DEPARTMENT OF TRANSPORTATION BEFORE THE PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION

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1 DEPARTMENT OF TRANSPORTATION BEFORE THE PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION Pipeline Safety: Public Workshop on ) Integrity Verification Process ) Docket No. PHMSA ) COMMENTS OF THE AMERICAN PETROLEUM INSTITUTE AND THE ASSOCIATION OF OIL PIPE LINES The American Petroleum Institute (API) 1 and the Association of Oil Pipe Lines (AOPL) 2 are pleased to offer the following comments on PHMSA s draft Integrity Verification Process, or IVP, for natural gas transmission pipelines. The comments supplement the presentation of David Ysebaert, President and CEO of Explorer Pipeline, made on behalf of API and AOPL at the August 7, 2013 Pipeline and Hazardous Materials Safety Administration (PHMSA) workshop in Arlington, VA. They also reiterate many of the points made by industry members of PHMSA s technical advisory committees at their August 8 & 9, 2013 meeting. Our members welcome the opportunity to review and comment upon the natural gas pipeline proposal given their desire for feasible, practical and affordable regulations that promote pipeline safety. I. Shared Commitment to Pipeline Safety Operators of our nation s liquid pipelines share PHMSA s goals of promoting pipeline safety. Member companies of API and AOPL gather regularly and frequently to advance pipeline safety initiatives. A snapshot of the next couple of months provides a window into the extensive efforts of the liquid pipeline industry to improve safety performance. In early- September, pipeline integrity and operations/engineering managers gathered in Washington, DC to exchange safety learnings and experiences through API s Pipeline Integrity Work Group and 1 API is the only national trade association that represents all aspects of America's oil and natural gas industry an industry which supports 9.2 million American jobs and 7.7 percent of the U.S. economy. API s more than 500 corporate members, from the largest major oil company to the smallest of independents, come from all segments of the industry. They are producers, refiners, suppliers, pipeline operators and marine transporters, as well as service and supply companies that support all segments of the industry. 2 AOPL is a national trade association that represents owners and operators of oil pipelines across North America and educates the public about the vital role oil pipelines serve in the daily lives of Americans. AOPL members bring crude oil to the nation s refineries and important petroleum products to our communities, including all grades of gasoline, diesel, jet fuel, home heating oil, kerosene, propane, and biofuels. Together, AOPL and API members operate approximately 90% of the hazardous liquids pipeline miles in the United States. 1

2 Operations and Technical Group (OTG). In mid-september, integrity staff from pipeline operators will gather in Houston, TX for industry-wide discussions of the latest technology and techniques to discover and diagnose cracks in pipelines. In late-september, liquid pipeline representatives will join representatives from natural gas transmission and distribution operators, federal and state pipeline safety regulators, and pipeline safety advocates in Washington, DC to continue joint development of a Recommended Practice for Pipeline Safety Management Systems as recommended by NTSB. In early-october, OTG will host its annual Pipeline Information Exchange conference in Houston, TX to discuss incidents, near misses and lessons that can be shared and learned from to improve pipeline safety. Immediately following PIX, risk managers will participate in a workshop to share information on data integration and risk to help operators improve how they identify and address pipeline threats. Also in mid-october, liquid operators are participating in workshops to improve liquid pipeline Public Awareness Programs, excavation damage prevention, and control room management across the industry. At the end of October, the Data Mining and Performance Excellence Teams of pipeline managers will gather in Houston, TX to review industry performance data, damage prevention and safety culture efforts. Pipeline operators also welcome opportunities to support PHMSA efforts to improve pipeline safety. Last year, pipeline operators supplied comments to PHMSA on how it could meet its Congressional mandate to analyze the feasibility and effectiveness of leak detection and automated valve technology. In these and other areas, the practical, real-world experience of pipeline operators support PHMSA's goal of regulations and requirements that improve pipeline safety performance. II. Congressional Mandate on Natural Gas Pipelines PHMSA now faces a requirement under the 2011 Pipeline Safety, Regulatory Certainty and Job Creation Act to verify the maximum allowable operating pressure (MAOP) of natural gas transmission pipelines. Section 23 of the 2011 law directs PHMSA specifically regarding "gas" pipelines, both interstate and intrastate, to confirm their operating pressures either through documentation or testing. The legislative history of this provision and the policies discussed during its debate reflect the focus on gas pipelines. Coming after investigation of the San Bruno, CA natural gas tragedy revealed inaccurate and incomplete documentation of that pipeline, attention turned to the so-called "grandfather" clause, which since 1970 has exempted some natural gas pipelines from pressure documentation and testing requirements. Section 23 now requires PHMSA to close this natural gas grandfather exemption. However, no such grandfathering exists for liquid pipelines. The pipeline pressure verification goals Congress mandates and PHMSA now proposes for gas pipelines were accomplished by regulation of liquid pipeline operators 15 years ago. In 1998, PHMSA amended section of the Code of Federal Regulations to require liquid pipeline operators 2

3 to pressure test their liquid pipelines or perform a risk-based engineering assessment of their pipelines to set an appropriate maximum operating pressure (MOP). III. Positive Elements of PHMSA's Proposal Liquid pipeline operators appreciate the range of options PHMSA proposes to confirm a pipeline's MAOP. PHMSA would allow operators to choose between hydrotesting, pressure reduction, or engineering critical assessment (ECA). Liquid pipeline operators support PHMSA's recognition that hydrotesting is not the only acceptable method to assess pipelines. In many cases, hydrotesting, especially with a spike test, is unnecessarily disruptive, costly or damaging to pipe. Alternative methods will meet the pressure verification goals of this mandate without disrupting supplies to customers, imposing unnecessary costs that could ultimately fall on consumers, or causing damage to the pipe from the test itself. Liquid pipeline operators also commend PHMSA's inclusion of an engineering critical assessment in the range of options. An engineering assessment allows for consideration of all the factors relevant to a pipeline's integrity including its physical and operational characteristics. Federal regulations for liquid pipeline pressure verification, as noted above, already utilized a risk-based engineering alternative to confirm the maximum operating pressure of pre-regulation liquid pipelines. It is appropriate that PHMSA include this option for gas pipelines. IV. Scope and Process Concerns with PHMSA's Proposal As discussed above, Section 23 mandates that PHMSA require gas pipeline operators to verify documentation of the maximum allowable operating pressure (MAOP) of their gas transmission pipelines, and where documentation is inadequate, reconfirm or establish the MAOP through testing. Section 23(d)(1) expressly specifies testing shall cover pipelines located in high consequence areas (HCA). However, PHMSA's IVP proposal exceeds this mandate by covering pipelines in a broader, newly created and undefined moderate-consequence area (MCA). Congress mandated creation of the HCA threshold at 49 USC It appropriately addresses areas with dense populations, commercially navigable waterway crossings, or unusually sensitive environmental areas. PHMSA promulgated the pipeline integrity management program and regulations using HCAs and pipeline operators have operated under this system for over 10 years. Similarly, PHMSA's pipe strength requirement exceeds both the specific language and intent of the law. Part 192 Section 23(d)(1) imposes a testing requirement on pipelines operating at a pressure greater than 30 percent of the specified minimum yield strength (SMYS) of the pipe. Contrary to this express language, PHMSA proposes testing requirements on pipelines operating at a lower 20 percent of SMYS, or even lower in additional ill-defined circumstances. The Congressional intent of this section is to guard against operating pipelines at a pressure so high they pose a public safety threat. PHMSA's inclusion of low-stress pipelines is contrary to this intent and diverts valuable attention and resources away from the greatest threats to public safety. 3

4 Not only do the individual MCA and 20% SMYS requirements exceed the express Congressional mandates of Section 23, their usage by PHMSA as additional requirements even after an operator verifies its pressure documentation also exceeds the Section 23 mandate. Subsection 23(c) mandates PHMSA require only those operators with insufficient records under 23(b)(1) to reconfirm their MAOP. Similarly, Section 23(d) mandates only those operators of previously untested pipelines to conduct tests to confirm the material strength of those pipelines. Nevertheless, PHMSA s IVP proposal requires operators with verified documents for pipelines that were not grandfathered from pressure testing to still in some circumstances perform additional pressure testing, pressure derating or engineering critical assessments. Criteria for additional testing include previously undefined conditions discussed further below, specified maximum yield strength below the express threshold set in Subsection 23(d), or in the MCA area previously undefined or authorized by statute or regulation. PHMSA's creation of requirements outside the express scope of Section 23 and imposition of these additional requirements even when pressure documents are verified suggests that PHMSA is seeking to address broader integrity management (IM) program issues through this IVP proposal. The IM program has been PHMSA's and the pipeline industry's core, fundamental pipeline safety program over the last ten years for pipelines operating in or near areas with high population and/or sensitive environmental features. Liquid pipeline operators spend over $1 billion a year evaluating, inspecting and maintaining their pipelines under the IM program. While IM applies to HCA pipe, this represents tens of thousands of miles of pipeline, years of planning and extensive organizational, financial and personnel commitment. Pipeline operators understand that PHMSA has a separate mandate from Congress under the 2011 reauthorization law to review and report on the IM program. Pipeline operators look forward to working with PHMSA in areas of potential improvement to the IM program through PHMSA s upcoming IMP 2.0 update process. However, any changes to this broad, complex and vital program should come only after thorough, open and inclusive analysis, discussion and exchange on how to make appropriate improvements. 3 An unnecessarily broad or complex PHMSA gas pipeline IVP proposal would almost certainly delay eventual finalization and adoption of the IVP program. Delay would be less likely with a simpler, more narrowly focused process. At the highest level, PHMSA can begin the process of reducing confusion and controversy over this proposal by abandoning the misleading Integrity component of the Integrity Verification Process proposal title. As discussed above, Congress through Section 23 mandated that PHMSA implement a program to confirm maximum allowable operating pressures, not the full, cyclic management of pipeline integrity. Integrity should be removed from the title and replaced with a different descriptor, such as Pressure, that is more indicative of what Congress is requiring PHMSA and operators 3 Of course, any requirements that would effectively expand the pipeline safety regulation must be proposed clearly and subjected to full prior notice and comment rulemaking procedures, as outlined in the Administrative Procedure Act. See 5 U.S.C

5 to verify. As stated above, liquid pipeline operators look forward to discussing appropriate IM program improvements with PHMSA through the upcoming IMP 2.0 process. With concerns about overly complicating or expanding the scope of Congress original mandate raised, liquid pipeline operators do recognize the current regulatory climate may suggest to PHMSA a practical strategy of packaging multiple efforts into a single notice and comment proposal. If PHMSA pursues a multi-element package that includes a pressure verification program under Section 23, liquid pipeline operators recommend that PHMSA keep distinct and focused the individual components of the proposal with separate and defined justifications, programmatic purposes and operational considerations. This will allow discussion of the merits of each component based on the programmatic goals and needs of each component. This will also prevent adoption through the IVP proposal of inappropriate or misplaced requirements. V. Technical Concerns with PHMSA s Proposal As touched on above, the inclusion of an IVP screening step focusing on low stress pipelines seems misplaced as it fails to recognize the relatively low risk associated with these lines. Manufacturing defects that lead to failures are highly stress-dependent, which also argues for less focus on low stress lines. The inclusion of a requirement to sample and test pipe for any system for which operators cannot demonstrate complete materials records by today s measures is not reasonable or necessary. This should only be a consideration for operators that may need to verify their operating pressure and choose to use an ECA approach. If an operator uses hydrotesting, pressure reduction or replacement for pressure verification, then cut-out sampling and testing would be unnecessary and a waste of resources that could be better applied to other safety activities. The proposed process suggests that a spike test in addition to what is currently required for pre-commissioning hydrotesting of pipelines be employed to verify operating pressure. 4 The use of a spike test to assess/address particular anomalies in the context of an operator s IMP may be appropriate, but is of little value in verifying safe operating pressure across the board. This is another area where PHMSA can focus the IVP proposal on the most appropriate methods of pressure verification and leave integrity management techniques to more appropriate IMP discussions and debates. As stated in Section 23(a)(2), the purpose of the documentation is to ensure that the records accurately reflect the physical and operational characteristics of the pipeline and confirm the established maximum allowable operating pressure of the pipelines. PHMSA s 4 This was part of NTSB s recommendations to PHMSA. While such recommendations should be thoroughly considered, there does not appear to be a good engineering basis for this particular recommendation. 5

6 proposal does not reflect a measured or substantive analysis of which documents are necessary to achieve these goals and at what point additional documents are unnecessary to further this goal. Instead, PHMSA appears to require in all cases use of design pressure material records, Subpart J records, historical operating pressure (including Subpart K uprate) records and records of operator analysis of segment history, regardless of whether each of these records are actually needed or useful to verify operating pressure for a particular segment. Some combination of each or several of these types of records may be appropriate for a given pipeline segment. On the other hand, a single record, such as records from a pressure test, could be sufficient to verify MAOP. Current regulations rightly recognize that different categories of documents may themselves be sufficient to establish MAOP. VI. Points for Clarification API and AOPL respectfully request that PHMSA clearly define the meaning of certain terms employed in the draft process. [L]egacy problematic pipe and legacy problematic construction methods are not defined in the regulations and are given only cursory treatment in what has been presented to-date. API and AOPL suggest that PHMSA attempt to use terms that are already defined in regulations, codes and standards (e.g., susceptible pipe ). As previously noted, material testing should only be required in the context of an ECA. Alternatives to cutting out and testing pipe are needed. There are in-the ditch tests to determine yield strength, wall thickness and diameter can be determined from internal inspection data, and coating effectiveness can be determined by cathodic data analysis. Any of these should be acceptable methods to acquire this data. Whatever methods are employed should be documented and available data integrated through the ECA process. One of the alternatives allows an operator to derate (lower the operating pressure) of the pipeline. Although not explicitly stated by PHMSA, API and AOPL presume a derate to 80% of the highest operating pressure experienced by the pipeline is intended as this provides a level of conservatism equivalent to a hydro test pressure of 125% of MOP. This provides an additional conservative margin of safety in addition to what is presumably already 72-80% of specified minimum yield strength. In fact, this is the same margin provided by a hydrotest relative to maximum operating pressure for liquid lines. Similar to the introduction of the IMP regulation to existing pipelines, API and AOPL presume an appropriate implementation timeline will be allowed given, after which time a derate would be required pending other means of achieving verification (i.e. hydrotest, conduct an ECA or replacement). Finally, PHMSA should clarify the length of time over which a pressure reduction would apply and how an operator may increase the operating pressure of their pipeline subsequent to taking a derate. 6

7 VII. Conclusion In summary, API and AOPL share PHMSA s goal of improving pipeline safety performance. Liquid pipeline operators are engaged in many ongoing efforts to improve pipeline safety, and are especially proud of the areas where we are pursuing improvements in partnership with regulators and safety experts and advocates. While the statutory provision mandating PHMSA verify operating pressures for gas pipelines does not cover liquid pipelines, liquid pipeline operators appreciate the opportunity to comment on this proposal. Liquid pipeline operators are concerned that PHMSA proposes to use the IVP process to impose new integrity management requirements. Liquid pipeline operators look forward to working with PHMSA on integrity management program improvements through PHMSA s upcoming IMP 2.0 process, rather than by ad hoc, piecemeal changes made to such a core pipeline safety program outside of deliberate and thoughtful consideration of the most appropriate ways to improve safety performance through integrity management. Most of all, API and AOPL submit that PHMSA should focus this proposal on its core pressure verification goals and avoid the extended stakeholder comments and likely delay that would come from a more complex and controversial proposal. Liquid pipeline operators stand ready to work with PHMSA on this proposal, and other proposals to improve safety. Again, thank you for the opportunity to comment on this proposal. Sincerely, Andrew J. Black Peter T. Lidiak Association of Oil Pipe Lines American Petroleum Institute 1808 Eye Street, NW 1220 L Street, NW Washington, DC Washington, DC Dated: September 11,