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DOT Pipeline Compliance News
April 2016 Special Edition

Proposed Gas Mega-Rulemaking (4/8/2016)
[Docket No. PHMSA-2011-0023 RIN 2137-AE72]

Clocking in at 135 pages of tiny type in the Federal Register, the NPRM published on April 8, 2016, is one of the most significant proposals that PHMSA has made in many years. One quarter of those pages are actual revisions or additions to existing text (33 FR pages!). The potential ramifications from this rule are hard to explain or predict, and the relevant trade associations are burning the midnight oil to prepare their comments (and file extensions). Your humble newsletter editor makes no claim to having a broad or deep understanding of all the potential issues surrounding this proposed rule. The rule might be described as "everything anyone at PHMSA has ever wanted to change in the gas pipeline regulations, but was afraid to ask."

As always, this is an abbreviated version which is no substitute for the original. That being said, below is our attempt to lay out the proposal and explain some of the issues, in a simple fashion and much less than 135 pages. I've put it in an outline, shorthand form to save space and hopefully make it easier to follow. Use at your own risk. Citations to the relevant proposed rule paragraphs are given in [brackets] for ease of reference. Enjoy!

Gathering and Production Jurisdiction Will Change
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  • RP80 will no longer be incorporated, and relevant definitions will be added to the rule including Gathering Line (onshore), Gas Processing Plant, Gas Treatment Facility, and Onshore Production Facility / Operation. [192.3 and .7]
    • Production will end at farthest of the last meter used for production allocation, or comingling.
  • Gathering lines with diameters >= 8” and >=20% SMYS in Class 1 areas would become regulated as Type A, Area 2 (a new classification). Type A, Area 2 must (mostly) meet the requirements for Type B lines, with 2 years to comply. [192.8]
    • Operators will be required to document the beginning and endpoints of each non-regulated and regulated gathering line in 6 months.

MCAs will be Defined
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  • Moderate Consequence Area = 5 structures, an occupied site (5 people in a structure for 50 days over 12 months, or 5 days a week for 10 weeks a year), or a major road crossing within the PIR. [192.3]

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  • New Appendix A, with detailed record retention requirements.
  • Add “Reliable” to the mix of Traceable, Verifiable, and Complete (TVC) records, which would become RTVC. This RTVC standard would apply to “records that demonstrate compliance with this Part” (i.e. ALL of Part 192!!!). [192.13(e)]
  • More records for class location determinations (for life!), steel pipe manufacturing, welder qualifications, pipe design, and pipeline components, including the specification in effect at the time of construction.… for ALL transmission pipelines. [192.5; .67; .127; .205; .227(c); and .285(e)]

More things will be required, period.
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  • The proposed rule will add definitions for close interval survey, dry gas, hard spot, in line inspection, in line inspection tool, legacy construction techniques, legacy pipe, “significant” seam cracking and stress corrosion cracking, wrinkle bend, and more! [192.3]
  • Over-pressure events will by definition be reportable Safety Related Conditions. [191.23]
  • ALL gathering, regulated and not, will be required to report under Part 191.1, but will not be required to report to NPMS. [191.1 and .29]
  • Repairs for transmission lines outside HCAs are much more prescriptive, with immediate, two-year, and monitored conditions [192.711 and .713]
  • Class 1 test factors will go from 1.1 to 1.25 [192.619(a)(2)]
  • Corrosion control requirements will change, including
    • Determining adequate CP [192.465]
    • Detecting coating damage after construction [192.319(d) and .461(f)]
    • Minimizing interference currents [192.473]
    • Detecting potentially corrosive gas [192.478]
    • Methods to evaluate general corrosion damage [192.485(c)]
  • Several ILI standards are incorporated by reference, including: API STD 1153-2005, NACE SP 0102-2010, 0204-2008, and 0206-2006, and ANSI/ANST ILI-PQ-2010. [192.7 and .493]
  • Management of Change will be required for ALL onshore transmission! [192.13(d)]
  • Severe weather = 72 hours for an evaluation. [192.613(c)]
  • Pressure relief systems for all pig traps. [192.750]
  • Guided Wave Ultrasonics (GWUT) - Prescriptive details on how to use. [New Appendix F]

Material Verification [new 192.607]
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  • Verify material properties in HCAs and Class 3 and 4, if not RTVC.
    • A LOT of tests will be required, perhaps during normal excavation, and even more if some give inconsistent results.
    • 180 days to develop the materials documentation plan, but no deadline to actually complete all the tests.

MAOP Verification [new 192.624]
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  • Verify Segment MAOP in HCAs and Class 3 and 4, if:
    • Segment pressure test records are not RTVC.
    • Segment has had any reportable incident after a SubPart J pressure test from a construction or material threat, or cracking (including segments in piggable MCAs).
    • MAOP is grandfathered per 192.619(c) (including segments in piggable MCAs).
  • Develop a plan in 1 year, complete 50% of affected mileage in 8 years, and 100% in 15 years.
    • Use pressure tests, pressure reductions, ECA (very prescriptive process), pipe replacements, or alternative technology that receives a letter of “no objection” from PHMSA.
  • If cracking is a threat on ANY segment (regardless of HCAs, etc.), a detailed and statistically valid fracture mechanics evaluation must be conducted, using conservative material property assumptions.
    • If calculated remaining life is less than 5 years, must pressure test or drop pressure in 1 year.
    • Otherwise, keep re-evaluating life at 50% of estimated remaining life, and decide if pressure tests are needed.

More things will be required inside HCAs [SubPart O]
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  • Additional, prescriptive risk assessment / data integration requirements.
  • Can’t assume a manufacturing or construction defect is “stable” if there has been that type of failure since the last pressure test.
  • More criteria on the use of Direct Assessment methods.
  • More immediate and 1 year repair conditions.
  • Additional P&M measures are identified, and including several that are mandated regarding internal and external corrosion.

Integrity Assessments beyond HCAs
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  • Spike pressure tests will be required for ALL transmission pipelines that operate at more than 30% SMYS and have integrity threats that can’t be addressed by other means [192.506]
    • Spike to the lesser of 150% of MAOP or 105% SMYS.
    • Must calculate a re-test interval, and spike test again and again...
    • Can use alternative technologies if PHMSA gives "no objection" letter
  • Assessments for Class 3, 4, and piggable MCAs that aren’t already HCAs [192.710]
    • >=30% SMYS: assess for every threat, with lots of technology options
    • Less than 30% SMYS: assess for internal and external corrosion
    • An expert has to evaluate the assessment, and consider statistical variation while using RTVC records about the pipe and material properties.
    • 15 year initial assessment period, 20 years thereafter.

Shameless Marketing Plug
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As always, we will be happy to consult with your company to explore any specific issues that you might have. Jessica would love to hear from you! jfoley@rcp.com.

Gas Pipeline "Mega-Rule" NPRM Overview Session

This overview session will cover the proposed changes and their potential impact, and provide participants with the opportunity to discuss those changes and to decide how their company should proceed. This session will be held on April 20, 2016 (Wednesday) from 12:30PM – 4:00 PM (Central Time) at RCP's corporate office. The cost to attend is $195/attendee. Registration can be found on RCP's training webpage.

We would welcome the opportunity to discuss our services with you.

Best Regards,

W. R. (Bill) Byrd, PE
RCP Inc.



About RCP
RCP is a registered professional engineering corporation staffed by more than 50 energy pipeline experts with extensive experience in energy pipeline risk management and regulatory compliance issues. Since 1995, RCP has assisted companies and organizations of all types and sizes, including every pipeline operator in the Forbes 500 down to small municipal operators, with the challenges of energy pipeline and terminal regulatory compliance and integrity management at the federal level, in every state, and in several foreign countries. Our personnel have experience as operators, engineers, and managers, and participate at the highest levels of the gas and liquid energy pipeline industry by serving on technical research committees and developing industry standards. RCP also offers pipeline integrity and corrosion control consulting services by providing operational support and program implementation management services, including selection, contracting, and management of subcontractors in the field to implement the required program activities for corrosion control, in-line inspection, direct assessment, and more. RCP has the perfect team to support your pipeline integrity and compliance requirements - from initial consulting, to program development, to implementation and final analysis of a broad range of pipeline regulatory compliance and integrity management issues.

For more information, please contact Jessica Foley at 713-655-8080 or visit www.rcp.com.

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