Final Rule: Safety of Gas Transmission Pipelines, MAOP Reconfirmation, Expansion of Assessment Requirements and Other Related Amendments

[Docket No. PHMSA–2011–0023; Amdt. Nos. 191–26; 192–125] RIN 2137–AE72

The long-awaited first of three gas transmission and gathering pipeline rulemakings was published in the Federal Register on October 1, 2019.  This rulemaking addresses several congressional mandates dating back to the 2011 reauthorization legislation, and addresses several NTSB recommendations following the PG&E San Bruno accident.  The effective date of the rule is July 1, 2020, with several requirements that extend out as much as 15 years to complete.  This is a significant rulemaking with a lot to digest, but we have tried to provide a brief summary of the highlights below.  For more information about how RCP can assist pipeline operators with integrating these new rules into your existing operations and integrity programs, contact Jessica Foley.

• New Definitions for Moderate Consequence Area (MCA) and Engineering Critical Assessment (ECA)
• Expansion of pipeline integrity management requirements beyond High Consequence Areas.
  • Applicable to onshore gas transmission lines with MAOP > 30%SMYS and located in a class 3 or 4 location, or within an MCA. An MCA is an onshore area that is within the potential impact circle, containing either:
    • 5 or more buildings intended for human occupancy, or
    • any portion of the paved surface of an interstate, freeway, expressway, or principal arterial roadway with 4 or more lanes.
  • Operators must assess the integrity of these segments by July 3, 2034 and periodically assess these segments every 10 years after the last assessment. 
• Methods for material verification
  • New section §192.607 lists the requirements for physical material properties (e.g., diameter, wall thickness, seam type, grade) for pipelines that do not have traceable, verifiable, and complete (TVC) records.
  • Allows for destructive and non-destructive means to obtain material properties.
  • Allows operators the choice of capturing these records through:
    • in situ examinations during excavation activities as opportunities present themselves (e.g., anomaly direct exams, repairs, replacements and relocations),
    • through a more prescriptive approach for sampling multiple segments of pipe sharing similar physical properties, or 
    • by submitting a written request to PHMSA for using an alternative method and proceeding forward if no objection letter is received from PHMSA within 90 days.
  • Records established must be maintained for the life of the pipeline and be TVC.
• MAOP reconfirmation
  • Reconfirmation of gas transmission MAOP for either of the following pipelines:
    • pipelines without TVC records necessary to establish MAOP, located within an HCA or a class 3 or 4 area.
    • “grandfathered” pipe with an MAOP > 30% SMYS located within an HCA, or a class 3 or 4 area, or an MCA capable of inspection by in-line inspection.
  • Operator have until July 3, 2028 to reconfirm MAOPs  for 50% of their affected mileage and until July 2, 2035 to reconfirm MAOP for 100% of their affected mileage.
  • Operators have six options to reconfirm MAOPs:
    • Subpart J pressure test with material verification at test head cutout locations,
    • Pressure reduction from highest sustained pressure from previous 5 years, divided by 1.25 or higher class location factor,
    • Engineering Critical Assessment,
    • Pipe replacement,
    • Pressure Reduction for Pipe with PIR < 150’, from highest sustained pressure from previous 5 years, divided by 1.1, or
    • Submit written request to PHMSA for use of alternative method and proceed forward if no objection letter is received from PHMSA within 90-days.
• Engineering Critical Assessment for MAOP Reconfirmation
  • §192.632 describes the prescriptive and data intensive processes required for an operator to follow if they chose to perform an ECA to reconfirm MAOP under §192.624.
• Analysis of Predicted Failure Pressure
  • §192.712 describes the process that an operator must take to determine the predicted failure pressure of a specific anomaly or defect as well as the remaining life of the pipeline segment at the location of the anomaly or defect.
• Recordkeeping Requirements for Gas Transmission Pipelines
  • Operator will be required to maintain records for:
    • Current class location,
    • Pipe design and material properties,
    • Component pressure rating (greater than 2 inches),
    • Welder qualification must be retained for a minimum of 5 years, and
    • Plastic pipe joining qualifications at the time of pipeline installation must be retained for a minimum of 5 years.
• Spike Testing
  • §192.506 describes the process required for operators who choose to perform a spike test to assess time dependent threats (stress corrosion cracking, selective seam weld corrosion, manufacturing defects, cracks and crack-like defects).
• Reporting MAOP exceedances
  • Usage of the safety-related condition report form to report MAOP exceedances within 5 days of the exceedance occurrence.
• 6-month grace period for 7-year gas transmission integrity reassessment intervals with written notice to the Secretary, with sufficient justification of the need for the extension.
• Consider Seismicity as a risk factor in integrity management
• Safety Requirements for In-line inspection launchers and receivers

PHMSA anticipates completing a second rulemaking to address the topics in the NPRM regarding repair criteria in HCAs, the new repair criteria for non-HCAs, pipeline inspection following extreme events, pipeline corrosion control updates, management of change process, clarification of certain other IM requirements, and strengthening IM assessment requirements. A third rulemaking is expected to address new requirements for gas gathering lines.  Stay tuned for those to be published in the federal register, possibly within the next year.