consequences. This NPRM also would establish standards for improving the effectiveness of emergency response. Specifically, the proposed rupture identification and mitigation regulations include: (1) Defining the term ``rupture'' as an event that results in an uncontrolled release of a large volume of commodity that can be determined according to specific criteria or that has been observed and reported to the operator; (2) a requirement to establish procedures for responding to a rupture; (3) a requirement to declare a rupture as soon as practicable but no longer than 10 minutes after initial notification or indication; (4) a requirement to immediately and directly notify the appropriate public safety answering point (9-1-1 emergency call centers) for the jurisdiction in which the rupture is located; and (5) a requirement 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. The term ``rupture-mitigation valve,'' as it pertains to this proposal, means the specific valve(s) that the operator would use to isolate a pipeline segment that experiences a rupture--the applicable ``shut-off segment'' as those are specified in this rulemaking. These valves can be any combination of automatic shutoff valves (ASVs), remote-control valves (RCVs), or equivalent technology. A ``shut-off segment,'' for the purposes of this NPRM, is the segment of applicable pipe between the rupture-mitigation valves closest to the upstream and downstream endpoints of a high-consequence area, a Class 3 location, or a Class 4 location so that the entirety of these areas is between rupture-mitigation valves. Multiple high-consequence areas, Class 3 locations, or Class 4 locations can be contained in a single shut-off segment, and all valves installed on a shut-off segment are rupture- mitigation valves. Additionally, operators would be required to perform post-accident reviews of any ruptures or other release events involving the closure of rupture-mitigation valves to ensure these proposed performance objectives are met and to apply any lessons learned system- wide. The new rupture mitigation requirements in this NPRM would take effect 12 months after the final rule is published. In this NPRM, PHMSA is only allowing operators to install or use manual valves if they can demonstrate to PHMSA that it would be economically, technically, or operationally infeasible to install or use an ASV, RCV, or equivalent technology. Examples of where an ASV, RCV, or equivalent technology might be infeasible include locations that may have issues with communication signals, power sources, space for actuators, or physical security. PHMSA is not proposing additional valve requirements for smaller diameter pipelines or leaks that don't meet the proposed definition of rupture in this rulemaking. PHMSA is also not requiring leak detection equipment on gas transmission and distribution pipelines as specifically recommended by NTSB Recommendation P-11-10. Pursuant to the findings in the Kiefner Leak Detection study that is referenced later in this rulemaking, it is typically more challenging to detect smaller leaks in an operationally, technically, and economically feasible manner. However, this proposed rule, for both hazardous liquid and gas transmission pipelines, requires the installation of pressure monitoring equipment at all rupture mitigation valves on both the upstream and downstream locations of the valve, which will help operators better detect ruptures and which can be used for leak detection. PHMSA continues to address the effectiveness of leak detection systems for other non-rupture type leaks through its rulemaking on the safety of hazardous liquid pipelines; \\8\\ research and development projects, including work on external-based leak detection sensors and acoustic pipeline leak detection systems; \\9\\ and engagement in new or updated standards being developed by standard developing organizations, including API recommended practices 1130 and 1175.\\10\\ The requirements in this NPRM of adding pressure detection and communication equipment at rupture mitigation valves are expected to drive further development and installation of leak detection technology and may help drive operators to make decisions to improve the capabilities of their leak detection systems to detect non-rupture-type events. --------------------------------------------------------------------------- \\8\\ https://www.regulations.gov/docket?D=PHMSA-2010-0229 . \\9\\ Details on all of PHMSA's leak detection research and development projects can be found at: https://primis.phmsa.dot.gov/matrix/PrjQuery.rdm?text1=leak&btn=Modern+Search . \\10\\ Computational Pipeline Monitoring for Liquids and Pipeline Leak Detection Program Management, respectively. --------------------------------------------------------------------------- C. Costs and Benefits Consistent with Executive Order 12866, PHMSA has prepared an assessment of the benefits and costs of the NPRM, as well as reasonable alternatives. Per the Preliminary Regulatory Impact Analysis (PRIA), PHMSA estimates the annual costs of the rule to be approximately $3.1 million, calculated using a 7 percent discount rate. The costs reflect the installation of valves on newly constructed and entirely replaced gas transmission and hazardous liquid pipelines, as well as incremental programmatic changes that operators will need to make to incorporate the proposed rupture detection and response procedures. PHMSA elected not to quantify the benefits of this rulemaking and instead discusses them qualitatively in the PRIA. PHMSA is posting the PRIA for this proposed rule in the public docket. In the PRIA, costs are aggregated by compliance method to estimate total [[Page 7165]] costs, by year, for the baseline and NPRM. 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. II. Background A. General Authority Congress has authorized Federal regulation of the transportation of gas and hazardous liquids by pipeline in the Pipeline Safety Laws (49 U.S.C. 60101 et seq.), a series of statutes that are administered by PHMSA. Congress established the current framework for regulating pipelines transporting gas in the Natural Gas Pipeline Safety Act of 1968 (Pub. L. 90-481) and the safety of hazardous liquid pipelines in the Hazardous Liquid Pipeline Safety Act of 1979 (Pub. L. 96-129). These laws give PHMSA the authority and responsibility to develop, prescribe, and enforce minimum Federal safety standards for the transportation of gas and hazardous liquids by pipeline. PHMSA prescribes and enforces comprehensive minimum safety standards for the transportation of gas and hazardous liquids by pipeline in 49 Code of Federal Regulations (CFR) parts 190-199. Among those standards, PHMSA has codified safety standards for the design, construction, testing, operation, and maintenance of gas and hazardous liquid pipelines in 49 CFR part 192, Transportation of Natural and Other Gas by Pipeline, and 49 CFR part 195, Transportation of Hazardous Liquids by Pipeline. Part 192 prescribes minimum safety requirements for the transportation of gas by pipeline, including ancillary facilities and within the limits of the outer continental shelf as defined in the Outer Continental Shelf Lands Act (43 U.S.C. 1331). Part 195 prescribes minimum safety requirements for pipeline facilities used in the transportation of hazardous liquids or carbon dioxide, including pipelines on the Outer Continental Shelf. B. Major Pipeline Accidents Although transmission pipelines are generally considered to be a very safe means of transporting natural gas and hazardous liquids,\\11\\ they can experience large-volume, uncontrolled releases that can have severe consequences. For example, and according to PHMSA hazardous liquid pipeline accident reports from 2006 to 2016, there were 91 reported incidents on pipelines within HCAs that would have been reported as ``ruptures'' per this proposed rulemaking and would have triggered this NPRM's rupture-mitigation response provisions. Such accidents can be aggravated by some combination of: Missed opportunities by the operator to identify that a rupture has occurred; failure of operating personnel to take appropriate action(s) once a rupture is identified; delays in accessing and closing available segment isolation valves; and an inability to quickly close isolation valves that would have the most significant impact in mitigating the consequences of a rupture. Typically, these types of incidents (i.e., failure events that result in rapidly occurring, large-volume releases) have been the most serious in terms of monetary and environmental damages and safety consequences--the aforementioned 91 hazardous liquid ``ruptures'' resulted in $1.21 billion dollars in damage and 88,506 bbls spilled. The Marshall, MI, and San Bruno, CA, accidents are examples of failure events that resulted in rapidly occurring, large- volume releases on high-pressure, large-diameter pipelines. --------------------------------------------------------------------------- \\11\\ Energy products being shipped through the nation's 2.7 million miles of pipelines reach their destinations without incident 99.997 percent of the time. https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/news/69671/aopl-api-speech.pdf . --------------------------------------------------------------------------- The intent of this NPRM is to improve operational practices that in turn will improve rupture mitigation and shorten rupture isolation times for certain onshore gas transmission and hazardous liquid pipelines. ``Rupture isolation time,'' as it is discussed in this NPRM, is the time it takes an operator to identify a rupture, implement response procedures, and fully close the appropriate mainline valves to terminate the uncontrolled flow of commodity from the ruptured pipeline segment. In accident investigations, PHMSA and the NTSB have identified issues relating to the timeliness of rupture identification and the appropriateness and timeliness of operators' responses to ruptures. Typically, no single aspect contributes to the deficiencies in rupture identification and response. Instead, there were multiple contributing factors associated with the technology, equipment, procedures, and human elements that resulted in inadequate rupture identification and response efforts. In some incidents, 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 instance, in the incident near Marshall, MI, the pipeline operator had in place leak detection systems (LDS) and supervisory control and data acquisition (SCADA) systems that notified the controller 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 excessive amount of time--18 hours--before the operator confirmed the rupture and initiated mitigative actions. In the incident in San Bruno, CA, the operator effectively identified there was a leak through LDS or SCADA systems but took 95 minutes to isolate the gas pipeline rupture, which caused the fire to continue to burn unabated. The NTSB noted that the operator, Pacific Gas & Electric (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 these incidents, the NTSB noted similar issues related to rupture response in its report on an incident occurring on March 23, 1994, in Edison Township, New Jersey.\\12\\ In the Edison incident, the operator took nearly 2\\1/2\\ hours to stop the flow of gas. The fire that followed the rupture destroyed 8 buildings, caused the evacuation of approximately 1,500 apartment residents, and caused more than $25 million worth of property damage. The director of the operator's Gas Control division stated in the NTSB accident report that the operator 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 valve depended on the employee's travel time to the valve site. In his experience, he found that employees could usually arrive at a valve site within 15 to 20 minutes, but in some instances it took more than 1 hour for employees to arrive at certain valves after being dispatched. In its accident report, the NTSB concluded that the lack of automatic- or remote-operated valves on the ruptured line prevented the company 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 (RSPA), that it expedite establishing requirements for installing automatic- or remote-operated mainline valves on high- pressure [[Page 7166]] pipelines in urban and environmentally sensitive areas to provide for rapid shutdown of failed pipeline systems (P-95-1). --------------------------------------------------------------------------- \\12\\ National Transportation Safety Board Pipeline Accident Report; Texas Eastern Transmission Corporation Natural Gas Pipeline Explosion and Fire; Edison, New Jersey; March 23, 1994. https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR9501.pdf . --------------------------------------------------------------------------- As recognized by Congress and several other stakeholders, these high-consequence rupture events deserve special consideration and regulatory treatment. Accordingly, PHMSA is proposing a combination of standards that focus on achieving the congressional objective of more timely rupture detection and mitigation in important areas while also requiring a broader installation of rupture-mitigating valves on newly constructed and entirely replaced pipeline infrastructure. C. National Transportation Safety Board Recommendations On August 30, 2011, the NTSB issued its report on the gas transmission pipeline accident that occurred in San Bruno, CA, on September 9, 2010.\\13\\ In its report, the NTSB issued safety recommendations P-11-8 through P-11-20 to PHMSA; safety recommendations P-11-24 through P-11-31 to PG&E, the operator of the failed line; and several recommendations to other entities, including the Governor of the State of California, the California Public Utilities Commission (CPUC), the American Gas Association (AGA), and the Interstate Natural Gas Association of America (INGAA). NTSB safety recommendations P-11-9, P-11-10, and P-11-11 recommended that PHMSA require operators to immediately and directly notify the appropriate public safety answering point (9-1-1 emergency call centers) in the communities and jurisdictions where a pipeline rupture is indicated; 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 require automatic shut-off valves (ASV) or remote-control valves (RCV) be installed in HCAs and Class 3 and 4 locations with the valves spaced considering risk analysis factors, respectively.\\14\\ --------------------------------------------------------------------------- \\13\\ NTSB/PAR-11/01, PB2011-916501, Pacific Gas and Electric Company Natural Gas Transmission Pipeline Rupture and Fire. \\14\\ NTSB Safety Recommendation addressed to PHMSA; September 26, 2011; https://www.ntsb.gov/safety/safety-recs/recletters/P-11-008-020.pdf . --------------------------------------------------------------------------- PHMSA determined that, although the NTSB directed these recommendations to onshore gas transmission pipelines in response to a natural gas transmission accident, certain aspects of these recommendations are also applicable to hazardous liquid pipelines, particularly as they relate to ruptures. D. Advance Notices of Proposed Rulemaking PHMSA published two ANPRMs seeking comments regarding the revision of several topic areas in the Pipeline Safety Regulations that are applicable to the safety of hazardous liquid pipelines (October 18, 2010; 75 FR 63774) and gas transmission pipelines (August 25, 2011; 76 FR 53086).\\15\\ This NPRM addresses issues that were raised in the ANPRMs related to rupture detection and mitigation, including leak detection, valve spacing, valve installation, and method of valve actuation. --------------------------------------------------------------------------- \\15\\ See www.regulations.gov , dockets PHMSA-2010-0229 and PHMSA- 2011-0023, respectively, for both the ANPRMs and NPRMs. --------------------------------------------------------------------------- In response to the questions in the ANPRMs, a variety of parties representing interests from the natural gas and hazardous liquid industries, citizen groups, regulators, and local governments, provided comments. PHMSA considered these comments as discussed in Section III of this NPRM. Separately, PHMSA is addressing several other topics considered in the hazardous liquid and gas transmission ANPRMs, specifically in NPRMs titled ``Safety of Hazardous Liquid Pipelines'' (October 13, 2015; 80 FR 61610) and ``Safety of Gas Transmission and Gathering Pipelines'' (April 8, 2016; 81 FR 20722). E. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and Related Studies Public Law 112-9, known as the ``Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011'' (2011 Pipeline Safety Act), was enacted on January 3, 2012. Several of the 2011 Pipeline Safety Act's statutory requirements relate directly to the topics addressed in the ANPRMs, which have an impact on this proposed rulemaking. This NPRM is, in part, a response to the mandates of section 4 and section 8 of the 2011 Pipeline Safety Act. 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 natural gas transmission pipeline facilities that are constructed or entirely replaced after the date on which the Secretary issues the final rule containing such requirements. PHMSA is proposing to address this mandate by establishing the minimum standards described in this NPRM. These standards were also developed in consideration of NTSB Recommendations P-11-10 and P-11-11, the GAO Report GAO-13-168, ``Better Data and Guidance Needed to Improve Pipeline Operator Incident Response,'' \\16\\ 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 was performed in response to the 2011 Pipeline Safety Act.\\17\\ --------------------------------------------------------------------------- \\16\\ Published January 2013; www.regulations.gov (Docket ID PHMSA-2013-0255-0002). \\17\\ Published October 31, 2012; www.regulations.gov (Docket ID PHMSA-2013-0255-0004). --------------------------------------------------------------------------- a. GAO Report GAO-13-168 Section 4 of the 2011 Pipeline Safety Act also 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. This study was published by the GAO in January 2013 and 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, although the current PHMSA regulations for incident response and the installation and use of ASVs and RCVs are performance- based, they are very general, currently requiring operators to respond to incidents in a ``prompt and effective [[Page 7167]] manner,'' \\18\\ 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.\\19\\ --------------------------------------------------------------------------- \\18\\ For natural gas and hazardous liquid pipelines, Sec. Sec. 192.615(a)(3) and 195.402(e)(2), respectively. \\19\\ Requirements for ASV and RCV installation are at Sec. 192.935(c), and requirements for EFRD installation 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 pipelines havi","truncated":true,"body_characters":206559}