PHMSA Proposes Alternative Safety Requirements for Gas Transmission Line Segments that Experience Class Location Changes

On September 3, the Pipeline and Hazardous Materials Safety Administration (PHMSA) released a pre-publication version of a Notice of Proposed Rulemaking (NPRM), “Class Location Change Requirements,” that would permit an alternative approach to managing the safety of certain eligible gas transmission pipe segments whose class locations change from Class 1 to Class 3.  Comments on the NPRM will be due 60 days after the NPRM is published in the Federal Register. 

Background.  PHMSA’s current regulations provide that, if the class location of a gas transmission pipeline segment changes, and the hoop stress corresponding to the established maximum allowable operating pressure (MAOP) for the pipe segment is not commensurate with the present class location, the operator must confirm or revise the MAOP of the line segment.  If the hoop stress corresponding to the MAOP exceeds specified limitations, the operator must either pressure test the line to confirm MAOP, reduce the MAOP, or replace the segment. 

PHMSA’s NPRM.  The NPRM proposes an additional alternative for certain eligible gas transmission line segments whose class location changes from a Class 1 to a Class 3 and the hoop stress associated with the line’s established MAOP is not commensurate with the present class location.  Specifically, proposed new § 192.618 would allow an operator to apply integrity management (IM) based principles to certain eligible pipe segments in lieu of having to pressure test or replace the line or reduce MAOP. 

Eligible pipe segments.  A pipeline segment with any of the following characteristics would not be eligible to use the IM-based alternative:

IM-Based Alternative.  Under the proposed IM-based alternative, an operator would have the ability to designate an eligible pipe segment as a high consequence area (HCA) and include the segment in the operator’s IM program.  An operator also would be required to comply with the following additional conditions:

• Integrity Assessment.  Within 24 months of the class location change, identify and document integrity threats to the segment and conduct an initial integrity assessment with a high-resolution inline inspection (ILI) tool between the nearest upstream ILI launcher and nearest downstream ILI receiver (i.e., the ILI inspection area).

• NDE.  Conduct a non-destructive Selective Seam Corrosion (SSC) inspection any time pipe in the ILI inspection area is exposed.

• Remediation Schedule and Repair Criteria.  In the ILI inspection area, apply additional and more conservative repair criteria and comply with more aggressive remediation timelines than required under existing IM regulations.

• Pipe and weld cracking inspections.  Except for pipe with fusion-bonded or liquid-applied epoxy coatings and excavations performed under damage prevention, inspect any pipe in the ILI inspection segment that is uncovered for any reason to evaluate for cracking where coating is removed.  If cracking is found, the operator must perform an analysis in accordance with proposed revised § 192.712 and perform appropriate remediation.

• Mandatory P&M Measures.  Implement additional preventative and mitigative measures, including performing a close interval survey (CIS) every 7 years; installing at least one cathodic protection test station no more than ½ mile apart; installing line-of-sight markers; performing interference surveys; maintaining depth of cover or adding markers at locations that do not meet requirements; performing monthly right-of-way patrols; performing quarterly leakage surveys; clearing metallic shorts at shorted casings.

• Remote-Controlled or Automatic Shutoff Valves.  Ensure that mainline valves on both sides of Class 1 and Class 3 location segments, and isolation valves on any crossover or lateral pipe designed to isolate a leak or rupture in such segments, can be operated remotely or have automatic shut-off capability, with the maximum distance of 20 miles between such mainline valves.  Valves must be able to close no more than 30 minutes after a rupture, be controlled by a SCADA system, and be maintained in accordance with PHMSA’s regulations.

• Required Documentation.  Maintain records of all compliance actions for the life of the pipeline

Revisions to § 192.712.  The NPRM would amend existing § 192.712 (Analysis of Predicted Failure Pressure and Critical Strain Level) to add a provision for evaluating dents and other mechanical damage that could result in a stress riser.

PHMSA Releases Frequently Asked Questions for Gas Transmission Final Rule

On September 15, PHMSA released Frequently Asked Questions (FAQs) addressing compliance issues related to implementation of the Gas Transmission Final Rule that was adopted October 1, 2019 and amended on July 6.  The FAQs include PHMSA’s responses to public comments that were received on a draft version of the FAQs released in January.  The FAQs address a number of issues including compliance deadlines, reporting requirements, notification provisions, moderate consequence areas, spike hydrostatic testing, material verification, MAOP establishment and reconfirmation, failure mechanics, and non-HCA assessments

PHMSA has not released FAQs addressing compliance issues related to implementation of the Hazardous Liquid Pipeline Final Rule that was also issued on October 1, 2019.

PHMSA Issues Advisory Bulletins to Operators of Distribution Systems

On September 29, PHMSA issued two advisory bulletins addressing regulatory requirements applicable to inside meters and regulators and addressing the protection of low-pressure distribution systems from overpressurization.

Inside Meters and Regulators (ADB-2020-01).  This advisory bulletin reminds operators of (1) existing regulations (§§ 192.353, 192.355, and 192.357) applicable to the inspection and maintenance of inside meters and regulators; (2) the requirement to conduct leakage and atmospheric corrosion surveys of their systems, including service regulators located inside and outside buildings; and (3) the obligation under distribution IM (DIMP) to understand their systems, including the location of meters and regulators, and the responsibility to evaluate and rank the risks associated with these facilities. 

Overpressure Protection on Low-Pressure Natural Gas Distribution Systems (ADB-2020-02).  This advisory bulletin reminds operators of low-pressure natural gas distribution systems of the risk of failure of overpressure protection systems, clarifies existing pipeline safety standards, and highlights the importance of evaluating and implementing overpressure protection design elements and operational practices within their compliance programs.  In particular, PHMSA reminds operators to review their DIMPs to ensure compliance with § 192.1005 and to ensure they specifically address the risk of an overpressurization event.  PHMSA also recommends that, in addition to procedures required under § 192.605 for operations, maintenance and emergencies, operators have written procedures for all activities involving new construction or pipe replacement projects for low-pressure distribution systems.  The advisory bulletin recommends specific elements that written procedures under DIMP and § 192.605 should contain.

Status of PHMSA Rulemakings 

The chart below shows the status of PHMSA’s pending pipeline safety rulemakings as reflected in (1) the Department of Transportation’s (DOT) February Significant Rulemaking Report, (2) PHMSA’s status Chart of legislatively mandated actions (updated August 18), and (3) the Office of Management & Budget’s (OMB) Office of Information and Regulatory Affairs (OIRA) Spring 2020 Unified Agenda of Regulatory and Deregulatory Actions

Pending Final Rules

Pending Notices of Proposed Rulemakings

Pending Advance Notices of Proposed Rulemakings

Other Updates from PHMSA

PHMSA announces GPAC meeting to consider NPRM on Gas Pipeline Regulatory Reform.  On September 8, PHMSA issued a notice that the Gas Pipeline Advisory Committee (GPAC) will convene a virtual public meeting to discuss the Gas Pipeline Regulatory Reform NPRM issued on June 9.  Additional information, including how to register, is here.

Updates from Capitol Hill

Proposed legislation would authorize limited safety-enhancing test programs.  On August 21, Congressman Marc Veasy (D-TX) introduced H.R. 8085 which would authorize PHMSA to establish and implement safety-enhancing testing programs through 2026 to evaluate innovative technologies and operational practices of natural gas and hazardous liquid pipeline facilities.  

Updates from Other Federal Agencies

DOT releases guidance regarding use of revised Federal Drug Testing Custody and Control Form.  On August 31, DOT released guidance addressing changes to the revised Federal Drug Testing Custody and Control Form (CFF) recently approved by OMB.  The new CCF must be used for oral fluid specimens.  The previous CFF, approved in 2017, may be used for urine specimens until August 30, 2021. 

Updates from Industry

Pipeline Association for Public Awareness publishes updated guidelines.  The Pipeline Association for Public Awareness has released the 2020 Edition of its Pipeline Emergency Response Guidelines.  The Guidelines address different types of products and facilities; emergency preparedness; incident response steps; and security and damage prevention.  

Updates on Litigation

Pipeline employee convicted and sentenced for falsifying pipeline safety documents. On August 24, DOT’s Office of Inspector General announced that a pipeline employee was sentenced by a federal district court for falsifying documents in connection with an interstate pipeline project.  The employee created documents falsely stating that pipeline welds had been x-rayed and that the resulting exposures were acceptable.  The employee was sentenced to 36 months’ probation, 100 hours of community service, and charged a $100 special assessment.  The employee had pled guilty in June.