US REGULATIONS-1 Regulatory updates place premium on testing, records management

Significant changes included new requirements for:

• Expansion of integrity management principles and maintenance practices to newly defined moderate consequence areas (MCAs), including highways, freeways, five or more buildings, or occupied sites within the potential impact radius.

• Reestablishing maximum-allowable operating pressure (MAOP) within 15 years via a pressure test, pressure reduction, engineering critical assessment, pipe replacement, or other PHMSA-approved technology for Class 3 or 4, HCA, or MCA transmission pipelines, where: (1) the existing basis is §192.619(c) [grandfather clause]; (2) records are not reliable, traceable, verifiable, or complete; or (3) a reportable incident has occurred since the last pressure test.

• Requiring material validation, including verification of records used to establish MAOP and material testing every time a pipeline is exposed in Class 3 or 4 or HCA to help ensure the basis for establishing MAOP accurately reflects the pipeline's physical and operational characteristics.

• Corrosion control and evaluation, including new requirements for performing electrical surveys under various conditions, more detailed requirements for interference and internal corrosion programs, more definition on remediation timelines, an update on the acceptance criteria for cathodic protection, and updates to the requirements for internal corrosion direct assessment and stress corrosion cracking direct assessment.

• Management of change processes, as outlined in ASME/ANSI B31.8S, Section 11.

• New sections in Subparts A through O for records requirements. 49 CFR 192's Appendix A provides a list of those new sections as well as records retention requirements.

Integrity management

The changes proposed by the PHMSA Notice of Proposed Rulemaking (NPRM), if approved, will affect every aspect of how operators structure their integrity management plans. The most significant changes affect:

• Coverage area expansion.

• Prescriptive data gathering and integration.

• Risk assessment validation.

• Assessment method limitation and usage.

• Preventative and mitigative measures.

Coverage area expansion

The NPRM greatly expands the applicable coverage area of integrity management principles and maintenance practices under Subpart M (Maintenance) and Subpart O (Gas Transmission Integrity Management Program, or TIMP) by introducing a new classification of pipeline segments: MCAs. MCAs include highways, freeways, and five or more co-located buildings or occupied sites within a potential impact radius not currently defined as an HCA.³ Subpart O of the current federal code applies only to pipeline segments in HCAs, roughly 7% of the US natural gas transmission pipeline infrastructure. PHMSA estimates the proposed change would expand the integrity management coverage area by about 70,000 miles from the 19,615 HCA miles reported in 2013 as part of the natural gas transmission pipeline system.⁴

Operators must assess the integrity of the newly identified mileage within 15 years of the new rules taking effect. Doing so will require identifying the mileage associated with an MCA and determining the pace required to complete baseline integrity assessments.

Collecting the data associated with this baseline assessment and integrating it with existing enterprise systems within the timeframe allowed will require great effort, given such a large expansion in the integrity assessment area. The common practice of siting pipeline near roadways for ease of access also may exacerbate the new requirement's impact, expanding the mileage requiring regular integrity or maintenance assessments and forcing operators to restructure their approaches to regulatory compliance.

Data gathering, integration

Section 192.917 previously allowed operators to base their data gathering and integration approach on ASME/ANSI B31.8S, according to what is applicable in each threat category (Section 4).⁵ The NPRM, however, is greatly expanding this requirement to include:

• Data gathered through integrity assessments required under this part, including but not limited to in-line inspections, pressure tests, direct assessment, guided wave ultrasonic testing, or other methods.

• Close-interval survey and electrical survey results.

• Cathodic protection rectifier readings.

• CP test point survey readings and locations.

• AC/DC and foreign structure interference surveys.

• Pipe coating surveys, including surveys to detect coating damage, disbonded coatings, or other conditions that compromise the effectiveness of corrosion protection, including but not limited to DC voltage gradient or AC voltage gradient inspections.

• Results of examinations of exposed portions of buried pipelines (e.g., pipe and pipe-coating condition, see §192.459), including the results of any nondestructive examinations of the pipe, seam, or girth weld (i.e., bell-hole inspections).

• Stress corrosion cracking excavations and findings.

• Selective seam weld corrosion excavations and findings.

• Gas stream sampling and internal corrosion monitoring results, including cleaning-pig sampling results.

Section 192.917 includes 45 separate data items, so the list above is not inclusive, instead representing the prescriptive nature of the new regulations' data collection methodology. Regulators have designed a data collection methodology based broadly on a threat identification and inspection program. An operator may have to collect, analyze, and store a large amount of data for a pipeline and subsequently define the risks associated. The operator will also have to verify and validate the data. Operators should seek further information from PHMSA on what is required for these verification and validations steps, because compliance may be labor intensive and potentially difficult to prove under audit.

The rule changes also seek to greatly reduce bias from inputs provided by subject matter experts. At the time of publication PHMSA had not proposed specific control measures to accomplish this bias reduction. In lieu of specific bias control requirements, operators may want to consider developing formal expert assessment protocols, processes, and training, including contributions from external technical experts to fill knowledge gaps and provide fresh perspectives within the organization.

In accordance with ASME/ANSI B31.8S recommendations, PHMSA also has proposed requiring data be analyzed for spatially interacting threats when conducting a risk assessment.⁶

Risk-assessment validation

The fundamentals of risk assessment do not change; the operator must identify the likelihood of threats and the consequences of an incident on each pipeline segment. The NPRM proposes requiring operators validate the risk assessment methodology implemented. Specifically, PHMSA states that risk assessment validation activities "must ensure the risk assessment methods produce a risk characterization that is consistent with the operator's and industry experience, including evaluations of the cause of past incidents, as determined by root cause analysis or other equivalent means, and include sensitivity analysis of the factors used to characterize both the probability of loss of pipeline integrity and consequences of the postulated loss of pipeline integrity."

The proposed rules also require that the assessment method "account for, and compensate for, uncertainties in the model and the data used in the risk assessment." Capturing and incorporating successes from ongoing research and development activities and operational experience should be considered in addition to past incidents, because an operator's understanding is improved through both success and failure.

MAOP, material validation

The primary objective of a pipeline operator is to construct and maintain a system that will reliably transport products during its lifetime at the lowest total cost. One of the most critical operational design attributes of a pipeline is its MAOP. This attribute largely defines the margin of safety to the public and environment as well as operational flexibility and serviceability. The burst capacity of a pipeline is a function of material properties (yield and tensile strengths), geometry (diameter, WT), manufacturing process (longitudinal seam, girth weld), and condition (wall loss, dents, cracks, etc.). As evidenced by several recent costly failures, effective integrity management requires comprehension of what is known, unknown, and uncertain. It also requires robust processes to collect, maintain, access, and evaluate information.

Section 23 of HR 2845 directs the government to issue regulations to:

• Ensure records accurately reflect the physical and operational characteristics of the pipelines in Class 3 and Class 4 locations and Class 1 and Class 2 HCA.

• Confirm the established MAOP of the pipelines.⁷

In response to this law, PHMSA has introduced §192.624, "Maximum allowable operating pressure verification: Onshore steel transmission pipelines," and modification §192.619, "Maximum allowable operating pressure: Steel or plastic pipelines," which would require operators to reestablish MAOP via a pressure test, pressure reduction, engineering critical assessment, pipe replacement, or other PHMSA-approved alternative technology.

The proposed rules apply to segments of the transmission pipeline system where public exposure is the greatest, specifically Class 3 or 4, HCA, and newly defined MCA segments where:

• The existing basis is §192.619(c) [grandfather clause].

• A reportable incident has occurred since the last pressure test (e.g., manufacturing-related defect or cracking-related defect).

• The existing basis is a strength test and associated records are not reliable, traceable, verifiable, or complete and located in Class 3 or 4 or HCA.

Table 1 provides examples of records that can be used to fulfill the recordkeeping portion of the proposed rule depending on the MAOP determination method of choice.

Although these changes address many of the issues and concerns that NTSB raised subsequent to its investigation of the San Bruno incident,² questions remain with respect to its implementation. For example, the NPRM does not specify what will constitute a reliable record and associated thresholds for the purposes of MAOP confirmation. The effective date of incidents that would require a pressure test also remains unspecified, leaving the door open to retroactive testing.

Initial studies suggest that requiring the reestablishment of MAOP for applicable segments currently determined by §192.619(c) will have its greatest impact on industry, principally via the MCAs. In 2013 PHMSA estimated that about 50,000 miles (25%) of Class 1 and 2 non-HCA pipe could be reclassified as MCA pipe. According to PHMSA, about 14% of the transmission system's MAOP is currently established under the grandfather clause, 12% of which is in HCA or Class 3 or 4 locations (about 5,000 miles of pipe). When MCAs are included this number could grow to as much as 13,000 miles (see Table 2).

Data from American Gas Association member companies and PHMSA, by comparison, indicate roughly 5,000 miles of the transmission pipeline infrastructure's MAOP is currently established by a pressure test in an HCA or Class 3 or 4 location that either has not completed an MAOP reconfirmation records review or has found the information to be deficient for this purpose.8 9

The NPRM would require operators be in full compliance within 15 years of the effective date of the regulation. Impacts will vary significantly depending on system configuration and records management history (including those of purchased entities over time). Operators should develop strategies to address:

• Expansion of hydrotest programs (including hydrotest failure analysis).

• Increased pipeline replacement projects.

• Shortage of skilled and experienced contractors.

• Strain on outage management resources (e.g., control room, mobile units).

• Rate case testimony, project justification.

• Material procurement, availability.

The NPRM also proposes to modify §192.607, Verification of Pipeline Material: Onshore Steel Transmission Pipelines, to ensure records accurately reflect the physical and operational characteristics of the pipelines per HR 2845 by requiring operators verify material properties through a series of validation tests in Class 3 and 4 locations and in HCAs where reliable, traceable, verifiable, and complete (RTVC) records are not available, regardless of the MAOP determination method chosen.

Although an operator may have performed a strength test and may have supporting RTVC documentation (pressure test record, chart, etc.), if the pipe is located in an HCA or Class 3 or 4 location, manufacturing records (e.g., mill test) or material validation tests will be required. The quantity of material verification tests required depends largely on the quantity of pipe missing documentation and the number of joints exposed.

If an operator elects to use nondestructive techniques (i.e., scratch resistivity-Mohs hardness, instrumented indentation technique, ultrasonic contact impedance, or magnetic flux leakage) to determine strength or chemical composition, the operator must use methods, tools, procedures, and techniques that have been independently validated by subject matter experts in metallurgy and fracture mechanics to produce results accurate within 10% of the actual value with 95% confidence for strength values, within 25% of the actual value with 85% confidence for carbon, and within 20% of the actual value with 90% confidence for manganese, chromium, molybdenum, and vanadium for the grade of steel being tested.

Part 2 of this article, its conclusion, will appear in the Dec. 5, 2016, issue of Oil & Gas Journal.

References

1. National Transportation Safety Board (NTSB), "Enbridge Incorporated Hazardous Liquid Pipeline Rupture and Release, Marshall, Michigan, July 25, 2010," Pipeline Accident Report NTSB/PAR-12/01, July 10, 2012.
2. NTSB, "Pacific Gas and Electric Company Natural gas Transmission Pipeline Rupture and Fire, San Bruno, California, Sept. 9, 2010," Pipeline Accident Report NTSB/PAR-11/01, Aug. 30, 2011.
3. Pipeline and Hazardous Materials Safety Administration (PHMSA), Notice of Proposed Rulemaking NPRM § 192.3, May 21, 2015.
4. NTSB, "Integrity Management of Gas Transmission Pipelines in High Consequence Areas," Safety Study, NTSB-SS15/01 PB2015-102735, Jan. 27, 2015.
5. American Society of Mechanical Engineers (ASME) B31.8S-2014 Appendix A, Table 4.2.1, "Data Elements of Prescriptive Pipeline Integrity Programs," 2014.
6. ASME B31.8S Sec. 2.2, 2014.
7. 112th Congress, "Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011," Public Law 112-90, HR 2845, Jan. 3, 2012.
8. PHMSA, "Comments of the AGA on the PHMSA Draft Integrity Verification Process," Exhibit 2: Evaluation of MAOP Testing for In-Service Transmission Pipelines by EN Engineering, June 20, 2013.
9. PHMSA, "Annual Report for Natural and Other Gas Transmission and Gathering Pipeline Systems," 2014-present.

The authors
Kofi Inkabi ([email protected]) is a senior associate at Exponent, Oakland, Calif. He holds a PhD in civil and environmental engineering with an emphasis in risk assessment and management (2009) and an MS in structural engineering, mechanics, and materials (2000) from the University of California, Berkeley, and a BS in civil and environmental Engineering from the University of California, Davis. He is a member of the American Society of Mechanical Engineers, Center for Catastrophic Risk Management, and serves on the American Gas Association's Distribution and Transmission Engineering Committee.
Elizabeth Reilly ([email protected]) is a senior managing engineer at Exponent, Menlo Park, Calif. She holds a PhD in mechanical engineering with an emphasis in mechanics of materials (2007) from the University of California, Berkeley, and a BS with honors in chemical engineering from Brown University, Providence, RI. She is a licensed professional engineer in California, and serves on the American Gas Association's Transmission Pipeline Operations Committee. Reilly is also a project management professional (PMP) and a registered patent agent with the US Patent and Trademark Office.