January 2017, Vol. 244, No. 1


Understanding PHMSA’s Proposed Expansion of MAOP Verification

By Daniel Thayer, Jacob Greenfield and Courtney Tripp

U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a notice of proposed rulemaking (NPRM) on April 8, published in Federal Register Vol. 81, No. 68, which outlines significant changes to the Pipeline Safety Regulations to increase the safety of onshore natural gas transmission and gathering pipelines across the country.

One of the most significant areas of these changes, which would bring with it far-reaching effects for owners and operators, focuses on maximum allowable operating pressure (MAOP) and pipeline material verification.

Tulsa, OK-based Shafer, Kline & Warren’s (SKW) Daniel Thayer, who heads an Integrity Management team, explains that understanding the forthcoming changes and how to address them proactively should be an essential part of operations and maintenance plans moving forward.

When approaching MAOP validation, Thayer breaks it into a two-part process. The first step is materials validation as part of 49 CFR, Part 192. For this, a design formula is used that accounts for the pipeline’s specified minimum yield strength (SMYS), wall thickness and diameter multiplied by the class location factor, which is based on population density and the number of residents living within close proximity of the pipeline. PHMSA’s Advisory Bulletin AD-12-06 published in Federal Register Vol. 77, No 88, on May 7, 2012, reminded operators to verify that their records are traceable, verifiable and complete.

During the second step, hydrostatic testing or other approved methods must be used to validate the lengths of pipe that have missing information, such as missing mill test report (MTR) data that provide information used in the design formula.

“During the first step we go through the records to identify gaps, and show that the parameters used in the design formula were accurate and support the pipeline’s current MAOP,” said Thayer. “The second step is really about proving the pipe through a PHMSA-approved method, the most common of which is hydrostatic testing.”

Case Study: Permian Basin

Thayer and Jacob Greenfield, SKW project manager for pipeline integrity, were contracted to complete records review, integrity assessment and MAOP validation for a larger gathering and midstream company in the Permian Basin.

“When reviewing their record books, we started with the weld tally, because generally, that’s the most accurate place to start if no as-builts are available,” said Greenfield. “In this case, the weld tally contained the heat number for the pipe. We then matched the heat number to the mill test reports (MTR) that were available.”

As Greenfield completed the records review, he discovered some gaps in the data, including pipelines with partial records, and in one case, a section of the pipeline that had no records. Often when assets are acquired through mergers and acquisitions, it can result in missing or incomplete records.

Based on this comprehensive records review, Greenfield and Thayer put together a series of recommendations for sections of pipe that require hydrostatic testing to validate the MAOP and which would require positive material identification (PMI) completed to determine the pipe strength.

“As part of their annual integrity management program, the company was already scheduled to complete inline integrity inspection (ILI) for a 6-inch pipeline that was missing MTRs and hydrostatic testing records, so we recommended they complete the integrity assessment before hydrostatic testing the pipe,” said Thayer. “Through the ILI, we identified a number of problems with this pipeline. We then used direct assessment of the pipeline and non-destructive examinations to further assess the corrosion on the pipe.”

Where the corrosion was found to be severe, the pipeline was repaired. Then, after the repairs were complete, hydrostatic testing was completed to establish the MAOP for the pipeline.

In some cases, PMI is used to verify materials. Thayer and Greenfield are experienced with project managing the optical emissions spectrometry (OES) to assess the elemental composition of the pipeline, which determines the grade and strength of the pipe. In this case, SKW’s team provided the engineering, calculations and project management for the required ILI and hydrostatic testing.

“Hydrostatic testing is complex in and of itself,” said Thayer. “Elevation is a significant factor. The pressure at the top of a hill is not going to be the same as at the bottom. The required pressure – 125% of MAOP – needs to be the pressure at the highest elevation of the pipeline for the eight hours of the test. You have to account for the loss of pressure caused by elevation when designing and monitoring the hydrostatic test.”

The assessment and validation process for this project is still ongoing, and there are other pipelines that need this same process completed because of varying degrees of inadequate or incomplete records.

“When assessing our records review and documentation to identify the pipeline sections that will need ILI, hydrostatic testing or PMI, the pipeline owners and operators generally prioritize testing and assessment based on production impact,” said Greenfield. “If the section is a large, main artery of the pipeline system, that section becomes a higher priority.”

In places where the population is high enough for the area to be considered a high-consequence area (HCA), PHMSA’s regulations include a requirement that if the pipe grade is unknown, the company must operate the pipeline at a lower design pressure based on 24,000-psi specified minimum yield strength (SMYS).

Testing, Assessment Expansion

Pipelines that were installed before 1970 can rely upon a grandfather clause that allows for the operation of the pipeline at the highest pressure it was operated at during the five years prior to 1970 without hydrostatic test records. In the April NPRM, it is recommended that the grandfather clause be eliminated. According to PHMSA, about 60% of natural gas transmission pipeline mileage was installed prior to 1970.

“The operating pressures that these pipelines are operating at under the grandfather clause may not have ever been substantiated,” said Thayer. “If that clause disappears as PHMSA is recommending, it will affect a large number of owners and operators who are going to need to prove these pipelines through hydrostatic testing or other methods approved by PHMSA.”

Another recommended change is the definition of moderate consequence areas (MCAs). Pipelines in the newly defined MCAs would be required to complete integrity assessments in addition to the HCAs. HCAs are subject to comprehensive integrity management regulations, and are defined as pipeline segments with 20 or more buildings intended for occupancy within the impact radius of the pipeline, which is calculated based on the pipeline’s diameter and MAOP. MCAs would be calculated using the same formula except the threshold would be five buildings, rather than 20.

According to the NPRM, “The intention is that any pipeline location at which persons are normally expected to be located would be afforded extra safety protections.” This would include periodic integrity assessment, reliable, traceable, verifiable and complete materials documentation, and MAOP verification.

The final two areas of regulatory expansion related to MAOP are the recommended addition of a spike test as part of the hydrostatic testing requirement and the application of transmission line MAOP regulations to certain gathering lines.

“The impacts of these regulations are far reaching, and, if enacted, may tax the capabilities of the integrity management industry as we work to meet the needs of pipeline operators,” said Thayer. “There will likely be a cost to waiting. As the demand for hydrotests and records validation increases, so may the cost of these services. By taking a proactive approach to these proposed changes, operators will avoid these market pressures while protecting themselves against regulatory enforcement as well as dangerous, costly pipeline incidents.”


Authors: Daniel Thayer is Shafer, Kline & Warren’s team leader of integrity management. He is a certified NACE Cathodic Protection Specialist – Level 4 with over 15 years of extensive industry experience in corrosion control, pipeline integrity and project management. Thayer is well-versed in all aspects of cathodic protection, pipeline integrity, design and installation. Before joining SKW in 2010, he managed multiple pipeline cathodic protection-related projects while serving as a member on an integrity management team during a natural gas distribution system troubleshooting project.

As a project manager, Jacob Greenfield works closely with clients and Shafer, Kline & Warren’s pipeline integrity team to implement integrity management for distribution, transmission, midstream, exploration and production companies. His expertise is in cathodic protection testing and troubleshooting, pipeline regulations, industry safety standards, integrity assessment and repair methods. He also understands the importance of accuracy in developing assessment and rehabilitation programs and procedures, and project management. Jacob is certified as a NACE Cathodic Protection Technician – Level 2.

As content marketing specialist, Courtney Tripp focuses on telling the stories of the surveyors, engineers and technicians at Shafer, Kline & Warren whose work helps make everyday life better, easier and safer in communities large and small. Tripp has a bachelor’s in journalism and a master’s degree in mass communication. She has been working in the marketing and public relations field for more than 10 years.

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