# Pipeline Safety: Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments

- **operation:** document
- **citation:** 87 FR 52224
- **title:** Pipeline Safety: Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments
- **source type:** rulemaking
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2022-08-24
- **effective on:** 2023-05-24
- **summary:** PHMSA is revising the Federal Pipeline Safety Regulations to improve the safety of onshore gas transmission pipelines. This final rule addresses several lessons learned following the Pacific Gas and Electric Company incident that occurred in San Bruno, CA, on September 9, 2010, and responds to public input received as part of the rulemaking process. The amendments in this final rule clarify certain integrity management provisions, codify a management of change process, update and bolster gas transmission pipeline corrosion control requirements, require operators to inspect pipelines following extreme weather events, strengthen integrity management assessment requirements, adjust the repair criteria for high-consequence areas, create new repair criteria for non-high consequence areas, and revise or create specific definitions related to the above amendments.
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- **source url:** https://www.federalregister.gov/documents/2022/08/24/2022-17031/pipeline-safety-safety-of-gas-transmission-pipelines-repair-criteria-integrity-management
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Federal Register, Volume 87 Issue 163 (Wednesday, August 24, 2022) [Federal Register Volume 87, Number 163 (Wednesday, August 24, 2022)] [Rules and Regulations] [Pages 52224-52279] From the Federal Register Online via the Government Publishing Office [ www.gpo.gov ] [FR Doc No: 2022-17031] [[Page 52223]] Vol. 87 Wednesday, No. 163 August 24, 2022 Part IV Department of Transportation ----------------------------------------------------------------------- Pipeline and Hazardous Materials Safety Administration ----------------------------------------------------------------------- 49 CFR Part 192 Pipeline Safety: Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments; Final Rule Federal Register / Vol. 87 , No. 163 / Wednesday, August 24, 2022 / Rules and Regulations [[Page 52224]] ----------------------------------------------------------------------- DEPARTMENT OF TRANSPORTATION Pipeline and Hazardous Materials Safety Administration 49 CFR Part 192 [Docket No. PHMSA-2011-0023; Amdt. No. 192-132] RIN 2137-AF39 Pipeline Safety: Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA), Department of Transportation (DOT). ACTION: Final rule. ----------------------------------------------------------------------- SUMMARY: PHMSA is revising the Federal Pipeline Safety Regulations to improve the safety of onshore gas transmission pipelines. This final rule addresses several lessons learned following the Pacific Gas and Electric Company incident that occurred in San Bruno, CA, on September 9, 2010, and responds to public input received as part of the rulemaking process. The amendments in this final rule clarify certain integrity management provisions, codify a management of change process, update and bolster gas transmission pipeline corrosion control requirements, require operators to inspect pipelines following extreme weather events, strengthen integrity management assessment requirements, adjust the repair criteria for high-consequence areas, create new repair criteria for non-high consequence areas, and revise or create specific definitions related to the above amendments. DATES: The final rule is effective May 24, 2023. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of May 24, 2023. The incorporation by reference of other publications listed in this rule was approved by the Director of the Federal Register on July 1, 2020. 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 Final Rule C. Costs and Benefits II. Background A. Overview B. Advance Notice of Proposed Rulemaking C. Notice of Proposed Rulemaking and Subsequent Final Rule III. Discussion of NPRM Comments, Gas Pipeline Advisory Committee Recommendations, and PHMSA Response A. IM Clarifications--Sec. Sec. 192.917(a)-(d), 192.935(a) i. Threat Identification, Data Collection, and Integration-- Sec. 192.917(a) & (b) ii. Risk Assessment Functional Requirements--Sec. 192.917(c) iii. Threat Assessment for Plastic Pipe--Sec. 192.917(d) iv. Preventive and Mitigative Measures--Sec. 192.935(a) B. Management of Change--Sec. Sec. 192.13 & 192.911 C. Corrosion Control--Sec. Sec. 192.319, 192.461, 192.465, 192.473, 192.478, and 192.935 and Appendix D i. Applicability ii. Installation of Pipe in the Ditch and Coating Surveys-- Sec. Sec. 192.319 & 192.461 iii. Interference Surveys--Sec. 192.473 iv. Internal Corrosion--Sec. 192.478 v. Cathodic Protection--Sec. 192.465 & Appendix D vi. P&M Measures--Sec. 192.935(f) & (g) D. Inspections Following Extreme Weather Events--Sec. 192.613 E. Strengthening Requirements for Assessment Methods--Sec. Sec. 192.923, 192.927, 192.929 i. Internal Corrosion Direct Assessment--Sec. Sec. 192.923, 192.927 ii. Stress Corrosion Cracking Direct Assessment--Sec. Sec. 192.923(c), 192.929 F. Repair Criteria--Sec. Sec. 192.714, 192.933 i. Repair Criteria in HCAs--Sec. 192.933 ii. Repair Criteria in non-HCAs--Sec. 192.714 iii. Cracking Criteria--Sec. Sec. 192.714 & 192.933 iv. Dent Criteria--Sec. Sec. 192.714 & 192.933 v. Corrosion Metal Loss Criteria--Sec. Sec. 192.714 & 192.933 vi. General Discussion G. Definitions--Sec. 192.3 i. Close Interval Survey ii. Distribution Center iii. Dry Gas or Dry Natural Gas iv. Electrical Survey v. Hard Spot vi. ILI and In-Line Inspection Tool or Instrumented Internal Inspection Device vii. Transmission Line viii. Wrinkle Bend IV. Section-by-Section Analysis V. Standards Incorporated by Reference VI. Regulatory Analysis and Notices I. Executive Summary A. Purpose of the Regulatory Action This final rule concludes a decade-long effort by PHMSA to amend its regulations governing onshore natural gas transmission pipelines in response to the tragic September 9, 2010, incident at a Pacific Gas and Electric Company (PG&E) gas transmission pipeline in San Bruno, CA, which resulted in the death of 8 people, injuries to more than 60 other people, and the destruction or damage of over 100 homes. PHMSA expects the new requirements in this final rule will reduce the frequency and consequences of failures and incidents from onshore natural gas transmission pipelines through earlier detection of threats to pipeline integrity, including those from corrosion or following extreme weather events. 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 natural gas pipeline incidents), and promote environmental justice for minority populations, low-income populations, and other underserved and disadvantaged communities that are located near interstate gas transmission pipelines. Although the Federal Pipeline Safety Regulations (49 Code of Federal Regulations (CFR) parts 190 through 199; PSR) applicable to gas transmission and gathering pipeline systems set forth in parts 191 and 192 have increased the level of safety associated with the transportation of gas, serious safety incidents continue to occur on gas transmission and gathering pipeline systems, resulting in serious risks to life and property. In its investigation of the 2010 PG&E incident, the National Transportation Safety Board (NTSB) found among several causal factors that PG&E had an inadequate integrity management (IM) program that failed to detect and repair or remove a defective pipe section on its gas transmission line.\1\ PG&E based its IM program on incomplete and inaccurate pipeline information, which led to, among other issues, faulty risk assessments, improper assessment method selections, and internal assessments of the program that were superficial and resulted in no meaningful improvement.\2\ --------------------------------------------------------------------------- \1\ NTSB, NTSB/PAR-11-01, ``Pipeline Accident Report: Pacific Gas and Electric Company, Natural Gas Transmission Pipeline Rupture and Fire, San Bruno, California, September 9, 2010'' (2011) (NTSB Incident Report on San Bruno). \2\ NTSB Incident Report on San Bruno at 107-115. --------------------------------------------------------------------------- Prior to the PG&E incident, PHMSA had initiated an advance notice of proposed rulemaking (ANPRM) to seek comment on whether the IM requirements in part 192 should be changed and whether other issues related to pipeline system integrity should be addressed by strengthening or expanding non-IM requirements. [[Page 52225]] PHMSA published the ANPRM on August 25, 2011.\3\ --------------------------------------------------------------------------- \3\ ``Safety of Gas Transmission Pipelines,'' 76 FR 53086 (Aug. 25, 2011). --------------------------------------------------------------------------- Based on the comments on the ANPRM, PHMSA published a notice of proposed rulemaking (NPRM) on April 8, 2016, to seek public comments on proposed changes to the PSR governing transmission and gathering lines.\4\ A summary of those proposed changes pertaining to this rulemaking, corresponding stakeholder feedback, and PHMSA's responses to stakeholder feedback on the individual provisions, is provided below in section III of this document (Discussion of NPRM Comments, GPAC Recommendations, and PHMSA Response). --------------------------------------------------------------------------- \4\ ``Safety of Gas Transmission and Gathering Pipelines,'' 81 FR 20722 (Apr. 8, 2016). --------------------------------------------------------------------------- PHMSA determined that the most efficient way to manage the proposals in the NPRM was to divide them into three separate final rule actions. The first of these final rules was published on October 1, 2019, and addressed topics primarily relating to congressional mandates and safety recommendations, including maximum allowable operating pressure (MAOP) reconfirmation and material properties verification, the expansion of integrity assessments beyond high-consequence areas (HCA), the consideration of seismicity, in-line inspection (ILI) launcher and receiver safety, MAOP exceedance reporting, and strengthened requirements for assessment methods (2019 Gas Transmission Rule).\5\ Provisions related to gas gathering pipelines were addressed in a separate rulemaking.\6\ This rulemaking finalizes the remaining provisions from the NPRM as outlined below. --------------------------------------------------------------------------- \5\ ``Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments,'' 84 FR 52180 (Oct. 1, 2019). \6\ ``Safety of Gas Gathering Pipelines: Extension of Reporting Requirements, Regulations of Large, High-Pressure Lines, and Other Related Amendments,'' 86 FR 63266 (Nov. 15, 2021) (Gas Gathering Final Rule). --------------------------------------------------------------------------- B. Summary of the Major Provisions of the Final Rule To reduce the risks of pipeline incidents, PHMSA is amending the PSR applicable to gas transmission pipelines to improve the protection of the public, property, and the environment; close regulatory gaps; and adopt additional safety measures to improve safety inside and outside of HCAs. Specifically, PHMSA is making changes to clarify the IM requirements; improve the management of change (MOC) process; strengthen corrosion control requirements; provide parameters for inspections following extreme weather events; strengthen requirements related to the IM assessment methods; and improve the repair criteria for pipeline anomalies. PHMSA is also amending certain definitions in part 192 in support of these provisions. PHMSA is modifying the IM regulations by adding specificity to the data integration language. The final rule establishes several pipeline attributes that must be included in an operator's risk analysis when an operator determines what threats are applicable to a pipeline segment. PHMSA is also explicitly requiring that operators integrate analyzed information into their IM programs and is requiring that data be verified and validated. Additionally, PHMSA is issuing requirements for applying knowledge gained through an operator's IM program, including provisions for analyzing interacting threats, potential failures, and worst-case incident scenarios from the initial failure to incident termination. Several of these items were proposed in response to NTSB findings following the PG&E incident that suggested pipeline operators were often not conducting data analysis, data integration, threat identification, and risk assessment in the manner originally intended and specified in subpart O of part 192. Similarly, following the PG&E incident, PHMSA, informed by (inter alia) the NTSB's evaluation of the incident and ANPRM comments, determined that the existing MOC requirements and industry practices were not sufficient \7\ and looked to align the regulatory requirements with the standards outlined in American Society of Mechanical Engineers/American National Standards Institute (ASME/ANSI) B31.8S.\8\ Specifically, this final rule requires each operator of an onshore gas transmission pipeline to develop and follow a MOC process, as outlined in ASME/ANSI B31.8S, section 11, that addresses technical, design, physical, environmental, procedural, operational, maintenance, and organizational changes to the pipeline or processes, whether permanent or temporary. --------------------------------------------------------------------------- \7\ See 81 FR 20796; NTSB Incident Report on San Bruno at 95-97 (concluding that the probable cause of the PG&E incident was PG&E's inadequate quality assurance and quality control in 1956 during its Line 132 relocation project, and noting that PG&E had poor quality control during a pipe installation project that later failed in 2008 in Rancho Cordova, CA). \8\ ASME/ANSI ``B31.8S-2004: Supplement to B31.8 on Managing System Integrity of Gas Pipelines'' (Jan. 14, 2005). --------------------------------------------------------------------------- This final rule also improves and updates the corrosion control requirements for gas transmission pipeline operators. Based on lessons PHMSA has learned following several pipeline failures, and following PHMSA's workshop on pipeline construction in Fort Worth, TX, on April 23, 2009,\9\ PHMSA determined that construction practices, including the installation of pipe in-ditch, can result in damaged coating that can compromise corrosion control. Therefore, this rule requires that operators perform assessments to identify suspected damage promptly after backfilling and then remediate any coating damage found. Further, PHMSA has noted that the existing regulations were not always effective at eliminating deficiencies in cathodic protection \10\ corrosion control or at preventing incidents from internal corrosion. Therefore, this rule strengthens the requirements for internal and external corrosion controls related to monitoring requirements and surveys. PHMSA also determined that additional prescriptive preventive and mitigative (P&M) measures are needed for managing electrical interference currents. --------------------------------------------------------------------------- \9\ https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=58 . \10\ Cathodic protection is a technique used to control corrosion by making the metal pipe a cathode of an electrochemical cell. Essentially, the pipeline is connected to a more easily corroded metal that acts as an anode. That ``sacrificial anode'' metal corrodes instead of the metal that is being protected. For pipelines, passive galvanic cathodic protection is often not adequate, and an external direct current (DC) electrical power source is used to provide sufficient current. --------------------------------------------------------------------------- Extreme weather has been a contributing factor in several pipeline failures. PHMSA issued Advisory Bulletins in 2015, 2016, and 2019 to communicate the potential for damage to pipeline facilities caused by severe flooding, including actions that operators should consider taking to ensure the integrity of pipelines in the event of flooding, river scour, river channel migration, and earth movement.\11\ As PHMSA has noted in another series of Advisory Bulletins, hurricanes are also capable of causing extensive damage to both offshore and inland pipelines.\12\ --------------------------------------------------------------------------- \11\ ``Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by Flooding, River Scour, and River Channel Migration,'' 80 FR 19114 (Apr. 9, 2015); ``Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by Flooding, River Scour, and River Channel Migration,'' 81 FR 2943 (Jan. 19, 2016); ``Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by Earth Movement and Other Geological Hazards,'' 84 FR 18919 (May 2, 2019). \12\ ``Potential for Damage to Pipeline Facilities Caused by the Passage of Hurricane Ivan,'' 69 FR 57135 (Sept. 23, 2004); ``Pipeline Safety Advisory: Potential for Damage to Pipeline Facilities Caused by the Passage of Hurricane Katrina,'' 70 FR 53272 (Sept. 7, 2005); ``Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by the Passage of Hurricanes,'' 76 FR 54531 (Sept. 1, 2011) (alerting operators to the potential for damage from Hurricane Ivan). --------------------------------------------------------------------------- [[Page 52226]] Because of the frequency and severe consequences of these events,\13\ operators must protect the public from pipeline risks in the event of a natural disaster or extreme weather. While many prudent operators might voluntarily perform inspections following such events, the potential risk to public safety and environment merits codification of those practices in regulatory requirements. Therefore, PHMSA is amending the PSR to require that operators commence inspection of their potentially affected facilities within 72 hours after the operator determines the affected area can be safely accessed following the cessation of an extreme weather event such as a hurricane, landslide, flood; a natural disaster, such as an earthquake; or another similar event that has the likelihood to damage infrastructure. If an operator finds an adverse condition during the inspection, the operator must take appropriate remedial action to ensure the safe operation of the pipeline.\14\ --------------------------------------------------------------------------- \13\ For the impacts of climate change on precipitation; droughts, floods, and wildfire; and extreme storms, see U.S. Global Change Research Program, ``Climate Science Special Report: Fourth National Climate Assessment, Volume 1,'' at ch. 7-9 (2017). \14\ PHMSA notes that these part 192 amendments are consistent with similar provisions adopted for part 195 for hazardous liquid pipelines. See ``Pipeline Safety: Safety of Hazardous Liquid Pipelines,'' 84 FR 52260 (Oct. 1, 2019). --------------------------------------------------------------------------- PHMSA is also strengthening the standards for performing pipeline assessments by incorporating by reference certain consensus standards for both stress corrosion cracking (NACE International Standard Practice 0204-2008, ``Stress Corrosion Cracking Direct Assessment Methodology'' (2008) (NACE 0204-2008)) and internal corrosion direct assessments (NACE International Standard Practice 0206-2006, ``Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas'' (2006) (NACE SP0206-2006)). Operators are already required to assess the condition of gas transmission pipelines in HCAs and certain non-HCAs periodically in accordance with Sec. Sec. 192.710, 192.921, and 192.937. When the initial IM regulations creating subpart O were issued in 2003 (2003 IM rule), industry standards did not exist for these types of assessments.\15\ By incorporating by reference the standards subsequently published by NACE International,\16\ PHMSA is ensuring greater consistency, accuracy, and quality when operators perform these assessments. --------------------------------------------------------------------------- \15\ ``Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines): Final Rule,'' 68 FR 69778 (Dec. 15, 2003). \16\ In 2021, NACE International merged with the Society for Protective Coatings, becoming the Association for Materials Protection and Performance (AMPP). They will continue to be referred to as NACE International throughout this document. --------------------------------------------------------------------------- This final rule also updates the existing repair criteria for HCAs by incorporating criteria for additional anomaly types such as crack anomalies, certain corrosion metal loss defects, and certain mechanical damage defects. Such revisions will provide greater assurance that operators will repair injurious anomalies and defects before those defects grow to a size that causes a leak or rupture. PHMSA also is finalizing explicit repair criteria for non-HCAs. Prior to this final rule, there were only general requirements in the regulations for operators to perform repairs in non-HCAs. The content of the non-HCA repair criteria being finalized in this rule is consistent with the criteria for HCAs; however, PHMSA has provided longer timeframes for the remediation of conditions that are not categorized as ``immediate'' conditions to provide operators the ability to prioritize remediating anomalous conditions in HCAs where consequences of a pipeline failure may be greater. The various changes in this rule have also prompted additions and changes to certain definitions in part 192. PHMSA has created or made changes to the following terms: ``close interval survey,'' ``distribution center,'' ``dry gas or dry natural gas,'' ``hard spot,'' ``in-line inspection (ILI),'' ``in-line inspection tool or instrumented internal inspection device,'' ``transmission line,'' and ``wrinkle bend.'' C. Costs and Benefits PHMSA has prepared an assessment of the benefits and costs of the final rule as well as reasonable alternatives. PHMSA estimates the annual costs of the rule to be approximately $17 million, calculated using a 7 percent discount rate. The costs reflect improvements made to the MOC process, additional corrosion control requirements, the provisions related to inspections following extreme weather events, and the changes made to the repair criteria. PHMSA finds that the other final rule requirements will not result in incremental costs. PHMSA is posting the Regulatory Impact Analysis (RIA) for this rule in the public docket. PHMSA has determined that the regulatory amendments adopted in this final rule will improve public safety, reduce threats to the environment (including, but not limited to, reduction of methane emissions contributing to the climate crisis), and promote environmental justice for minority populations, low-income populations, and other underserved and disadvantaged communities. PHMSA finds the regulatory amendments adopted in this final rule are technically feasible, reasonable, cost-effective, and practicable because the public safety, environmental, and equity benefits of its regulatory amendments described herein and within its supporting documents (including the RIA and environmental assessment, each available in the docket for this rulemaking) will justify any associated costs and demonstrate and the superiority of the final rule compared to alternatives. II. Background A. Overview On September 9, 2010, a 30-inch-diameter natural gas transmission pipeline, owned and operated by PG&E, ruptured in a residential neighborhood in San Bruno, CA. The rupture produced a crater approximately 72 feet long by 26 feet wide. The segment of pipe that ruptured weighed approximately 3,000 pounds, was 28 feet long, and was found 100 feet south of the crater. When the escaping gas ignited, the resulting fire killed 8 people, injured approximately 60 more, destroyed or damaged 108 homes, and caused the evacuation of over 300 people. In its pipeline accident report for the incident, the NTSB determined that the probable cause of the incident was PG&E's inadequate quality control and assurance when it relocated the line in 1956 and its inadequate IM program. The NTSB determined that PG&E's IM program was deficient and ineffective because it was based on incomplete and inaccurate pipeline information, did not consider how the pipeline's design and materials contributed to the risk of a pipeline failure, and failed to consider the presence of previously identified welded seam cracks as part of its risk assessment. These deficiencies resulted in the selection of an assessment method that could not detect welded seam defects and led to internal assessments of PG&E's IM program that were superficial and resulted in no improvements. Ultimately, this inadequate IM program failed to detect and repair or replace the defective pipe section. [[Page 52227]] In response to this incident, Congress, the NTSB, and the Government Accountability Office (GAO) called for PHMSA to improve IM and address other weaknesses and gaps in the PSR. As described in more detail in the sections that follow, this is the second of three planned rulemakings that are the culmination of this rulemaking initiative. B. Advance Notice of Proposed Rulemaking On August 25, 2011, PHMSA published an ANPRM to seek public comments regarding potential revisions to the PSR pertaining to the safety of gas transmission and gathering pipelines. PHMSA requested comments on 122 questions spread across 15 broad issues involving IM and non-IM requirements. The issues related to IM requirements included whether the definition of an HCA should be revised and whether additional restrictions should be placed on the use of certain pipeline assessment methods. The issues related to non-IM requirements included whether revised requirements were needed for mainline valve spacing and actuation, whether requirements for corrosion control should be strengthened, and whether new regulations were needed to govern the safety of gas gathering lines and underground natural gas storage facilities. Based on the comments received on several of the ANPRM topics, PHMSA developed specific proposals for some of those topics in an NPRM that was the basis for this final rule. C. Notice of Proposed Rulemaking and Subsequent Final Rule On April 8, 2016, PHMSA published an NPRM seeking public comments on proposed revisions to the PSR pertaining to the safety of onshore gas transmission pipelines and gas gathering pipelines. PHMSA considered the comments it received from the ANPRM and proposed new pipeline safety requirements and revisions of existing requirements in several major topic areas. A summary of the NPRM proposals and topics pertinent to this rulemaking, the comments received on those specific proposals, and PHMSA's response to the comments received, is provided under section III (Discussion of NPRM Comments, GPAC Recommendations, and PHMSA Response). On October 1, 2019, PHMSA promulgated a subset of the rules proposed in the NPRM by issuing the first of three planned final rules. In that rule, PHMSA addressed gas transmission pipelines and established minimum Federal safety standards for MAOP reconfirmation, pipeline physical material properties verification, the expansion of integrity assessments beyond HCAs, the consideration of seismicity in an operator's risk assessment and P&M measures, ILI tool launcher and receiver safety, MAOP exceedance reporting, and strengthened requirements for IM assessment methods. This final rule, the second of three planned rules, finalizes several proposed amendments in the NPRM related to gas transmission pipelines, including provisions related addressing repair criteria, IM improvements, cathodic protection, MOC processes, and other related amendments. A separate rulemaking, dealing with the safety of onshore gas gathering pipelines, was the subject of a final rule published on November 15, 2021, and extended reporting and safety requirements to certain gathering pipelines that were formerly not subject to Federal safety oversight. PHMSA estimated in that Gas Gathering Final Rule that there were over 400,000 miles of gas gathering pipelines that were not subject to minimum Federal pipeline safety standards, including basic incident and mileage reporting. The Gas Gathering Final Rule extended annual and incident reporting requirements to all gathering pipelines and defined a new category of ``Type C'' gathering pipelines to address the safety of larger-diameter, higher-pressure onshore gathering pipelines that were formerly unregulated. The scope of the requirements for Type C gas gathering pipelines are risk-based; basic damage prevention provisions apply to all Type C gas gathering pipelines while other safety requirements apply to larger-diameter Type C gas gathering pipelines or those Type C gas gathering pipelines that are located near buildings intended for human occupancy. III. Discussion of NPRM Comments, Gas Pipeline Advisory Committee Recommendations, and PHMSA Response The comment period for the NPRM ended on July 7, 2016. PHMSA received approximately 300 submissions to the docket containing thousands of comments on the NPRM. Submissions were received from the NTSB; groups representing the regulated pipeline industry; groups representing public interests, including environmental groups; State utility commissions and regulators; members of Congress; individual pipeline operators; and private citizens. PHMSA also received late- filed comments to this rulemaking from the major industry trade associations and others following advisory committee meetings as discussed below. Consistent with DOT Order 2100.6 and 190.323, PHMSA considered all comments, including those that were filed late, given their relevance to the rulemaking and the absence of additional expense or delay resulting from considering these comments. Some of the comments PHMSA received in response to the NPRM were considered in finalizing the 2019 Gas Transmission Rule targeted at statutory mandates, while other comments were considered in response to the third final rule on gas gathering pipelines (under RIN 2137-AE38). In this final rule, PHMSA considers those comments that are relevant to repair criteria, IM improvements, cathodic protection, MOC, and other related amendments. PHMSA does not address the comments on pipeline safety issues that were beyond the scope of the NPRM and, therefore, beyond the scope of this final rule. 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 remaining comments reflect a wide variety of views on the merits of particular sections of the proposed regulations. The Technical Pipeline Safety Standards Committee, commonly known as the Gas Pipeline Advisory Committee (GPAC or ``the committee''), is a statutorily mandated advisory committee that advises and comments on PHMSA's proposed safety standards, risk assessments, and safety policies for natural gas pipelines prior to their final adoption. The GPAC is one of two pipeline advisory committees focused on technical safety standards that were established under the Federal Advisory Committee Act (Pub. L. 92-463) and section 60115 of the Federal Pipeline Safety Statutes (49 U.S.C. 60101 et seq.). Each committee consists of approximately 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. Due to the size and technical detail of the NPRM, the GPAC met 5 times in 2017 and 2018 to discuss the proposed [[Page 52228]] regulations applicable to gas transmission pipelines. The GPAC convened one time in 2019 to discuss the provisions related specifically to gas gathering pipelines.\17\ During those meetings, the GPAC considered the specific regulatory proposals of the NPRM and discussed various comments made on the NPRM's proposal by stakeholders, including the pipeline industry at large, public interest groups, and government entities. To assist the GPAC in its deliberations, PHMSA presented a description and summary of the major proposals in the NPRM and the comments received on those issues. Stakeholders could comment on the proposals during the meeting prior to the committee discussion. PHMSA assisted the committee in fostering discussion and developing recommendations by providing direction on which issues were most pressing. --------------------------------------------------------------------------- \17\ Specifically, the committee met on January 11-12, 2017; June 6-7, 2017; December 14-15, 2017; March 2, 2018; March 26-28, 2018; and June 25-26, 2019. Information on these meetings can be found at regulations.gov under docket no. PHMSA-2011-0023 and at PHMSA's public meeting page: https://primis.phmsa.dot.gov/meetings/ . --------------------------------------------------------------------------- For the proposals addressed in this final rule, the committee came to consensus when voting on the technical feasibility, reasonableness, cost-effectiveness, and practicability of the NPRM's provisions. In many instances, the committee recommended changes to certain proposals that the committee found would make the rule more feasible, reasonable, cost-effective, or practicable. This section discusses the substantive comments on the NPRM that were submitted to the docket, as well as the GPAC's recommendations. They are organized by topic and include PHMSA's response to, and resolution of, those comments. A. IM Clarifications--Sec. Sec. 192.917(a)-(d), 192.935(a) i. Threat Identification, Data Collection, and Integration--Sec. 192.917(a) and (b) 1. Summary of PHMSA's Proposal Subpart O of 49 CFR part 192 prescribes requirements for managing pipeline integrity in HCAs and requires that operators identify and evaluate all potential threats to each covered pipeline segment. Operators are required to identify threats to which the pipeline is susceptible, collect data for analysis, and perform a risk assessment that informs the operator's baseline assessment schedule and reassessment intervals as well as any additional P&M measures that may be needed for the covered segment. The regulations also require operators to address particular threats, such as third-party damage and manufacturing and construction defects. For these requirements, the regulations reference, through incorporation, ASME/ANSI B31.8S. For threat identification, the regulations in Sec. 192.917 specify that the potential threats operators must consider include, but are not limited to, the threats listed in section 2 of ASME/ANSI B31.8S. Those threats are grouped into time-dependent threats, static or resident threats, time-independent threats, and human error. In performing data gathering and integration, operators must follow the requirements in ASME/ANSI B31.8S, section 4. At a minimum, operators must gather and evaluate the set of data specified in Appendix A to ASME/ANSI B31.8S, which are the year of installation; pipe inspection reports; leak history; wall thickness; diameter; past hydrostatic test information; gas, liquid, or solid analysis; bacteria culture test results; corrosion detection devices; operating parameters; and operating stress level. An operator must also conduct a risk assessment that follows ASME/ANSI B31.8S section 5. In a risk-based IM approach, data collection and integration is the backbone of an effective IM program. The PG&E incident exposed several problems in the way operators collect and manage pipeline condition data, showing that some operators have inadequate records regarding the physical and operational characteristics of their pipelines. The use of erroneous information leads to insufficient understanding of pipeline risks and incorrect integrity-related decision making. PG&E's IM program was missing or misidentified data elements that were necessary to characterize risk correctly and establish and validate MAOP, which is critically important for providing an appropriate margin of safety to the public. Threat identification, data collection, and data integration are basic pillars on which IM was founded with the issuance of the 2003 IM rule. As specified in Sec. 192.907(a), operators were to start with a framework, evolve that framework into a more detailed and comprehensive program, and continually improve their IM programs.\18\ Operators would accomplish this constant improvement, in part, through learning about the IM process itself and learning more about the physical condition of their pipelines via IM assessments and the development of that data. --------------------------------------------------------------------------- \18\ See 68 FR 69789. --------------------------------------------------------------------------- Data collection for new pipeline construction is relatively simple. However, collecting missing material property records for pipeline segments that have been in the ground for years can be challenging, as such data collection must be completed through integrity assessments or excavations. Operators are required to identify missing data and apply conservative assumptions, but incomplete data presents issues for risk assessment. The over-application of assumptions in the absence of real data, even if those assumptions are conservative, can lead to skewed or otherwise inaccurate risk analysis results. In the NPRM, PHMSA proposed to revise Sec. 192.917 to include specific requirements for collecting, validating, and integrating pipeline data. These requirements would add further specificity to the data integration regulations, list specific pipeline attributes that must be included in these analyses, explicitly require that operators integrate analyzed information, and require that data be verified and validated. PHMSA also proposed to require that operators use validated, objective data to the maximum extent practical. To the degree that subjective data from subject matter experts (SME) must be used, PHMSA would require that operator programs include specific features to compensate for SME bias, including training SMEs to recognize or avoid bias, and using outside technical experts or independent expert reviews to assess SME judgment and logic. Further, in Sec. 192.917(b)(3), PHMSA proposed to require operators to identify and analyze spatial relationships among anomalous information (e.g., corrosion coincident with foreign line crossings and evidence of pipeline damage where overhead imaging shows evidence of encroachment), stating that storing or recording the information in a common location, including a geographic information system (GIS) alone, is not sufficient. 2. Summary of Public Comment Many stakeholders agreed with PHMSA that verified and validated data is important for data integration and threat analysis. The NTSB expressed support for the proposed additions to the IM analysis requirements and commented that expanded pipeline record and data requirements are a significant safety improvement in the management of pipelines through their service lifecycle. However, certain [[Page 52229]] stakeholders had concerns with PHMSA's specific proposed changes. PHMSA also received comments from the industry on the feasibility of threat identification, data gathering, and integration. The American Petroleum Institute (API) stated that while the totality of attributes listed in proposed Sec. 192.917 should not pose a major burden on the industry, some specific attributes listed may not be feasible to obtain in practice. Enterprise Products stated that including just four or five attributes that point to a specific conclusion would be more useful than the lengthy list of attributes in the proposed provisions. A few com
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