Pipeline Safety Alert
(by James Curry, Keith Coyle and Brianne Kurdock)
This is the last alert in a four-part Babst Calland series on PHMSA’s final rule amending the gas pipeline safety regulations at 49 C.F.R. Part 192 (Rule), published in the Federal Register on October 1, 2019. The first alert reviewed new requirements for materials verification and reconfirmation of maximum allowable operating pressure (MAOP). The second alert discussed PHMSA’s extension of integrity assessment requirements to areas outside high consequence areas (HCAs). The third alert reviewed the new recordkeeping requirements. This alert discusses the remaining rule topics: strengthening assessment requirements, extending the integrity management (IM) reassessment schedule, adding safety features to launchers and receivers, evaluating seismicity, and reporting MAOP exceedances.
Strengthening Assessment Requirements
PHMSA has incorporated a series of industry consensus standards regarding the use of in-line inspection (ILI) tools for pipeline assessments. PHMSA has also expanded the array of assessment methods that operators may use, both for covered segments in HCAs and in non-HCA areas.
What’s in the Rule?
- Incorporation by reference of NACE SP0102-2010, Inline Inspection of Pipelines, which relates to the design and construction of pipeline facilities to accommodate the passage of ILI devices, as well as the performance of ILI assessments (§§ 192.150 and 192.493). Operators may use tethered or remotely controlled tools not explicitly noted in NACE SP0102, as long as they comply with the sections of that standard that are applicable given the technology.
- Incorporation by reference of API STD 1163, In-Line Inspection Systems Qualification Standard, which sets out performance-based requirements for ILI procedures, personnel, equipment and software and ANSI/ASNT ILI-PQ, In-Line Inspection Personnel Qualification and Certification (§ 192.493).
- Operators may continue to use direct assessment (DA) for IM covered segments, but its use is now explicitly limited to those internal and external corrosion and stress corrosion cracking (SCC) threats that DA is capable of assessing (§ 192.921).
- Spike hydrostatic pressure tests can be used to assess for time-dependent threats (SCC, selective seam weld corrosion, manufacturing and related defects (pipe body and seams) and other cracks and crack-like defects) on covered segments and elsewhere (§§ 192.921 and 192.506).
- Excavation and in situ DA can be used to assess a threat on a covered segment if the selected method is capable of evaluating the threat. PHMSA lists a variety of technologies that can be used (§ 192.921).
- Guided Wave Ultrasonic Testing (GWUT) may be used for IM assessments on covered pipe without prior notification to PHMSA, and the agency has adopted a modified version of its prior guidance on GWUT as a new Appendix F to Part 192.
What’s not in the Rule?
- PHMSA struck the proposal that operators comply with both the “requirements and recommendations” of the ILI-related industry consensus standards proposed for incorporation into Part 192 (§§ 192.150 and 192.493), based on comments and a GPAC recommendation. This change allows operators to implement those consensus standards as drafted, and to use their discretion in determining whether to apply the recommendations.
- PHMSA had proposed to limit DA only to pipelines that could not be assessed with ILI, but based on industry comments and GPAC recommendations, the Agency decided to allow the continued use of DA (including on ILI-piggable lines) as long as it is suitable for the threat being evaluated.
- PHMSA rejected numerous industry comments related to ILI tool selection for specific threats and ILI tool capabilities and tolerances on the basis that these comments were out of scope.
- The Agency removed language from proposed § 192.921 that was duplicative of existing § 192.915 regarding the qualifications of persons reviewing ILI data.
Six-Month Extension to IM Reassessment Schedule
PHMSA modified its regulations to allow for the possibility of a six-month extension to the seven calendar year maximum reassessment schedule. This extension was authorized through self-executing language in the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Act). Although operators have been able to apply for an extension since 2011, PHMSA is now updating the regulations for consistency purposes. The new regulations will become effective on July 1, 2020.
What’s in the Rule?
- Operators that are unable to perform the required pipeline IM assessment on a covered segment within seven calendar years can apply for a six-month extension by providing sufficient justification in writing to PHMSA.
What’s not in the Rule?
- PHMSA did not clarify what “sufficient justification” means, but stated that “at a minimum, must demonstrate that the extension does not pose a safety risk.”
- PHMSA did not specify a processing time for these applications.
Launchers and Receivers
PHMSA added new requirements for pipeline launchers and receivers used for ILI tools and cleaning pigs. The new rule is intended to prevent inadvertent system breaches due to incorrect operation. These requirements take effect on July 1, 2021.
What’s in the Rule?
- Launchers and receivers must include a suitable means to relieve pressure in the barrel and indicate either the barrel pressure or prevent opening if the pressure has not been relieved. Most launchers and receivers are already equipped with such devices. PHMSA asserts this change is “consistent with current industry practice” and expects it will affect at most 20 of the 1,205 operators subject to the rule (§ 192.750).
What’s not in the Rule?
- Operators do not need to upgrade existing launchers and receivers now but an operator must make the modifications before using the launcher and receiver.
Seismicity and Other Threat Evaluation Clarifications
As required in the 2011 Act, PHMSA amended the requirements for the IM threat evaluation process by requiring operators to consider seismicity. PHMSA also added new requirements for pipeline segments with crack or crack-like defects and will require operators to determine if cyclic fatigue analyses remain valid on seven-year intervals.
What’s in the Rule?
- Operators must consider seismicity, geology, and soil stability when identifying potential threats to covered segments.
- Every seven years, operators are required to determine if cyclic fatigue analyses remain valid, or must be revised based on changes to operating pressure cycles or other loading conditions.
- Operators may only consider manufacturing, fabrication, or construction (MFC) defects as stable threats if the covered segment has been subject to a hydrostatic pressure test of 1.25 times MAOP and has not experienced a reportable incident due to a MFC defect since that pressure test. If the segment has experienced a reportable incident, the operator must prioritize the segment for baseline assessment or reassessment.
- Operators must evaluate and remediate, if necessary, all similar pipeline segments if a crack or crack-like defect on a covered pipeline is identified.
What’s not in the Rule?
- PHMSA deleted the proposed reference to the MAOP reconfirmation requirements for pipeline segments with MFC threats that have experienced a reportable incident, an MAOP increase, or an increase in stresses leading to cyclic fatigue. Instead, PHMSA has referenced the new fracture mechanics requirements.
- PHMSA did not agree with industry comments and a GPAC recommendation to consider removing “hydrostatic” and allow other testing media in § 192.917(e)(3) for evaluating MFC threats. PHMSA observed that such change would be contrary to a National Transportation Safety Board recommendation that MFC threats can only be considered as stable threats if the pipeline segment had a hydrostatic pressure test of at least 1.25 times MAOP.
Reports of MAOP Exceedances
PHMSA amended the safety-related condition reporting requirements by adding a reporting requirement for owners and operators of gas pipeline facilities that exceed their MAOP beyond the build-up allowed for the operation of pressure-limiting or control devices. The change updates the regulations to reflect the self-executing provision in the 2011 Act and add detail on how to make the report. PHMSA first notified operators about the requirement in 2012 in Advisory Bulletin ADB-2012-11. This requirement will take effect on July 1, 2020.
What’s in the Rule?
- Operators of transmission pipelines must make a report of each MAOP exceedance to PHMSA within 5 business days and will not be able to use the exceptions from reporting listed in § 191.23(b).
In contrast, as required by current regulation, operators of gathering or distribution pipelines, LNG facilities, or underground natural gas storage facilities must report pressure exceedances due to malfunctions or operating error. However, operators of those pipelines will have 5 to 10 days to report, as opposed to 5 days, and may use the § 191.23(b) exception to reporting, if applicable.
