May 2014, Vol. 241, No. 5


PHMSA Shifts Emphasis Toward Preventing Highest Risk Events

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

Pipeline integrity management is a hot topic. Pipeline failures, while statistically rare, can be catastrophic and have captured attention as never before. Risk tolerance for pipeline failures from existing pipelines is very low, and getting lower.

Federal, state and local agencies are focusing on pipeline integrity, and numerous pipeline safety advocacy groups are well organized and well informed – demanding ever-higher levels of performance.

The pipeline industry operates a lot of legacy pipe that was designed and built before the advent of federal pipeline safety regulations – some of those pipelines have few, perhaps no original records. Even modern pipes are subject to failures from a variety of causes. Assessment technologies to address pipe integrity issues are still being perfected. Meanwhile, populations continue to increase adjacent to pipelines, and new pipelines are being built close to existing populations.

With these trends in mind, this article helps explain the status of pipeline safety issues and initiatives at the national level. There are many regulations and other initiatives in progress to address these issues. Some changes may occur through “raising the bar” in expectations under current rules, instead of literal rule changes.

The pipeline industry is developing new “Recommended Practice for Pipeline Safety Management Systems Requirements (RP 1173),” which just underwent public review. This document will help pipeline operators demonstrate management commitment, structure safety risk management decisions, increase confidence in risk controls, provide a platform for sharing knowledge and lessons learned and promote safety culture.

At the federal Pipeline and Hazardous Material Safety Administration (PHMSA) Pipeline Advisory Committee meetings in February, Administrator Cynthia Quarterman said PHMSA’s main areas of focus in 2014 are building a public understanding of safety and safety risks, and preventing the highest risk events.

For all pipeline operators, there is an ongoing stakeholder group working on consensus definitions of pipeline performance metrics. PHMSA also intends to refine the integrity management program, often called “IMP 2.0”.

Quarterman also hinted PHMSA may use a different method for pipeline inspection going forward that would emphasize:

• Pipeline reversals and conversions, ensuring companies “know what they need to do so that releases do not happen in the future.”

• Research on cracking and seam issues, as well as other research and development programs.

• Damage prevention efforts.

PHMSA and the Occupational Safety and Health Administration (OSHA) are also working to clarify jurisdiction over midstream facilities (specifically NGL fractionation, storage and related pipe). PHMSA does not want to regulate processing units and would like to avoid overlapping regulation with OSHA, but does not want to leave any regulatory gaps.

A collection of companies have formed a working group to address these issues, and the advisory committees approved a motion supporting a subcommittee that will also look at these issues and report back.

PHMSA has shown significant interest in materials documentation and verification to support the maximum operating pressure (MOP) and maximum allowable operating pressure (MAOP) calculations for gas and liquid lines, respectively. This has been expressed in two advisory bulletins (ADB), and will likely culminate in the integrity verification process (IVP).

PHMSA issued ADB 2011-01 for gas and liquid pipeline operators on Jan. 4, 2011, which stated operators should “diligently search, review and scrutinize documents and records” to record MAOP or MOP, and that PHMSA will place emphasis on information reliability in future IMP audits. If those records are not “traceable, verifiable, and complete,” they can’t be used to justify MAOP or MOP.

If the operator isn’t “fully cognizant” of all relevant information for pipelines operating above 30% specified minimum yield strength (SMYS), they should have an “aggressive” program to obtain information, assess risks and take proper mitigation measures. If key risk factors are involved, a pressure reduction to 80% should be “strongly considered.”

This advisory bulletin created much concern within the pipeline community – especially around the definition of “traceable, verifiable, and complete.” PHMSA addressed these concerns in a May 7, 2012 advisory bulletin, ADB 2012-06, which provided additional guidance. PHMSA will give more direction about how to fill in data gaps and re-establish MAOP for operators who lack necessary documentation. Meanwhile, operators should check with PHMSA if they want to use an alternative technology to determine pipe characteristics.

ADB 2012-06 also stated that beginning with 2013, PHMSA will require gas pipeline operators to submit data to provide verification that records accurately reflect MAOP of pipelines within Class 3 and Class 4 locations and in Class 1 and Class 2 locations in high-consequence areas (HCAs) via the “Gas Transmission and Gathering Systems Annual Report.” This information will be used by PHMSA to determine their response to the National Transportation Safety Board’s (NTSB) request that PHMSA eliminate the grandfather clause and require hydrostatic testing of all grandfathered pipelines.

While data submittals are currently limited to only some gas pipelines, PHMSA said both gas and liquid owners, and operators should consider the guidance in this advisory for all pipeline segments. Every owner or operator of a pipeline must meet the recordkeeping requirements of Part 192 and Part 195 in support of MAOP and MOP determination, regardless of current reporting requirements.

PHMSA has already proposed an IVP for gas transmission pipelines with the latest official draft dated Sept. 10; development is still in progress. The IVP applies to pipe in currently defined HCAs, and to pipe in newly defined medium consequence areas (MCAs). Having only one house in a potential impact radius (PIR) will qualify as an MCA, and trigger this process. There is significant disagreement about how much pipeline mileage might be affected by this rule, and how significant the effect might be.

The IVP requires documentation of materials and pipe data – which PHMSA sees as a pre-requisite to integrity management over the long term, for every gas transmission pipe affecting an HCA or MCA. If the operator does not have design and material documentation (in accordance with 192.619(a)(1) per ADB 11-01 & 12-06), the segment, it is deemed inadequate. Required records include mill test reports (or equivalent) showing test results for chemical and mechanical properties. If records are insufficient, the operator must develop and implement a program to test pipe samples. The program should be based on a long-term statistical sampling, covering each combination of pipe type and vintage. It should use in situ non-destructive evaluation (NDE), cutouts and destructive tests, and destructive tests of pipe cutout for other reasons (such as repairs and relocations). If the data are incomplete, the operator must use conservative assumptions for evaluation of defects and repair criteria.

Under the IVP, grandfathered pipes, those with a history of materials or construction failures, or pipes with test pressures less than required by 49 CFR 619(a)(2) (or less than 125% of MAOP for legacy pipe, whichever is greater), must be replaced, de-rated or pressure tested. If the operator does not have pressure test records in accordance with 192.619(a)(2), the segment is deemed to not have a valid pressure test.

While the IVP is currently directed at gas transmission pipelines, other pipelines are likely to have a similar process soon.

For liquid pipeline operators, a rule is pending publication (ANRPM, Oct. 18, 2010) covering assessments beyond HCAs, leak detection beyond HCAs, automated valve requirements, repair criteria in HCA and non-HCA areas, stress corrosion cracking, piggability of lines, reporting requirements for gathering lines and the gravity line exemption.

For gas pipeline operators, a rule is in the works that may apply integrity management principles instead of current class location requirements in some situations [Docket No. PHMSA-2011-0023]. This would make changes to the Gas Transmission Integrity Management regulations, including expansion of integrity management requirements beyond HCAs, definition of an HCA, repair criteria for both HCA and non-HCA areas and assessment methods. Changes to valve spacing guidelines, corrosion control, and integrity management for gas gathering pipelines were included.

At the advisory committee meetings, there seemed to be consensus for a blended approach that retained class location concepts for many uses, while providing more sophisticated integrity management approaches in some locations and situations.

PHMSA is developing a notice of proposed rulemaking (NPRM), concerning rupture detection and valves. This rule would establish and define rupture detection and response time metrics, including the integration of automatic shutoff valves (ASV) and remote control valve (RCV) placement. This rule responds to requirements of the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (The Act), including:

• Section 4: ASV[automatic shutoff valve]/RCV [remote control valve] or equivalent technology be installed on newly constructed or entirely replaced natural gas and hazardous liquid transmission pipelines two years after the act was issued.

• Section 8: Require operators of hazardous liquid pipeline facilities to use leak detection systems and establish standards for their use.

• NTSB Recommendation P-11-10 (gas), which requires transmission and distribution operators to equip SCADA systems with tools to assist with recognizing and pinpointing leaks.

The Act also mandated two studies of leak detection and response, one by the General Accountability Office (GAO), and one by PHMSA. In March 2012, PHMSA commissioned the Oak Ridge Laboratory to study the ability of transmission pipeline facility operators to respond to a hazardous liquid or natural gas release from a pipeline segment located in HCAs.

During the advisory committee meetings, the Pipeline Safety Trust, a public pipeline safety organization, called for greater transparency regarding regulations, reports and spill response planning; greater public involvement in pipeline routing decisions and increased incentives to avoid populated areas; regulation of land agents; reimbursements for landowner legal fees; and different standards for the approval regarding public necessity for new pipeline projects.

Author: W.R. Byrd has been president of RCP Inc. for almost 20 years and was previously a supervising engineer at Exxon. He earned a master’s and bachelor’s degree in mechanical engineering from the Georgia Institute of Technology in Atlanta.

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