Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments, 52180-52257 [2019-20306]

Download as PDF 52180 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations DEPARTMENT OF TRANSPORTATION Pipeline and Hazardous Materials Safety Administration 49 CFR Parts 191 and 192 [Docket No. PHMSA–2011–0023; Amdt. Nos. 191–26; 192–125] RIN 2137–AE72 Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments Pipeline and Hazardous Materials Safety Administration (PHMSA), DOT. ACTION: Final rule. jbell on DSK3GLQ082PROD with RULES2 AGENCY: SUMMARY: PHMSA is revising the Federal Pipeline Safety Regulations to improve the safety of onshore gas transmission pipelines. This final rule addresses congressional mandates, National Transportation Safety Board recommendations, and responds to public input. The amendments in this final rule address integrity management requirements and other requirements, and they focus on the actions an operator must take to reconfirm the maximum allowable operating pressure of previously untested natural gas transmission pipelines and pipelines lacking certain material or operational records, the periodic assessment of pipelines in populated areas not designated as ‘‘high consequence areas,’’ the reporting of exceedances of maximum allowable operating pressure, the consideration of seismicity as a risk factor in integrity management, safety features on in-line inspection launchers and receivers, a 6-month grace period for 7-calendar-year integrity management reassessment intervals, and related recordkeeping provisions. DATES: The effective date of this final rule is July 1, 2020. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of July 1, 2020. The incorporation by reference of ASME/ANSI B31.8S was approved by the Director of the Federal Register as of January 14, 2004. FOR FURTHER INFORMATION CONTACT: Technical questions: Steve Nanney, Project Manager, by telephone at 713– 272–2855. General information: Robert Jagger, Senior Transportation Specialist, by telephone at 202–366–4361. SUPPLEMENTARY INFORMATION: I. Executive Summary A. Purpose of the Regulatory Action VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 B. Summary of the Major Provisions of the Regulatory Action in Question C. Costs and Benefits II. Background A. Detailed Overview B. Pacific Gas and Electric Incident of 2010 C. Advance Notice of Proposed Rulemaking D. National Transportation Safety Board Recommendations E. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 F. Notice of Proposed Rulemaking III. Analysis of Comments, GPAC Recommendations and PHMSA Response A. Verification of Pipeline Material Properties and Attributes—§ 192.607 i. Applicability ii. Method B. MAOP Reconfirmation—§§ 192.624, 192.632 i. Applicability ii. Methods iii. Spike Test—§ 192.506 iv. Fracture Mechanics—§ 192.712 v. Legacy Construction Techniques/Legacy Pipe C. Seismicity and Other Integrity Management Clarifications—§ 192.917 D. 6-Month Grace Period for 7-CalendarYear Reassessment Intervals—§ 192.939 E. ILI Launcher and Receiver Safety— § 192.750 F. MAOP Exceedance Reporting— §§ 191.23, 191.25 G. Strengthening Assessment Requirements—§§ 192.150, 192.493, 192.921, 192.937, Appendix F i. Industry Standards for ILI—§§ 192.150, 192.493 ii. Expand Assessment Methods Allowed for IM—§§ 192.921(a) and 192.937(c) iii. Guided Wave Ultrasonic Testing— Appendix F H. Assessing Areas Outside of HCAs— §§ 192.3, 192.710 i. MCA Definition—§ 192.3 ii. Non-HCA Assessments—§ 192.710 I. Miscellaneous Issues i. Legal Comments ii. Records iii. Cost/Benefit Analysis, Information Collection, and Environmental Impact Issues IV. GPAC Recommendations V. Section-by-Section Analysis VI. Standards Incorporated by Reference A. Summary of New and Revised Standards B. Availability of Standards Incorporated by Reference VII. Regulatory Analysis and Notices I. Executive Summary A. Purpose of the Regulatory Action PHMSA believes that the current regulatory requirements applicable to gas pipeline systems have increased the level of safety associated with the transportation of gas. Still, incidents continue to occur on gas pipeline systems resulting in serious risks to life and property. One such incident occurred in San Bruno, CA, on PO 00000 Frm 00002 Fmt 4701 Sfmt 4700 September 9, 2010, killing 8 people, injuring 51, destroying 38 homes, and damaging another 70 homes (PG&E incident). In its investigation of the incident, the National Transportation Safety Board (NTSB) found among several causal factors that the operator, Pacific Gas and Electric (PG&E), had an inadequate integrity management (IM) program that failed to detect and repair or remove the defective pipe section. PG&E was basing its IM program on incomplete and inaccurate pipeline information, which led to, among other things, faulty risk assessments, improper assessment method selection, and internal assessments of the program that were superficial and resulted in no meaningful improvement in the integrity of the pipeline system nor the IM program itself. The PG&E incident underscored the need for PHMSA to extend IM requirements and address other issues related to pipeline system integrity. In response, PHMSA published an ANPRM seeking comment on whether IM and other requirements should be strengthened or expanded, and other related issues, on August 25, 2011 (76 FR 53086). The NTSB adopted its report on the PG&E incident on August 30, 2011, and issued several safety recommendations to PHMSA and other entities. Several of these NTSB recommendations related directly to the topics addressed in the 2011 ANPRM and are addressed in this final rule. Also, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Pipeline Safety Act) was enacted on January 3, 2012. Several of the 2011 Pipeline Safety Act’s statutory requirements related directly to the topics addressed in the 2011 ANPRM and are a focus of this rulemaking. Another incident that influenced this rulemaking was the rupture of a gas transmission pipe operated by Columbia Gas near Sissonville, WV, on December 11, 2012. The escaping gas ignited, and fire damage extended nearly 1,100 feet along the pipeline right-of-way and covered an area roughly 820 feet wide. While there were no fatalities or serious injuries, three houses were destroyed by the fire, and several other houses were damaged. The ruptured pipe was one of three in the area that cross Interstate 77, and the incident closed the highway in both directions for 19 hours until a section of thermally damaged road surface approximately 800 feet long could be replaced. Following this incident, the NTSB finalized an accident report on February 19, 2014, issuing recommendations to PHMSA to include principal arterial roadways, E:\FR\FM\01OCR2.SGM 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES2 including interstates, other freeways and expressways, and other principal arterial roadways as defined by the Federal Highway Administration, to the list of ‘‘identified sites’’ that establish a high consequence area (HCA) for the purposes of an operator’s IM program. On April 8, 2016, PHMSA published an NPRM to seek public comments on proposed changes to the gas transmission pipeline safety regulations (81 FR 20722). A summary of those proposed changes, and PHMSA’s response to stakeholder feedback on the individual provisions, is provided below in section IV of this document (Analysis of Comments and PHMSA Response). The purpose of this final rule is to increase the level of safety associated with the transportation of gas. PHMSA is finalizing requirements that address the causes of several recent incidents, including the PG&E incident, by clarifying and enhancing existing requirements. PHMSA is also addressing certain statutory mandates of the 2011 Pipeline Safety Act and NTSB recommendations. While the NPRM addressed 16 major topic areas, PHMSA believes the most efficient way to manage the proposals in the NPRM is to divide them into three rulemaking actions. PHMSA is finalizing the provisions in this final rule as a first step. PHMSA anticipates completing a second rulemaking to address the topics in the NPRM regarding repair criteria in HCAs and the creation of new repair criteria for non-HCAs, requirements for inspecting pipelines following extreme events, updates to pipeline corrosion control requirements, codification of a management of change process, clarification of certain other IM requirements, and strengthening IM assessment requirements.1 A third rulemaking is expected to address requirements related to gas gathering lines that were proposed in the NPRM.2 B. Summary of the Major Provisions of the Regulatory Action in Question Several of the amendments made in this rule are related to congressional legislation from the 2011 Pipeline Safety Act. The Act provides a 6-month grace period, with written notice, for the completion of periodic integrity management reassessments that otherwise would be completed no later than every 7 calendar years.3 Another requirement is that operators explicitly consider and account for seismicity in identifying and evaluating potential 1 RIN 2137–AF39. 2137–AF38. 3 2011 Pipeline Safety Act § 5(e). 2 RIN VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 threats.4 The Act also requires operators to report exceedances of the maximum allowable operating pressure (MAOP) of gas transmission pipelines.5 6 PHMSA is incorporating these changes into the PSR at 49 CFR parts 190–199 in this final rule. This rule also requires operators of certain onshore steel gas transmission pipeline segments to reconfirm the MAOP of those segments and gather any necessary material property records they might need to do so, where the records needed to substantiate the MAOP are not traceable, verifiable, and complete. This includes previously untested pipelines, which are commonly referred to as ‘‘grandfathered’’ pipelines, operating at or above 30 percent of specified minimum yield strength (SMYS). Records to confirm MAOP include pressure test records or material property records (mechanical properties) that verify the MAOP is appropriate for the class location.7 Operators with missing records can choose one of six methods to reconfirm their MAOP and must keep the record that is generated by this exercise for the life of the pipeline. PHMSA has also created an opportunistic method by which operators with insufficient material property records can obtain such records. These physical material property and attribute records include the pipeline segment’s diameter, wall thickness, seam type, grade (the minimum yield strength and ultimate tensile strength of the pipe), and Charpy V-notch toughness values (full-size specimen and based on the lowest operational temperatures),8 if applicable or required. PHMSA considers ‘‘insufficient’’ material property records to be those records where the pipeline’s physical material properties and attributes are not documented in 4 2011 Pipeline Safety Act § 29. Pipeline Safety Act § 23. 6 MAOP means the maximum pressure at which a pipeline or segment of a pipeline may be operated under this part. 7 PHMSA uses class locations throughout part 192 to provide safety margins and standards commensurate with the potential consequence of a pipeline failure based on the surrounding population. Class locations are defined at § 192.5. A Class 1 location is an offshore area or a class location unit with 10 or fewer buildings intended for human occupancy. A Class 2 location is a class location unit with more than 10 but fewer than 46 buildings intended for human occupancy. A Class 3 location is a class location unit with 46 or more buildings intended for human occupancy, and a Class 4 location is where buildings with 4-or-more stories above ground are prevalent. 8 A Charpy V-notch impact test and its values indicate the toughness of a given material at a specified temperature and is used in fracture mechanics analysis. 5 2011 PO 00000 Frm 00003 Fmt 4701 Sfmt 4700 52181 traceable, verifiable, and complete records. PHMSA is requiring operators to perform integrity assessments on certain pipelines outside of HCAs, whereas prior to this rule’s publication, integrity assessments were only required for pipelines in HCAs. Pipelines in Class 3 locations, Class 4 locations, and in the newly defined ‘‘moderate consequence areas’’ (MCA) 9 must be assessed initially within 14 years of this rule’s publication date and then must be reassessed at least once every 10 years thereafter. These assessments will provide important information to operators about the conditions of their pipelines, including the existence of internal and external corrosion and other anomalies, and will provide an elevated level of safety for the populations in MCAs while continuing to allow operators to prioritize the safety of HCAs. This action fulfills the section 5 mandate from the 2011 Pipeline Safety Act to expand elements of the IM requirements beyond HCAs where appropriate. This rule also explicitly requires devices on in-line inspection (ILI), launcher or receiver facilities that can safely relieve pressure in the barrel before inserting or removing ILI tools, and requires the use of a device that can indicate whether the pressure has been relieved in the barrel or can otherwise prevent the barrel from being opened if the pressure is not relieved. PHMSA is finalizing this requirement in this final rule because it is aware of incidents where operator personnel have been killed or seriously injured due to pressure build-up at these stations. C. Costs and Benefits Consistent with Executive Order 12866, PHMSA has prepared an assessment of the benefits and costs of the final rule as well as reasonable alternatives. PHMSA estimates the annual costs of the rule to be approximately $32.7 million, calculated using a 7 percent discount rate. The costs reflect additional integrity assessments, MAOP reconfirmation, and ILI launcher and receiver upgrades. PHMSA is publishing the Regulatory Impact Analysis (RIA) for this rule in the public docket. The table below 9 A MCA is defined in § 191.3 as an onshore area within a potential impact circle, as that term is defined in § 192.903, containing either (1) 5 or more buildings intended for human occupancy or (2) any portion of the paved surface, including shoulders, of a designated interstate, other freeway, or expressway, as well as any other principal arterial roadway with 4 or more lanes, as defined in the Federal Highway Administration’s Highway Functional Classification Concepts, Criteria and Procedures, Section 3.1. E:\FR\FM\01OCR2.SGM 01OCR2 52182 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations provides a summary of the estimated costs for the major provisions in this rulemaking (see the RIA for further detail on these estimates). PHMSA finds that the other final rule requirements will not result in incremental costs. PHMSA did not quantify the cost savings from material properties verification under the final rule compared to existing regulations. PHMSA also elected to not quantify the benefits of this rulemaking and instead discusses them qualitatively. PHMSA estimated total annual costs of the rule of $31.4 million using a 3 percent discount rate, and $32.7 million using a 7 percent discount rate. SUMMARY OF ANNUALIZED COSTS, 2019–2039 [$2017 thousands] Annualized cost Provision 1. 2. 3. 4. 5. 6. 7. 8. 7% Discount rate MAOP Reconfirmation & Material Properties Verification ................................................................................... Seismicity ............................................................................................................................................................. Six-Month Grace Period for Seven Calendar-Year Reassessment Intervals ..................................................... In-Line Inspection Launcher/Receiver Safety ..................................................................................................... MAOP Exceedance Reports ............................................................................................................................... Strengthening requirements for assessment methods ....................................................................................... Assessments outside HCAs ................................................................................................................................ Related Records Provisions ................................................................................................................................ $25,848 0.00 0.00 27.4 0.00 0.00 5,482 0.00 $27,899 0.00 0.00 37.5 0.00 0.00 4,713 0.00 Total .................................................................................................................................................................. 31,357 32,650 II. Background A. Detailed Overview Introduction Recent significant growth in the nation’s production and use of natural gas is placing unprecedented demands on the Nation’s pipeline system, underscoring the importance of moving this energy product safely and efficiently. Changing spatial patterns of natural gas production and use and an aging pipeline network has made improved documentation and data collection increasingly necessary for the industry to make reasoned safety choices and for preserving public confidence in its ability to do so. Congress recognized these needs when passing the 2011 Pipeline Safety Act, calling for an examination of issues pertaining to the safety of the Nation’s pipeline network, including a thorough application of the risk-based integrity assessment, repair, and validation system known as IM.10 This final rule advances the goals established by Congress in the 2011 Pipeline Safety Act and is consistent with the emerging needs of the natural gas pipeline system. This final rule also advances the important discussion about the need to adapt and expand risk-based safety practices. As some severe pipeline incidents have occurred jbell on DSK3GLQ082PROD with RULES2 3% Discount rate 10 The IM regulations specify how pipeline operators must identify, prioritize, assess, evaluate, repair, and validate the integrity of gas transmission pipelines in HCAs that could, in the event of a leak or failure, affect high consequence areas in the United States. These areas include certain populated and occupied areas. See § 192.903. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 in areas outside HCAs 11 where the application of IM principles are not required, and as gas pipelines continue to experience failures from causes that IM was intended to address, this conversation is increasingly important. This final rule strengthens IM requirements, including to ensure operators select the appropriate inspection tool or tools to address the pertinent identified threats to their pipeline segments, and clarifies and expands recordkeeping requirements to ensure operators have and retain the basic physical and operational attributes and characteristics of their pipelines. Further, this final rule establishes requirements to periodically assess pipeline segments in locations outside of HCAs where the surrounding population is expected to potentially be at risk from an incident, which are defined in the rule as MCAs. Even though these pipeline segments are not within currently defined HCAs, they could be located in areas with significant populations. This change facilitates prompt identification and remediation of potentially hazardous defects while still allowing operators to make risk-based decisions on where to 11 HCAs are defined at § 192.903. There are two methods that can be used to determine and HCA, the specific differences of which we do not address here. Very broadly and regardless of which method used, operators must calculate the potential impact radius for all points along their pipelines and evaluate corresponding impact circles to identify what populations are contained within each circle. Potential impact circles with 20 or more structures intended for human occupancy, or those circles with ‘‘identified sites’’ such as stadiums, playgrounds, office buildings, and religious centers, are defined as HCAs. PO 00000 Frm 00004 Fmt 4701 Sfmt 4700 allocate their maintenance and repair resources. Natural Gas Infrastructure Overview The U.S. natural gas pipeline network is designed to transport natural gas to and from most locations in the lower 48 States. Approximately two-thirds of the lower 48 States depend almost entirely on the interstate transmission pipeline system for their supply of natural gas.12 One can consider the Nation’s natural gas pipeline infrastructure as three interconnected parts—gathering, transmission, and distribution—that together transport natural gas from the production field, where gas is extracted from underground, to its end users, where the gas is used as an energy fuel or chemical feedstock. This final rule applies only to gas transmission lines and does not address gas gathering or natural gas distribution infrastructure and its associated issues. Currently, there are over 300,000 miles of onshore gas transmission pipelines throughout the U.S.13 Transmission pipelines primarily transport natural gas from gas treatment plants and gathering systems to bulk customers, local distribution networks, and storage facilities. Transmission pipelines can range in size from several inches to several feet in diameter. They can operate over a wide range of pressures, from a relatively low 200 pounds per square inch gage (psig) to 12 U.S. Department of Energy, ‘‘Appendix B: Natural Gas,’’ Quadrennial Energy Review Report: Energy Transmission, Storage, and Distribution Infrastructure, p. NG–28, April 2015. 13 U.S. DOT Pipeline and Hazardous Materials Safety Administration Data as of 4/26/2018. E:\FR\FM\01OCR2.SGM 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations over 1,500 psig. They can be hundreds of miles long, and can operate within the geographic boundaries of a single State, or cross one or more State lines. Regulatory History jbell on DSK3GLQ082PROD with RULES2 PHMSA and its State partners regulate and enforce the minimum Federal safety standards authorized by statute 14 and codified in the PSR for jurisdictional 15 gas gathering, transmission, and distribution systems. Federal regulation of gas pipeline safety began in 1968 with the creation of the Office of Pipeline Safety and the passage of the Natural Gas Pipeline Safety Act of 1968 (Pub. L. 90–481). The Office of Pipeline Safety issued interim minimum Federal safety standards for gas pipeline facilities and the transportation of natural and other gas by pipeline on November 13, 1968, and subsequently codified broad-based gas pipeline regulations on August 19, 1970 (35 FR 13248). The PSR were revised several times over the following decades to address different aspects of natural gas transportation by pipeline, including construction standards, pipeline materials, design standards, class locations, corrosion control, and MAOP. In the mid-1990s, following models from other industries such as nuclear power, PHMSA started to explore whether a risk-based approach to regulation could improve safety of the public and reduce damage to the environment. During this time, PHMSA found that many operators were performing forms of IM that varied in scope and sophistication but that there were no uniform standards or requirements. PHMSA began developing minimum IM regulations for both hazardous liquid and gas transmission pipelines in response to a hazardous liquid accident in Bellingham, WA, in 1999 that killed 3 people and a gas transmission incident in Carlsbad, NM, in 2000 that killed 12. PHMSA finalized IM regulations for gas transmission pipelines in a 2003 final rule.16 The IM regulations are intended to provide a structure to operators to focus resources on improving pipeline integrity in the areas where a failure would have the greatest impact on public safety. The IM 14 Title 49, United States Code, Subtitle VIII, Pipelines, Sections 60101, et. seq. 15 Typically, onshore pipelines involved in the ‘‘transportation of gas’’—see 49 CFR 192.1 and 192.3 for detailed applicability. 16 ‘‘Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines).’’ 68 FR 69778; December 15, 2003. Corrected April 6, 2004 (69 FR 18227) and May 26, 2004 (69 FR 29903). VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 final rule accelerated the integrity assessment of pipelines in HCAs, improved IM systems, and improved the government’s ability to review the adequacy of IM plans. The IM regulations require that operators conduct comprehensive analyses to identify, prioritize, assess, evaluate, repair, and validate the integrity of gas transmission pipelines in HCAs. Approximately 7 percent of onshore gas transmission pipeline mileage is located in HCAs.17 PHMSA and State inspectors review operators’ IM programs and associated records to verify that the operators have used all available information about their pipelines to assess risks and take appropriate actions to mitigate those risks. Since the implementation of the IM regulations, sweeping changes in the natural gas industry have caused significant shifts in supply and demand, and the Nation’s pipeline network faces increased pressures from these changes as well as from the increased exposure caused by a growing and geographically dispersing population. Also, longidentified pipeline safety issues, some of which IM set out to address, remain problems. A records search following the PG&E incident required by Congress in the 2011 Pipeline Safety Act, showed that some pipeline operators do not have the records they need to substantiate the current MAOP of their pipelines, as required under existing regulations, and lacked other critical information needed to properly assess risks and threats and perform effective IM.18 PHMSA’s inspection experience indicates pipelines continue to be vulnerable to failures stemming from outdated construction methods or materials. Finally, some severe pipeline incidents have occurred in areas outside HCAs where the application of IM principles is not required. Following the significant pipeline incident in 2010 at San Bruno, CA, in which 8 people died and more than 50 people were injured, Congress charged PHMSA with improving the IM regulations. Additionally, the NTSB and Government Accountability Office 17 Per PHMSA’s 2018 Annual Report, accessed April 9, 2019, 20,435 of the 301,227 miles of gas transmission pipelines are classified as being in HCAs. 18 An effective IM program requires operators to analyze many data points regarding threats to their systems in addition to pipe attributes, including, but not limited to, construction data (year of installation, pipe bending method, joining method, depth of cover, coating type, pressure test records, etc.), operational data (maximum and minimum operating pressures, leak and failure history, corrosion monitoring, excavation data, corrosion surveys, ILI data, etc.). PO 00000 Frm 00005 Fmt 4701 Sfmt 4700 52183 (GAO) issued recommendations regarding IM.19 Comments in response to a 2011 ANPRM on these and related topics suggested there were many common-sense improvements that could be made to IM, as well as a clear need to extend certain IM provisions to pipelines outside of HCAs that were not covered by the IM regulations. A large portion of the transmission pipeline industry has voluntarily committed to extending certain IM provisions to nonHCA pipe, which demonstrates a common understanding of the need for this strategy. Through this final rule, PHMSA is making improvements to IM and is improving the ability of operators to engage in a long-range review of risk management and information needs, while also accounting for a changing landscape and a changing population. Supply Changes The U.S. natural gas industry increased production dramatically between 2005 and 2017, from 19.5 trillion cubic feet per year to 28.8 trillion cubic feet per year.20 This growth was enabled by the production of ‘‘unconventional’’ natural gas supplies using improved technology to extract gas from low permeability shales. The increased use of directional drilling 21 and improvements to a longexisting industrial technique—hydraulic fracturing,22 which began as an experiment in 1947—made the recovery of unconventional natural gas easier and economically viable. This has led to decreased prices and increased use of natural gas, despite a reduction in the production of conventional natural gas of about 14 billion cubic feet per day. Unconventional shale gas production now accounts for nearly 70 percent of overall gas production in the U.S. Growth in unconventional natural gas production has shifted production away from traditionally gas-rich regions towards inland shale gas regions. To illustrate, in 2004, wells in the Gulf of Mexico’s produced 5,066,000 million 19 More information on the NTSB recommendations being addressed in this rule are discussed in further detail in Section II. D. of this document ‘‘National Transportation Safety Board Recommendations.’’ See also, GAO–06–946, Natural Gas Pipeline Safety: Integrity Management Benefits Public Safety, but Consistency of Performance Measures Should be Improved,’’ September 8, 2006. 20 U.S. Department of Energy, Energy Information Administration, ‘‘U.S. Natural Gas marketed Production’’ https://www.eia.gov/dnav/ng/hist/ n9050us2a.htm, accessed 6/28/18. 21 Directional drilling is the practice of drilling non-vertical wells. 22 The extraction of oil or gas deposits performed by forcing open fissures in subterranean rocks by introducing liquid at high pressures. E:\FR\FM\01OCR2.SGM 01OCR2 52184 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations cubic feet of natural gas per year (Mcf/ year), approximately 20 percent of the Nation’s natural gas production at the time. By 2016, that number had fallen to 1,220,000 Mcf/year, and approximately 4 percent of natural gas production in the U.S. During that same period, Pennsylvania’s share of production grew from 197,217 Mcf/year to 5,463,783 Mcf/year, or approximately 17 percent of total natural gas production in the U.S.23 24 An analysis conducted by the Department of Energy’s Office of Energy Policy and Systems Analysis projects that the most significant increases in production through 2030 will occur in the Marcellus and Utica Basins in the Appalachian Basin,25 and natural gas production is projected to grow from the 2015 levels of 66.5 Bcf/d to more than 93.5 Bcf/d.26 jbell on DSK3GLQ082PROD with RULES2 Demand Changes The increase in domestic natural gas production has led to lower average natural gas prices.27 In 2004, the outlook for natural gas production and demand growth was weak. Monthly average spot prices at Henry Hub 28 were high based on historic comparison of prices, fluctuating between $4 per million British thermal units (Btu) and $7 per million Btu. Prices rose above $11 per million Btu for several months in both 2005 and 2008.29 Since 2008, after production shifted to onshore unconventional shale resources, and price volatility fell away following the Great Recession, natural gas has traded between about $2 per million Btu and $5 per million Btu.30 These low prices have fueled consumption growth and changes in 23 U.S. Department of Energy, Energy Information Administration, ‘‘Gulf of Mexico—Offshore Natural Gas Withdrawals,’’ https://www.eia.gov/dnav/ng/ hist/na1060_r3fmtf_2a.htm, accessed 6/28/18. 24 U.S. Department of Energy, Energy Information Administration, ‘‘Pennsylvania Natural Gas Gross Withdrawals,’’ https://www.eia.gov/dnav/ng/hist/ n9010pa2a.htm, accessed 6/28/18. 25 U.S. Department of Energy, ‘‘Appendix B: Natural Gas,’’ Quadrennial Energy Review Report: Energy Transmission, Storage, and Distribution Infrastructure, p. NG–28, April 2015. 26 Id., at NG–6. 27 Id., at NG–11. 28 Henry Hub is a Louisiana natural gas distribution hub where conventional Gulf of Mexico natural gas can be directed to gas transmission lines running to different parts of the country. Gas bought and sold at the Henry hub serves as the national benchmark for U.S. natural gas prices. (Id., at NG– 29, NG–30). 29 Energy Information Administration, Natural Gas Spot and Futures Prices, https://www.eia.gov/ dnav/ng/ng_pri_fut_s1_m.htm, retrieved August 2018. 30 U.S. Department of Energy, ‘‘Appendix B: Natural Gas,’’ Quadrennial Energy Review Report: Energy Transmission, Storage, and Distribution Infrastructure, p. NG–11, April 2015. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 markets and spatial patterns of consumption. A shift towards natural gas-fueled electric power generation, cleaner than other types of fossil fuels, is helping to serve the needs of the Nation’s growing population, and increased gas production and lower domestic prices have created opportunities for international export. Plentiful domestic natural gas supply and comparatively low natural gas prices have changed the economics of electric power markets.31 To accommodate recent growth and expected future growth in natural gasfueled power, changes in pipeline infrastructure will be needed, including flow reversals of existing pipelines; additional lines to gas-fired generators; looping of existing networks, where multiple pipelines are laid parallel to one another along a single right-of-way to increase the capacity of a single system; and, potentially, new pipelines as well. Increasing Pressures on the Existing Pipeline System Due to Supply and Demand Changes Despite the significant increase in domestic gas production and the widespread distribution of domestic gas demand, significant flexibility and capacity in the existing transmission system mitigates the level of pipeline expansion and investment required. Some of the new gas production is located near existing or emerging sources of demand, which reduces the need for additional natural gas pipeline infrastructure. In many instances where new natural gas transmission capacity is needed, the network is being expanded by pipeline investments to enhance network capacity on existing lines rather than increasing coverage through new infrastructure. Additionally, operators have avoided building new pipelines by increasing pipeline diameters or operating pressures. In short, the nation’s existing pipeline system is facing the brunt of this dramatic increase in natural gas supply and the shifting energy needs of the country. In cases where use of the existing pipeline network is high, the next most cost-effective solution is to add capacity to existing lines via compression.32 Compression requires infrastructure investment in the form of more compressor stations along the pipeline route, but it can be less costly, faster, and simpler for market participants in 31 Id., at NG–9. can be reduced in volume by increasing its pressure. Therefore, operators can pack more gas into their lines if they can increase the pressure of the gas being transported. comparison to building a new pipeline. Adding compression, however, raises pipeline operating pressures and can expose previously hidden defects. New pipeline projects have been proposed to address pending supply constraints and higher prices. However, gaining public acceptance for natural gas pipeline construction has proved to be a substantial challenge. Pipeline expansion and construction projects often face significant challenges in determining feasible right-of-ways and developing community support for the projects. Data Challenges Operators and regulators must have an intimate understanding of the threats to, and operations of, their entire pipeline system. Data gathering and integration are important elements of good IM practices, and while operators have made many strides over the years to collect more and better data, several data gaps still exist. Ironically, the comparatively positive safety record of the Nation’s gas transmission pipelines to date makes it harder to quantify some of these gaps. Over the 20-year period of 1998–2017, transmission facilities accounted for 50 fatalities and 179 injuries, or about one-sixth to oneseventh of the total fatalities and injuries caused by natural gas pipeline incidents in the U.S.33 Given the relatively limited number of significant incidents that occur, it can be challenging to project the possible impact of low-probability but highconsequence events. See the RIA included in the public docket for a more detailed analysis of key types of incidents that may be mitigated by this final rule. On September 9, 2010, a 30-inchdiameter segment of an intrastate natural gas transmission pipeline owned and operated by PG&E ruptured in a residential area of San Bruno, CA. The natural gas that was released subsequently ignited, resulting in a fire that destroyed 38 homes and damaged 70. Eight people were killed, many were injured, and many more were evacuated from the area. The PG&E incident exposed several problems in the way data on pipeline conditions is collected and managed, showing that the operator had inadequate records regarding the physical and operational characteristics of their pipelines. These records are necessary for the correct setting and validation of MAOP, which is critically 32 Gas PO 00000 Frm 00006 Fmt 4701 Sfmt 4700 33 PHMSA, Pipeline Incident 20-Year Trends, https://www.phmsa.dot.gov/pipeline/library/datastats/pipelineincidenttrends. E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations important for providing an appropriate margin of safety to the public. Much of operator data is obtained through the assessments and other safety inspections required by IM regulations. However, this testing can be expensive, and the approaches to obtaining data that are most efficient over the long term may require significant upfront costs to modernize pipes and make them suitable for automated inspection. As a result, there continue to be data gaps that make it hard to fully understand the risks to and the integrity of the Nation’s pipeline system. To evaluate a pipeline’s integrity, operators generally choose between three methods of testing a pipeline: Inline inspection (ILI), pressure testing, and direct assessment (DA). In 2017, PHMSA estimates that about two-thirds of gas transmission interstate pipeline mileage was suitable for ILI, compared to only about half of intrastate pipeline mileage, and therefore, intrastate operators use more pressure testing and DA than interstate operators. ILIs are performed using tools, referred to as ‘‘smart pigs,’’ which are usually pushed through a pipeline by the pressure of the product being transported. As the tool travels through the pipeline, it identifies and records potential pipe defects or anomalies. Because these tests can be performed with product in the pipeline, the pipeline does not have to be taken out of service for testing to occur, which can prevent excessive cost to the operator and possible service disruptions to consumers. Further, unlike pressure testing, ILI does not risk destroying the pipe, and it is typically less costly to perform on a per-unit basis than other assessment methods. Pressure tests, also known as hydrostatic tests, are used by pipeline operators as a means to determine the integrity (or strength) of the pipeline immediately after construction and before placing the pipeline in service, as well as periodically during a pipeline’s operating life. In a pressure test, water or an alternative test medium inside the pipeline is pressurized to a level greater than the normal operating pressure of the pipeline. This test pressure is held for a number of hours to ensure there are no leaks in the pipeline. Direct assessment is the visual evaluation of a pipeline at a sample of locations along the line to detect corrosion threats, dents, and stress corrosion cracking of the pipe body and seams. In general, corrosion direct assessments are carried out by performing four steps. Operators will review records and other data, then VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 inspect the pipeline through assessments that do not require excavation or use mathematical models and environmental surveys to find likely locations on a pipeline where corrosion is most likely to occur. For external corrosion, operators must use two or more complementary indirect assessment tools, including, for example, close interval surveys, direct current voltage gradient surveys, and alternating current voltage gradient surveys, to determine potential areas of corrosion to examine. For internal corrosion, operators must analyze data to establish whether water was present in the pipe, determine the locations where water would likely accumulate, and provide for a detailed examination and evaluation of those locations. Areas identified where corrosion may be occurring are then excavated, examined visually, and remediated as necessary. Operators also perform a postassessment on segments where corrosion direct assessments are used to evaluate the effectiveness of the technique and determine re-assessment intervals as needed.34 For cracking, operators collect and analyze data to determine whether the conditions for stress corrosion cracking are present, prioritize potentially susceptible segments of pipelines, and select specific sites for examination and evaluation. A DA would then evaluate the presence of stress corrosion cracking and determine its severity and prevalence. Operators are required to repair anomalies, if found, and determine further mitigation requirements as necessary. Direct assessment can be prohibitively expensive to use on a wide scale and may not give an accurate representation of the condition of lengths of entire pipeline segments when the high expense leads the operator to select an insufficient number of observations. Further, as DA can only be used to validate specific threats, an operator that relies solely on a DA without performing a thorough risk analysis or running multiple tools specific to multiple threats might be leaving other threats unremediated in their pipelines. Ongoing research and industry response to the ANPRM 35 and NPRM 36 indicate that ILI and spike hydrostatic 34 See PHMSA’s fact sheet on DA at https:// primis.phmsa.dot.gov/Comm/FactSheets/FSdirect AssessmentGas.htm. 35 ‘‘Pipeline Safety: Safety of Gas Transmission Pipelines—Advanced Notice of Proposed Rulemaking,’’ 76 FR 5308; August 25, 2011. 36 ‘‘Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines,’’ 81 FR 20722; April 8, 2016. PO 00000 Frm 00007 Fmt 4701 Sfmt 4700 52185 pressure testing 37 is more effective than DA for identifying pipe conditions that are related to stress corrosion cracking defects. Regulators and operators agree that improving ILI methods as an alternative to hydrostatic testing is better for risk evaluation and management of pipeline safety. Hydrostatic pressure testing can result in substantial costs, occasional disruptions in service, and substantial methane emissions due to the routine evacuation of natural gas from pipelines prior to tests. Further, many operators prefer not to use hydrostatic pressure tests because it can be destructive.38 ILI testing can obtain data along a pipeline not otherwise obtainable via other assessment methods, although this method also has certain limitations.39 This final rule expands the range of permissible assessment methods and incorporates new guidelines to help operators in the selection of appropriate assessment methods. Promoting the use of ILI technologies, combined with further research and development by PHMSA as well as stakeholders to make ILI testing more accurate, is expected to drive innovation in pipeline integrity testing technologies that leads to improved safety and system reliability through better data collection and assessment. Flow Reversals, Product Changes, and Manufacturing Defects Significant growth of production outside the Gulf Coast region— especially in Pennsylvania and Ohio 40—is causing a reorientation of the Nation’s transmission pipeline network. The most significant of these changes will require reversing flows on pipelines to move gas from the Marcellus and Utica shale formations to the southeastern Atlantic region and the Midwest. Reversing a pipeline’s flow can cause added stress on the system due to changes in gas pipeline pressure and temperature, which can increase the risk 37 A ‘‘spike’’ hydrostatic pressure test is typically used to resolve cracks that might otherwise grow during pressure reductions after hydrostatic tests or as the result of operational pressure cycles. 38 National Transportation Safety Board, ‘‘Pacific Gas and Electric Company; Natural Gas Transmission Pipeline Rupture and Fire; San Bruno, California; September 9, 2010,’’ Pipeline Accident Report NTSB/PAR–11–01, Page 96, 2011. 39 For example, ILI tools are ideal for gathering certain information about the physical condition of the pipe, including corrosion, deformations, or cracking. However, ILI technology cannot reliably detect other conditions, such as coating damage or environmental issues. 40 U.S. Energy Information Administration, ‘‘Annual Energy Outlook 2019,’’ p. 78—Dry shale gas production by region. https://www.eia.gov/ outlooks/aeo/pdf/aeo2019.pdf E:\FR\FM\01OCR2.SGM 01OCR2 52186 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES2 of internal corrosion. Occasional failures on natural gas transmission pipelines have followed operational changes that include flow reversals and product changes.41 Operators have recently submitted proposed flow reversals and product changes on gas transmission lines. In response to this phenomenon, PHMSA issued an Advisory Bulletin in 2014 notifying operators of the potentially significant impacts such changes may have on the integrity of a pipeline and recommended additional actions operators should consider performing before, during, and after flow reversals, product changes, and conversions to service, including notifications, operations and maintenance requirements, and IM requirements.42 Data indicates that some pipelines are vulnerable to issues stemming from outdated construction methods or materials. Some gas transmission infrastructure was made before the 1970s using techniques that have proven to contain latent defects due to the manufacturing process. For example, pipe manufactured using low frequency electric resistance welding is susceptible to seam failure. Because these pipelines were installed before the Federal gas regulations were issued, many of those pipes were exempted from certain regulations, most notably the requirement to pressure test the pipeline segment immediately after construction and before placing the pipeline into service. A substantial amount of this type of pipe is still in service.43 The IM regulations include specific requirements for evaluating such pipe if located in HCAs, but infrequent-yet-severe failures that are attributed to longitudinal seam defects continue to occur. The NTSB’s investigation of the PG&E incident in San Bruno determined that the pipe failed due to a similar defect, a fracture originating in the partially welded longitudinal seam of the pipe. According to PHMSA’s accident and incident database, between 2010 and 2017, 30 other reportable incidents were 41 On September 29, 2013, the Tesoro High Plains pipeline leaked 20,000 barrels of crude oil in a North Dakota field. The location of pressure and flow monitoring equipment had not been changed to account for the reversed flow. On March 19, 2013, Exxon’s Pegasus pipeline failed; the flow on that pipeline was reversed in 2006. 42 ‘‘Pipeline Safety: Guidance for Pipeline Flow Reversals, Product Changes, and Conversion to Service,’’ ADB PHMSA–2014–0040, 79 FR 56121; September 18, 2014. 43 Currently, PHMSA’s data shows that roughly 168,000 of the Nation’s 301,000 miles of onshore gas transmission pipelines were installed prior to the 1970 requirement for hydrostatic pressure testing. See https://hip.phmsa.dot.gov/ analyticsSOAP/saw.dll?PortalPages. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 attributed to seam failures, resulting in over $18 million of reported property damage. Protecting the Safety and Integrity of the Nation’s Pipeline System Beyond HCAs The current IM program improves pipeline operators’ ability to identify and mitigate the risks to their pipeline systems. IM regulations require that operators adopt procedures and processes to identify HCAs; determine likely threats to the pipeline within the HCA; evaluate the physical integrity of the pipe within the HCA; and repair, remediate, or monitor any pipeline defects found based on severity. Because these procedures and processes are complex and interconnected, effective implementation of an IM program relies on continual evaluation and data integration. HCAs were first defined on August 6, 2002,44 providing concentrations of populations with corridors of protection spanning 300, 660, or 1,000 feet, depending on the diameter and MAOP of the particular pipeline.45 In a later NPRM,46 PHMSA proposed changes to the definition of a HCA by introducing the concept of a covered segment, which PHMSA defined as the length of gas transmission pipeline that could potentially impact an HCA.47 Previously, only distances from the pipeline centerline related to HCA definitions. PHMSA also proposed using Potential Impact Circles (PIC), Potential Impact Zones, and Potential Impact Radii (PIR) to identify covered segments instead of a fixed corridor width. The final Gas Transmission Pipeline Integrity Management Rule, incorporating the new HCA definition using the PIR and PIC concepts, was issued on December 15, 2003.48 The PG&E incident in 2010 motivated a comprehensive reexamination of gas transmission pipeline safety. In response to the PG&E incident, Congress 44 ‘‘Pipeline Safety: High Consequence Areas for Gas Transmission Pipelines,’’ Final rule, 67 FR 50824; August 6, 2002. 45 The influence of the existing class location concept on the early definition of HCAs is evident from the use of class locations themselves in the definition, and the use of fixed 660 ft. distances, which corresponds to the corridor width used in the class location definition. This concept was later significantly revised, as discussed later, in favor of a variable corridor width based on case-specific pipe size and operating pressure. 46 ‘‘Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines),’’ Notice of Proposed Rulemaking, 68 FR 4278; January 28, 2003. 47 HCA and PIR definitions are in 49 CFR 192.903. 48 ‘‘Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines),’’ Final rule, 68 FR 69778; December 15, 2003. PO 00000 Frm 00008 Fmt 4701 Sfmt 4700 passed the 2011 Pipeline Safety Act, which directed PHMSA to reexamine many of its safety requirements, including the expansion of IM regulations for transmission pipelines. Further, both the NTSB and the GAO issued several recommendations to PHMSA to improve its IM program and pipeline safety. The NTSB noted in a 2015 study 49 that IM requirements have reduced the rate of failures due to deterioration of pipe welds, corrosion, and material failures. However, the NTSB noted that pipeline incidents in HCAs due to other factors increased between 2010 and 2013, and the overall occurrence of gas transmission pipeline incidents in HCAs has remained stable. Since 2013 there have been an average of 9 incidents within HCAs, which is below a peak of 12 incidents per year in 2012 and 2013, but still higher than the number of incidents in 2010 and 2011. The NTSB also found many types of basic data necessary to support comprehensive probabilistic modeling of pipeline risks are not currently available. Looking at Risk Beyond HCAs PHMSA posed a series of questions to the public in the context of an August 25, 2011, ANPRM titled ‘‘Safety of Gas Transmission Pipelines’’ (76 FR 53086), including whether the regulations governing the safety of gas transmission pipelines needed changing. In particular, PHMSA asked whether to add prescriptive language to IM requirements, and whether other issues related to system integrity should be addressed by strengthening or expanding non-IM requirements. PHMSA sought comment on the definition of an HCA and whether additional restrictions should be placed on the use of DA as an IM assessment method. PHMSA also requested comment on non-IM requirements, including valve spacing and installation, corrosion control, and whether regulations for gathering lines needed to be modified. PHMSA received 103 submissions containing thousands of comments in response to the ANPRM, which are summarized in more detail below. This feedback helped identify a series of proposed improvements to IM, including improvements to assessment goals such as integrity verification, MAOP verification, and material documentation; adjusted repair criteria; clarified protocol for identifying threats, 49 National Transportation Safety Board, ‘‘Safety Study: Integrity Management of Gas Transmission Pipelines in High Consequence Areas,’’ NTSB SS– 15/01, January 27, 2015. E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations risk assessments and management, and prevention and mitigation measures; expanded and enhanced corrosion control; requirements for inspecting pipelines after incidents of extreme weather; and new guidance on how to calculate MAOP in order to set operating parameters more accurately and predict the risks of an incident. PHMSA published an NPRM on April 8, 2016 (81 FR 20722), which is discussed in more detail below. Many of these aspects of IM have been an integral part of PHMSA’s expectations since the inception of the IM program. As specified in the first IM rule, PHMSA expects operators to start with an IM framework, evolve a more detailed and comprehensive IM program, and continually improve their IM programs as they learn more about the IM process and the material condition of their pipelines through integrity assessments. Section 23 of the 2011 Pipeline Safety Act required PHMSA to have pipeline operators conduct a records verification to ensure that their records accurately reflect the physical and operational characteristics of their pipelines in certain HCAs and class locations, and to confirm the established MAOP of those pipelines. Based on the data received from operators following the records verification, incidents that have occurred in non-HCA areas, and other knowledge gained since the 2011 Pipeline Safety Act was passed, PHMSA has become increasingly concerned that a rupture on the scale of San Bruno, with the potential to cause death and serious injury, as well as damage to the environment or the disruption of commerce, could occur elsewhere on the Nation’s pipeline system in both HCA and non-HCA pipeline segments. There have been several recent incidents in non-HCAs that show significant incidents can occur in nonHCAs. For example, on December 14, 2007, two men were driving in a pickup truck on Interstate 20 near Delhi, LA, when a 30-inch gas transmission pipeline owned by Columbia Gulf Transmission Company ruptured. One of the men was killed, and the other was injured. Further, on December 11, 2012, a 20inch-diameter gas transmission line operated by Columbia Gas Transmission Company ruptured about 106 feet west of Interstate 77 (I–77) in Sissonville, WV. An area of fire damage about 820 feet wide extended nearly 1,100 feet along the pipeline right-of-way. Three houses were destroyed by the fire, and several other houses were damaged. Reported losses, repairs, and upgrades from this incident totaled over $8.5 VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 million, and major transportation delays occurred. I–77 was closed in both directions because of the fire and resulting damage to the road surface. The northbound lanes were closed for approximately 14 hours, and the southbound lanes were closed for approximately 19 hours while the road was resurfaced, causing delays to both travelers and commercial shipping. Finally, on April 29, 2016, an incident occurred on a Texas Eastern Transmission Corporation gas transmission line operated by Spectra Energy near Delmont, PA, which is approximately 25 miles away from Pittsburgh, PA. The explosion seriously injured one person, destroyed a house, damaged three other homes and vehicles outside, and caused the evacuation of nine other homes in the area. Even though the pipeline was in a Class 1 rural area, it still had a significant impact on the local population. The Nation’s population is growing, moving, and dispersing, leading to changes in population density that can affect the class location of a pipeline segment, as well as whether it is in an HCA. The definition of HCA is not necessarily an accurate reflection of whether an incident will have an impact on people. Requiring assessment and repair criteria for pipelines that, if ruptured, could pose a threat to areas where any people live, work, or congregate would improve public safety and would improve public confidence in the Nation’s natural gas pipeline system. Some pipeline operators have said they are already moving towards expanding the protections of IM beyond HCAs. In 2012, the Interstate Natural Gas Association of America (INGAA) issued a ‘‘Commitment to Pipeline Safety,’’ 50 underscoring its efforts towards a goal of zero incidents, a committed safety culture, a pursuit of constant improvement, and applying IM principles on a system-wide basis. To accomplish this goal, INGAA’s members committed to performing actions that include applying risk management beyond HCAs; raising the standards for corrosion management; demonstrating ‘‘fitness for service’’ on pre-regulation pipelines; and evaluating, refining, and 50 Letter from Terry D. Boss, Senior Vice President of Environment, Safety and Operations to Mike Israni, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, dated January 20, 2012, ‘‘Safety of Gas Transmission Pipelines, Docket No. PHMSA– 2011–0023.’’ INGAA represents companies that operate approximately 65 percent of the gas transmission pipelines, but INGAA does not represent all pipeline operators subject to 49 CFR part 192. PO 00000 Frm 00009 Fmt 4701 Sfmt 4700 52187 improving operators’ ability to assess and mitigate safety threats. These actions aim to extend protection to people who live near pipelines but not within defined HCAs. Further, this final rule takes important steps toward developing a comprehensive approach for the entire industry by finalizing requirements for assessments outside of HCAs. This final rule implements risk management standards that most accurately target the safety of communities while also providing sufficient ability to prioritize areas of greatest possible risk and impact. Given the results of incident investigations, IM considerations, and the feedback from the ANPRM and the NPRM, PHMSA has determined it is appropriate to improve aspects of the current IM program and codify requirements for additional gas transmission pipelines to receive integrity assessments on a periodic basis to monitor for, detect, and remediate pipeline defects and anomalies. In addition, to achieve the desired outcome of performing assessments in areas where people live, work, or congregate, while balancing the cost of identifying such locations, PHMSA based the requirements for identifying those locations on effective processes already being implemented by pipeline operators and that protect people on a risk-prioritized basis. Establishing integrity assessment requirements for non-HCA pipeline segments is important for providing safety to the public. Although those pipeline segments are not within defined HCAs, they will usually be in populated areas, and pipeline accidents in these areas may cause fatalities, significant property damage, or disrupt livelihoods. This final rule adopts a newly defined definition for MCAs to identify additional non-HCA pipeline segments that would require integrity assessments, thus assuring the timely discovery and repair of pipeline defects in MCA segments that could potentially impact people, property, or the environment. At the same time, operators can allocate their resources to HCAs on a higher-priority basis. B. Pacific Gas and Electric Incident of 2010 On September 9, 2010, a 30-inchdiameter segment of a gas transmission pipeline owned and operated by PG&E ruptured in a residential neighborhood in San Bruno, CA, producing a crater approximately 72 feet long by 26 feet wide. The segment of pipe that ruptured weighed approximately 3,000 pounds, was 28 feet long, and was found 100 feet E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 52188 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations south of the crater. Over the course of the incident, 47.6 million standard cubic feet of natural gas was released. The escaping gas ignited, and the resultant fire destroyed 38 homes, damaged another 70, killed 8 people, injured approximately 60 people (10 seriously), destroyed or damaged 74 vehicles, and caused the evacuation of over 300 more people. The initial 911 calls described the fire as a ‘‘gas station explosion’’ and a ‘‘possible airplane crash.’’ After 91 minutes, PG&E was able to shut off the flow of gas to the rupture site, which allowed firefighters to approach the rupture site and begin containment efforts. Firefighting operations continued for 2 days; more than 900 emergency responders from San Bruno and surrounding areas were part of the emergency response, 600 of which were firefighters and emergency medical services personnel.51 The NTSB, in its pipeline accident report for the incident, determined that the probable cause of the accident was PG&E’s inadequate quality assurance and control when it relocated the line in 1956 and an inadequate IM program. The NTSB determined that PG&E’s IM program was deficient and ineffective because it was based on incomplete and inaccurate pipeline information, did not consider the pipeline’s design and materials contribution to the risk of a pipeline failure, and failed to consider the presence of previously identified welded seam cracks as part of its risk assessment. These deficiencies resulted in the selection of an examination method that could not detect welded seam defects and led to internal assessments of PG&E’s IM program that were superficial and resulted in no improvements. Ultimately, this inadequate IM program failed to detect and repair or remove the defective pipe section. The NTSB found that PG&E’s inaccurate geographic information system records at the time of the incident indicated that the ruptured segment was constructed from 30-inchdiameter seamless API 5L X42 steel pipe. However, seamless pipe has never been available in 30-inch diameter. According to PG&E employees who testified during the investigation, all 30inch pipe purchased by PG&E at that time would have been double submerged arc welded, which has been found in cases to be susceptible to weld failure. This inaccuracy was 51 National Transportation Safety Board. 2011. Pacific Gas and Electric Company Natural Gas Transmission Pipeline Rupture and Fire, San Bruno, California, September 9, 2010. Pipeline Accident Report NTSB/PAR–11/01. Washington, DC. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 compounded with the discovery that the material code from the journal voucher that PG&E’s records were originally composed from erroneously indicated the ruptured segment was X52 grade pipe (52,000 pounds per square inch (psi)), not X42 grade pipe (42,000 psi). X52 pipe has a higher minimum yield strength than X42 pipe,52 and incorporating such values into MAOP calculations would produce values that would be inconsistent with the pipeline’s actual MAOP. PG&E also could not produce any design, material, or construction specifications from the 1956 construction project. In short, no one from PG&E could reliably determine what type of pipe was in the ground that ruptured. The NTSB also noted that PHMSA’s exemption of pipelines installed before 1970 from the regulatory requirement for pressure testing, which likely would have detected the installation defects, was a contributing factor to the accident. When the initial Federal minimum safety standards for natural gas transmission pipelines were finalized in 1970, an exemption was carved out for pre-1970s pipelines from the requirement for a post-construction hydrostatic pressure test. This exemption was not proposed in any of the NPRMs that preceded the initial regulations and was based on an assertion from the Federal Power Commission 53 that ‘‘there are thousands of miles of jurisdictional interstate pipelines installed prior to 1952,54 in compliance with the then-existing codes, that could not continue to operate at their present pressure levels and be in compliance with [the proposed MAOP determination requirements].’’ 55 Upon reviewing the operating record of interstate pipeline companies, the Commission found ‘‘no evidence that would indicate a material increase in safety would result from requiring wholesale reductions in the pressure of existing pipelines which have been proven capable of withstanding present operating pressures through actual operation.’’ The Office of Pipeline Safety, at the time, determined it ‘‘[did] not now have enough information to determine that existing operating pressures are unsafe,’’ and taking into account the statements from the Federal Power Commission, included the ‘‘grandfather’’ clause in the final rule to permit the continued operation of pipelines at the highest pressure to which the pipeline had been subjected during the 5 years preceding July 1, 1970.56 57 The 5-year limit was prescribed so that operators would be prevented from ‘‘using a theoretical MAOP which may have been determined under some formula used 20, 30, or 40 years ago.’’ 58 The NTSB noted in its investigation that the ‘‘grandfathering’’ of the ruptured line resulted in missed opportunities to detect the defective pipe, as a hydrostatic pressure test to the prescribed levels for a Class 3 location would likely have exposed the defective pipe that led to the accident. Following the PG&E incident, the California Public Utilities Commission (CPUC) required PG&E and other gas transmission pipeline operators regulated by CPUC to either hydrostatically pressure test or replace certain transmission pipelines with grandfathered MAOPs, stating that gas transmission pipelines ‘‘must be brought into compliance with modern standards for safety’’ and that ‘‘historic exemptions must come to an end.’’ 59 Currently, PHMSA’s data shows that roughly 168,000 of the Nation’s 301,000 miles of onshore gas transmission pipelines were installed prior to the 1970 requirement for hydrostatic pressure testing.60 On April 1, 2014, the Department of Justice indicted PG&E for multiple criminal violations of part 192 for the 2010 incident in San Bruno, CA. The trial began on June 14, 2016, and after a 5 1⁄2 week trial, a Federal jury found PG&E guilty of knowingly and willingly violating 5 sections of PHMSA’s IM regulations and obstructing the NTSB investigation. Specifically, with respect to the Federal Pipeline Safety Regulations, the jury found that between 2007 and 2010, PG&E knowingly and willfully failed to: (1) Gather and integrate existing data and information that could be relevant to identifying and evaluating potential threats on covered pipeline segments; (2) identify and evaluate all potential 56 35 52 52,000 psi vs. 42,000 psi. 53 The predecessor of the Federal Energy Regulatory Commission. 54 Between 1935 and 1951, the B31 Code only required a pipeline be tested to a pressure of 50 psig in excess of the pipeline’s proposed MAOP. The 1970 regulations required pressure testing to 125 percent in excess of the proposed MAOP. 55 ‘‘Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards,’’ 35 FR 13248; August 19, 1970. PO 00000 Frm 00010 Fmt 4701 Sfmt 4700 FR 13248. requirement is currently under § 192.619(c). 58 35 FR 13248. 59 ‘‘Decision Determining Maximum Allowable Operating Pressure Methodology and Requiring Filing of Natural Gas Transmission Pipeline Replacement or Testing Implementation Plans;’’ California Public Utilities Commission Order; June 9, 2011. 60 https://hip.phmsa.dot.gov/analyticsSOAP/ saw.dll?PortalPages. 57 This E:\FR\FM\01OCR2.SGM 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES2 threats to each covered pipeline segment; (3) include in its baseline assessment plan all potential threats on a covered segment and to select the most suitable assessment method; (4) prioritize high-risk pipeline segments for assessment where certain changed circumstances rendered the manufacturing threats on those segments unstable; and (5) prioritize pipeline segments containing lowfrequency ERW pipe or other similar pipe as a high-risk segment for assessment if certain changed circumstances rendered a manufacturing seam threat on that segment unstable. Congress required PHMSA, per the 2011 Pipeline Safety Act, to issue regulations to confirm the material strength of previously untested natural gas transmission pipelines located in HCAs and operating at a pressure greater than 30 percent of SMYS. Through this final rule, PHMSA is implementing that congressional directive and other safety measures. This final rule will improve the safety and public confidence of the Nation’s onshore natural gas transmission pipeline system. C. Advance Notice of Proposed Rulemaking On August 25, 2011, PHMSA published an ANPRM to seek public comments regarding the revision of the Federal Pipeline Safety Regulations applicable to the safety of gas transmission pipelines. In the 2011 ANPRM, PHMSA requested comments on 122 questions spread through 15 broad topic areas covering both IM and non-IM requirements. Among the issues related to IM that PHMSA considered included whether the definition of an HCA should be revised and whether additional restrictions should be placed on the use of certain pipeline assessment methods. PHMSA also requested comment on non-IM regulations, including whether revised requirements are needed for mainline valve spacing and actuation, whether requirements for corrosion control should be strengthened, and whether new regulations are needed to govern the safety of gas gathering lines and underground natural gas storage facilities. Based on the comments received on several of the ANPRM topics, PHMSA developed proposals for some of those topics in a NPRM that is the basis for this final rule. That NPRM and the comments received, are discussed below. PHMSA did not find it appropriate to address all the topics in a single rulemaking. Those topics that were not discussed further in the NPRM VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 for this final rule have been discussed or will be discussed in other rulemakings. D. National Transportation Safety Board Recommendations On August 30, 2011, following the issuance of the ANPRM, the NTSB adopted its report on the gas pipeline incident that occurred on September 9, 2010, in San Bruno, CA. On September 26, 2011, the NTSB issued safety recommendations P–11–8 through -20 to PHMSA. Several of the NTSB’s recommendations related directly to the topics discussed in the 2011 ANPRM and 2016 NPRM, and they shaped the direction of this final rule. The NTSB recommendations addressed in this final rule include: • Exemption of Facilities Installed Prior to the Regulations. NTSB Recommendation P–11–14: Amend Title 49 Code of Federal Regulations 192.619 to repeal exemptions from pressure test requirements and require that all gas transmission pipelines constructed before 1970 be subjected to a hydrostatic pressure test that incorporates a spike test.’’ • Pipe Manufactured Using Longitudinal Weld Seams. NTSB Recommendation P–11–15: ‘‘Amend Title 49 Code of Federal Regulations Part 192 of the Federal pipeline safety regulations so that manufacturing- and construction-related defects can only be considered stable if a gas pipeline has been subjected to a post-construction hydrostatic pressure test of at least 1.25 times the maximum allowable operating pressure.’’ • Incorporating interstates, highways, etc., into the list of ‘‘identified sites’’ that establish a HCA. NTSB Recommendation P–14–1: ‘‘Revise Title 49 CFR Section 903, Subpart O, Gas Transmission Pipeline Integrity Management, to add principal arterial roadways including interstates, other freeways and expressways, and other principal arterial roadways as defined in the Federal Highway Administration’s ‘‘Highway Functional Classification Concepts, Criteria and Procedures’’ to the list of ‘‘identified sites’’ that establish an HCA. • Increase the use of ILI tools. NTSB Recommendation P–15–20: ‘‘Identify all operational complications that limit the use of in-line inspection tools in piggable pipelines, develop methods to eliminate the operational complications, and require operators to use these methods to increase the use of in-line inspection tools.’’ PO 00000 Frm 00011 Fmt 4701 Sfmt 4700 52189 E. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 The 2011 Pipeline Safety Act relates directly to the topics addressed in PHMSA’s ANPRM of August 25, 2011, and the NPRM issued on April 8, 2016. The related topics and statutory citations include, but are not limited to: • Section 5(e)—Allow periodic reassessments to be extended for an additional 6 months if the operator submits sufficient justification. • Section 5(f)—Requires the expansion of IM system requirements, or elements thereof, beyond HCAs, if appropriate. • Section 23—Requires the reporting of each exceedance of the MAOP that exceeds the build-up allowed for the operation of pressure-limiting or -control devices. • Section 23—Requires testing to confirm the material strength of previously untested natural gas transmission pipelines and pipelines lacking records that accurately reflect the pipeline’s physical and operational characteristics. • Section 29—Requires consideration of seismicity when evaluating pipeline threats. F. Notice of Proposed Rulemaking On April 8, 2016, PHMSA published an NPRM seeking public comments on the revision of the Federal Pipeline Safety Regulations applicable to the safety of gas transmission pipelines and gas gathering pipelines (81 FR 20721).61 When developing the NPRM, PHMSA considered the comments it received from the ANPRM and proposed new pipeline safety requirements and revisions of existing requirements in several major topic areas, including those topics addressing congressional mandates and related NTSB recommendations. A summary of the NPRM proposals and topics pertinent to this rulemaking, the comments received on those specific proposals, and PHMSA’s response to the comments received is below under the ‘‘Analysis of Comments and PHMSA Response’’ section. PHMSA determined it could more quickly move a rulemaking that focuses on the mandates from the 2011 Pipeline Safety Act by splitting out the other provisions contained in the NPRM into two other, separate rules. Promptly issuing a final rule focused on mandates will improve safety and respond to Congress, industry, and public safety groups. 61 https://www.regulations.gov/document? D=PHMSA-2011-0023-0118. E:\FR\FM\01OCR2.SGM 01OCR2 52190 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES2 As such, not all the topics from the NPRM nor the comments received on those topics are discussed as a part of this rulemaking. PHMSA intends to issue two additional final rules to address the remaining topics from the NPRM. III. Analysis of NPRM Comments, GPAC Recommendations, and PHMSA Response On April 8, 2016, PHMSA published an NPRM (81 FR 20722) proposing several amendments to 49 CFR part 192. The NPRM proposed amendments addressing topiic areas including verification of pipeline material properties, MAOP reconfirmation, IM clarifications, MAOP exceedance reports, ILI launcher and receiver safety, assessing areas outside of HCAs, and recordkeeping. The comment period for the NPRM ended on July 7, 2016. PHMSA received approximately 300 submissions containing thousands of comments on the NPRM. Submissions were received from groups representing the regulated pipeline industry; groups representing public interests, including environmental groups; State utility commissions and regulators; members of Congress; specific pipeline operators; and private citizens. Some of the comments PHMSA received in response to the NPRM were comments beyond the scope or authority of the proposed regulations. The absence of amendments in this proceeding involving other pipeline safety issues (including several topics listed in the ANPRM) does not mean that PHMSA determined additional rules or amendments on those other issues are not needed. Such issues may be the subject of other existing rulemaking proceedings or future rulemaking proceedings. The remaining comments reflect a wide variety of views on the merits of particular sections of the proposed regulations. PHMSA read and considered all the comments posted to the docket for this rulemaking. The Technical Pipeline Safety Standards Committee, commonly known as the Gas Pipeline Advisory Committee (GPAC; the committee), is a statutorily mandated advisory committee that advises PHMSA on proposed safety standards, risk assessments, and safety policies for natural gas pipelines.62 The GPAC is one of two pipeline advisory committees that focus on technical safety standards that were established under the Federal Advisory Committee Act (Pub. L. 92–463, 5 U.S.C. App. 1– 62 49 U.S.C. 60115. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 16) and section 60115 of the Federal Pipeline Safety Statutes (49 U.S.C. Chap. 601). Each committee consists of 15 members, with membership divided among Federal and State agencies, regulated industry, and the public. The committees consider the ‘‘technical feasibility, reasonableness, costeffectiveness, and practicability’’ of each proposed pipeline safety standard and provide PHMSA with recommended actions pertaining to those proposals. Due to the size and technical detail of this rulemaking, the GPAC met five times to discuss this rulemaking throughout 2017 and 2018.63 During those meetings, the GPAC considered the specific regulatory proposals of the NPRM and discussed various comments made on the NPRM’s proposal by stakeholders, including the pipeline industry at large, public interest groups, and government entities. To assist the GPAC in its deliberations, PHMSA presented a description and summary of the major proposals in the NPRM and the comments received on those issues. PHMSA also assisted the committee by fostering discussion and developing recommendations by providing direction on which issues were most pressing. For the proposals finalized in this rulemaking, the committee came to consensus when voting on the technical feasibility, reasonableness, costeffectiveness, and practicability of the NPRM’s provisions. In many instances, the committee recommended changes to certain proposals that the committee found would make certain proposals more feasible, reasonable, cost-effective, or practicable. The substantive comments received on the NPRM as well as the GPAC’s recommendations are organized by topic below and are discussed in the appropriate section with PHMSA’s response and resolution to those comments. A. Verification of Pipeline Material Properties and Attributes—§ 192.607 i.—Applicability 1. Summary of PHMSA’s Proposal Section 23 of the 2011 Pipeline Safety Act requires the Secretary of Transportation to require the verification of records used to establish MAOP to ensure they accurately reflect the physical and operational 63 Specifically, the GPAC met on January 11–12, 2017; June 6–7, 2017; December 14–15, 2017; March 2, 2018; and March 26–28, 2018. Information on these meetings can be found at regulations.gov under docket PHMSA–2011–0023 and at PHMSA’s public meeting page: https://primis.phmsa.dot.gov/ meetings/. PO 00000 Frm 00012 Fmt 4701 Sfmt 4700 characteristics of the pipelines and to confirm the established MAOP of gas transmission pipelines. Since 2012, operators have submitted information indicating that a portion of transmission pipeline segments do not have adequate records to establish MAOP or that accurately reflect the physical and operational characteristics of the pipeline. Therefore, PHMSA determined that additional regulations are needed to implement this requirement of the 2011 Pipeline Safety Act. Specifically, PHMSA proposed that operators conduct tests and other actions needed to confirm and document the physical and operational characteristics for those pipeline segments where adequate records are not available, and PHMSA proposed standards for performing these actions. PHMSA sought to appropriately address pipeline risk without extending the requirement to all pipelines where risk and potential consequences are not as significant, such as pipelines in remote, sparsely-populated areas. As a result, PHMSA proposed criteria that would require material properties verification for higher-risk locations through a new § 192.607; specifically, by adding requirements for the verification of pipeline material properties for existing onshore, steel, gas transmission pipelines that are located in HCAs or Class 3 or Class 4 locations. 2. Summary of Public Comment Several citizen and public safety groups, including Pipeline Safety Trust (PST), Pipeline Safety Coalition, National Association of Pipeline Safety Representatives (NAPSR), Coalition to Reroute Nexus, Earthworks, and The Michigan Coalition to Protect Public Rights-of-Way, supported the proposed provisions for establishing adequate material properties documentation and records. Some of these groups noted that the need for this section in the regulations would suggest poor operator implementation of the IM requirements since the inception of subpart O back in 2003. Trade associations and pipeline industry entities were largely opposed to the material properties verification requirements for several reasons outlined below. Many trade association and pipeline industry commenters expressed concern that the material properties verification requirements were potentially retroactive. American Petroleum Institute (API) and American Gas Association (AGA) asserted that this proposal would require operators to document and verify the material properties of existing pipelines beyond E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations what was required by the regulations that were in place at the time those pipelines were put into service. These commenters stated that this retroactive requirement extends beyond the congressional authority provided to PHMSA. Several commenters, including AGL Resources, Dominion East Ohio, and New Jersey Natural Gas, expressed concern with the proposed provisions for verifying specific physical characteristics of pipelines, fittings, valves, flanges, and components for existing transmission pipelines. These stakeholders stated that it might be impossible to achieve ‘‘reliable, traceable, verifiable, and complete’’ records on a retroactive basis for existing pipelines. Some commenters, including AGA, stated that a pipeline’s MAOP should be considered confirmed and there should be no need to further document material properties to verify the MAOP if operators had a pressure test record of a test conducted at 1.25 times MAOP for the pipeline segment. Commenters also expressed concern about PHMSA’s proposed new references to the material properties verification requirements under § 192.607 throughout part 192, which could be interpreted as being applicable not only to a subset of transmission pipelines but also to distribution pipelines. Commenters stated that PHMSA did not provide justification within the NPRM for applying material properties verification requirements to distribution systems, and such requirements would significantly impact distribution systems. These commenters requested that PHMSA explicitly exclude distribution pipelines from the proposed material properties verification requirements. Similarly, some commenters urged PHMSA to restrict these requirements only to gas transmission lines operating at greater than 30 percent SMYS based on the premise that lines operating below 30 percent SMYS, in most cases, tend to leak before rupture and are therefore less risky to the public. Additionally, commenters suggested that PHMSA review the various cross-references in the NPRM and eliminate those that would expand the applicability of the material properties verification requirements beyond onshore steel gas transmission pipelines in HCAs and Class 3 and Class 4 locations. Some commenters recommended changing the size limit for small components that might trigger the material properties verification requirements from greater-than-orequal-to 2 inches to greater-than 2 inches. A further comment on components discussed how the material VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 properties verification provisions, as proposed, require the operator to know the weld-end bevel conditions for inservice valves and flanges. Operators noted, however, that once a weld-end is welded to a piece of pipe or other component, there is no method that can be employed to determine the condition of that bevel. Accordingly, the commenters requested this requirement be deleted or clarified. There was also a comment to delete the sampling requirement and not perform material properties verification if, when the applicable pipeline is excavated for repairs, a repair sleeve is installed. Other commenters felt that the proposed material properties verification requirements would not deliver clear, identifiable safety benefits and would lead to several unintended consequences that would decrease the integrity of pipeline systems and cause energy supply disruption. Accordingly, these commenters suggested PHMSA withdraw the proposed requirements for material properties verification. Multiple commenters also expressed concerns that the revised provisions for establishing MAOP under § 192.619, specifically the requirement for operators to maintain all records necessary to establish and document a pipeline’s MAOP as long as the pipeline remains in service, would impose extensive new recordkeeping requirements applicable to operators of distribution pipelines, including retroactive recordkeeping requirements. Commenters requested that PHMSA clarify that the new recordkeeping requirements in § 192.619(f) are applicable only to gas transmission pipelines. Pipeline industry entities also provided comments on the relationship of the material properties verification requirements in § 192.607 and the MAOP reconfirmation requirements in § 192.624. The Gas Piping Technology Committee (GPTC) suggested that the proposed material properties verification requirements be revised to include an option of using the provisions of § 192.619(a)(1) for establishing MAOP when traceable, verifiable, and complete material property records are not available for calculating design pressure. Similarly, commenters suggested operators should be allowed to establish design yield strengths for unknown pipe grade as described at § 192.107(b)(1). Xcel Energy also stated that if an operator has previously established MAOP as per the § 192.619(a)(2) strength test requirements or will do so per the proposed § 192.624 methodology for pressure test or pressure reduction, the PO 00000 Frm 00013 Fmt 4701 Sfmt 4700 52191 verification of pipeline material proposed in § 192.607 is not necessary for the purpose of ensuring safe operation. Over the course of the meetings on June 7, 2017, and December 14, 2017, the GPAC had a robust discussion regarding the applicability of the material properties verification requirements. More specifically, the GPAC discussed the fact that two separate activities drive the need for material properties verification: (1) MAOP reconfirmation for pipelines lacking traceable, verifiable, and complete records to support the pipeline’s current MAOP; and (2) the application of IM principles, especially where anomaly response and remediation calculations are concerned. The GPAC believed these aspects needed to be addressed separately in the final rule. Subsequently, on December 14, 2017, the GPAC recommended that PHMSA modify the proposed rule by removing the applicability criteria of the material properties verification requirements and make material properties verification a procedure for obtaining missing or inadequate records or otherwise verifying pipeline attributes if and when required by MAOP reconfirmation requirements or by other code sections. In discussing the issue, the GPAC recognized that the broad applicability of the material properties verification requirements in the proposed rule was PHMSA’s attempt to address the issue of inadequate records for MAOP verification, IM requirements and standard pipeline operations. The GPAC believed amending the proposed rule to remove the proposed applicability and instead explicitly refer back to the material properties verification requirements, when needed, in various regulatory sections, would more closely follow Congress’ direction in the 2011 Pipeline Safety Act. This change would also obviate the need for operators to create a material properties verification program plan per the originally proposed requirements, so the GPAC recommended PHMSA remove that requirement from the rule. Further, the committee recommended during a later meeting that PHMSA consider modifying the rule in both §§ 192.607 and 192.619 to clarify that the material properties verification requirements apply to onshore steel gas transmission lines and not to distribution or gathering pipelines. 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding the scope and requirements for E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 52192 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations reconfirming the material properties of pipelines with unknown or undocumented properties. PHMSA agrees that the need for this rule is caused, in part, by poor implementation of existing IM requirements. However, PHMSA disagrees that the requirements would not deliver safety benefits or would lead to decreased integrity of pipeline systems and cause energy supply disruption. The basic knowledge of pipeline material properties is essential to pipeline safety. PHMSA disagrees that material properties verification is not needed if the pipeline segment has been pressure tested to 1.25 times MAOP. Other reasons for needing documented, confirmed material properties (e.g., wall thickness, yield strength, and seam type) include IM program requirements, implementation of pipe repair criteria and determination of the design pressure of the pipeline segment. This rule supplements existing IM requirements by providing operators a method to reconfirm material properties without necessarily performing destructive testing of the pipe material. Operators can use this method in their IM programs, to reconfirm MAOP where needed, to implement repair requirements, and to otherwise comply with part 192 where necessary. Indeed, PHMSA hopes that operators will use this method for material properties verification even when not specifically required by part 192 because it provides a common-sense, opportunistic, and practical approach for gathering the records necessary to substantiate safe MAOPs, properly implement IM, and otherwise ensure the safe operation of the nation’s pipeline network. PHMSA also disagrees that material properties verification is only needed for pipeline segments operating at pressure greater than 30 percent of SMYS. IM requirements apply to all gas transmission pipeline segments in HCAs, including those that operate at less than 30 percent of SMYS. Moreover, the gas transmission subpart O integrity management regulations at § 192.917(b), Data gathering and integration, require operators to gather pipe attributes including pipe wall thickness, diameter, seam type and joint factor, manufacturer, manufacturing date, and material properties. These physical properties and attributes are explicitly outlined in ASME/ANSI B31.8S—2004 Edition, section 4, table 1—Data Elements for Prescriptive Pipeline Integrity Program, which is incorporated by reference in § 192.7. PHMSA did not intend that the requirements proposed in § 192.607 would be retroactive or would apply to VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 distribution or gathering lines. Therefore, PHMSA is clarifying the final rule to assure that the provisions finalized in § 192.607 are not retroactive 64 and apply only to transmission lines. However, PHMSA believes that operators with IM programs that are properly following subpart O, specifically § 192.917(b), should already have this pipe information. Regarding material properties verification for non-line pipe components, PHMSA is revising this final rule to apply the requirements to components greater than 2 inches and is removing the requirement to know the weld-end bevel conditions. PHMSA agrees with the GPAC members who commented that 2-inch pipe is not used in mainline applications and need not be subject to additional regulatory requirements to maintain safety. Also, fittings and flanges will have an ANSI class rating that will confirm whether the components meet or exceed the MAOP of the pipeline, so further regulatory requirements for components under 2 inches are not necessary to maintain safety. To further address comments and the GPAC recommendations related to the scope and applicability of the material properties verification requirements, PHMSA is modifying this final rule to address MAOP reconfirmation and material properties verification separately from the application of IM principles. PHMSA believes this change will improve the organization of the rule. PHMSA is accomplishing this by removing the applicability criteria of the material properties verification requirements and making material properties verification a procedure for obtaining records for physical pipeline properties and attributes that are not documented in traceable, verifiable, and complete records or otherwise verifying physical pipeline properties and attributes when required by MAOP reconfirmation requirements, IM requirements, repair requirements, or other code sections. This obviates the need for all operators to create a material properties verification program plan per the originally proposed requirements, so PHMSA is removing that requirement from the rule as well. 64 The material properties verification requirements are not retroactive as they mandate the creation and retention of records as operators execute the methodology in § 192.607 on a prospective basis. Operators who have not verified their records in accordance with this methodology before the effective date of this rule will not be subject to enforcement action based on § 192.607. After the effective date of the rule, operators with missing or inadequate records must follow the verification methodology in § 192.607. PO 00000 Frm 00014 Fmt 4701 Sfmt 4700 Instead, only operators who do not have traceable, verifiable, and complete records will be required to create such a plan. A. Verification of Pipeline Material Properties and Attributes—§ 192.607 ii.—Method 1. Summary of PHMSA’s Proposal The conventional method for determining the properties of unknown steel pipe material is to cut test specimens known as ‘‘coupons’’ out of the pipe and perform destructive testing. Because of the large amount of pipe operators reported in Annual Report submissions for which there are unknown or inadequately documented properties, the cost of such a conventional approach would likely be onerous. Therefore, PHMSA proposed standards in § 192.607 by which operators could develop a material properties verification plan and use an opportunistic sampling technique to reconstitute and document material properties in a more cost-effective manner. More specifically, PHMSA proposed to allow operators to use recently developed technology to perform in situ, non-destructive examinations for determining the properties of unknown steel pipe material. While PHMSA acknowledged in the preamble of the NPRM that such techniques may not be possible in every situation, PHMSA stated that it was aware that this option is already being widely deployed in the pipeline industry. Secondly, PHMSA proposed to allow operators to determine pipe properties at a sampling of similar locations and apply those results to the entire population of pipeline segments. PHMSA proposed to allow operators to take advantage of opportunities when the pipeline is exposed for other reasons, such as during maintenance and repair excavations, by requiring that material properties be verified whenever the pipe is exposed. This would reduce the number of excavations that might otherwise be required. Excavations are a large portion of the cost of reconstituting material properties for unknown pipe. 2. Summary of Public Comment Several commenters suggested that the data required by the material properties verification process proposed by PHMSA can be obtained only through destructive pipe testing. These commenters asserted that the proposed requirements would lead to unnecessary service outages, increased methane emissions, and increased personnel E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations safety risks due to unnecessary excavation activities. Black Hills Energy stated that their pipeline system consists of mainly smaller-diameter transmission pipelines and that the proposed provisions would force them to take lines out of service to perform costly cutouts. API asserted that the expense and risk required for the excavations necessary to comply with the proposed provisions outweigh the value of obtaining and documenting material pipe properties. Some commenters suggested that it would be less costly for operators to simply replace pipe rather than obtain the material properties for pipe already in the ground. A commenter asserted that the proposed requirements would require unnecessary breaching of the pipeline coating, which is important for effective cathodic protection. API suggested that rather than requiring operators to gather documentation on material properties that may only be of marginal value for assessing pipeline safety, PHMSA should require a combination of hydrostatic pressure testing and ILI. API stated that, as opposed to the proposed rule’s focus on the precise documentation of materials, this would appropriately shift the emphasis of the proposed regulations to confirming MAOP and away from material properties verification. Several commenters stated that some of the data that PHMSA proposed operators verify is unnecessary for MAOP reconfirmation or other operational reasons. For example, the Interstate Natural Gas Association of America (INGAA) stated that several of the data elements that would need to be verified pursuant to the proposed material properties verification requirements are unnecessary for integrity management-related activities. Commenters suggested that PHMSA limit the required records to what is needed to calculate design pressure in order to determine MAOP. Commenters noted that the proposed requirements would require testing for stress corrosion cracking (SCC) in all cases, and that the requirement should be limited to only pipelines that are susceptible to SCC. Some commenters disagreed with the requirement to determine and keep a record for the chemical composition of steel transmission pipeline segments installed prior to the effective date of the final rule, suggesting that this information has not been previously required. Another commenter stated that the basis for having accurate chemical composition records is unclear. PG&E recommended that VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 PHMSA recognize that chemical composition and manufacturing specifications provide limited information that can be used to evaluate the safety of an existing pipeline system. Piedmont Natural Gas stated that any requirement to retroactively obtain ultimate tensile strength and chemical composition is unnecessarily burdensome and detracts from the ultimate goal of pipeline safety by diverting valuable resources away from other risk-reduction efforts. A similar comment asserted there was no benefit in determining pipeline chemical compositions, as there is a high probability that many pipelines that might otherwise have adequate material documentation would fail the recordkeeping requirements because of a lack of existing chemical composition records and would subsequently be subject to the entire material properties verification process. Pipeline industry entities also commented on the proposed sampling and testing requirements that would occur during excavations. Commenters asserted that the sampling requirements should be removed, and the number of excavations should not be specified. One commenter stated that the minimum number of excavations should be determined by the operator in their material properties verification plan and through statistical analysis aimed at achieving targeted confidence levels. Texas Pipeline Association (TPA) stated that there is no technical justification for the number of material properties tests being required at each test location by the proposed rule, and that the requirement of five tests in each circumferential quadrant for nondestructive tests and one test in each circumferential quadrant for destructive tests is unsupported in the proposal. TPA further stated that they are unaware of any indication that there is great variability in material properties within the body of a pipe, and that presently, material properties verification involves a single test per cylinder. Additionally, commenters stated this requirement could be unnecessarily costly and have a negative impact on pipeline safety, as the integrity of the pipeline would need to be compromised to perform these evaluations and a new joint of pipe would need to be welded onto the existing pipeline. Lastly, Spectra Energy Partners objected to the requirement that non-destructive testing be validated with unity plots comparing the results from non-destructive and destructive testing. They stated that this severely limits the value of non-destructive PO 00000 Frm 00015 Fmt 4701 Sfmt 4700 52193 testing since the operator will have to remove samples for destructive testing to create the unity plots. CenterPoint Energy stated that the definition of excavation is unclear, and that pipe may be excavated to a point for many operational activities, including spotting for construction safety and installing cathodic protection tests or current source wires. CenterPoint Energy stated that they do not view these types of excavations as opportunities for material properties verification data gathering because that would require the full exposure of a pipeline segment and the removal of good coating from the pipe. Another commenter suggested that confidence specifications for non-destructive testing would add significant cost due to inherently inaccurate test results. Similarly, there were comments that encouraged consistency between the material properties verification requirements and the requirements for recordkeeping for materials, pipe design, and pipeline components. These comments suggested that inconsistencies between the documentation and the recordkeeping requirements could create scenarios where operators meet the recordkeeping requirements but do not have adequate documentation to prevent the material properties verification requirements from triggering. Some commenters opposed the proposed requirement to obtain a ‘‘no objection’’ letter from PHMSA in order to use a new or other technology. PG&E recommended that PHMSA provide additional regulatory language to allow an operator to proceed with the new technology if a ‘‘no objection letter’’ to PHMSA is not received within 45 days prior to the planned use of technology. They stated that operators put in considerable time to set up contracts, schedule work, acquire permits, and that waiting on an approval or disapproval from PHMSA can dramatically impact schedule and costs. Further, commenters suggested that PHMSA’s enforcement and regulatory procedures do not provide for ‘‘no objection’’ letters, and adding a new process that is not well-defined could cause additional confusion. AGA proposed an alternative approach to material properties verification, MAOP reconfirmation, and integrity assessments outside of HCAs, which other pipeline industry entities supported. The approach included requiring operators to either pressure test or utilize an alternative technology that is determined to be of equal effectiveness on high-risk gas transmission pipelines that do not have E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 52194 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations a record of a subpart J pressure test or are currently utilizing the grandfather clause for MAOP determination (§ 192.619(c)). AGA suggested a threetiered approach that prioritized pipelines located in HCAs and operating at pressures greater than 30 percent SMYS. The approach also included the use of ILI tools on all gas transmission pipelines that are able to accommodate inspection by means of an instrumented ILI tool. The ILI tool used would be qualified to find defects that would fail a subpart J pressure test. Commenters stated that this alternative approach is simpler and would allow operators to focus resources on the areas of highest risk within pipeline systems. In conjunction with AGA’s approach, commenters recommended including language that would allow the use of advanced ILI and non-destructive evaluations to comply with the proposed material properties verification requirements. Certain commenters also suggested PHMSA provide a deadline by which operators must implement their material properties verification plan, as it was unclear in the proposal. Following committee discussion and PHMSA feedback, industry groups also recommended to allow operators to use their own statistical sampling plans when undertaking material properties verification rather than have PHMSA specify the number of samples that must be obtained. At the GPAC meeting on December 14, 2017, the committee recommended that PHMSA modify the method for material properties verification by clarifying that operators are only required to confirm attributes pertinent to the goal of MAOP reconfirmation, integrity management, or other reasons when the material properties verification is being performed. The GPAC also recommended that PHMSA require operators keep records developed using the material properties verification method. The GPAC recommended that PHMSA retain the opportunistic approach of obtaining unknown or undocumented material properties when excavations are performed for repairs or other reasons, using a one-per-mile standard proposed by PHMSA, but allow operators to propose an alternative statistical approach and submit a notification to PHMSA with justification for their method. The GPAC also recommended that if operators notify PHMSA of an alternative sampling approach, and the operator does not receive an objection letter from PHMSA within 90 days of such a notification, the operator can proceed with their chosen method VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 unless PHMSA notifies the operator that additional review time or additional information from the operator is needed for PHMSA to complete its review. Similarly, the committee recommended PHMSA delete specified program requirements for how to address sampling failures and replace that with a requirement for operators to determine how to deal with sample failures through an expanded sample program that is specific to their system and circumstances. They further recommended that PHMSA require operators to notify PHMSA of the expanded sample program and establish a minimum standard that sampling programs must be based on a minimum 95 percent confidence level. Further, the committee recommended that PHMSA retain the flexibility for operators to conduct either destructive or non-destructive tests when material properties verification is needed and requested PHMSA drop accuracy specifications but retain the requirement that any test methods used be validated and be performed with calibrated equipment. The GPAC also recommended PHMSA reduce the number of quadrants at which nondestructive evaluation tests be made from four to two. Regarding the number of test locations and the number of excavations that must be performed, the GPAC recommended PHMSA accommodate situations where a single material properties verification test is needed (e.g., additional information is needed for an anomaly evaluation/repair) and drop the mandatory requirements for testing multiple joints for large excavations. The GPAC also recommended PHMSA clarify the applicability of the requirements for developing and implementing procedures for conducting material properties verification tests on populations of undocumented or inadequately documented pipeline segments and the minimum number of excavations and tests that must be performed for those pipeline segments. 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding the method for material properties verification. PHMSA disagrees with implementing the alternative approach proposed by AGA, but the underlying comments of AGA and others related to having an alternative approach are discussed in this rulemaking and are addressed below. PHMSA strongly believes that knowledge of pipeline physical properties and attributes are essential for a modern IM program (see PO 00000 Frm 00016 Fmt 4701 Sfmt 4700 § 192.917(b)—Data gathering and integration) as well as effective pipeline and public safety. The PG&E incident at San Bruno, CA, was caused, in part, by PG&E mistakenly classifying the pipe that failed as seamless pipe. That pipe was welded seam pipe, and the failure occurred at a partially welded seam. The NPRM included a list of material properties that could be confirmed using the material properties verification process. One of them in particular, steel toughness, is conventionally obtained only through destructive testing. It was not PHMSA’s intent that toughness would need to be confirmed every time an operator was performing material properties verification, thus in effect requiring destructive testing for every location. Therefore, PHMSA is modifying this final rule to address toughness properties in a separate paragraph and is allowing the use of techniques that are reliable without specifying destructive testing. This is intended to accommodate new, non-destructive techniques currently under development. The new paragraph with these requirements also makes it clear that toughness is required only where needed and not necessarily in every case. PHMSA is also modifying other sections of this final rule to provide reasonably conservative default toughness values so that operators may achieve the goals of IM and MAOP reconfirmation using assumed values without the need for destructive testing. These changes will be discussed further in subsequent sections of this document. Similarly, PHMSA is modifying the verbiage related to the listing of material properties to which the material properties verification process would apply. The clarification will make it clear that the material properties verification process only applies to the pertinent properties needed to achieve the goals of the activity for which material properties verification is needed, such as MAOP reconfirmation or IM. This avoids the potential for requiring that all properties be documented each time an operator goes out to perform material properties verification when only a subset of properties is needed. PHMSA is also replacing the prescriptive accuracy specifications and unity plot validation for non-destructive testing with more general verbiage that requires that methods are validated and that operators account for the accuracy of the method used. This change will help accommodate new technology and techniques currently under development and avoid situations that E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations might require destructive testing to validate the non-destructive methods. In response to the comments, PHMSA is relaxing the number of test points for non-destructive tests from four quadrants to two quadrants. This allows the operator to perform material properties verification on the top half of the pipe and would avoid the need to access the bottom half of the pipe when the repair or maintenance activity would not otherwise require it. PHMSA is also removing the proposed requirement to conduct material verification at multiple locations within a single large excavation based on the number of joints of line pipe exposed. PHMSA believes the methods described in this final rule will provide operators accurate material properties information without requiring more excavation activities than necessary. In this final rule, PHMSA is modifying § 192.607 to specifically list the types of excavations where operators that need to verify material properties should seek to conduct material properties verification. This revision intends to avoid requiring operators perform the material properties verification process at partial excavations that do not expose the pipeline segment. For example, PHMSA considers excavations associated with direct examinations of anomalies to be an opportunity to perform material properties verification. Similarly, PHMSA is modifying the language to acknowledge the need to perform onetime material properties verification activities at specific locations, such as when performing repairs. An operator who has complete material documentation for a particular pipeline segment would not need to undertake the sampling program at excavations on that particular segment. The sampling program is specifically required when the operator needs to document material properties for entire segments of pipelines. PHMSA disagrees with the removal of the number of samples needed and is maintaining the minimum standard to define the number of excavations in the sampling program as 1 per mile or 150 if the population of pipeline segments is more than 150 miles, whichever is less. However, PHMSA is modifying the rule to provide operators the option of proposing an alternative sampling program if they send a notification and justification of the alternative program to PHMSA in accordance with the new notification procedures at § 192.18. Operators may use an alternative sampling program 91 days after submitting a notification per § 192.18 to PHMSA if the operator has not received VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 a letter of objection or a request from PHMSA for more time to review. PHMSA is also withdrawing the expanded sampling requirements to address cases where operators identify problems in the initial sampling program. Instead, operators may use an alternative sampling approach that addresses how the operator’s sampling plan will address findings that reveal physical pipeline properties and attributes that are not consistent with all available information or existing expectations or assumed physical pipeline properties and attributes used for pipeline operations and maintenance in the past. Operators taking such an approach must notify PHMSA of the adverse findings and provide PHMSA with specific details of the alternative sampling plan with a justification for such a plan in a notification to PHMSA. The alternative sampling program must be designed to achieve a 95 percent confidence level. In accordance with the new notification procedures at § 192.18, operators may use an alternative sampling plan 91 days after submitting a notification to PHMSA if the operator has not received a letter of objection or a request from PHMSA for more time to review. In response to committee discussion, PHMSA is modifying its notification process broadly throughout part 192 to allow operators to propose using methods and technologies by notifying PHMSA in accordance with the new procedures in § 192.18. If an operator does not receive a letter of objection or a request from PHMSA for more time to review within 90 days of the notification, then the operator may use the proposed method or technology. Some committee members were concerned that some provisions throughout the NPRM would require action from PHMSA in the form of a ‘‘no objection’’ letter. Members noted that such a process can leave companies unable to proceed until PHMSA provided affirmative approval of the request. Committee members suggested that it may be more efficient and less burdensome for PHMSA to issue letters to operators only when they specifically object to proposed plans or solutions, and otherwise allow the operator to proceed as planned in the absence of such a letter. Other members were concerned that PHMSA might authorize sub-optimal plans or technologies by missing a deadline. To this end, members recommended an approach where PHMSA could request additional time for review beyond the 90-day period. PHMSA noted at the meeting that this is a similar process that is used by PHMSA for state waivers and the PO 00000 Frm 00017 Fmt 4701 Sfmt 4700 52195 change should improve regulatory efficiency. PHMSA’s letter or email of objection will specify the reasons PHMSA does not approve of the proposed method or technology, while a request from PHMSA for more time to review the notification will extend the review period beyond 90 days. Further, to establish a verifiable record, it will be PHMSA’s policy to send a ‘‘no objection’’ letter or email, either before or after the 90-day review period, when PHMSA does not object to an operator’s proposed method or technology. PHMSA is applying this approach to other places in this rulemaking that require notifications and has created a general notification provision in subpart A of part 192. PHMSA is modifying the recordkeeping requirement for the material properties verification provisions to avoid potential conflicts with other provisions in this rulemaking, such as MAOP reconfirmation, to clarify that operators are required to keep any records created, for the life of the pipeline, when verifying specific properties using the methods in § 192.607. These records must also be traceable, verifiable, and complete. These recordkeeping requirements are not retroactive, as they mandate the creation and retention of records as operators execute the methodology in § 192.607 on a prospective basis. PHMSA disagrees with commenters that asked for PHMSA to establish a deadline for operators to complete the sampling programs. The opportunistic approach PHMSA proposed and retained for this final rule requires material properties verification activities to occur at excavation sites where operators are directly examining anomalies; performing in-situ evaluations; or are performing repairs, remediation, or maintenance. PHMSA does not expect operators to perform material properties verification for unknown pipe properties on pipeline segments exposed during one-call excavations. PHMSA has determined this approach is reasonable and will minimize the cost impacts of this final rule. A deadline for the material properties verification requirements of this rulemaking is not practical because it is impossible to forecast the rate or timing at which opportunities would arise to perform material properties verification for a given population of pipe. Lastly, operators should have most of the required pipe information from following § 192.917(b) since subpart O of part 192 was codified over 15 years E:\FR\FM\01OCR2.SGM 01OCR2 52196 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations ago in 2003. Section 192.917(b) requires operators to identify and evaluate the potential threats to pipeline segments by gathering and integrating existing data and information on the entire pipeline that could be relevant to the pipeline segment. In performing this identification and evaluation, operators must follow the requirements in ASME/ ANSI B31.8S, section 4, and at a minimum gather and evaluate the set of data specified in Appendix A to ASME/ ANSI B31.8S. The material properties needed to establish and substantiate MAOP are included in these lists. B. MAOP Reconfirmation—§§ 192.624 & 192.632 jbell on DSK3GLQ082PROD with RULES2 i.—Applicability 1. Summary of PHMSA’s Proposal In the NPRM, PHMSA proposed to require operators reconfirm MAOP for the following three categories of pipeline: (1) Grandfathered pipe, in direct response to section 23(d) of the 2011 Pipeline Safety Act and NTSB recommendation P–11–14; (2) Pipe for which documentation is inadequate to support the MAOP, in direct response to section 23(c) of the 2011 Pipeline Safety Act; and (3) Pipe that has experienced a reportable in-service incident since its most recent successful subpart J pressure test due to an original manufacturing-related defect; a construction-, installation-, or fabrication-related defect; or a crackingrelated defect, including, but not limited to, seam cracking, girth weld cracking, selective seam weld corrosion, hard spots, or stress corrosion cracking. It is important to note that a given pipeline segment for which the MAOP reconfirmation process would apply might fit into one, two, or all three of these proposed categories. For pipeline segments where records of the pipeline physical properties and attributes to substantiate the current MAOP are not documented in traceable, verifiable, and complete records, only those segments located within an HCA or a Class 3 or Class 4 location would be subject to the MAOP reconfirmation process under the NPRM. This proposal directly correlates to section 23 of the 2011 Pipeline Safety Act and NTSB recommendation P–11– 14 regarding the need for spike hydrostatic testing where in-service incidents have occurred. The NTSB recommended such testing for all pipe manufactured before 1970. For pipeline segments where operators established the MAOP in accordance with the grandfather clause VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 at § 192.619(c) (i.e., pipeline segments where the MAOP is based upon the highest actual operating pressure records from a 5-year interval between July 1, 1965, to July 1, 1970, and where operators therefore do not have pressure test or material property records) or for segments with a history of in-service incidents caused by cracks or crack-like defects, PHMSA proposed to restrict the applicability of MAOP reconfirmation to HCAs, Class 3 or Class 4 locations, or MCAs, if the MCA segment can accommodate an ILI tool. The proposed inclusion of pipeline segments in these locations and with these traits slightly expand on the mandate contained in section 23 of the 2011 Pipeline Safety Act, which applied only to previously untested pipeline segments operating at a pressure greater than 30 percent SMYS located in an HCA. In recommendation P–11–14, the NTSB recommended that all pipe manufactured before 1970 be subjected to a hydrostatic pressure test that would include a spike hydrostatic test, which PHMSA considered in its process for reconfirming MAOP. PHMSA’s preliminary evaluation concluded that doing so may not be cost-effective, since a large amount of such pipe could be in remote locations where the likelihood of personal injury or property damage as a result of an incident would be low. PHMSA’s proposal expanded the applicability of MAOP reconfirmation beyond the minimum required by the congressional mandate to include pipe operating at less than 30 percent SMYS. In addition, the NPRM expanded the location criteria to include some nonHCA locations in the form of MCAs and Class 3 and Class 4 locations. As PHMSA proposed in the definitions section of the NPRM, MCAs are areas that, while not meeting the HCA criteria, include 5 or more persons or dwellings intended for human occupation or are otherwise locations where people congregate, including the right-of-ways of major roadways. See section H of this final rule for additional background on the MCA definition. The NPRM also specified that the MAOP reconfirmation process would apply only to MCA pipeline segments able to accommodate an ILI tool. This provision would not preclude an operator from choosing to conduct a pressure test, but it would avoid forcing operators to conduct a pressure test because the pipeline segment was not ‘‘piggable.’’ 2. Summary of Public Comment Many stakeholders provided input on the proposed provisions in § 192.624 that require MAOP reconfirmation for pipeline segments previously excluded PO 00000 Frm 00018 Fmt 4701 Sfmt 4700 from testing by the grandfather clause, pipeline segments without adequate documentation to substantiate the current MAOP, and pipeline segments that have experienced a reportable inservice incident. Regarding the first criterion above, several commenters, including INGAA, AGA, and NAPSR, generally supported the provision requiring operators of pipeline segments where the MAOP was established via the grandfather clause to reconfirm the MAOP of those segments. Several of the pipeline industry trade associations and industry entities, however, did not support the proposed application of these criteria to all grandfathered pipeline segments within HCAs, Class 3 and Class 4 locations, and Class 1 and Class 2 piggable segments within MCAs. Gas Processors Association’s Midstream Association (GPA) and AGA stated that while they support the congressional mandate to conduct testing to confirm the material strength of previously untested gas transmission pipelines in HCAs that operate at a pressure above 30 percent SMYS, they oppose the proposed provisions which extend to additional pipeline segments. INGAA and Washington Gas supported the applicability of MAOP reconfirmation in MCAs for pipelines operating at greater than or equal to 30 percent SMYS but disagreed with the proposed provisions that included MCA pipelines operating at less than 30 percent SMYS. Some citizen groups, including PST, expressed concern that the proposed changes regarding the grandfather clause did not go far enough and suggested that PHMSA should fully implement the recommendations set forth by the NTSB. They stated that PHMSA should eliminate the grandfather clause given that the proposed provisions would not include the following groups of pipelines: (1) Pipelines in non-HCA areas within Class 1 and Class 2 locations; and (2) pipeline segments for which there is an inadequate record of a hydrostatic pressure test in areas newly designated as an MCA that are not capable of being assessed by an in-line tool. Conversely, Northeast Gas Association (NGA) stated that PHMSA should retain the grandfather clause as it prevents existing, historically safe, and maintained pipelines from being subjected to unwarranted requirements. For pipeline segments where operators do not have adequate documentation to support the current MAOP and that PHMSA proposed would be subject to the new MAOP reconfirmation requirements, some commenters stated that they support the E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations requirement to the extent that it is consistent with the congressional mandate to reconfirm MAOP for pipeline segments with insufficient records within Class 3 and Class 4 locations and Class 1 and Class 2 HCAs. These commenters further stated that § 192.624(a)(2) within the proposed MAOP reconfirmation requirements should be revised to clarify that it applies only to those gas transmission pipeline segments in HCAs and Class 3 and Class 4 locations that were constructed and put into operation since the adoption of the Federal Pipeline Safety Regulations in 1970, stating that otherwise § 192.624(a)(2) would apply to those pipelines put into service prior to the implementation of Federal regulations where the requirement to maintain a pressure test record does not apply. Some commenters also stated that PHMSA should revise § 192.624(a) within the proposed MAOP reconfirmation requirements to make clear that operators that have used one of the proposed allowable methods for establishing MAOP in § 192.624(b) other than the pressure test method are not required to have a pressure test record to comply with the record requirements of the section. Washington Gas asserted that the MAOP reconfirmation requirements should apply to only pipeline segments in HCAs that operate at a pressure of greater than or equal to 30 percent SMYS. Other commenters, including Xcel Energy, stated that the proposed provisions should allow operator discretion regarding what constitutes a reliable, traceable, verifiable, and complete record to determine the necessary documentation to support a pressure test record and the necessary material properties for MAOP verification. Additionally, AGA recommended the deletion of the phrase ‘‘reliable, traceable, verifiable, and complete’’ from the proposed MAOP reconfirmation provisions in § 192.624(a)(2). Similarly, other commenters, including INGAA, recommended omitting ‘‘reliable’’ from the phrase and provided a suggested definition for ‘‘traceable, verifiable, and complete.’’ Lastly, with regard to the third category of applicable pipeline segments to the proposed MAOP reconfirmation requirements, many commenters either disagreed or requested clarification for the requirement that MAOP must be reconfirmed in cases where an inservice incident occurred due to a manufacturing defect listed under § 192.624(a)(1). For example, INGAA stated that an operator can evaluate such manufacturing defects more VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 effectively through ongoing operations and maintenance activities rather than through MAOP reconfirmation, and that the defects PHMSA is concerned with are already addressed through integrity management. Similarly, Boardwalk Pipeline stated that pipelines that have experienced an in-service incident because of the listed defects in § 192.624(a)(1) should be subject to integrity management measures rather than MAOP reconfirmation. TransCanada and TPA recommended adding text to the applicability section of the MAOP reconfirmation requirements that would exclude a pipeline segment from such requirements if the operator has already acted to address the cause of the reported incident. Additionally, one commenter suggested that this requirement should apply only to pipelines in HCAs. Some commenters, including AGA and Consolidated Edison of New York (Con Ed), also requested additional time to comply with the proposed MAOP reconfirmation provisions, asserting that operators would be required to replace many of their transmission mains to comply with the new requirements because their current records would not be satisfactory. Due to the urban density and scale of the service areas of certain operators, AGA and Con Ed stated that this replacement process would take longer than the 15-year schedule provided in the rule. One commenter suggested that if the applicability criteria for pipeline segments with inservice incidents and manufacturing defects remains in the rule, it should be limited to a more contemporary time frame, such as a rolling 15-year window or those in-service incidents that have occurred since 2003. Pipeline Safety Trust, on the other hand, stated that the proposed timeframe of 15 years is too long for operators to reconfirm MAOP in HCAs and complete critical safety work, and they urged PHMSA to adopt significantly shorter timelines in the final rule. Additionally, AGA asserted that the proposed MAOP provisions do not address how the completion plan and completion dates of the section would apply to pipelines that might experience a failure in the future and would then be subject to the proposed MAOP reconfirmation requirements, or for pipelines that are not currently located in a MCA but may be in the future. Lastly, INGAA stated that section 23 of the 2011 Pipeline Safety Act requires that PHMSA consult with the Chairman of the Federal Energy Regulatory Commission (FERC) and State regulators PO 00000 Frm 00019 Fmt 4701 Sfmt 4700 52197 before establishing timeframes for the testing of previously untested pipes, and it is not evident that PHMSA has complied with this requirement. As a general comment, several stakeholders, including AGA, Louisville Gas & Electric, New Mexico Gas Company, National Grid, NW Natural, PECO Energy, TECO Pipeline Gas, and New York State Electric and Gas (NYSEG), proposed an alternative method for MAOP reconfirmation where operators would execute two separate sets of actions that they stated could be performed simultaneously or separately. First, operators would either assess high-risk gas transmission pipelines using a pressure test or an alternative technology that is determined to be of equal effectiveness. Operators would categorize these pipelines in three tiers and schedule them for testing depending on the pipeline’s SMYS and class location. Second, operators would use an ILI tool on all gas transmission pipelines, regardless of class location, that are capable of accommodating ILI tools. The ILI tool used would be qualified to find defects that would fail a subpart J pressure test. These commenters stated that this alternative methodology was necessary because the proposed provisions would create operational inefficiencies that would likely result in excessive cost and limited public benefit. In addition to providing this alternative proposal, many of these commenters provided other assorted comments on the proposed provisions. At the GPAC meeting on March 26, 2018, the GPAC recommended that PHMSA revise the scope of the proposed MAOP reconfirmation provisions by excluding lines with previously reported incidents due to crack defects. To go along with this, the GPAC also recommended PHMSA create a new section in subpart O of part 192, the natural gas IM regulations, to address pipeline segments with crackrelated incident histories. Doing these actions would eliminate the need for the proposed definitions of ‘‘modern pipe,’’ ‘‘legacy pipe,’’ and ‘‘legacy construction techniques,’’ and the impact of this is discussed later in this document. The GPAC also recommended that the MAOP reconfirmation provisions be revised to apply to pipeline segments in HCAs or Class 3 or Class 4 locations that do not have traceable, verifiable, and complete records necessary to establish MAOP under § 192.619. Previously, the provisions were applicable to those pipeline segments without traceable, verifiable, and complete subpart J pressure test records. Similarly, the GPAC recommended that the MAOP E:\FR\FM\01OCR2.SGM 01OCR2 52198 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES2 reconfirmation provisions only apply to grandfathered pipelines in HCAs, Class 3 or Class 4 locations, or MCAs able to accommodate inspection with ILI tools, and that have MAOPs producing a hoop stress greater than or equal to 30 percent SMYS. In the NPRM, the provisions applied to all grandfathered pipelines in those locations regardless of SMYS. In making this recommendation, the GPAC also suggested PHMSA review the costs and benefits of applying the MAOP reconfirmation provisions to non-HCA Class 3 and Class 4 grandfathered pipe with MAOPs less than 30 percent SMYS. During the meeting on March 27, 2018, the GPAC also recommended revisions to other sections related to the applicability of MAOP reconfirmation provisions, including withdrawing the proposed revisions to § 192.503, which tied general requirements of the subpart J pressure test to alternative MAOP and MAOP reconfirmation provisions, and withdrawing the proposed revisions to § 192.605(b)(5), which cross-referenced several sections related to the MAOP reconfirmation requirements to the requirements regarding an operator’s procedural manuals. The GPAC also examined the provisions related to the completion date of these actions and recommended that PHMSA revise the appropriate paragraph to account for pipelines that may be subject to these requirements in the future, such as for pipelines that are not in an HCA or Class 3 or Class 4 location now, but due to population growth or development may be in such a location in the future. More specifically, the GPAC recommended that an operator would have to complete all actions required by the MAOP reconfirmation provisions on 100 percent of their pipelines that meet the applicability requirements by 15 years after the effective date of the rule or as soon as practicable but no later than 4 years after the pipeline segment first meets the applicability conditions, whichever is later. The GPAC also recommended PHMSA consider a waiver or no-objection procedure if operators cannot meet the requirements within 4 years under this scenario. 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding the applicability of MAOP reconfirmation. After considering these comments and as recommended by the GPAC input, PHMSA is modifying the rule to address many of these comments. Regarding the applicability of the new MAOP reconfirmation requirements at VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 § 192.624, PHMSA notes that a simplistic repeal of the ‘‘grandfather clause’’ at § 192.619(c) is not practical because it applies to gathering and distribution lines. As the proposed rule was primarily focused on the safety of gas transmission pipelines, a broad repeal of the grandfather clause was not contemplated in the proposed rule. Further, a major expansion of the MAOP reconfirmation requirements beyond the scope of the congressional mandate in the 2011 Pipeline Safety Act would be costly, and the GPAC noted at the meeting on March 26, 2018, that there may be cost-benefit concerns to test all grandfathered pipelines. The GPAC recommended PHMSA analyze requiring operators to reconfirm the MAOP of all grandfathered lines, and PHMSA considered this as an alternative in the RIA.65 In response to the comments received and the recommendations of the GPAC, PHMSA is modifying the applicability of the MAOP reconfirmation requirements as follows: (1) The applicability related to pipeline segments with past in-service incidents is being eliminated. As commenters mentioned, operational failures are already addressed within integrity management and other subparts of part 192. Section 192.617, for example, would require an operator of a gas transmission line that had an in-service incident caused by an incorrect MAOP to determine the proper MAOP of the segment before placing it back into service. Causes of in-service failures are also already incorporated into the risk analyses required by the current IM regulations. If the cause of an incident is an incorrect MAOP, for example, then operators would be required to reconfirm it following the incident within their IM program. However, PHMSA is adding a new paragraph to strengthen the IM requirements at § 192.917(e)(6) to specifically include actions operators must take to address pipeline segments susceptible to cracks and crack-like defects. (2) PHMSA is also modifying the applicability of these requirements by specifying the MAOP reconfirmation requirements are applicable to pipeline segments that do not have the pipeline physical properties and attributes needed to establish MAOP documented in traceable, verifiable, and complete records, specifically those records required to establish and substantiate the MAOP in accordance with § 192.619(a), including those records required under § 192.517(a). More specifically, these requirements to verify 65 See PO 00000 section 5.9.1 of the RIA for further details. Frm 00020 Fmt 4701 Sfmt 4700 MAOP would apply to such pipelines without traceable, verifiable, and complete records in HCAs and Class 3 and Class 4 locations as specified in the congressional mandate. Further, PHMSA is dropping the word ‘‘reliable’’ from the applicability section of the regulatory text to be consistent with previous PHMSA advisory bulletins on this topic.66 (3) PHMSA is modifying the applicability of the MAOP reconfirmation provisions for ‘‘grandfathered’’ pipeline segments to pipelines with an MAOP greater than or equal to 30 percent of SMYS, as specified in the congressional mandate. In addition to these requirements applying to grandfathered pipelines in HCAs, PHMSA is retaining the MAOP reconfirmation applicability requirement for grandfathered pipeline segments in Class 3 and Class 4 locations and in piggable MCAs to address the NTSB recommendation on this topic. As per the committee’s suggestion, PHMSA analyzed whether it would be feasible to make the MAOP reconfirmation requirements applicable to non-HCA Class 3 and Class 4 pipe operating below 30 percent SMYS. This analysis is presented as an alternative in the RIA for this rulemaking. Ultimately, PHMSA did not choose to include these categories of pipelines in the scope for the applicability of the MAOP reconfirmation requirements because the GPAC recommended it was costeffective for the provision to only apply to pipe operating above 30 percent SMYS in Class 3 and 4 locations and because those pipelines present the greatest risk to safety. With respect to the completion date, PHMSA acknowledges the comments received stating that pipeline segments could meet applicability criteria at some point in the future such that it would be difficult or impossible to meet the 15year deadline for completion. Therefore, PHMSA agrees with the GPAC recommendation discussed above and is modifying the requirements in this final rule to include an alternative completion deadline of 4 years for pipeline segments that meet the applicability standards at some point in the future, for example for those pipeline segments that were in nonHCA locations that later become HCA locations. However, PHMSA emphasizes that this 4-year timeframe does not supersede, invalidate, or otherwise modify the existing requirements in § 192.611 for operators to confirm or revise the MAOP of 66 Pipeline Safety: Verification of Records; 77 FR 26822; May 7, 2012; https://www.govinfo.gov/ content/FR-2012-05-07/pdf/2012-10866.pdf. E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations segments within 24 months of a change in class location. PHMSA also acknowledges that some commenters thought the 15-year compliance timeframe for MAOP reconfirmation was too long. PHMSA believes a 15-year timeframe is necessary to be consistent with § 192.939, which allows operators to use a confirmatory direct assessment to confirm their MAOP in two, 7-year inspection cycles. This timeframe was discussed by the GPAC and was approved by unanimous vote. PHMSA will note that operators are required to have 50 percent of the applicable mileage completed within 8 years of the effective date of the rule. PHMSA would expect operators to prioritize and reconfirm the MAOP of the highest-risk segments first. PHMSA is also withdrawing miscellaneous revisions to § 192.503, which tied general requirements of the subpart J pressure test to alternative MAOP and MAOP reconfirmation provisions, and miscellaneous revisions from § 192.605(b)(5), which crossreferenced several sections related to MAOP requirements to the requirements regarding an operator’s procedural manuals. These changes were made to simplify the regulations. Additionally, because PHMSA has eliminated pipeline segments with past in-service incident history from the scope of the MAOP reconfirmation requirements, PHMSA is striking the proposed references within the MAOP reconfirmation requirements to the alternative MAOP requirements at § 192.620(a)(ii). Operators who used the alternative requirements to establish the MAOP of their pipelines were required to have complete documentation 67 and therefore would not be subject to the MAOP reconfirmation requirements. If an operator had previously established the MAOP of a pipeline segment under the alternative MAOP requirements, but has since lost the records necessary to validate the alternative, they would have to reconfirm MAOP using the alternative MAOP requirements, or apply for a special permit to continue operation. Per the requirement in section 23 of the 2011 Pipeline Safety Act, PHMSA consulted with members of FERC and State regulators, including representatives from NAPSR and the National Association of Regulatory Utility Commissioners, as appropriate, to establish the timeframes for 67 ‘‘Pipeline Safety: Standards for Increasing the Maximum Allowable Operating Pressure for Gas Transmission Pipelines; Final Rule;’’ October 17, 2008; 73 FR 62148. The effective date of the rule was November 17, 2008. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 completing MAOP reconfirmation. As a part of this consultation, which occurred as a function of the GPAC meetings from 2017 through 2018, PHMSA accounted for potential consequences to public safety and the environment while also accounting for minimal costs and service disruptions. These representatives provided both input and positive votes that the provisions surrounding MAOP reconfirmation were technically feasible, reasonable, cost-effective, and practicable if certain changes were made. As previously discussed, PHMSA has taken the GPAC’s input into consideration when drafting this final rule and made the according changes to the provisions. 52199 must incorporate a spike pressure feature into the pressure test procedure. PHMSA proposed standards for the spike hydrostatic test in § 192.506. If the operator has reason to believe any pipeline segment may be susceptible to cracks or crack-like defects, the operator would be required to also estimate the remaining life of the pipeline in accordance with the same standards specified in Method 3, the engineering critical assessment method. Summary of Public Comment: Method 1—Pressure Test Summary of PHMSA’s Proposal: Method 1—Pressure Test A pressure test is the most conventional assessment method by which an operator may reconfirm a pipeline segment’s MAOP. PHMSA proposed standards for conducting pressure tests for MAOP reconfirmation in part to meet the intent of NTSB recommendations P–11–14 and P–11– 15. First, PHMSA proposed minimum test pressure standards where a pipeline segment’s MAOP would be equal to the test pressure divided by the greater of either 1.25 or the applicable class location factor. Second, if the pipeline segment might be susceptible to cracks or crack-like defects,68 then the operator Several commenters opposed the proposed provisions requiring a spike test to be conducted as part of the pressure test for the purposes of MAOP reconfirmation, and these comments are discussed further under the ‘‘spike test’’ portion of the proposal and comment summary of this rulemaking. API suggested that a pipeline segment’s MAOP can be best established through performing a combination of pressure tests and ILI examinations, and they discussed how operators could conduct hydrostatic pressure testing to determine the in-place yield strength of a segment of pipeline by conducting a ‘‘spike’’ test pressure held for a few minutes followed by a subpart J pressure test approximately 10 percent below the spike level. API further stated that using ILI tools in conjunction with this method would further substantiate the results, as geometry ILI tools capable of measuring inside diameter to detect yielding could further substantiate and quantify the results of the pressure test. AGA stated that while they believe that pressure testing is a straightforward and well-established method, the proposed Method 1 MAOP reconfirmation requirements are unnecessarily complex. AGA further stated that subpart J provides different requirements and specifications for pressure tests based on the type of pipe being tested, and that Method 1 should refer to subpart J rather than to § 192.505(c) specifically, which requires unnecessarily stringent requirements. PG&E supported the proposed provisions and committed to pressure testing all pipes. INGAA stated that since the basic strength properties of steel pipe do not change over time, PHMSA should not limit allowable tests to only those conducted after July 1, 1965, as was proposed in § 192.619(a)(2)(ii). They emphasized that the test parameters, not 68 These pipelines can include pipelines constructed with ‘‘legacy pipe’’ or using ‘‘legacy construction techniques;’’ pipelines with evidence or risk of stress corrosion cracking or girth weld cracks; or pipelines that have experienced an incident due to an original manufacturing-related defects, construction-related defects, installationrelated defects, or fabrication-related defects. B. MAOP Reconfirmation—§§ 192.624 & 192.632 ii.—Methods In developing regulations to reconfirm MAOP where necessary, Congress mandated that PHMSA consider safety testing methodologies that include pressure testing and other alternative methods, including in-line inspections, determined to be of equal or greater effectiveness. The NTSB recommended an expansive pressure test approach to address the safety issues identified in their investigation of the PG&E incident through recommendations P–11–14 and P–11–15. In response to the congressional mandate, PHMSA evaluated other methodologies and identified five additional methods that could provide an equivalent or greater level of safety. Therefore, PHMSA proposed to allow the following six methods for MAOP reconfirmation, including the conventional pressure test method. PO 00000 Frm 00021 Fmt 4701 Sfmt 4700 E:\FR\FM\01OCR2.SGM 01OCR2 52200 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES2 the test date, should be considered for MAOP reconfirmation. Further, INGAA stated that recognizing the validity of earlier tests would not necessarily mean that no further pressure tests would be conducted, as periodic testing may be required to ensure the continued integrity of the pipeline segment under the operator’s integrity management program. However, such additional tests are managed under IM, which is separate from MAOP reconfirmation. Certain commenters stated that a spike test is not required to establish an adequate margin of safety for MAOP reconfirmation and suggested PHMSA eliminate spike testing from the pressure test method of MAOP reconfirmation. Regarding the proposed definitions of ‘‘legacy pipe’’ and ‘‘legacy construction,’’ AGA and Xcel Energy commented that as proposed, the definitions could be interpreted to apply to distribution pipelines as well as gas transmission pipelines. Commenters requested that PHMSA explicitly exclude distribution pipelines from these definitions, which would be applicable to all part 192. On March 26, 2018, the GPAC recommended that PHMSA delete the spike test requirements from the pressure test method of MAOP reconfirmation. The GPAC also recommended that PHMSA require operators to perform a pressure test in accordance with subpart J of part 192 rather than refer to specific requirements in § 192.505. Further, and as discussed during the meetings of December 2017 and March 26, 2018, if the applicable pressure test segment does not have traceable, verifiable, and complete MAOP records, the operator must use the best available information upon which the MAOP is currently based to conduct the pressure test. The GPAC recommended PHMSA create a requirement for the operator of such a pipeline segment to add the test segment to its plan for opportunistically verifying material properties in accordance with the material properties verification provisions. During the meeting, PHMSA noted that most pressure tests would present at least two opportunities for material properties verification at the test manifolds. PHMSA Response: Method 1—Pressure Test PHMSA appreciates the information provided by the commenters regarding the pressure test method of MAOP reconfirmation (Method 1). After considering these comments and as recommended by the GPAC, PHMSA is eliminating the spike testing VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 requirement as part of the pressure test method of MAOP reconfirmation. As commenters stated, spike testing is primarily used for the mitigation of cracks and crack-like defects, and PHMSA has determined it would therefore be more appropriate to be placed within the context of threat management under IM. Additionally, PHMSA is removing the definitions for and related references to ‘‘legacy pipe’’ and ‘‘legacy construction’’ in this final rule because the applicability to pipe with ‘‘legacy pipe or construction’’ leaks or failures was dropped from the applicability criteria for MAOP reconfirmation. PHMSA also modified the rule to refer to subpart J pressure tests rather than paragraph § 192.505(c), specifically, and to recognize the validity of earlier pressure tests. Lastly, if an operator does not have traceable, verifiable, and complete records for the material properties needed to establish MAOP by pressure testing, PHMSA is requiring that operators test, in accordance with the material verification requirements, the pipe materials cut out from the test manifold sites at the time the pressure test is conducted. Further, if there is a failure during the pressure test, the operator must test any removed pipe from the pressure test failure in accordance with the material properties verification requirements to ensure that the segment of pipe is consistent with operator’s sampling program established under § 192.607. This will avoid issues where operators may not have the documented and verified physical pipeline material properties and attributes that would otherwise be necessary to perform a hydrostatic pressure test to reconfirm MAOP. Summary of Proposal: Method 2— Pressure Reduction In the NPRM, PHMSA proposed that pipeline operators could choose to reduce the MAOP of the applicable pipeline segment to reconfirm the segment’s MAOP. This approach would use the recent operating pressure as a de facto pressure test, and then an operator would set the pipeline segment’s MAOP at a slightly lower pressure. PHMSA proposed that operators using this method set the pipeline’s MAOP to no greater than the highest actual operating pressure sustained by the pipeline during the 18 months preceding the effective date of the final rule divided by the greater of either 1.25 or the applicable class location, which are the same safety factors as used for the pressure testing in Method 1. PHMSA included standards for establishing the highest actual sustained pressure for the PO 00000 Frm 00022 Fmt 4701 Sfmt 4700 purposes of reconfirming MAOP under this method and included standards for addressing class location changes. Additionally, PHMSA proposed that, if the operator has reason to believe any pipeline segment contains or may be susceptible to cracks or crack-like defects, the operator would be required to estimate the remaining life of the pipeline. Summary of Public Comment: Method 2—Pressure Reduction AGA commented that the 18-month look-back time frame listed in the pressure reduction MAOP reconfirmation method is a much too narrow time frame for consideration and that the section should be rewritten to clarify that the pressure reduction should be taken from either (1) the immediate past 18 months, or (2) 5 years from the time the last pressure reduction was taken, stating that tying the baseline pressure to the effective date of the rule is arbitrary. Enterprise Products recommended that PHMSA clarify the derating criteria used for pipes that use this method of reconfirming MAOP. Further, Piedmont expressed concern that this method does not account for the actual gap that can occur between MAOP and operating pressure. Some commenters questioned whether the MAOP from which to take a pressure reduction was based on the most recent pressure test or the historical highest-pressure test, and some commenters suggested PHMSA revise this provision to allow operators to reconfirm the MAOP based on the existing MAOP and not using an 18month look-back period unless an incident caused by a material-related or construction-related defect has occurred on the pipeline since its last subpart J pressure test. TPA stated that using this method unfairly penalizes operators in situations where the operator has prepared for future needs and has not operated at MAOP for a period greater than 18 months. Similarly, another commenter suggested that operators who have already reduced MAOP on pipeline segments to be proactive should not be penalized by having to take an additional reduction in MAOP. Some commenters recommended limiting the applicability of this method to those pipelines operating at 30 percent SMYS or greater. Regarding the pressure reduction method for MAOP reconfirmation, the GPAC recommended PHMSA increase the look-back period from 18 months to 5 years and remove the requirements for operators selecting to take the pressure reduction to reconfirm MAOP to E:\FR\FM\01OCR2.SGM 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations perform fracture mechanics analysis on those pipeline segments. PHMSA Response: Method 2—Pressure Reduction PHMSA appreciates the information provided by the commenters regarding the pressure reduction method of MAOP reconfirmation (Method 2). After considering these comments and as recommended by the GPAC, PHMSA is increasing the look-back period to 5 years from the publication date of the rule and is removing the requirements for operators to perform fracture mechanics analysis on those pipeline segments where the operator has selected Method 2. PHMSA made this change because the 5-year look-back period is consistent with IM requirements regarding MAOP confirmation. jbell on DSK3GLQ082PROD with RULES2 Summary of PHMSA’s Proposal: Method 3—Engineering Critical Assessment Method 3 directly addresses the congressional mandate for PHMSA to consider safety testing methodologies that include other alternative methods, including ILI, determined to be of equal or greater effectiveness. Demonstrating that knowledge gained from an ILI assessment provides an equivalent level of safety as a pressure test is technically challenging. PHMSA used best safety practices gained from implementation of integrity management since 2003; development of class location special permits; and technical research on related topics, such as analysis of crack defects and seam defects. PHMSA applied these principles and analytical methods to develop an engineering critical assessment (ECA) methodology, which applies state-of-the-art fracture mechanics analysis to analyze defects in the pipe and determine if those defects would or would not survive a hydrostatic pressure test at the test pressure needed to establish MAOP. In addition, PHMSA proposed that if the operator has reason to believe any pipeline segment contains or may be susceptible to cracks or crack-like defects, the operator would be required to estimate the remaining life of the pipeline using the fracture mechanics standards PHMSA specified. Summary of Public Comment: Method 3—Engineering Critical Assessment Several trade associations and pipeline industry entities stated that ILI is the best and most practical method for MAOP reconfirmation due to its cost-effectiveness and environmentally friendly nature, and that PHMSA should allow operators to use ILI as a VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 reconfirmation method. These commenters, however, also stated that the requirements proposed for the usage of ILI with an ECA are overly complicated and burdensome, and they specifically recommended that the final rule should be simplified so that this method will play a greater role in MAOP reconfirmation in lieu of a pressure test. For example, INGAA asserted that PHMSA should remove the requirements in the ECA related to operations, maintenance, and integrity management, arguing that these requirements do not factor into MAOP reconfirmation and would be covered elsewhere in part 192. Further, INGAA proposed additional alternatives for using the ECA method to obtain necessary data for MAOP reconfirmation, asserting that these alternatives would be less burdensome and equally effective. More specifically, INGAA suggested removing duplicate regulatory language, removing the preapproval process for ILI, and adding unity plots as a method for operators to demonstrate that ILI is reliable for identifying and sizing actionable anomalies. TransCanada and PECO Energy Co. stated that for the ECA method to be used by industry, the detailed requirements listed under this method in the proposed rule should be replaced with the use of standard ECA best practices. Some commenters suggested that operators have long relied on sound engineering judgments and conservative assumptions to account for record gaps. Commenters stated that, if stripped of the ability to use sound engineering judgment and conservative assumptions, operators would need to substantially invest in processes, procedures, tests, and project engineering and support to develop and implement a comprehensive material properties verification plan as outlined in the proposed regulations. Another commenter asked for clarification on using assumptions of Grade A pipe (30,000 psi) versus the use of 24,000 psi as noted in § 192.107(b)(2) if the SMYS or actual material yield strength and ultimate tensile strength is unknown or is not documented in traceable, verifiable, and complete records. Another commenter suggested that in cases where a pipeline has been pressure tested, but not to the level of 1.25 times MAOP, PHMSA should allow operators to augment the original test with an ECA and other analysis to reconfirm the pipeline segment’s MAOP under method 3. The PST stated that there are certain cases in which the ECA method should not be allowed as an alternative to PO 00000 Frm 00023 Fmt 4701 Sfmt 4700 52201 pressure testing. Citing a white paper prepared by Accufacts, Inc. on ECA methodology, the PST recommended that PHMSA prohibit the use of the ECA method for determining the strength of a pipeline segment in cases where there are girth weld crack threats, significant stress corrosion cracking threats, or dents with stress concentrator threats. During the GPAC meeting on March 27, 2018, the GPAC recommended that PHMSA remove the fracture mechanics analysis for failure stress and crack growth analysis requirements from the ECA method of MAOP reconfirmation and move them to a stand-alone section in the regulations. Further, the GPAC recommended that such a section should not specify when, or for which pipeline segments, fracture mechanics analysis would be required. The GPAC suggested that this new fracture mechanics section outline a procedure by which operators perform fracture mechanics analysis when required or allowed by other sections of part 192, which was similar to its treatment of the proposed material properties verification procedures at § 192.607. Under the GPAC’s proposal, the ECA method for MAOP reconfirmation would not contain any specific technical fracture mechanics requirements or Charpy V-notch toughness values but would instead refer to the new fracture mechanics section. Other recommendations related specifically to the new fracture mechanics section are discussed in that area of the proposal and comment summary section of this document. The GPAC also recommended PHMSA add a requirement to verify material properties in accordance with the rule’s material properties verification provisions if the information needed to conduct a successful ECA is not documented in traceable, verifiable, and complete records. PHMSA Response: Method 3— Engineering Critical Assessment PHMSA appreciates the information provided by the commenters regarding the ECA method of MAOP reconfirmation (Method 3). As recommended by the GPAC, PHMSA is removing the fracture mechanics analysis requirements from the ECA method of MAOP reconfirmation and moving them to a new stand-alone § 192.712. PHMSA agrees this change will improve comprehension of the regulations. This new section does not specify when, or for which pipeline segments, fracture mechanics analysis would be required but instead outlines a procedure by which operators perform E:\FR\FM\01OCR2.SGM 01OCR2 52202 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations fracture mechanics analysis when required by other sections of part 192. Section 192.712 is referenced in the pressure reduction, ECA, and ‘‘other technology’’ methods of MAOP reconfirmation under § 192.624, as well as in § 192.917 for cyclic fatigue loading. Therefore, the ECA method for MAOP reconfirmation does not contain any specific technical fracture mechanics requirements or Charpy Vnotch toughness values (full-size specimen, based on the lowest operational temperature) but instead refers to the new § 192.712. Comments related to the assumptions an operator can use when material properties are unknown are addressed in the discussion on § 192.712 below. PHMSA also added a requirement to verify material properties in accordance with the rule’s material properties verification provisions at § 192.607 if the information needed to conduct a successful ECA is not documented in traceable, verifiable, and complete records. PHMSA disagrees that the additional analytical requirements, beyond ILI, are overly complicated or burdensome. To conclude that an ECA is of equal or greater effectiveness as a pressure test for the purposes of MAOP reconfirmation, as mandated by Congress, more than an ILI and repair program is required. A pressure test proves that any flaws in the pipe are small enough to hold the test pressure without leaking. Such subcritical flaws must be analyzed to prove that they would pass a pressure test, even if the pressure test is not conducted. A fracture mechanics analysis is capable of reliably drawing such conclusions but must be carefully and capably performed. Such an analysis also requires accurate data. In the absence of reliable data for key parameters, such as fracture toughness, PHMSA allows the use of appropriately conservative assumptions. This is discussed in more detail in the sections below. Based on an ASME report and research sponsored by PHMSA,69 the ECA analysis can be reliably used to ascertain if a pipeline segment would pass a pressure test, even if it has seam weld cracking, and the final rule includes requirements for conducting ILI using tools capable of detecting girth jbell on DSK3GLQ082PROD with RULES2 69 See: American Society of Mechanical Engineers (ASME) Standards Technology Report ‘‘Integrity Management of Stress Corrosion Cracking in Gas Pipeline High Consequence Areas’’ (STP–PT–011), and ‘‘Final Summary Report and Recommendations for the Comprehensive Study to Understand Longitudinal ERW Seam Failures—Phase 1’’ (Task 4.5); https://primis.phmsa.dot.gov/matrix/ PrjHome.rdm?prj=390. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 weld cracks. The ECA must analyze any cracks or crack-like defects remaining in the pipe, or that could remain in the pipe, to determine the predicted failure pressure (PFP) of each defect. PHMSA also notes that the final rule addresses cases where a pipeline has been pressure tested, but not to the level of 1.25 times MAOP, by allowing operators to account for those test results and augment the original test with an ECA, or conduct an ILI tool assessment program to characterize defects remaining in the pipe along with using an ECA to establish MAOP, to reconfirm the pipeline segment’s MAOP using Method 3. Detailed ILI requirements are addressed in new § 192.493, which is discussed in more detail below. PHMSA is moving the ECA process requirements in this final rule to a new stand-alone § 192.632. Section 192.624(c)(3) (ECA method of MAOP reconfirmation) and the new § 192.632 will cross-reference each other. PHMSA decided to make this change when finalizing this rulemaking only to improve the readability of the regulations. No substantive changes were made to the requirements in connection with this organizational change. Summary of PHMSA’s Proposal: Method 4—Pipe Replacement When reconfirming MAOP on certain pipeline segments, some operators may face significant technical challenges or costs when performing either a pressure test or an ILI examination, and it may be more economically viable to replace the pipeline. Therefore, PHMSA proposed to allow pipe replacement for operators to reconfirm their MAOP. In such cases, the replacement pipeline would be designed, constructed, and pressure tested according to current standards to establish MAOP. Summary of Public Comment: Method 4—Pipe Replacement Commenters, including MidAmerican Energy Company and Paiute Pipeline, stated their support for this method. The GPAC similarly supported this method and did not recommend any changes for this aspect of MAOP reconfirmation. PHMSA Response: Method 4—Pipe Replacement PHMSA appreciates the information provided by the commenters regarding the pipe replacement method of MAOP reconfirmation (Method 4). After considering these comments and as recommended by the GPAC, PHMSA is PO 00000 Frm 00024 Fmt 4701 Sfmt 4700 retaining the proposed rule text for Method 4 in the final rule. Summary of PHMSA’s Proposal: Method 5—Pressure Reduction for Small, Low-Pressure Pipelines For low-pressure, smaller-diameter pipeline segments with small potential impact radii (PIR), PHMSA proposed an MAOP reconfirmation method similar to the pressure reduction under Method 2. Operators of pipeline segments for which (1) the MAOP is less than 30 percent SMYS, (2) the PIR is less than or equal to 150 feet, (3) the nominal diameter is equal to or less than 8 inches,70 and (4) which cannot be assessed using ILI or a pressure test, may reconfirm the MAOP as the highest actual operating pressure sustained by the pipeline segment 18 months preceding the effective date of the final rule, divided by 1.1. In addition to this pressure reduction, operators of these lines would be required to perform external corrosion direct assessments in accordance with the IM provisions, develop and implement procedures to evaluate and mitigate any cracking defects, conduct a specified number of line patrols at certain intervals, conduct periodic leak surveys, and odorize the gas transported in the pipeline segment. Summary of Public Comment: Method 5—Pressure Reduction for Small, LowPressure Pipelines AGA stated that PHMSA did not provide enough justification for imposing the additional pressure reduction requirements listed under this method, asserting that this method should require either a 10 percent pressure reduction or the implementation of additional preventative actions that are feasible and practical, but not both. TPA stated that the 18-month criterion penalizes operators who may have operated pipelines at lower capacities to anticipate future needs. Furthermore, TPA urged PHMSA to limit the requirements for MAOP reconfirmation under Method 5 to the reduction in MAOP and not impose additional safety requirements, stating that these pipelines are generally considered lowstress pipelines and that their risk of rupture is very low. Similarly, API stated that the proposed requirements for odorization and frequent instrumented leak surveys are impractical. Some commenters felt that the terms for small potential impact radius and the applicable diameters should be defined. 70 8.625 E:\FR\FM\01OCR2.SGM inches actual diameter. 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations On March 27, 2018, the GPAC recommended PHMSA delete the size and pressure criteria of this method and base the applicability solely on a potential impact radius of less than or equal to 150 feet. The GPAC also recommended increasing the look-back period to 5 years from 18 months. Further, the GPAC recommended PHMSA strike the additional requirements in this method related to external corrosion direct assessment, crack analysis, gas odorization, and fracture mechanics analysis. They also recommended PHMSA change the frequency of patrols and surveys to 4 times a year for Class 1 and Class 2 locations, and 6 times per year for Class 3 and Class 4 locations. jbell on DSK3GLQ082PROD with RULES2 PHMSA Response: Method 5—Pressure Reduction for Small, Low-Pressure Pipelines PHMSA appreciates the information provided by the commenters regarding the pressure reduction method of MAOP reconfirmation for small, low-pressure pipelines (Method 5). After considering these comments and as recommended by the GPAC, PHMSA is deleting the pipeline segment size and pressure criteria of this method and basing the applicability solely on a potential impact radius of less than or equal to 150 feet. PHMSA believes this change streamlines the regulations while maintaining pipeline safety. PHMSA is increasing the look-back period to 5 years, which is consistent with other sections of part 192, including integrity management. Additionally, PHMSA is deleting the requirements in this method related to external corrosion direct assessment, crack analysis, gas odorization, and fracture mechanics analysis. PHMSA is also changing the frequency of patrols and surveys to 4 times a year for Class 1 and Class 2 locations, and 6 times per year for Class 3 and Class 4 locations. PHMSA believes these changes increase regulatory flexibility while maintaining pipeline safety. Summary of Proposal: Method 6— Alternative Technology PHMSA proposed that operators may use an alternative technical evaluation process that provides a documented engineering analysis for the purposes of MAOP reconfirmation. If an operator elects to use an alternative method for MAOP reconfirmation, it would have to notify PHMSA and provide a detailed fracture mechanics analysis—including the safety factors—to justify the establishment of the MAOP using the proposed alternative method. The notification would have to demonstrate VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 that the proposed alternative method would provide an equivalent or greater level of safety than a pressure test. PHMSA included this option to allow and encourage the continual research and development needed to improve state-of-the-art fracture mechanics analysis, integrity assessment methods, advances in metallurgical engineering, and new techniques. Summary of Public Comment: Method 6—Alternative Technology For the alternative technologies method of MAOP reconfirmation, several stakeholders opposed the timeframes, case-by-case approval process, and procedural barriers PHMSA proposed for using this method. Several commenters, including Cheniere Energy, Delmarva Power & Light, and INGAA, suggested that the procedural hurdles required by the proposed provisions would make this option difficult for operators to use for MAOP reconfirmation as well as for any other provisions PHMSA allows alternative technology use with notification. More specifically, these commenters suggested that a process whereby PHMSA could object to the use of an alternative technology at any time during a project’s lifecycle does not provide the level of certainty necessary for operators to move forward with using alternative technologies. That uncertainty would deter the development of what could be better or safer alternatives. Piedmont stated that it does not believe that the role of PHMSA includes determining the appropriate technologies to be used to reconfirm MAOP. Piedmont further stated that currently under subpart O, operators are required to obtain approval from PHMSA to use alternative technologies for integrity assessment, and that operators have waited more than 180 days for PHMSA to respond to these requests. Piedmont stated that this uncertainty cannot be reconciled with the planning and business considerations that an operator must consider when evaluating how to invest in technology and which methods to use for establishing MAOP. The PST stated that the approval process should be similar to the process used for special permits and that before these methods are approved by PHMSA, they should be subject to public review and comment under the National Environmental Policy Act of 1969 (NEPA). At the meeting on March 27, 2018, the GPAC recommended PHMSA incorporate the 90-day notification and objection procedure for the use of PO 00000 Frm 00025 Fmt 4701 Sfmt 4700 52203 alternative technology. To summarize, operators would have to notify PHMSA of its intent to use other technology, and PHMSA would have 90 days to respond with an objection if PHMSA had one, or a need for more review time. Otherwise, the operator would be free to use the proposed method or technology. PHMSA Response: Method 6— Alternative Technology PHMSA appreciates the information provided by the commenters regarding the other technology method of MAOP reconfirmation (Method 6). After considering these comments and as recommended by the GPAC, PHMSA is modifying the rule to incorporate the 90-day notification and objection procedure the committee recommended. Operators would have to notify PHMSA of its intent to use other technology to reconfirm MAOP in accordance with § 192.18, and PHMSA would have 90 days to respond with an objection if PHMSA had one or a notice that PHMSA required more time for its review, which would extend the timeframe. Without a notice of objection or additional review by PHMSA, the operator would be allowed to use the alternative technology. PHMSA has successfully applied the notification process to other technology assessments under subpart O since its inception and does not believe a special permit process is warranted for every notification for alternative technology. PHMSA believes the changes made in the final rule will address the concerns about timeliness of notification reviews by PHMSA. B. MAOP Reconfirmation—§ 192.624 iii.—Spike Test 1. Summary of PHMSA’s Proposal The ‘‘spike’’ hydrostatic pressure test is a special feature of the pressure testing method of MAOP reconfirmation. PHMSA intends this aspect of the MAOP reconfirmation process to address the intent of NTSB recommendations P–11–14 (related to spike testing for grandfathered pipe) and P–11–15 (related to pressure testing to show that manufacturing and construction-related defects are stable). PHMSA proposed that a spike test would be required for cases where a pipeline segment might be susceptible to cracks or crack-like defects. Such pipe may include ‘‘legacy pipe;’’ pipe constructed using ‘‘legacy’’ construction techniques; pipelines that have experienced an incident due to an original manufacturing-related defect, a construction-, installation-, or fabrication-related defect; or pipe with E:\FR\FM\01OCR2.SGM 01OCR2 52204 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES2 stress corrosion cracking or girth weld cracks. Cracks and crack-like defects in some cases may be susceptible to a phenomenon called ‘‘pressure reversal,’’ which is the failure of a defect at a pressure less than a pressure level that the flaw has previously experienced and survived. The increased stress from the test pressure may cause latent cracks that are almost, but not quite, large enough to fail to grow during the test. If the crack does not fail before the test is completed, the resultant crack that remains in the pipe may be large enough to no longer be able to pass another pressure test. The spike portion of the pressure test is designed to cause such marginal crack defects to fail during the early, spike phase of the pressure test. The post-spike, long-duration test pressure validates the operational strength of the pipe. Using a shortduration, very high spike pressure followed by a long-duration integrity verification pressure provides greater assurance that the test is not ‘‘growing cracks’’ that could fail in-service after the test is completed. PHMSA proposed standards for the spike hydrostatic test in § 192.506. PHMSA used several technical reports and studies, including PHMSA-sponsored research, to inform the standards proposed for the spike test. Those materials include, American Society of Mechanical Engineers Standards Technology Report ‘‘Integrity Management of Stress Corrosion Cracking in Gas Pipeline High Consequence Areas’’ (STP–PT–011), and ‘‘Final Summary Report and Recommendations for the Comprehensive Study to Understand Longitudinal ERW Seam Failures— Phase 1’’ (Task 4.5).71 2. Summary of Public Comment Some commenters supported the concept of requiring the use of a spike hydrostatic pressure test as part of the MAOP reconfirmation process for establishing MAOP but expressed concern over specific aspects of the provision. For example, AGA urged PHMSA to allow pneumatic pressure tests as well as hydrostatic pressure tests. In addition, AGA disagreed with the allotted test duration provided in the proposal. Similarly, other operators who commented, such as CenterPoint Energy and Dominion East Ohio, stated that the proposed spike test target hold pressure of 30 minutes exceeds the time needed to determine the mechanical integrity of the pipeline test segment and will cause pre-existing crack-like defects to grow. Alternatively, 71 https://primis.phmsa.dot.gov/matrix/ PrjHome.rdm?prj=390. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 Dominion Transmission, Tallgrass Energy Partners, SoCalGas, and Paiute Pipelines stated that a test level of 100 percent SMYS, not 105 percent SMYS, would be sufficient to remediate cracking threats. Enterprise Products stated that the requirements for the design of a spike test should be based on integrity science, such as fatigue life and reassessment intervals, and suggested PHMSA’s proposed spike test pressure limits were set at an arbitrary level. Enterprise further stated that the utility of stressing a pipe beyond 100 percent of its yield strength is questionable and potentially damages the pipe. Other commenters, including MidAmerican Energy Co., requested that pneumatic spike tests to 1.5 times MAOP be allowed when the resultant pressure complies with the limitations stated in the table in § 192.503(c). Trade associations and pipeline industry entities, including INGAA, GPA, and TPA, asserted that PHMSA should eliminate the spike test requirement for establishing MAOP entirely. These commenters stated that the proposed provisions went beyond what was required to reconfirm MAOP for an accepted margin of safety. These commenters further asserted that spike testing is not an appropriate technique for MAOP reconfirmation, and it could result in unintended negative consequences without improving pipeline safety. They stated that spike testing is an aggressive and destructive technique that should be used only in cases in which time-dependent threats, such as a significant risk of stress corrosion cracking, exist. INGAA and other commenters agreed with PHMSA that the use of spike hydrostatic testing is appropriate for time-dependent threats, such as stress corrosion cracking. INGAA, however, suggested changes to the proposed spike hydrostatic pressure test provisions and the cross-reference to those provisions in the proposed IM assessment method revisions to limit the spike testing requirement to time-dependent threats, to test to a minimum of 100 percent SMYS instead of 105 percent, and to provide an alternative for use of an instrumented leak survey. INGAA agreed that spike testing is the best means of testing a pipeline with a history of environmental cracking, such as stress corrosion cracking that has developed while a pipeline is in service, and noted that a spike test may be of value for in-service pipelines where metallurgical fatigue is of concern. INGAA further stated that pressure cycling should not need to be included in the proposed spike test provisions and that PHMSA should amend the PO 00000 Frm 00026 Fmt 4701 Sfmt 4700 proposed rule to limit spike testing only to those pipeline segments with stress corrosion cracking. An additional commenter suggested PHMSA should allow operators to use the short-duration spike portion of a spike pressure test to determine the lower bound of the yield strength of the test section, including all pipe and components that are subjected to the test pressure. Such a test, if used for this purpose, must also confirm that yielding beyond that experienced in a standard tensile test to determine yield strength, typically on the order of 0.5 percent, has not occurred. This confirmation may be demonstrated by data from a pressurevolume plot of the test or a post-test geometry tool in-line inspection. Public interest and other groups, including Pipeline Safety Coalition, Environmental Defense Fund (EDF), and NAPSR, expressed support for spike testing, stating that it would provide for increased pipeline safety. NAPSR further stated that the option of applying to use alternative technology or an alternative technological evaluation process would allow for some flexibility in cases in which a hydrostatic test is impractical. EDF also suggested additional measures to mitigate emissions from methane gas lost during testing. At the GPAC meeting on March 2, 2018, the GPAC recommended that PHMSA revise the spike test requirements to change the minimum spike pressure to the lesser of 100 percent SMYS or 1.5 times MAOP, reduce the spike hold time to a minimum of 15 minutes after the spike pressure stabilizes, revise the applicable language to refer specifically to ‘‘timedependent’’ cracking, incorporate the 90-day notification and objection procedure discussed for other sections, and adjust the SME requirements by adding language describing a ‘‘qualified technical subject matter expert’’ where applicable. 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding the requirements for spike pressure testing. After considering these comments and as recommended by the GPAC, PHMSA is modifying the rule to change the minimum spike pressure to the lesser of 100 percent SMYS or 1.5 times MAOP, as PHMSA believes these pressures are sufficient to maintain pipeline safety. PHMSA is specifying a spike hold time of a minimum of 15 minutes after the spike pressure stabilizes, rather than a 30-minute overall hold time, to be consistent with pipeline safety. Additionally, PHMSA is E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations modifying the rule to revise the applicable language to refer specifically to ‘‘time-dependent’’ cracking, incorporate the same notification procedure under § 192.18 with the 90day timeframe for objections or requests for more review time, and adjust the SME requirements by using broader language describing a ‘‘qualified technical subject matter expert’’ where applicable instead of specifying technical fields of expertise such as metallurgy or fracture mechanics. PHMSA believes these changes increase regulatory flexibility while maintaining pipeline safety. In addition, as stated above, the spike test is being removed from the MAOP reconfirmation requirements. The spike test procedure in the new § 192.506 would be used whenever required by other requirements in part 192 to address crack remediation and the integrity threat of cracks and crack-like defects. PHMSA disagrees with allowing pneumatic spike tests to 1.5 times MAOP based on safety concerns. Pneumatic pressure tests are allowed in § 192.503(c), with certain limitations, for new, relocated, or replaced pipe. For new, relocated, or replaced pipe, there is knowledge that the pipe is likely sound and is usually manufactured with recent mill pressure tests to confirm the pipe meets applicable standards. A spike test to perform an integrity assessment on in-situ pipe with known or suspected cracks or crack-like defects presents a much higher likelihood of the pipeline segment experiencing a leak or rupture during the test with resultant consequences, including the possibility of fire or explosion. PHMSA notes that conducting a pneumatic test using a compressible gas, such as air, nitrogen, or methane, would be a safety concern for the public and operating personnel. Gas that is highly compressed has stored energy that would be suddenly released should there be a flaw in the pipe. Liquids, such as water, do not have the stored energy release that a compressible gas has should the pipe have a flaw that either leaks or ruptures. Therefore, the safety risk of performing a hydrostatic pressure test (with water) is much lower due to the lesscompressible nature of liquids. Compressed gas would be a fire or explosion hazard to the public. However, as specified in the proposed and final rules, operators that desire to use a pneumatic spike test may propose using such a test, with justification, by submitting a notification to PHMSA. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 B. MAOP Reconfirmation—§ 192.624 iv.—Fracture Mechanics 1. Summary of PHMSA’s Proposal In the proposal, PHMSA determined that fracture mechanics analysis is a key aspect of meeting the congressional mandate to consider safety testing methodologies for MAOP reconfirmation of equal or greater effectiveness as a pressure test, including other alternative methods such as ILI. Demonstrating that knowledge gained from an ILI assessment provides an equivalent level of safety as a pressure test is technically challenging. An ILI assessment might reveal the presence of crack flaws and crack-like defects and characterize them within the accuracy of tool performance capabilities, but determining whether those cracks would survive a pressure test to reconfirm MAOP requires very in-depth and highly technical analysis. Such an analysis not only requires an accurate characterization of cracks, it also requires accurate and known metallurgical properties of the pipe. To address these aspects, PHMSA proposed more detailed requirements in § 192.921 for evaluating defects discovered during ILI to account for tool accuracy and other factors to accurately characterize flaw dimensions and support accurate fracture mechanics analysis. In addition, the material properties verification and documentation requirements PHMSA proposed are critical to performing fracture mechanics analysis of ILIdiscovered defects that would be accurate enough to establish MAOP in a way that is demonstrably equivalent in safety to a pressure test. In the MAOP reconfirmation provisions, PHMSA proposed new requirements for fracture mechanics analysis for failure stress and cracks, listing specific requirements, standards, and data operators must use when performing a fracture mechanics analysis. 2. Summary of Public Comment Most industry stakeholders were opposed to the proposed fracture mechanics requirements. AGA, New Mexico Gas Co., and TPA suggested that fracture mechanics have a limited place in preventing pipeline failures or predicting them accurately and should not be a component of MAOP reconfirmation. AGA stated that the rule should not prescriptively require fracture mechanics calculations to be performed for a broad range of applications but should be narrowed to include only transmission pipelines operating at a hoop stress greater than 30 percent SMYS, given that pipelines PO 00000 Frm 00027 Fmt 4701 Sfmt 4700 52205 that operate below 30 percent SMYS have a strong tendency to leak rather than rupture. Commenters also stated that requiring fracture mechanics as any part of the MAOP reconfirmation process was overly burdensome and unclear. Specifically, API stated that some of the requirements listed under the MAOP reconfirmation requirements were overly conservative and burdensome for most situations where this technique would be used. For instance, a commenter noted that there is no nondestructive evaluation (NDE) methodology for obtaining Charpy Vnotch toughness values. Therefore, PHMSA’s requirement to obtain Charpy V-notch toughness values eliminates the availability of non-destructive testing. Further, a commenter noted that the proposed ECA analysis prescribed a body toughness of 5-ft.-lbs. and a seam toughness of 1-ft.-lbs., which are arbitrary and very conservative. Vintage pipelines will not have Charpy V-notch toughness data, and requiring an overly conservative assumption of toughness is not reasonable. Toughness can vary depending on the manufacturer, the manufacturing method, and the pipe vintage, and it should not be prescribed in the regulations. The commenter further noted that using the conservative defaults, especially the overly conservative defaults PHMSA proposed, may result in an unacceptably short remaining life of the pipeline. Similarly, commenters recommended PHMSA allow alternative methods of assessing strength properties that provide a suitable lower bound to the actual strengths. Allowing alternative methods will provide flexibility to consider conservative, but realistic, estimates of material properties. Commenters also stated that SMEs in both metallurgy and fracture mechanics are not needed to validate nondestructive test (NDT) methods. Engineers with knowledge in test validation methods but not necessarily metallurgy and fracture mechanics are capable of validating NDT methods. More broadly, Energy Transfer Partners suggested that the proposed language for fracture mechanics is misplaced in MAOP reconfirmation and should be moved to the proposed requirements for non-HCA assessments, or elsewhere, since this text more closely resembles an ‘‘assessment.’’ Other commenters agreed with that concept, suggesting fracture mechanics is more appropriate under the IM measures for threat mitigation rather than for MAOP reconfirmation. As previously discussed in this document, the GPAC recommended E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 52206 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations PHMSA move the fracture mechanics analysis requirements out of the ECA method of MAOP reconfirmation and into a new stand-alone section in the regulations, making it a process for performing fracture mechanics analysis whenever required or allowed by part 192. The committee therefore recommended that PHMSA delete any cross-references to the MAOP reconfirmation and the spike pressure test provisions. The GPAC also recommended that operators make and retain specific records to document fracture mechanics analyses performed. Along with moving the fracture mechanics analysis requirements to a stand-alone section, the GPAC had several specific recommendations related to how the requirements would function. The GPAC recommended PHMSA remove ILI tool performance specifications and replace them with a requirement for operators to verify tool performance using unity plots or equivalent technologies, and also recommended revisions to the fracture mechanics requirements by striking the sensitivity analysis requirements and replacing them with a requirement for operators to account for model inaccuracies and tolerances. As it pertains to the Charpy V-notch toughness values (full-size specimen, based on the lowest operational temperatures) used in fracture mechanics analysis, the GPAC recommended that operators could use a conservative Charpy V-notch toughness value based on the sampling requirements of the material properties verification provisions or use Charpy Vnotch toughness values from similarvintage pipe until the actual properties are obtained through the operator’s opportunistic testing program. The GPAC recommended that PHMSA clarify that default Charpy V-notch toughness values of 13-ft.-lbs. for pipe body and 4-ft.-lbs. for pipe seam only apply to pipe with suspected lowtoughness properties or unknown toughness properties. Further, if a pipeline segment has a history of leaks or failures due to cracks, the GPAC recommended PHMSA require the operator to work diligently to obtain any unknown toughness data. In the interim, operators of such pipeline segments must use Charpy V-notch toughness values of 5-ft.-lbs. for pipe body and 1ft.-lbs. for pipe seam. The GPAC also recommended PHMSA include a 90-day notification procedure similar to the previously agreed-upon procedure if operators wanted to request the use of differing Charpy V-notch toughness values. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding the proposed fracture mechanics requirements. After considering these comments and as recommended by the GPAC, PHMSA is moving the fracture mechanics analysis requirements out of the ECA method of MAOP reconfirmation and into a new standalone § 192.712 in the regulations, making it a process by which operators must perform fracture mechanics analysis whenever required by part 192. This change was made to increase the readability of the regulations. As a part of making these provisions into a standalone section in the regulations, PHMSA is also deleting the references within § 192.712 to the MAOP reconfirmation and the spike pressure test provisions. PHMSA is adding a requirement for operators to make and retain specific records documenting any fracture mechanics analyses performed. PHMSA is also removing ILI tool performance specifications and sensitivity analysis requirements and replacing them with a requirement for operators to verify tool performance using unity plots or equivalent technologies and to account for model inaccuracies and tolerances. This change will increase regulatory flexibility while maintaining pipeline safety. Regarding the default Charpy V-notch toughness values (full-size specimen, based on the lowest operational temperatures) used in fracture mechanics analysis when actual values are not known, industry and the GPAC had significant comments. PHMSA is aware of pipe manufactured per API Specification 5L in this decade (2010– 2019) with Charpy V-notch toughness values for the weld seam as low as 1ft. lbs. that has been used in gas transmission pipelines. Furthermore, API 5L does not contain required minimum Charpy V-notch toughness values for the weld seam. A single default assumed toughness value might be inappropriate or overly conservative under some circumstances, or it might be a proper choice under other circumstances. To address this issue in this final rule, PHMSA is allowing the use of: (1) Charpy V-notch toughness values (full-size specimen, based on the lowest operational temperatures) from the same vintage and the same steel pipe manufacturers with known properties; (2) a conservative Charpy V-notch toughness value to determine the toughness based upon the ongoing material properties verification process specified in § 192.607; (3) maximum Charpy V-notch PO 00000 Frm 00028 Fmt 4701 Sfmt 4700 toughness values of 13.0 ft.-lbs. for body cracks and 4.0 ft.-lbs. for cold weld, lack of fusion, and selective seam weld corrosion defects if the pipeline segment does not have a history of reportable incidents caused by cracking or cracklike defects; (4) maximum Charpy Vnotch toughness values of 5.0 ft.-lbs. for body cracks and 1.0 ft.-lbs. for cold weld, lack of fusion, and selective seam weld corrosion if the pipeline segment has a history of reportable incidents caused by cracking or crack-like defects; or (5) other appropriate Charpy V-notch toughness values that an operator demonstrates can provide conservative Charpy V-notch toughness values for the analysis of the crack-related conditions of the line pipe upon submittal of a notification to PHMSA. These modifications will provide flexibility to operators for considering conservative but realistic estimates of material properties. PHMSA is also clarifying that operators do not need to use distinct metallurgy and fracture mechanics subject matter experts to review fracture mechanics analyses. In this final rule, PHMSA is replacing that requirement with a general requirement stating that fracture mechanics analyses must be reviewed and confirmed by a qualified subject matter expert. PHMSA expects a qualified subject matter expert to be an individual with formal or on-the-job technical training in the technical or operational area being analyzed, evaluated, or assessed. The operator must be able to document that the individual is appropriately knowledgeable and experienced in the subject being assessed. B. MAOP Reconfirmation—§ 192.624 v.—Legacy Construction Techniques/ Legacy Pipe 1. Summary of PHMSA’s Proposal PHMSA proposed to add a definition to part 192 for ‘‘legacy construction techniques,’’ which defined historical practices used to construct or repair transmission pipeline segments that are no longer recognized as acceptable. In addition, PHMSA proposed a definition for ‘‘legacy pipe’’ that is defined by the presence of specific legacy manufacturing, welding, and joining techniques. 2. Summary of Public Comment AGA expressed significant concerns with the proposed definitions of legacy pipe and legacy construction techniques for the purposes of part 192, commenting that PHMSA should eliminate the use of the terms entirely or otherwise revise these definitions to E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations exclude currently acceptable manufacturing and construction techniques. AGA stated if PHMSA were to codify the definitions of legacy pipe and legacy construction techniques, then PHMSA should limit its catch-all provisions within the language of the definitions to pipes with a longitudinal joint factor of less than 1.0. Doing so would ultimately include pipes with unknown joint factors, as § 192.113 requires a default longitudinal joint factor of 0.80 for any pipe with an unknown longitudinal joint factor. Similarly, AGL Resources, Alliant Energy, Atmos Energy, and TECO Peoples Gas supported AGA’s suggested revisions to the definitions of legacy construction techniques and legacy pipe. API commented that PHMSA’s proposed definition of legacy construction technique inappropriately includes the repair technique of puddle welds and recommended PHMSA clarify the definitions of wrought iron and pipe made from Bessemer steel. Dominion Transmission commented there may be instances where the longitudinal seam for modern day pipe is unknown, yet the pipe is not a highrisk seam type. They stated that such pipe does not present an integrity threat and should be excluded from the ‘‘legacy pipe’’ definition. Gas Piping Technology Committee commented that the proposed definition of legacy construction techniques seems to contain some erroneous information. They asserted that the proposed definition went too far by implying that all the listed methods are no longer used to construct or repair pipelines, stating that while wrinkle bends may no longer be a common construction technique, they are still allowed under § 192.315 for steel pipe operating at a pressure producing a hoop stress of less than 30 percent of SMYS. Similarly, Oleksa and Associates commented that some operators are still installing Dresser couplings. The Michigan Public Service Commission staff suggested that PHMSA add to the definition of ‘‘legacy construction techniques’’ a subsection that addresses other legacy construction techniques that are not in the current list and include within this subsection language referencing ‘‘all other’’ techniques. Northern Natural Gas proposed PHMSA eliminate the phrase ‘‘including any of the following techniques’’ from the definition of legacy construction techniques as it implies the list is not complete. They suggested that the definition of legacy pipe should differentiate between ductile and brittle pipe by toughness values in both the seam and the pipe VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 body. Lastly, SoCalGas thought it would be more appropriate to reference these definitions under the IM regulations in subpart O instead of defining the terms in the context of the entire part. These definitions were taken up by the GPAC in the context of the scope of MAOP reconfirmation, and they recommended in the meeting on March 26, 2018, that the definitions be withdrawn. Because the GPAC recommended to revise the scope of MAOP confirmation to not include pipelines with previous reportable incidents due to crack defects, these definitions would no longer be needed in the rule. 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding the proposed definitions for ‘‘legacy pipe’’ and ‘‘legacy construction techniques.’’ After considering these comments and as recommended by the GPAC, PHMSA is withdrawing these definitions from the final rule. Because the revised scope of MAOP confirmation requirements, discussed in the previous sections, no longer includes pipelines with previous reportable incidents due to crack defects, these definitions are no longer necessary. C. Seismicity and Other Integrity Management Clarifications—§ 192.917 1. Summary of PHMSA’s Proposal Subpart O of 49 CFR part 192 prescribes requirements for managing pipeline integrity in HCAs. It requires operators of covered segments to identify potential threats to pipeline integrity and use that threat identification in their integrity programs. Included within this process are requirements to identify threats to which the pipeline is susceptible, collect data for analysis, and perform a risk assessment. Special requirements are included to address particular threats such as third-party damage and manufacturing and construction defects. Following the PG&E incident, the NTSB recommended that PG&E evaluate every aspect of its IM program, paying particular attention to the areas identified in the incident investigation, and implement a revised IM program. PHMSA held a workshop on July 21, 2011, to address perceived shortcomings in the implementation of IM risk assessment processes and the information and data analysis (including records) upon which such risk assessments are based. PHMSA also sought input from stakeholders on these issues in the ANPRM. PO 00000 Frm 00029 Fmt 4701 Sfmt 4700 52207 Section 29 of the 2011 Pipeline Safety Act requires that operators consider the seismicity of the geographic area in identifying and evaluating all potential threats to each pipeline segment, pursuant to 49 CFR part 192. Pipeline threat analysis is addressed as one program element in the IM regulations in subpart O. Addressing seismicity is already implicitly required by § 192.917 as part of addressing outside force threat through the incorporation by reference of ASME B31.8S. Based on the direction of the mandate, PHMSA proposed to explicitly require that operators analyze seismicity and related geotechnical hazards, such as geology and soil stability, as part of the threat identification IM program element and mitigate those threats of outside force damage. PHMSA determined this would clarify expectations for this requirement and explicitly implement section 29 of the 2011 Pipeline Safety Act. PHMSA also proposed revisions to § 192.917(e) to clarify that certain pipe designs must be pressure tested to assume that seam flaws are stable and that failures or changes to operating pressures that could affect seam stability are evaluated using fracture mechanics analysis. 2. Summary of Public Comment There was broad support for explicitly requiring the consideration of the seismicity of a geographic area when identifying and evaluating all potential threats to a pipeline segment, and several stakeholders suggested minor revisions to the proposal. California Public Utilities Commission (CPUC) supported the proposed provisions and recommended adding text that would require consideration of any significant localized threat that could affect the integrity of the pipeline. CPUC further commented that operating conditions on the pipeline must also be a factor when operators identify local threats. Some commenters, including PG&E and NGA, requested further clarification regarding what would constitute a seismic event for the purposes of identifying threats under the IM program for compliance purposes. AGA requested clarification on the requirements regarding whether operators are expected to conduct a onetime investigation on the risk of seismicity and geology, or if there is an expectation of a periodic requirement for re-investigation. Multiple commenters disagreed with the proposed requirement in § 192.917(e) for operators to perform annual cyclic fatigue analyses if an operator identifies cyclic fatigue as a threat. INGAA and National Fuel E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 52208 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations suggested that cyclic fatigue is an uncommon risk for natural gas pipelines and asserted that PHMSA did not provided significant technical justification for this analysis requirement. Some commenters suggested that the proposal to address cyclic fatigue and require pressure tests on seam threats is an overcompensation for the level of risk the threats present. Trade associations and pipeline industries proposed several alternative requirements for the conditions under which cyclic fatigue analyses should be required. API stated that they did not object to the measures listed, but the proposed provisions in § 192.935(b)(2) imply that an operator must take all the actions listed. API asserted that PHMSA should modify this proposed provision to state that operators must consider taking the actions listed but would not be specifically required to take all of them. Other commenters expressed concern that these proposed requirements conflict with the proposed requirements for pipeline segments needing to undertake MAOP reconfirmation because they experienced an incident due to manufacturing and construction (M&C) defects. Specifically, the requirements under § 192.917(e)(3) only allow operators to consider M&C defects stable if they have been subjected to a hydrostatic pressure test of 1.25 times MAOP, which would seemingly disallow or otherwise make fruitless the other methods of MAOP reconfirmation for these types of pipeline segments. At the GPAC meeting on January 12, 2017, the GPAC recommended that no changes should be made to the proposed provisions on seismicity. Regarding § 192.917(e)(2), which was discussed during the meeting on June 6– 7, 2017, the GPAC noted that, under this provision, operators should be monitoring for condition changes that would cause the threat to potentially activate, and those condition changes should be what triggers a reassessment. The GPAC also noted problems with a suggested revision of performing a cyclic fatigue analysis within a 7calendar-year period to match certain IM requirements because it would then impose a hard deadline on the continuous monitoring process and would prompt operators to act and again study cyclic fatigue even if the monitoring showed no evidence of cyclic fatigue being a threat. At the meeting, PHMSA suggested that operators could ensure the data involved in a cyclic fatigue analysis is periodically verified within a period not exceeding 7 years to align with IM requirements, but operators would only VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 be required to perform a full evaluation if the data has changed. Following that discussion, the GPAC recommended revising the proposed requirements for cyclic fatigue at § 192.917 based on the discussion of GPAC members and considering PHMSA’s proposed language that was presented at the meeting. At the GPAC meeting on March 26– 28, 2018, a public commenter suggested PHMSA remove the word ‘‘hydrostatic’’ from the requirements for considering M&C-related defects stable because any strength test that is approved in subpart J should qualify. Further, that public commenter suggested adding language where a pressure reduction or an ILI assessment with an ECA could be allowed for M&C defects as well. Another public commenter suggested removing references to cracks in these sections if PHMSA was intending to create a new section dedicated to addressing crack defects. Ultimately, the GPAC recommended PHMSA revise the proposed requirements for M&C defects by deleting a cross-reference with the MAOP reconfirmation requirements, updating an applicability reference, and considering removing the term ‘‘hydrostatic’’ while allowing other authorized testing procedures. For the requirements related to electric resistance welded (ERW) pipe, the GPAC recommended PHMSA delete the phrase related to pipe body cracking and have those requirements be addressed in a new section within the IM regulations related to crack defects. 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding the consideration of seismicity and manufacturing- and construction-related defects under the IM regulations. After considering these comments as well as recommendations by the GPAC, PHMSA is revising § 192.917(e)(2) to require operators monitor operating pressure cycles and periodically determine if the cyclic fatigue analysis is valid at least once every 7 calendar years, not to exceed 90 months, as necessary. PHMSA is also deleting a reference to the MAOP reconfirmation requirements in § 192.624 and is referencing the new § 192.712 for fracture mechanics analysis. PHMSA believes these changes are consistent with current IM requirements and will increase regulatory flexibility while maintaining pipeline safety. In § 192.917(e)(3), PHMSA deleted a cross-reference to the MAOP reconfirmation requirements in § 192.624 and replaced it with a PO 00000 Frm 00030 Fmt 4701 Sfmt 4700 requirement to prioritize the pipeline segment if it has experienced an inservice reportable incident since its most recent successful subpart J pressure test due to an original manufacturing-related defect; or a construction-, installation-, or fabrication-related defect. This clarifies that the IM requirement in § 192.917(e)(3) is not part of the MAOP reconfirmation standards. Although the GPAC asked PHMSA to consider removing the term ‘‘hydrostatic’’ and allow other testing procedures, PHMSA is retaining the term ‘‘hydrostatic’’ in § 192.917(e)(3), as the proposed revision, as written, addresses NTSB recommendation P–11–15. The NTSB specifically recommended that PHMSA amend part 192 so that manufacturingand construction-related defects can only be considered stable following a postconstruction hydrostatic pressure test of at least 1.25 times the MAOP. Therefore, deleting the word ‘‘hydrostatic’’ would be contrary to the letter and intent of this NTSB recommendation. For the requirements related to ERW pipe in § 192.917(e)(4), PHMSA has deleted the phrase related to pipe body cracking and deleted a cross-reference to the MAOP reconfirmation requirements in § 192.624, referencing the new § 192.712 for fracture mechanics analysis instead for cracking and crackrelated issues. PHMSA made these changes to streamline the regulations and increase readability. D. 6-Month Grace Period for 7-CalendarYear Reassessment Intervals—§ 192.939 1. Summary of PHMSA’s Proposal Section 5 of the 2011 Pipeline Safety Act identifies a technical correction amending 49 U.S.C. 60109(c)(3)(B) to allow the Secretary of Transportation to extend the 7-calendar-year IM reassessment interval for an additional 6 months if the operator submits written notice to the Secretary with sufficient justification of the need for the extension. The NPRM proposed to codify this technical correction as required by the statute. 2. Summary of Public Comment PHMSA received a comment regarding the 6-month grace period for the 7-calendar-year reassessment interval from a trade organization expressing general support of the proposed provisions and requesting that PHMSA clarify that the 6-month extension begins after the close of the 7calendar-year reassessment interval period, which would be consistent with E:\FR\FM\01OCR2.SGM 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations the 2011 Pipeline Safety Act revision to the Federal Pipeline Safety Statutes. At the GPAC meeting on January 12, 2017, the GPAC voted that the proposed changes on the 6-month grace period for the reassessment intervals are technically feasible, reasonable, costeffective, and practicable, and did not recommend that PHMSA modify these proposed provisions. 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding the grace period for IM reassessment intervals. After considering the comment and as recommended by the GPAC, PHMSA is retaining the proposed revisions to § 192.939 in this final rule. The proposed rule clearly stated that the 6-month extension begins after the close of the 7-calendar-year reassessment interval period. This is mirrored in PHMSA’s frequently asked questions (FAQ) for the IM program,72 which clarifies that the maximum interval for reassessment may be set using the specified number of calendar years in accordance with the 2011 Pipeline Safety Act. The use of calendar years is specific to gas pipeline reassessment interval years under IM and does not alter the interval requirements that appear elsewhere in the code for various inspection and maintenance requirements. jbell on DSK3GLQ082PROD with RULES2 E. ILI Launcher and Receiver Safety— § 192.750 1. Summary of PHMSA’s Proposal PHMSA determined that more explicit safety requirements are needed when performing maintenance activities that use launchers and receivers for inserting and removing ILI maintenance tools and devices. The current regulations for hazardous liquid pipelines under part 195 have, since 1981, contained safety requirements for scraper and sphere facilities. However, the current regulations for natural gas transmission pipelines do not similarly require controls or instrumentation to protect against an inadvertent breach of system integrity due to the incorrect operation of launchers and receivers for ILI tools, or scraper and sphere facilities. As a result, PHMSA proposed to add a new section to the Federal Pipeline Safety Regulations to require ILI launchers and receivers include a suitable means to relieve pressure in the barrel and either a means to indicate the pressure in the barrel or a means to prevent opening if pressure has not been relieved. While most launchers and 72 FAQ–41 at https://primis.phmsa.dot.gov/ gasimp/faqs.htm. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 receivers are already equipped with such devices, some older facilities may not be so equipped. Under the proposed provisions, operators would be required to have this safety equipment installed consistent with current industry practice. 2. Summary of Public Comment Stakeholders, including TPA, provided input on PHMSA’s changes to the requirements for safety when performing maintenance activities that utilize launchers and receivers for inserting and removing inspection and maintenance tools and devices. TPA supported the proposed safety additions to the regulations but stated that § 192.750 should be included within the regulations for pipeline components rather than the subpart for pipeline maintenance. In addition, TPA suggested PHMSA revise the language to allow 18 months after the effective date of the rule to comply with the provisions. This change would allow for more time to plan, budget, and complete the work safely. Another commenter recommended these provisions be effective prior to the next time an operator would use an applicable launcher or receiver. Public interest groups and others, such as PST and NAPSR, had broad support for the proposed provisions regarding ILI launcher and receiver safety. At the GPAC meeting on January 12, 2017, a public commenter suggested clarification on PHMSA’s use of the term ‘‘relief device’’ or ‘‘relief valve’’ within the proposed provisions. During discussion, the committee noted that there are requirements for ‘‘relief valves’’ elsewhere in the code, and calling a needed safety device for ILI launchers and receivers a ‘‘relief valve’’ would then make it subject to those additional requirements. Based on that discussion, the committee recommended that PHMSA modify the proposed rule to clarify that the rule does not require ‘‘relief valves’’ or use ‘‘relief valve’’ as an officially defined term within the provision, as those terms have distinct meanings within the broader context of the Federal Pipeline Safety Regulations. 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding launcher and receiver safety. After considering these comments and the GPAC input, PHMSA is finalizing the provisions as they were proposed in the NPRM, with the exception of a compliance date 1 year after the effective date of the rule. This approach avoids disruption of work planned PO 00000 Frm 00031 Fmt 4701 Sfmt 4700 52209 within a year of the effective date of the rule, and it allows operators that are not planning work until beyond the 1-year grace period to implement the upgrade before the next planned use. Therefore, special modification work would not be required before the launcher or receiver is needed. Operators would not be required to perform the upgrades until the launcher or receiver is to be used. Consistent with the originally proposed language, this final rule does not use the term ‘‘relief valve’’ and instead uses the generic phrase ‘‘device capable of safely relieving pressure.’’ The proposed rule effectively avoided any potential for confusion with respect to the defined term ‘‘relief valve’’ and the requirements associated with those components, therefore no change to this wording was necessary for this final rule. PHMSA believes that this requirement is appropriately located in subpart M, ‘‘Maintenance,’’ of part 192, and notes that the comparable requirement in part 195 for hazardous liquid pipelines is located in subpart F, ‘‘Operations and Maintenance.’’ F. MAOP Exceedance Reporting— §§ 191.23, 191.25 1. Summary of PHMSA’s Proposal Section 23 of the 2011 Pipeline Safety Act requires that operators report each exceedance of a pipeline’s MAOP beyond the build-up allowed for the operation of pressure-limiting or control devices. On December 21, 2012 (77 FR 75699), PHMSA published Advisory Bulletin ADB–2012–11 to advise operators of their responsibility under section 23 of the 2011 Pipeline Safety Act to report such exceedances. The advisory bulletin further stated that the reporting requirement is applicable to all gas transmission pipeline facility owners and operators. PHMSA advised pipeline owners and operators to submit this information in the same manner as safety-related condition reports. The information pipeline owners and operators submit should comport with the information listed at § 191.25(b), and pipeline owners and operators submitting such information should use the reporting methods listed at § 191.25(a). Although this provision of the 2011 Pipeline Safety Act is self-executing, PHMSA proposed to revise the safetyrelated condition reporting requirements under part 191 to codify this requirement and harmonize part 191 with the statutory requirement by eliminating the reporting exemption and to provide a consistent procedure, E:\FR\FM\01OCR2.SGM 01OCR2 52210 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations format, and structure for operators to submit such reports. jbell on DSK3GLQ082PROD with RULES2 2. Summary of Public Comment Trade associations, citizen groups, and pipeline industries generally supported PHMSA’s codification of the statutory reporting requirements for MAOP exceedances for transmission lines. API and GPA objected to MAOP exceedance reporting requirements for unregulated gathering pipelines. GPA stated that PHMSA did not sufficiently weigh the benefits of reporting MAOP exceedance against the hurdles to compliance for unregulated gathering pipelines. GPA also questioned whether PHMSA has the authority to require unregulated gathering pipelines report MAOP exceedance, since complying with this reporting requirement would necessitate that unregulated gathering pipelines establish MAOP, which they are currently not required to do. Citizen and other safety groups, including Earthworks, NAPSR, the Pipeline Safety Coalition, and PST, supported the inclusion of unregulated gathering pipelines in this section, stating that it would improve pipeline safety. Several commenters suggested editorial revisions to streamline and improve these provisions. NGA expressed concern that the proposed provisions could apply to distribution systems and suggested that PHMSA clarify that reporting requirements for MAOP exceedance only apply to transmission pipelines. Additionally, Spectra Energy Partners requested that PHMSA require reporting of MAOP exceedances only when the operator is unable to respond to MAOP exceedances within the timeframe required elsewhere in part 192. One operator expressed concern that the proposed change would require operators to submit additional safetyrelated condition reports anytime the operator had to implement a pressure reduction upon discovering an immediate condition. At the GPAC meeting on June 7, 2017, there was brief discussion on whether the 5-day reporting requirement was too prescriptive, but the committee agreed that PHMSA was properly implementing the statutory requirement as written and intended by Congress. Following that discussion, the committee recommended that PHMSA modify the proposed rule to clarify that the MAOP exceedance reporting provisions do not apply to gathering lines. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding MAOP exceedance reporting. The 2011 Pipeline Safety Act mandates that an operator report MAOP exceedances on gas transmission lines, regardless of whether the operator corrects the safetyrelated condition through repair or replacement. After considering the comments PHMSA received on the NPRM and as recommended by the GPAC, PHMSA is inserting the word ‘‘only’’ in the additional MAOP exceedance reporting provision in § 191.23(a)(10) to make it clearer that the amended requirement applies only to gas transmission lines and not to gathering or distribution lines. Conforming changes were made to § 191.23(a)(6). PHMSA notes that the prior safety-related condition reporting requirements and exceptions related to pressure exceedances for gathering and distribution lines have not been altered. G. Strengthening Assessment Requirements—§§ 192.150, 192.493, 192.921, 192.937, Appendix F i. Industry Standards for ILI— §§ 192.150, 192.493 1. Summary of PHMSA’s Proposal In the NPRM, PHMSA proposed to revise § 192.150 to incorporate by reference a NACE Standard Practice, NACE SP0102–2010, ‘‘In-line Inspection of Pipelines,’’ to promote a higher level of safety by establishing consistent standards for the design and construction of pipelines to accommodate ILI devices. In § 192.493, PHMSA proposed requirements for operators to comply with the requirements and recommendations of API STD 1163, Inline Inspection Systems Qualification Standard; ANSI/ASNT ILI–PQ–2005, Inline Inspection Personnel Qualification and Certification; and NACE SP0102– 2010, In-line Inspection of Pipelines. PHMSA also proposed to allow operators to conduct assessments using tethered or remotely controlled tools. 2. Summary of Public Comment NAPSR supported the proposed provisions in § 192.493, commenting that the incorporation by reference of the three consensus standards provides enhanced guidance for the determination of adequate procedures and qualifications related to in-line inspections of transmission pipelines. Some industry representatives commented that it is unnecessary to incorporate American Society for Nondestructive Testing (ASNT) ILI–PQ by reference since API 1163 requires PO 00000 Frm 00032 Fmt 4701 Sfmt 4700 that providers of ILI services ensure that their employees are qualified. Others commented that PHMSA should exclude requirements contained in section 11 of API 1163, which pertains to quality management systems. Lastly, industry representatives asserted that ILI vendors may not be able to meet the 90 percent tool tolerance specified in the referenced standards, and PHMSA should relocate these proposed requirements to a different subpart. Several commenters noted that if PHMSA required compliance with ‘‘the requirements and recommendations of’’ the recommended practices and standards, it would create enforceable requirements out of actions that the standards themselves did not necessarily mandate. During the GPAC meeting of March 2, 2018, the committee recommended PHMSA revise this provision by striking the phrase ‘‘the requirements and the recommendations of,’’ so that recommendations within the incorporated standard would not be made mandatory requirements. 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding the incorporation by reference of industry standards for ILI. After considering these comments and as recommended by the GPAC, PHMSA is deleting the phrase ‘‘the requirements and the recommendations of’’ from §§ 192.150 and 192.493 so that the recommendations within the incorporated standard would not be made mandatory requirements. PHMSA believes that the inclusion of the NACE standard at § 192.150 will help to address the NTSB recommendation P–15–20, which asked PHMSA to identify all operational complications that limit the use of ILI tools in piggable pipelines, develop methods to eliminate those complications, and require operators use such methods to increase the use of ILI tools. PHMSA also believes that more pipelines will become piggable in the future as the nation’s pipeline infrastructure ages and is eventually replaced. A current provision in the regulations requires that all new and replaced pipeline be piggable, and as operators address higher-risk infrastructure through this rulemaking, there is a likelihood that some previously unpiggable pipe will be replaced. PHMSA disagrees that ASNT ILI–PQ is unnecessary. The foreword of API 1163 states ‘‘This standard serves as an umbrella document to be used with and complement companion standards. E:\FR\FM\01OCR2.SGM 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations NACE SP0102, In-line Inspection of Pipelines and ASNT ILI–PQ, In-line Inspection Personnel Qualification and Certification.’’ These three standards are complimentary and are intended to be used together. PHMSA also disagrees that quality requirements should be excluded from the rule. One of the fundamental objectives of this rule is to establish a minimum standard for quality in conducting ILI. Also, the consensus industry standard API 1163 only uses 90 percent tool tolerance as an example to illustrate key points but does not specify or establish a minimum standard tool tolerance of 90 percent. G. Strengthening Assessment Requirements—§§ 192.150, 192.493, 192.921, 192.937, Appendix F ii. Expand Assessment Methods Allowed for IM—§§ 192.921(a) and 192.937(c) jbell on DSK3GLQ082PROD with RULES2 1. Summary of PHMSA’s Proposal In the current Federal Pipeline Safety Regulations, § 192.921 requires that operators with pipelines subject to the IM rules must perform integrity assessments. Currently, operators can assess their pipelines using ILI, pressure test, direct assessment, and other technology that the operator demonstrates provides an equivalent level of understanding of the condition of the pipeline. In the NPRM, PHMSA proposed to require that direct assessment only be allowed when the pipeline cannot be assessed using ILI. As a practical matter, direct assessment is typically not chosen as the assessment method if the pipeline can be assessed using ILI. Further, PHMSA proposed to add three additional assessment methods to the regulations: 1. A spike hydrostatic pressure test, which is particularly well-suited to address stress corrosion cracking and other cracking or crack-like defects; 2. Guided Wave Ultrasonic Testing (GWUT), which is particularly appropriate in cases where short segments such as road or railroad crossings are difficult to assess; and 3. Excavation with direct in situ examination. 2. Summary of Public Comment NAPSR expressed its support for the proposed provisions. Many comments expressed concerns with the proposed provisions for the assessment methods regarding uncertainties in reported results. Multiple commenters stated that operators should be able to run the appropriate assessment or ILI tools for the threats that are known or likely to exist on the pipeline based on its VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 condition. Atmos Energy commented that ASME/ANSI B318.S requirements should be the standard to which operators are required to follow. Enable Midstream Partners proposed that PHMSA add ‘‘significant’’ to make a distinction between significant and insignificant threats and offered specific language to address its concerns. PG&E commented on the proposed provisions for ILI assessments, requesting that PHMSA provide guidance as to how to explicitly consider the numerous uncertainties associated with ILI regarding anomaly location accuracy, detection thresholds, and sizing accuracy, and suggested that PHMSA allow industry guidance and best practices to be used where practical. Some commenters expressed concern that PHMSA proposed to add requirements surrounding the detection of anomalies that many ILI tools could not meet. These commenters stated that there are no tools designed to find girth weld cracks and that most incidents caused by girth weld cracks have thirdparty excavation damage as a contributing factor. Commenters further stated that this is a threat that is best handled by procedures that require caution around girth welds during excavation and backfilling procedures. Several entities commented on the proposed qualification requirements under the ILI assessment method provisions, expressing concern that they are redundant with existing operator qualification regulations under the IM regulations at § 192.915 and the proposed revisions to § 192.493 incorporating the industry ANSI standard on ILI personnel qualification. Multiple entities proposed changes to remove such redundancies and improve clarity. Commenters requested clarification that the proposed text in the IM assessment provisions ‘‘apply one or more of the following methods for each threat to which the covered segment is susceptible’’ does not mean that at least one assessment is required for each threat. Additionally, commenters disagreed with adding an explicit requirement for a ‘‘no objection’’ letter as notification of using ‘‘other technology’’ and suggested that if this notification is required, operators should be allowed to proceed with the technology if they do not receive a ‘‘no objection’’ letter from PHMSA within a certain period. The NTSB commented that PHMSA’s proposal to revise the pipeline inspection requirements to allow the direct assessment method to be used only if a line is not capable of inspection by internal inspection tools PO 00000 Frm 00033 Fmt 4701 Sfmt 4700 52211 directly conflicts with the recommendations of their pipeline safety study, Integrity Management of Gas Transmission Lines in High Consequence Areas, which recommended that PHMSA develop and implement a plan for eliminating the use of direct assessment as the sole integrity assessment method for gas transmission pipelines. The CPUC asserted that direct assessment must always be supplemented with other methods, such as ILI or a pressure test. Many industry entities argued that PHMSA’s proposed changes to the IM assessment provisions limiting direct assessment to unpiggable lines are not technically justified. Several entities, including AGA and API, believed it was unreasonable to limit operators’ ability to use direct assessment for pipeline assessments unless all other assessment methods have been determined unfeasible or impractical. PG&E requested that PHMSA recognize that although a pipeline may be considered piggable, it does not mean that ILI technology is available, and they provided specific suggestions for revision. Similarly, AGA stated that free-swimming flow-driven ILI tools are often not compatible with intrastate transmission lines for several reasons, stating that certain conditions must exist to assess a pipeline by ILI and obtain valid data, including adequate flow rate, lack of bends or valves that would impede diameter, and ability to insert and remove the tool from the system. Therefore, AGA provided a suggested definition for ‘‘able to accommodate inspection by means of an instrumented in-line inspection tool.’’ Trade associations asserted that direct assessment is a proven assessment technique that works in addressing the threat of corrosion. INGAA stated that the criteria for when direct assessment can be used should depend on whether direct assessment can provide the necessary information about the pipe condition rather than whether other assessment methods can be used. AGA commented that it is not aware of any industry study that would suggest that direct assessment does not work effectively to identify corrosion defects in certain circumstances, which it describes in its comments. In addition, AGA stated that direct assessment is a predictive tool that identifies areas where corrosion could occur, including time-dependent threats, while other methods can only detect where corrosion has resulted in a measurable metal loss. Atmos Energy commented that limiting the use of direct assessment only to those pipeline segments that are not capable of E:\FR\FM\01OCR2.SGM 01OCR2 52212 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations inspection by internal inspection tools is not consistent with other requirements of subpart O. At the GPAC meeting on December 15, 2017, the committee voted to revise the ‘‘no objection’’ process to incorporate language stating that, if an operator does not receive an objection letter from PHMSA within 90 days of notifying PHMSA of an alternative sampling approach, the operator can proceed with their method. Additionally, the GPAC, during the meeting on March 2, 2018, recommended that PHMSA change these provisions to clarify that operators should select the appropriate assessment based on the threats to which the pipeline is susceptible and remove certain language that is duplicative to another existing section of the regulations. The GPAC also recommended that PHMSA clarify that direct assessment is allowed where appropriate but may not be used to assess threats for which the method is not suitable. Further, the GPAC wanted PHMSA to incorporate the notification and objection procedure and 90-day timeframe that the GPAC approved under the material properties verification requirements. jbell on DSK3GLQ082PROD with RULES2 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding the inclusion of additional assessment methods for integrity assessments. After considering these comments and as recommended by the GPAC, PHMSA is clarifying in this final rule that operators should select the appropriate assessment method based on the threats to which the pipeline is susceptible and is removing language regarding the qualification of persons reviewing ILI results that is duplicative with existing § 192.915. PHMSA is also clarifying in § 192.921 that direct assessment is allowed where appropriate but may not be used to assess threats for which the method is not suitable, such as assessing pipe seam threats. In addition, PHMSA incorporated the notification procedure under § 192.18 with the 90-day timeframe and objection process. PHMSA notes that other comments regarding the determination of suitable assessment methods for applicable threats and ILI tool capabilities relate to long-standing IM regulations that were not proposed for revision. PHMSA did provide substantial additional guidance and standards for implementing the integrity assessment requirements for ILI by incorporating the industry standards in § 192.493, as discussed in the previous sections. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 G. Strengthening Assessment Requirements—§§ 192.150, 192.493, 192.921, 192.937, Appendix F iii. Guided Wave Ultrasonic Testing— Appendix F 1. Summary of PHMSA’s Proposal When expanding assessment methods for both HCA and non-HCA areas, PHMSA proposed to add three additional assessment methods, one being GWUT. Under the existing regulations, GWUT is considered ‘‘other technology,’’ and operators must notify PHMSA prior to its use. PHMSA developed guidelines for the use of GWUT, which have proven successful, and proposed to add them under a new Appendix F to part 192—Criteria for Conducting Integrity Assessments Using Guided Wave Ultrasonic Testing. As such, future notifications to PHMSA would not be required, representing a cost savings for operators. 2. Summary of Public Comment Multiple entities commented in support of using GWUT and the inclusion of proposed Appendix F. NAPSR expressed its agreement with and support for the proposed Appendix. American Public Gas Association (APGA) applauded PHMSA for including guidelines for GWUT; however, it cautioned that the guidance only specifies Guided Ultrasonics LTD (GUL) Wavemaker G3 and G4, which use piezoelectric transducer technology, as acceptable technology. APGA recommended that Magnetostrictive Sensor technology also be included as an acceptable guided wave technology, stating that at least one of its members reported good results using this technology for guided wave assessment of an unpiggable segment of a transmission pipeline. A commenter noted that the requirement of both torsional and longitudinal wave modes in all situations introduces unnecessary complexity into the GWUT data interpretation process. The commenter further noted that PHMSA should specify that torsional wave mode is the primary wave mode when utilizing GWUT, and that longitudinal wave mode may be used as an optional, secondary mode. Other commenters recommended additional changes to Appendix F, such as stating that qualified GWUT equipment operators are trained to understand the strengths, weaknesses, and proper applications of each wave mode and should have the freedom to select the appropriate and most effective wave mode(s) for the given situation. PG&E requested that PO 00000 Frm 00034 Fmt 4701 Sfmt 4700 PHMSA recognize that this technology is used at locations other than casings as implied in the introductory paragraph and commented that doubleended inspections are not always required to meet the specification. During the GPAC meeting on December 15, 2017, the GPAC agreed with the provisions related to Appendix F and GWUT but recommended PHMSA revise the ‘‘no objection’’ letter process. 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding GWUT. After considering these comments and as recommended by the GPAC, PHMSA is removing the reference to GUL equipment for clarity. PHMSA is modifying the notification process to allow operators to proceed with an alternative process for using GWUT if the operator does not receive an objection letter from PHMSA within 90 days of notifying PHMSA in accordance with § 192.18. PHMSA believes this change increases regulatory flexibility while maintaining pipeline safety. In this final rule, PHMSA is retaining the requirement to use both torsional and longitudinal wave modes since that is a long-standing requirement in PHMSA’s guidance for accepting GWUT as an allowed technology under an ‘‘other technology’’ notification. Also, PHMSA recognizes that GWUT is used at locations other than casings, although it is most often deployed for the integrity assessment of cased crossings. However, double-ended inspections would not always be required to meet Appendix F, and Appendix F does not require double-ended inspections. Double-ended inspections are not necessary as long as the guided wave ultrasonic test covers the entire length of the assessment as well as the ‘‘dead zone’’ where the equipment is set up. The proposed rule already addresses validation of operator training, but in this final rule, PHMSA is deleting the sentence ‘‘[t]here is no industry standard for qualifying GWUT service providers’’ to provide clarity. H. Assessing Areas Outside of HCAs— §§ 192.3, 192.710 i. MCA Definition—§ 192.3 1. Summary of PHMSA’s Proposal In the NPRM, PHMSA introduced a new definition for a Moderate Consequence Area (MCA). The proposed rule defined an MCA as an onshore area, not meeting the definition of an HCA, that is within a potential impact circle, as defined in § 192.903, containing 5 or more buildings intended E:\FR\FM\01OCR2.SGM 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES2 for human occupancy; an occupied site; or a right-of-way for a designated interstate, freeway, expressway, or other principal four-lane arterial roadway as defined in the Federal Highway Administration’s ‘‘Highway Functional Classification Concepts, Criteria and Procedures.’’ PHMSA proposed that requirements for data analysis, assessment methods, and immediate repair conditions within these MCAs would be similar to requirements for HCA pipeline segments but with longer timeframes so that operators could properly allocate resources to higherconsequence areas. PHMSA proposed that the 1-year repair conditions that currently exist for HCA pipeline segments would be 2-year repair conditions when found on MCA pipeline segments. These changes would ensure the prompt remediation of anomalous conditions that could potentially affect people, property, or the environment, commensurate with the severity of the defects, while still allowing operators to allocate their resources to HCAs on a higher-priority basis. 2. Summary of Public Comment The NTSB stated that the proposed provisions to create an MCA category and include a highway size threshold in the definition of an MCA accomplishes part of what the NTSB intended in Safety Recommendation P–14–1. However, the NTSB objected to the proposed highway coverage as being limited to four lanes and stated its support of expanding the highway size threshold as they had specifically recommended in P–14–1. The NTSB asserted that the proposed language would exclude the category of other principal arterial roadways wider than four lanes when, in fact, the wider roadways should be included. INGAA supported the addition of an MCA category to the Federal Pipeline Safety Regulations but recommended several modifications to the proposed definition. INGAA suggested PHMSA should limit the definition of an MCA to only those pipeline segments that could be assessed through an ILI inspection, amend the MCA definition to avoid ambiguity regarding residential structures, remove ‘‘outside areas and open structures’’ from the portion of the definition of MCA related to ‘‘identified sites,’’ include timeframes for incorporating changes to existing MCAs, and permit operators to use the edge of the pavement rather than the highway right-of-way to determine if a roadway intersects with a Potential Impact Circle. AGA, API, APGA, and several pipeline entities agreed with INGAA’s VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 comments on the modification to PHMSA’s proposed MCA definition. Additionally, AGA, API, and APGA emphasized PHMSA should remove the reference to ‘‘a right-of-way’’ for the designated roadways, commenting that the MCA definition could be interpreted so that if a Potential Impact Circle touches any portion of the roadway right-of-way, the pipeline segment is an MCA. That interpretation would put undue burden on operators in areas where its pipelines lay at or near the edge of the public right-of-way that would not normally contain ‘‘persons or property’’ that would sustain damage or loss in the event of a pipeline failure. Further, API added that the reference to ‘‘a right-of-way’’ is problematic because roadway right-of-ways are variable, cannot be seen with the naked eye, and are often not included in publicly available data sources. Commenters also disagreed with the definition of ‘‘occupied site’’ within the MCA definition. GPA asserted that the criterion used in the MCA definition should be limited to interstate highways, and the definition of ‘‘occupied site’’ should be eliminated to more clearly distinguish between MCAs and HCAs and to provide greater clarity in identifying and managing MCAs. Similarly, Enlink Midstream commented that PHMSA should eliminate the definition of occupied site and remove this criterion from the proposed definition of MCA. Doing so would permit the continued focus on HCAs that the IM process was intended to accomplish. AGL Resources also expressed concern with the proposed definition of occupied site, commenting that this definition could require operators to effectively perform a census-like identification of structures to verify the count of persons within that structure. There were conflicting viewpoints on where the definition of MCA should be placed in the regulations. API and other commenters stated that they preferred a new category and a distinct definition for MCA as opposed to expanding the definition of HCA or making a subcategory in the HCA definition for MCAs, whereas SoCalGas encouraged expanding the scope of HCAs rather than creating a new category. Enterprise Products commented PHMSA should move the MCA definition to subpart O and remove the ‘‘occupied site’’ criteria from the proposed definition of MCA, which would provide more distinction between MCAs and HCAs in the regulations and would also more appropriately place them under the IM regulations. PO 00000 Frm 00035 Fmt 4701 Sfmt 4700 52213 AGA and several other organizations expressed concern over the resourceintensive administrative task of identifying MCAs, especially pertaining to recordkeeping requirements. API asserted that the proposed provisions would limit operators’ ability to prioritize resources for pipelines that pose the highest risk. They further stated that while they agree with the inclusion of all Class 3 and Class 4 locations, occupied sites, and major roadways in the definition of MCA, they disagree with the proposed threshold of five buildings intended for human occupancy within the potential impact radius. They suggested that a more appropriate threshold would be more than 10 buildings intended for human occupancy, as that number is consistent with longstanding part 192 class location designations. Multiple groups, such as AGI, INGAA, and Cheniere Energy, also stated objections over various aspects of defining and identifying MCAs and provided suggestions for revised language, including several broad clarifications or deletions to the definition. In addition to requesting modifications to the definition of MCA, INGAA objected to the provided geographic information system (GIS) layer for right-of-way determination, and suggested that PHMSA provide one database for roadway classification. Numerous trade associations and pipeline companies asked PHMSA to consider a qualifier that the definition of MCA only applies to pipelines operating at greater than 30 percent SMYS. EnLink Midstream suggested using a threshold level of 16-inch pipe diameter to identify pipelines that pose a greater risk. The GPAC had a comprehensive discussion on the MCA definition during the meeting on March 2, 2018, and approved of the definition with some changes. First, the GPAC recommended changing the highway description within the definition to remove reference to the roadway ‘‘rights-of-way’’ and to add language so that the highway consists of ‘‘any portion of the paved surface, including shoulders.’’ Secondly, the GPAC recommended clarifying that highways with 4 or more lanes are included, and they also wanted PHMSA to work together with the Federal Highway Administration to provide operators with clear information relative to this aspect of the rulemaking and discuss it in the preamble. The GPAC also recommended that PHMSA discuss in the preamble what they expect the definition of ‘‘piggable’’ to be, as it is critical for aspects of the MCA E:\FR\FM\01OCR2.SGM 01OCR2 52214 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations definition as it relates to MAOP confirmation. Finally, the GPAC recommended PHMSA modify the term ‘‘occupied sites’’ in the MCA definition and in the definitions section of part 192 by removing the language referring to ‘‘5 or more persons’’ and the timeframe of 50 days and tying the requirement into the HCA survey for ‘‘identified sites’’ as discussed by GPAC members and PHMSA at the meeting. The committee noted that such site identification could be made through publicly available databases and class location surveys. The committee suggested PHMSA consider the necessary sites and enforceability of the definition per direction by the committee members. jbell on DSK3GLQ082PROD with RULES2 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding the definition of moderate consequence area. After considering these comments and the GPAC input, PHMSA is modifying the highway description within the definition to remove reference to the roadway ‘‘rights-ofway’’ and to add language so that the highway consists of ‘‘any portion of the paved surface, including shoulders.’’ Also, PHMSA is specifying that highways with 4 or more lanes are included. PHMSA believes these changes provide additional clarity. Per the GPAC’s request that PHMSA provide additional guidance on what roadways are included in the MCA definition as it pertains to ‘‘other principal roadways with 4 or more lanes,’’ PHMSA notes that the Federal Highway Administration defines Other Principal Arterial roadways 73 as those roadways that serve major centers of metropolitan areas, provide a high degree of mobility, and can also provide mobility through rural areas. Unlike their access-controlled counterparts (interstates, freeways, and expressways), abutting land uses can be served directly. Forms of access for Other Principal Arterial roadways include driveways to specific parcels and atgrade intersections with other roadways. For the most part, roadways that fall into the top three functional classification categories (Interstate, Other Freeways & Expressways, and Other Principal Arterials) provide similar service in both urban and rural areas. The primary difference is that 73 Federal Highway Administration, Office of Planning, Environment, & Realty (HEP), Highway Functional Classification Concepts, Criteria and Procedures (2013) https://www.fhwa.dot.gov/ planning/processes/statewide/related/highway_ functional_classifications/ section03.cfm#Toc336872980. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 there are usually multiple arterial routes serving a particular urban area, radiating out from the urban center to serve the surrounding region. In contrast, an expanse of a rural area of equal size would be served by a single arterial. The MCA definition does not include all roadways that meet this definition but instead is limited to those roadways meeting this definition that have four or more lanes. With respect to ‘‘occupied sites,’’ PHMSA evaluated the comments and the GPAC discussion and concluded that including occupied sites within the MCA definition was not necessary. Industry representatives on the GPAC asserted that most locations meeting the definition of occupied site are, as a practical matter, already included as an identified site and designated as an HCA. Commenters suggested most operators find it expedient to declare sites similar to occupied areas as HCAs instead of counting the specific occupancy of such locations to see if they meet the occupancy standard over the course of a year. Operators then monitor occupancy in subsequent years for changes that might change the site’s status as an occupied site. Such an approach would require fewer resources and be more conservative from a public safety standpoint. Based on these comments, PHMSA is persuaded that including another category of locations, similar to identified sites in HCAs but with a lower occupancy standard of 5 persons, is unnecessarily burdensome without a comparable decrease in risk. PHMSA disagrees that the MCA definition should be moved to subpart O. The term is used in sections outside of subpart O. Including the MCA definition in § 192.3 is necessary for it to apply to the sections in which it is used throughout part 192. H. Assessing Areas Outside of HCAs— §§ 192.3, 192.710 ii. Non-HCA Assessments—§ 192.710 1. Summary of PHMSA’s Proposal PHMSA proposed to add a new § 192.710 to require that pipeline segments in Class 3 or Class 4 locations, and piggable segments in MCAs, be initially assessed within 15 years and no later than every 20 years thereafter on a recurring basis. PHMSA also proposed to require assessments in these areas be conducted using the same methods that are currently allowed for HCAs. PHMSA has found that operators have assessed significant non-HCA pipeline mileage in conjunction with performing HCA integrity assessments in the same pipeline. Therefore, PHMSA proposed to allow the use of those prior PO 00000 Frm 00036 Fmt 4701 Sfmt 4700 assessments of non-HCA pipeline segments to comply with the new § 192.710. In effect, to this limited population of pipeline segments outside of HCAs, PHMSA proposed to expand the applicability of IM program elements related to baseline integrity assessments, remediating conditions found during integrity assessments, and periodic reassessments. In addition, under the proposed provisions, MCAs would be subject to other requirements related to the congressional mandates, including material properties verification and MAOP reconfirmation. Any assessments an operator would conduct to reconfirm MAOP under proposed § 192.624 would count as an initial assessment or reassessment, as applicable, under the proposed requirements for non-HCA assessments. 2. Summary of Public Comment The NTSB and multiple citizen groups supported the expansion of IM elements to gas transmission pipelines in areas outside those currently defined as HCAs. However, several entities, including PST, stated that applying a limited suite of IM tools to these areas was insufficient and requested that the full suite of IM elements be applied to the additional pipeline segments. Some citizen groups expressed concern that the 15-year implementation period and 20-year re-inspection period was too long. While pipeline companies and trade associations generally supported PHMSA’s efforts to expand IM elements beyond HCAs, many of them stated concerns over the time and cost required to identify MCAs, the efficacy of the changes, and the language and requirements regarding both the limitation of assessments to pipeline segments accommodating inline inspection tools and (re)assessment periods. Many groups requested a clear, concise set of codified requirements for IM outside of HCAs to simplify identification, recordkeeping, and repairs. Several commenters provided input on the allowable assessment methods for non-HCAs. AGA suggested that PHMSA create a new subpart consisting of a clear and concise set of codified requirements for the non-HCA assessments, including new definitions regarding the limitation of assessments to pipeline segments accommodating instrumented inline inspection tools. Many trade associations and pipeline companies stated that they thought the direct assessment method could achieve a satisfactory level of inspection in place of costlier in-line inspection, E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations especially given the additional detail added to the in-line inspection assessment method in the proposal. API requested that PHMSA allow operators to rely on any prior assessments performed under subpart O requirements of part 192 in effect at the time of the assessment rather than limit the allowance to ILI. Furthermore, other organizations supported AGA’s proposal that mirrors and extends to MCAs the two-methodology approach used to determine HCAs in the existing § 192.903, which allows for identification based on class location or by the pipeline’s potential impact radius. Entities, including API and Atmos Energy, requested clarification regarding assessment periods and reassessment intervals due to the language regarding shorter reassessment intervals ‘‘based on the type [of] anomaly, operational, material and environmental conditions [. . .], or as otherwise necessary.’’ Those commenters said that language was vague and subject to varying interpretations, so they suggested revisions to the language for the reassessment intervals. Lastly, AGA suggested that PHMSA define the term ‘‘pipelines that can accommodate inspection by means of an instrumented in-line inspection tool’’ used in proposed §§ 192.710 and 192.624, stating that providing the criteria that a pipeline must meet to be able to accommodate an in-line inspection tool would remove uncertainty and inconsistency in determining which pipelines meet PHMSA’s proposed qualifier. The GPAC discussed the provisions related to assessments outside of HCAs during the meeting on March 2, 2018. The GPAC found the provisions to be technically feasible, reasonable, costeffective, and practicable if PHMSA clarified that direct assessment could be used only if appropriate for the threat being assessed and could not be used to assess threats for which direct assessment is not suitable, and removed the provisions related to low-stress assessments. The GPAC also recommended revising the initial assessment and reassessment intervals for applicable pipeline segments from an initial assessment within 15 years of the effective date of the rule and periodic assessments every 20 years thereafter to an initial assessment within 14 years of the effective date of the rule and periodic assessments every 10 years thereafter. The GPAC stated that the prioritization of initial assessments and reassessments should be based on the risk profiles of the pipelines. The GPAC also wanted VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 PHMSA to apply the assessment and reassessment requirements only to pipelines with MAOPs greater than or equal to 30 percent SMYS. 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding integrity assessments outside HCAs. After considering these comments and as recommended by the GPAC, PHMSA is modifying the rule to specify that direct assessment may be used only if appropriate for the threat being assessed and cannot be used to assess threats for which direct assessment is not suitable, such as assessing pipe seam threats. PHMSA made these changes to provide clarity regarding the proper use of direct assessments. In addition, PHMSA is revising the applicability of § 192.710 to apply only to pipelines with an MAOP of greater than or equal to 30 percent of SMYS. PHMSA made this change because the GPAC recommended it was costeffective for the provision to only apply to pipe operating above 30% SMYS in Class 3 and 4 locations and because those pipelines present the greatest risk to safety. Because of this modification, PHMSA is withdrawing provisions related to low-stress assessments since they will no longer be applicable. Based on the comments and recommendations from the GPAC, PHMSA is also modifying the initial assessment deadline and reassessment intervals for applicable pipeline segments to 14 years after the publication date of the rule and every 10 years thereafter, which was reduced from 15 years and 20 years, respectively. PHMSA believes this change increases regulatory flexibility while maintaining pipeline safety. PHMSA is also adding a requirement that the initial assessments must be scheduled using a risk-based prioritization. PHMSA disagrees with the need to implement a dual approach to MCA identification that would be similar to the ways that HCAs are identified. Subpart O and the IM regulations were first promulgated before pipeline operators had experience with potential impact radius (PIR) techniques, and incorporating an alternative HCA identification method into the original IM regulations using conventional class locations was convenient and appropriate. Pipeline operators now have over 15 years of experience working with the PIR concept; therefore, PHMSA determined using the PIR method for determining MCAs in the definition of MCAs is appropriate. PHMSA also disagrees that a separate subpart would be preferable and is PO 00000 Frm 00037 Fmt 4701 Sfmt 4700 52215 retaining the requirements for MCA assessments in a new § 192.710. PHMSA believes the requirement to have a shorter reassessment interval is clear and is not modifying that aspect of the rule. PHMSA included a requirement for operators to not automatically default to the maximum reassessment interval but to establish shorter reassessment intervals ‘‘based upon the type anomaly, operational, material, and environmental conditions found on the pipeline segment, or as necessary to ensure public safety’’ when appropriate. Operators have been required to perform similar analyses and adjustment of reassessment intervals for HCAs since the inception of the IM regulations in 2003 and should be familiar with this process over 15 years later. PHMSA believes that stating the overarching goal of assuring public safety by evaluating each pipeline and its circumstances and establishing appropriate assessment intervals based on those circumstances provides clear intent and is an appropriate approach. PHMSA believes that the term ‘‘piggable segment’’ is very widely understood in the industry and is not including additional definitions or regulatory language to expand upon this term. PHMSA understands that a pipeline segment might be incapable of accommodating an in-line inspection tool for a number of reasons, including but not limited to short radius pipe bends or fittings, valves (reduced port) that would not allow a tool to pass, telescoping line diameters, and a lack of isolation valves for launchers and receivers. Some unpiggable pipelines can be made piggable with modest modifications, but others cannot be made piggable short of pipe replacement. PHMSA understands that a pipeline segment is piggable if it can accommodate an instrumented ILI tool without the need for major physical or operational modification, other than the normal operational work required by the process of performing the inline inspection. This normal operational work includes segment pigging for internal cleaning, operational pressure and flow adjustments to achieve proper tool velocity, system setup such as valve positioning, installation of temporary launchers and receivers, and usage of proper launcher and receiver length and setup for ILI tools. In addition, a pipeline segment that is not piggable for a particular threat because of limitations in technology such that an ILI tool is not commercially available, might be piggable for other threats. For example, a pipeline that is unable to accommodate a crack tool might be able E:\FR\FM\01OCR2.SGM 01OCR2 52216 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations to accommodate a conventional MFL or deformation tool, and thus be piggable for those threats. Launcher and receiver lengths are not a reason for a pipeline to be considered unpiggable, since through a minor modification they can be modified to be piggable, and the removal of launchers or receivers from the pipeline segment does not make a pipeline unpiggable either. I. Miscellaneous Issues i. Legal Comments The following section discusses industry comments related to legal and administrative procedure issues with the proposed rule. jbell on DSK3GLQ082PROD with RULES2 Summary of Public Comment Several commenters asserted that the proposed provisions go beyond PHMSA’s statutory authority provided by the 2011 Pipeline Safety Act. Many trade associations and pipeline industry entities stated that PHMSA exceeded the congressional mandates in the proposed provisions by imposing retroactive recordkeeping requirements and retroactive material properties verification requirements. These comments are discussed in more detail in their respective sections above. Commenters asserted that, in the 2011 Pipeline Safety Act, Congress identified specific factors that PHMSA is required to consider when proposing regulations per the statutory mandates, including whether certain proposed provisions would be economically, technically, and operationally feasible, and that the proposed rule did not adequately address these factors. For example, AGA expressed concerns that PHMSA proposed to adopt NTSB recommendations without independently justifying those provisions based on the specific factors required by Congress or providing the reasoning behind adopting said recommendations. AGA and INGAA also stated that PHMSA did not adequately consider the impact that the Natural Gas Act of 1968 would have on implementation of the proposed rule. Noting that operators are required to obtain permission from FERC before removing pipelines from service or replacing pipelines, these commenters stated that obtaining permissions could hinder operators from quickly performing required tests and repairs. INGAA and AGA also stated that PHMSA did not consult with FERC and State regulators about implementation timelines for certain provisions, which PHMSA is required to do in accordance with 49 U.S.C. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 60139(d)(3) because gas service would be affected by the proposed rule. I. Miscellaneous Issues PHMSA Response 1. Summary of PHMSA’s Proposal PHMSA appreciates the information provided by the commenters regarding the statutory authority for the proposed rule. With regard to the comments about imposing retroactive recordkeeping requirements and retroactive material properties verification requirements, PHMSA explained in this document that the final provisions of this rule are prospective and do not create retroactive requirements. This topic is discussed in more detail in the respective sections about recordkeeping and material properties verification. Pertaining to PHMSA’s broader authority, Congress has authorized the Federal regulation of the transportation of gas by pipeline in the Pipeline Safety Laws (49 U.S.C. 60101 et seq.) and established the current framework for regulating pipelines transporting gas in the Natural Gas Pipeline Safety Act of 1968, Public Law 90–481. Through these laws, Congress has delegated the DOT the authority to develop, prescribe, and enforce minimum Federal safety standards for the transportation of gas, including natural gas, flammable gas, or toxic or corrosive gas, by pipeline. As required by law, PHMSA has considered whether the provisions of this rule are economically, technically, and operationally feasible and has provided relevant analysis in the Regulatory Impact Analysis and preamble of this rule. In accordance with section 23 of the 2011 Pipeline Safety Act, PHMSA consulted with the Federal Energy Regulatory Commission and State regulators as appropriate to establish the timeframes for completing MAOP reconfirmation. As a part of this consultation, PHMSA accounted for potential consequences to public safety and the environment while also accounting for minimal costs and service disruptions. Furthermore, PHMSA will note that both a FERC member and a NAPSR member are on the GPAC, providing both input and positive votes that the provisions were technically feasible, reasonable, costeffective, and practicable if certain changes were made. As previously discussed, PHMSA has taken the GPAC’s input into consideration when drafting this final rule and made the according changes to the provisions. Many pipeline records are necessary for the correct setting and validation of MAOP, which is critically important for providing an appropriate margin of safety to the public. Much of operator and PHMSA data is obtained through testing and inspection under the existing IM requirements. Section 192.917(b) requires operators to gather pipeline attribute data as listed in ASME/ANSI B31.8S—2004 Edition, section 4, table 1. ASME/ANSI B31.8S— 2004 Edition, section 4.1 states: ‘‘Pipeline operator procedures, operation and maintenance plans, incident information, and other pipeline operator documents specify and require collection of data that are suitable for integrity/risk assessment. Integration of the data elements is essential in order to obtain complete and accurate information needed for an integrity management program. Implementation of the integrity management program will drive the collection and prioritization of additional data elements required to more fully understand and prevent/mitigate pipeline threats.’’ However, despite this requirement, there continue to be data gaps that make it hard to fully understand the risks to and the integrity of the nation’s pipeline system. Therefore, PHMSA proposed amendments to the records requirements for part 192, specifically under the general recordkeeping requirements, class location determination records, material mechanical property records, pipe design records, pipeline component records, welder qualification records, and the MAOP reconfirmation provisions. PO 00000 Frm 00038 Fmt 4701 Sfmt 4700 ii.—Records 2. Summary of Public Comment Several commenters provided input on the proposed amendments to the records requirements for part 192. Several public interest groups, including Pipeline Safety Coalition and PST, supported the increased emphasis on recordkeeping requirements, stating that the requirements are a proactive response to NTSB recommendations and are common-sense business best practices. Several commenters opposed the proposed provisions providing general recordkeeping requirements for part 192. Commenters asserted that these proposed provisions apply significant new recordkeeping requirements on operators by requiring that operators E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations document every aspect of part 192 to a higher and impractical standard than before. Commenters also stated that the proposed recordkeeping requirements appear to be retroactive and stated that it would be inappropriate to require operators to document compliance in cases where there have not been requirements to document or retain records in the past. Commenters also asserted that the Pipeline Safety Laws at 49 U.S.C. 60104(b) prohibits PHMSA from applying new safety standards pertaining to design, installation, construction, initial inspection, and initial testing to pipeline facilities already existing when the standard is adopted, and that PHMSA does not have the authority to apply these requirements retroactively. These commenters suggested that even the recordkeeping requirements in these non-retroactive subparts could not be changed under PHMSA’s current authority. Subsequently, commenters requested that PHMSA confirm that the proposed general, material, pipe design, and pipeline component recordkeeping requirements would not apply to existing pipelines and that recordkeeping requirements for the qualification of welders and qualifying plastic pipe joint-makers would not apply to completed pipeline projects. Additionally, several commenters also requested that PHMSA clarify that many of the proposed recordkeeping requirements apply only to gas transmission lines. AGA also expressed concern regarding the proposed reference to material properties verification requirements in the proposed general recordkeeping requirements, which, as written, would also require distribution pipelines without documentation to comply with the proposed material properties verification requirements. Many commenters opposed the proposed application of the term ‘‘reliable, traceable, verifiable, and complete’’ in part 192 beyond the requirements for MAOP records, and AGA recommended the deletion of ‘‘reliable, traceable, verifiable and complete’’ from proposed provisions under MAOP reconfirmation. Similarly, other commenters, including INGAA, recommended omitting ‘‘reliable’’ from the phrase and provided a suggested definition for ‘‘traceable, verifiable, and complete’’ records. Additionally, commenters opposed the use of this term in the general recordkeeping requirements at § 192.13, stating that it would apply a new standard of documentation to part 192. Citing a 2012 PHMSA Advisory Bulletin in which PHMSA stated that verifiable VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 records are those ‘‘in which information is confirmed by other complementary, but separate, documentation,’’ INGAA requested that PHMSA acknowledge that a stand-alone record will suffice and a complementary record is only necessary for cases in which the operator is missing an element of a traceable or complete record.74 INGAA also provided examples of records that they believed to be acceptable, and requested that PHMSA includes these examples in the final preamble. Several commenters also opposed the proposed Appendix A to part 192 that summarizes the records requirements within part 192 and requested that it be eliminated, stating that Appendix A goes beyond summarizing the existing records requirements and introduces several new recordkeeping requirements and retention times. Commenters also asserted that Appendix A should not be retroactive. Some commenters supported the inclusion of Appendix A, saying that it is a much-needed clarification of record requirements and retention. Noting that the title of Appendix A suggests that it is specific to gas transmission lines but that it does include some record retention intervals for distribution lines, NAPSR recommended that Appendix A be expanded to include records and retention intervals for all types of pipelines. Many commenters requested that PHMSA clarify that the proposed changes to Appendix A apply only to gas transmission lines. Some commenters also opposed the newly proposed recordkeeping requirements for pipeline components at § 192.205. Commenters, including Dominion East Ohio, stated that PHMSA should exclude pipeline components less than 2 inches in diameter, as these small components are often purchased in bulk with pressure ratings and manufacturing specifications only printed on the component or box. They further stated that in doing this, PHMSA would be consistent with its proposed material properties verification requirements. Another commenter stated that these requirements should be eliminated because they are duplicative of the current requirements for establishing and documenting MAOP at § 192.619(a)(1). Some commenters also opposed the proposed recordkeeping requirements regarding qualifications of welders and welding operators and qualifying persons to make joints in §§ 192.227 and 192.285, stating that keeping these 74 https://www.phmsa.dot.gov/regulations-fr/ notices/2012-10866; 77 FR 26822; May 7, 2012, ‘‘Pipeline Safety: Verification of Records.’’ PO 00000 Frm 00039 Fmt 4701 Sfmt 4700 52217 records for the life of the pipeline is not needed, nor are they necessary for the establishment of MAOP. Issues related to records were discussed during all of the GPAC meetings in various capacities. At the meeting in January 2017, several issues were discussed, including: broad records guidance in a general duties clause might be a good idea in theory but might cause unintended consequences, and they discussed the advisability of addressing necessary record components individually in the context of specific code sections. The GPAC discussed the proposed addition of ‘‘reliable’’ to the phrase ‘‘traceable, verifiable, and complete’’ (TVC) record in the proposed rule. The ‘‘TVC’’ standard was recommended by the NTSB following the PG&E incident. Changing that standard could potentially derail work being done by operators to meet that traceable, verifiable, and complete record standard. The GPAC also discussed PHMSA’s statutory authority to impose the proposed recordkeeping requirements, even in subparts that are retroactive, because PHMSA is not requiring particular types of design, installation, construction, etc., but is requiring that operators keep records relevant to current operation. At the GPAC meeting on June 6, 2017, the GPAC discussed the proposed recordkeeping requirements for the qualification of welders and welding operators as well as the qualification of persons making joints on plastic pipe systems. Specifically, the discussion revolved around whether the recordkeeping requirements should be for the life of the pipeline, as proposed in the NPRM, or whether it should be for 5 years. Certain members believed it should be a 5-year requirement to be consistent with other operator qualification requirements, and other members believed that a 5-year requirement would be adequate due to the ‘‘bathtub curve’’ phenomenon where pipelines are more likely to fail early or late in their service history. Therefore, having the records for welding qualification within that early period would be sufficient. Following that discussion, the committee recommended that PHMSA modify the proposed rule to delete the word ‘‘reliable’’ from the records standard to now read ‘‘traceable, verifiable, and complete’’ wherever that standard is used; clarify that documentation be required to substantiate the current class location under § 192.5(d); and modify the recordkeeping provisions related to the E:\FR\FM\01OCR2.SGM 01OCR2 52218 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES2 qualification of welders and the qualification of persons joining plastic pipe to include an effective date and change the retention period of the necessary records to 5 years. At the March 2, 2018, meeting, the GPAC recommended that PHMSA withdraw the general duty recordkeeping requirement at § 192.13(e) and Appendix A; modify the recordkeeping requirements for pipeline components to clarify they apply to components greater than 2 inches in nominal diameter; and revise the requirements related to material, pipe design, and pipeline component records to clarify the effective date of the requirements. At the meeting on March 27, 2018, the GPAC recommended that PHMSA provide guidance in the preamble regarding what constitutes a traceable, verifiable, and complete record. Further, the GPAC recommended PHMSA clarify that the MAOP recordkeeping requirements in the MAOP establishment section at § 192.619(f) apply only to onshore, steel, gas transmission pipelines, and that they only apply to the records needed to demonstrate compliance with paragraphs (a) through (d) of the section. The GPAC suggested PHMSA could remove examples of acceptable MAOP documents from the rule and include that listing in the preamble of the final rule and through guidance materials. The GPAC also recommended that PHMSA clarify that the MAOP recordkeeping requirements are not retroactive, that existing records on pipelines installed prior to the rule must be retained for the life of the pipeline, that pipelines constructed after the effective date of the rule must make and retain the appropriate records for the life of the pipeline, and that MAOP records would be required for any pipeline placed into service after the effective date of the rule. Further, the GPAC recommended PHMSA revise the rule by changing other sections, including §§ 192.624 and 192.917, to require when and for which pipeline segments missing MAOP records would need to be verified in accordance with the MAOP reconfirmation and material properties verification requirements of the rulemaking. 3. PHMSA Response PHMSA appreciates the information provided by the commenters regarding the proposed records requirements. After considering these comments and as recommended by the GPAC, PHMSA is modifying the rule to withdraw the proposed § 192.13(e) and Appendix A to avoid possible confusion regarding VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 recordkeeping requirements. Also, whenever new recordkeeping requirements are included, PHMSA modified the rule to clarify that the new requirements are not retroactive. To the degree that operators already have such records, they must retain them. Operators must retain records created while performing future activities required by the code. In addition to these general modifications, with regard to specific records requirements, PHMSA is modifying the rule as follows: (1) In § 192.5(d), operators must retain records documenting the current class location (but not historical class locations that no longer apply because PHMSA agrees they are not necessary). (2) In § 192.67, the rule is being modified to delete reference to ‘‘original steel pipe manufacturing records’’ to avoid retroactivity concerns, add wall thickness and seam type to clarify that this manufacturing information must be recorded, and include an effective date to eliminate retroactivity concerns. (3) In § 192.205, records for components are only required for components greater than 2 inches (instead of greater than or equal to 2 inches) (see Section III(A)(i)(3)). (4) In § 192.227, records demonstrating each individual welder qualification must be retained for a minimum of 5 years because PHMSA believes 5 years of welder qualification records are sufficient to evaluate whether systemic issues are present upon inspection and at the start-up of the pipeline. (5) In § 192.285, records demonstrating plastic pipe joining qualifications at the time of pipeline installation in accordance must be retained for a minimum of 5 years because PHMSA believes 5 years of records are sufficient to evaluate whether systemic issues are present upon inspection and at the start-up of the pipeline. (6) In § 192.619, PHMSA clarified that new recordkeeping for MAOP only apply to onshore, steel, gas transmission pipelines. In addition, PHMSA deleted the sentence with examples of records that establish the pipeline MAOP, which include, but are not limited to, design, construction, operation, maintenance, inspection, testing, material strength, pipe wall thickness, seam type, and other related data to prevent redundancies in the regulations as this list is maintained in § 192.607. PHMSA notes that the recordkeeping requirements in this final rule under §§ 192.67, 192.127, 192.205, and 192.227(c) applicable to gas transmission pipelines will apply to offshore gathering pipelines and Type A gathering pipelines as well. In PO 00000 Frm 00040 Fmt 4701 Sfmt 4700 accordance with this final rule’s requirements, operators of such pipelines must keep any of the pertinent records they have upon this rule’s issuance, and they must retain any records made when complying with these requirements following the publication of this rule. PHMSA notes that the requirements for creating records in §§ 192.67, 192.127, 192.205, and 192.227(c) are forward-looking requirements. However, and in accordance with this final rule, operators must retain any records they currently have for their pipelines. Any records generated through the course of operation, including, most notably, records generated by the material properties verification process at § 192.607, must also be retained by operators for the life of the pipeline. As requested by the GPAC, PHMSA considered moving § 192.619(e) to be a subsection of § 192.619(a) and considered referencing § 192.624 in § 192.619(a). However, PHMSA is retaining the proposed paragraph (e) in the final rule and the reference to § 192.624 within § 192.619(e) because it more clearly requires pipeline segments that meet any of the applicability criteria in § 192.624(a) must reconfirm MAOP in accordance with § 192.624, even if they comply with § 192.619(a) through (d). This also avoids the potential for conflict if this requirement were to be placed in a paragraph that applies to gathering lines and distribution lines. It also makes it clear that pipeline segments with MAOP reconfirmed under § 192.624 are not required to comply with § 192.619(a) through (d). Lastly, throughout this final rule, PHMSA is deleting the word ‘‘reliable’’ from the records standard to now read ‘‘traceable, verifiable, and complete’’ wherever that description is used. PHMSA issued advisory bulletins ADB 12–06 on May 7, 2012 (77 FR 26822) and ADB 11–01 on January 10, 2011 (76 FR 1504). In these advisory bulletins, PHMSA provided clarification and guidance that all documents are not records and provided additional information on the definition and standard for records. For a document to be a record, it must be traceable, verifiable, and complete. PHMSA provides further explanation of these concepts below. Traceable records are those which can be clearly linked to original information about a pipeline segment or facility. Traceable records might include pipe mill records, which include mechanical and chemical properties; purchase requisition; or as-built documentation indicating minimum pipe yield E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations strength, seam type, wall thickness and diameter. Careful attention should be given to records transcribed from original documents as they may contain errors. Information from a transcribed document, in many cases, should be verified with complementary or supporting documents. Verifiable records are those in which information is confirmed by other complementary, but separate, documentation. Verifiable records might include contract specifications for a pressure test of a pipeline segment complemented by pressure charts or field logs. Another example might include a purchase order to a pipe mill with pipe specifications verified by a metallurgical test of a coupon pulled from the same pipeline segment. In general, the only acceptable use of an affidavit would be as a complementary document, prepared and signed at the time of the test or inspection by a qualified individual who observed the test or inspection being performed. Complete records are those in which the record is finalized as evidenced by a signature, date or other appropriate marking such as a corporate stamp or seal. For example, a complete pressure testing record should identify a specific segment of pipe, who conducted the test, the duration of the test, the test medium, temperatures, accurate pressure readings, and elevation information as applicable. An incomplete record might reflect that the pressure test was initiated, failed and restarted without conclusive indication of a successful test. A record that cannot be specifically linked to an individual pipeline segment is not a complete record for that segment. Incomplete or partial records are not an adequate basis for establishing MAOP or MOP. If records are unknown or unknowable, a more conservative approach is indicated. For example, a mill test report must be traceable, verifiable, and complete, which is a typical record for pipelines. For the mill test report to be traceable it would need to be dated in the same time frame as construction or have some other link relating the mill record to the material installed in the pipeline, such as a work order or project identification. For the mill test report to be verified, it would need to be confirmed by the purchase or project specification for the pipeline or the alignment sheet with consistent information. Such an example would be verified by independent records. For the mill test report to be complete, it must be signed, stamped, or otherwise authenticated as a genuine and true record of the material by the source of the record or VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 information, in this example it could be the pipe mill, supplier, or testing lab. Another common record is a pressure test record, which must be traceable, verifiable, and complete. For the pressure test record to be traceable, it would need to identify a specific and unique segment of pipe that was tested (such as mileposts, survey stations, etc.) or have some other link relating the pressure test to the physical location of the test segment, such as a work order, project identification, or alignment sheet. For the pressure test record to be verified, it would need to be confirmed by the purchase or project specification for the pipeline or the alignment sheet with consistent information. Such an example would be verified by independent records. For the pressure test record to be complete, it should identify a specific segment of pipe, who conducted the test, the duration of the test, the test medium, temperatures, accurate pressure readings, elevation information, and any other information required by § 192.517, as applicable. An incomplete record might reflect that the pressure test was initiated, failed and restarted without conclusive indication of a successful test. I. Miscellaneous Issues iii.—Cost/Benefit Analysis, Information Collection, and Environmental Impact Issues NPRM Assumptions/Proposals U.S. Code, title 49, chapter 601, section 60102 specifies that the U.S. Department of Transportation (U.S. DOT), when prescribing any pipeline safety standard, shall consider relevant available gas and hazardous liquid pipeline safety information, environmental information, the appropriateness of the standard, and the reasonableness of the standard. In addition, the U.S. DOT must, based on a risk assessment, evaluate the reasonably identifiable or estimated benefits and costs expected to result from implementation or compliance with the standard. PHMSA prepared a preliminary regulatory impact analysis (PRIA) to fulfill this statutory requirement for the proposed rule and a new regulatory impact analysis (RIA) for this final rule. In addition, PHMSA’s Environmental Assessment (EA) is prepared in accordance with NEPA, as amended, and the Council on Environmental Quality (CEQ) regulations for implementing NEPA (40 CFR parts 1500–1508). When an agency anticipates that a proposed action will not have significant environmental effects, the CEQ regulations provide for the preparation of an EA to determine PO 00000 Frm 00041 Fmt 4701 Sfmt 4700 52219 whether to prepare an environmental impact statement or finding of no significant impact. Summary of Public Comment Cost Impacts Several commenters provided input on the cost analysis conducted in the PRIA, providing comments on the structure, assumptions, and unit costs in the PRIA as well as on the lack of accounting for impacts such as the abandonment of pipelines and the cost increase to electricity ratepayers. Some public interest groups provided input on the cost analysis in the PRIA. EDF stated that the PRIA reasonably addressed uncertainty and lack of information surrounding certain key data assumptions. EDF further stated that the PRIA aligned with Office of Management and Budget guidance on the development of regulatory analysis for rulemakings. They stated that PHMSA used conservative values when making best professional judgments. PST asserted that the costs included in the PRIA for reconfirmation of MAOP, data gathering, record maintenance, and data integration for lines subject to the IM provisions result from the current IM regulations and practices and should not be attributed to this rulemaking. They further stated that the PRIA should be amended to remove these costs related to lines within HCAs. Several trade associations and industry pipeline entities provided input on the assumptions, methodology, and unit costs used in the PRIA, stating that PHMSA underestimated the cost of complying with the proposed regulations. AGA stated that the organization of the PRIA by ‘‘topic areas’’ made it difficult to evaluate the cost estimates of the various provisions of the rule and requested that PHMSA provide a RIA with the final rule that addresses each regulatory section as organized in the preamble. Many commenters, including INGAA, AGA, AGL Resources, and Piedmont, stated that the PRIA underestimated the cost impacts of increased material properties verification, recordkeeping, and MAOP reconfirmation requirements. AGL Resources asserted that complying with the proposed record requirements would involve increased labor and investment costs that should be quantified in the final RIA. AGA stated that it was unclear whether or how the PRIA incorporated material properties verification costs related to material documentation, plan creation, revisions, and testing. NYSEG asserted that the PRIA underestimated the cost impact of the proposed rule on smaller local E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 52220 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations distribution companies with combined transmission and distribution systems and estimated that they would have to perform IM elements on 8 times the mileage currently in their IM program. Lastly, INGAA provided a higher cost for MAOP confirmation than was estimated in the PRIA due in large part to their assumption that industry would continue to rely on pressure testing, as they asserted that the proposed methods for ILI and ECA are not feasible. INGAA, AGA, and API submitted detailed cost analyses to the rulemaking docket, while many other commenters (approximately 40) provided estimated unit costs for various provisions of the proposed rule that were generally higher than the unit costs used in the PRIA. For example, Southwest Gas stated that the costs included in the PRIA for options such as ILI and pressure testing were not representative of the costs to their system. With regard to the cost of integrity assessments, BG&E stated that it would cost them over $1 million per year to perform integrity assessments on the additional 100 miles of MCA transmission pipelines, a total which equates to a higher cost per mile estimate than was used in the PRIA. Additionally, New Mexico Gas Co. stated that the proposed rule would cost their company $5.6 million per year to perform integrity assessments on 528 miles of MCA transmission pipe. Vectren estimated the impact to its transmission system would cost $22 million annually. Lastly, PG&E stated that their forecasted costs to implement the proposed rule are significantly higher than the estimates in the PRIA. PG&E provided a comparison of the PRIA costs with their expected expenditures to comply with many provisions in the proposed rule. They projected the cost of compliance would require an upfront investment of $578 million in addition to $222 million per year (as well as a reoccurring cost of $30 million every 7 years) and stated that, comparatively, the PRIA estimates a present value annualized cost of $47 million per year. Some stakeholders provided input on the estimated number of miles that PHMSA used to determine the regulatory impact of the provisions in the proposed rule. For example, INGAA stated that it assumed the mileage estimated by PHMSA for estimation of MAOP confirmation, material properties verification, and integrity assessments outside HCAs to be accurate with the addition of reportable in-service incidents since last pressure test data. INGAA also asserted that the mileage estimated for MCA transmission pipes should be done on the per-foot basis VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 instead of on the per-mile basis because these pipes are likely to be an aggregation of short pipeline segments that are 1 mile or shorter in length. The North Dakota Petroleum Council asserted that proposed changes in the definition of onshore gathering lines would dramatically increase the number of miles of regulated gathering wells beyond the mileage estimates in the PRIA. Some commenters asserted that the financial impact of the proposed rule would be immense and that, because operators would not be able to bear these costs alone, they would likely pass the costs on to the ratepayers. For example, APGA stated that all of their member utilities purchase gas and pay transportation charges to transmission pipelines to deliver gas from the producer to the utility. They asserted that ratepayers would pay for the costs that would be incurred by their transmission suppliers to comply with this rule. Similarly, Indiana Utility Regulatory Commission requested that PHMSA consider the costs to ratepayers in its cost analysis. Other commenters stated that this rule could force operators to take significant portions of their pipelines out of service while they are brought into compliance and that the PRIA failed to recognize that FERC requires interstate natural gas pipelines operators to provide demand charge credits to customers when service is disrupted. Some commenters stated that the proposed rule may cause pipeline abandonment and that these impacts should be considered in the final RIA. Boardwalk Pipeline stated that if a pipe is no longer economic to operate, but FERC does not grant abandonment authority, a pipeline company would be forced to either operate a pipeline that may not meet PHMSA standards or undertake expensive replacement projects. Boardwalk Pipeline further stated that while operators may seek to recover the costs of replacement projects through rate increases, in a competitive pipeline market where operators are forced to discount their pipeline rates in order to retain customers, these costs might be too great to recover. Similarly, the Independent Petroleum Association of America stated that the PRIA failed to account for the costs that could be incurred by operators if pipeline infrastructure is abandoned because the cost that would be required to comply with the rule would necessitate this abandonment. The Public Service Commission of West Virginia suggested that, should operators abandon wells and pipelines due to the requirements of this proposed rule, it could cause an PO 00000 Frm 00042 Fmt 4701 Sfmt 4700 environmental and economic liability for State regulators if operators abandon wells and pipelines without proper clean up. Several commenters expressed concern that PHMSA’s cost-benefit analysis does not meet the requirements established by the 2011 Pipeline Safety Act and the Administrative Procedures Act (APA). Trade associations stated that the PRIA does not fulfill PHMSA’s statutory obligations because it omits relevant costs, relies on incorrect assumptions, and contains multiple inconsistencies. INGAA asserted that the PRIA does not comply with the APA because the finding in the PRIA that the proposed benefits outweigh the costs is contingent on an underestimation of the costs of the proposed rule. INGAA also noted that flawed cost-benefit analysis can be grounds for courts to reject agency rulemakings. INGAA asserted that the proposed rulemaking does not comply with the Paperwork Reduction Act (PRA), because PHMSA’s estimate of the information collection burden did not include the costs of these additional recordkeeping requirements for transmission pipeline operators. Benefit Estimates PHMSA also received comments on the benefits associated with the proposed rule. Physicians for Social Responsibility expressed their support of the proposed rule and the analysis of reduced accidents and increased worker safety in the PRIA. Additionally, Physicians for Social Responsibility stated that many harmful air pollutants, such as nitrous oxide, sulfur dioxide, particulate matter, formaldehyde, and lead, are all associated with gas pipelines and compressor stations. They further stated that this rule would help reduce or mitigate this pollution and that these public health benefits should be accounted for in the benefits calculations. Other commenters, including AGA and INGAA, stated that PHMSA overestimated the damage caused by incidents in the quantification of benefits in the PRIA. AGA stated that PHMSA allowed one major incident to skew the data in their benefits analysis and proposed that PHMSA adopt a new approach to quantify the benefits of reduced accidents. INGAA stated that using data from the past 13 years skewed the results and that the most recent 5 years of incident history would more reasonably reflect positive developments in pipeline safety, given that significant developments in pipeline safety have occurred within this time period. E:\FR\FM\01OCR2.SGM 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES2 Several commenters provided input on the proposed use of the social cost of carbon and the social cost of methane in the PRIA. EDF and National Resource Defense Council supported the use of the social costs of carbon and methane methodology in the PRIA. However, these commenters stated that the estimates for social costs of carbon and methane were likely too conservative and that the values should be higher than those used in the PRIA. These commenters stated that PHMSA should encourage the Interagency Working Group on Social Cost of Carbon to update regularly the social cost of carbon and social cost of methane as new economic and scientific information emerges. API stated that the proposed use of the social cost of methane to calculate the benefits of emissions reductions was flawed due to the discount rates used by PHMSA. They asserted that PHMSA used low discount rates that led to a liberal damage estimate. In addition, API and Industrial Energy Consumers of America asserted that the social cost of carbon values used by PHMSA inappropriately impose global carbon costs on domestic manufacturers, which damages the industry’s ability to compete internationally. AGA stated that the process used to develop the social cost of methane values in the PRIA did not undergo sufficient expert and peer review. INGAA stated that PHMSA overestimated the amount of greenhouse gas emissions that the rule would reduce. Environmental Impacts Several commenters noted that the 2011 Pipeline Safety Act mandates that PHMSA consider the environmental impacts of proposed safety standards. Citizen groups stated that the proposed regulation fulfills this statutory obligation and is a step forward in reducing methane emissions from natural gas pipelines. Multiple citizen groups emphasized the consequences of climate change, the high global warming potential of methane, and the responsibility of natural gas systems for a significant portion of U.S. methane emissions. Citizen groups underlined the importance of regulating methane leaks and considering methane’s climate implications in natural gas regulations. The Lebanon Pipeline Awareness Group addressed local environmental impacts, requesting that pipelines not be permitted to contaminate agricultural soils. Trade associations asserted that PHMSA did not fulfill its statutory obligation to consider the full environmental impacts of the proposed VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 safety standards, suggesting that PHMSA failed to consider several topics in the NPRM that would have direct environmental impacts. These commenters claimed that certain topics and their impacts, including IM clarifications, MAOP reconfirmation, and hydrostatic pressure testing, were mischaracterized in the EA, and that PHMSA further underestimated the number of excavations that would need to be made per the proposal as well as the impacts of procuring and disposing of water for hydrostatic tests. Trade associations further expressed concerns that, while PHMSA had addressed the emissions avoided under the proposed rule, PHMSA had not addressed the extent to which the proposed rule would increase emissions. AGA and INGAA noted that operators need to purge lines of natural gas before conducting hydrostatic tests or removing pipelines from service for replacement or repair. These commenters stated that the proposed regulation would increase methane emissions by increasing the number of hydrostatic tests, pipeline replacements, and pipeline repairs required and asserted that the EA did not take the increased emissions from these blowdowns into account. INGAA asserted that not considering these methane emissions constituted a violation of the 2011 Pipeline Safety Act and failure to ‘‘engage in reasoned decision making.’’ INGAA also suggested that the methane emissions resulting from this rulemaking would run counter to President Obama’s goals of reducing methane emissions. EDF and PST commissioned a study from M.J. Bradley & Associates (MJB&A) that calculated the extent to which the proposed rule would result in blowdown emissions. MJB&A found that potential methane emissions resultant from the proposed rule would increase annual methane emissions from natural gas transmission systems by less than 0.1 percent and increase annual methane emissions from transmission system routine maintenance by less than one percent. MJB&A also noted five mitigation methods that if implemented, could decrease blowdown emissions by 50 to 90 percent.75 MBJ&A calculated that the societal benefits of methane reduction outweighed the mitigation costs for all mitigation options considered. Based on 75 The methods are (1) gas flaring; (2) pressure reduction prior to blowdown with inline compressors; (3) pressure reduction prior to blowdown with mobile compressors; (4) transfer of gas to a low-pressure system; and (5) reducing the length of pipe requiring blowdown by using stopples. PO 00000 Frm 00043 Fmt 4701 Sfmt 4700 52221 this study, EDF asserted that while the marginal increase in emissions from the proposed rule would be small, the total emissions from blowdowns would nonetheless be significant. They stated that PHMSA should require operators to select and implement one of the mitigation options and report to PHMSA information about their blowdown events, such as the mitigation option selected and the amount of product lost due to blowdowns required by the proposed rule. EDF also stated that if operators do not mitigate blowdown emissions, they should be required to provide an engineering or economic analysis demonstrating why mitigation is deemed infeasible or unsafe. AGA stated that the EA did not address other environmental impacts resultant from hydrostatic pressure testing. AGA noted two anticipated water-related impacts: (1) Hydrostatic pressure testing’s water demand could aggravate water scarcity in already water-scarce environments, and (2), the water used in hydrostatic tests could introduce contaminants if disposed onsite (or be very expensive to transport to off-site disposal). AGA explained that wastewater from hydrostatic tests could include hydrocarbon liquids and solids, chlorine, and metals. AGA also asserted that the EA did not adequately consider the land disturbances that could result from the proposed hydrostatic testing requirements, nor did it consider that performing inline inspections and modifying pipelines to accommodate inline inspection tools would generate waste and disturb natural lands. AGA explained that operators must clean pipelines prior to conducting inline inspections or modifying pipelines for inline inspection tools and that this cleaning could produce large volumes of pipeline liquids, mill scale, oil, and other debris. AGA expressed concerns that the proposed EA did not discuss these environmental impacts associated with requiring MAOP confirmation, given that PHMSA anticipates that most affected pipelines would verify MAOP using ILI and pressure testing. AGA also provided input on the local environmental impacts of the proposed increased testing and inspection. AGA expressed concerns that the EA had (1), underestimated the quantity of excavations that would be required under the proposed rule, and (2), inadequately assessed the environmental impacts of those excavations. AGA asserted that the EA had insufficiently considered the extent to which more excavations would generate water and soil waste. AGA also suggested that the proposed rule may E:\FR\FM\01OCR2.SGM 01OCR2 52222 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations induce operators to modify or replace pipelines and that these modifications and replacements may affect land beyond existing rights of way. AGA asserted that this additional land area should be considered in the EA. Trade associations raised other technical issues regarding the EA. AGA expressed concerns that PHMSA provided insufficient information about methods used to calculate values in the EA and that this insufficient documentation interfered with stakeholders’ ability to provide comments on the values that PHMSA chose. INGAA asserted that the proposed rule fell short of several legal obligations under NEPA, stating that the EA does not provide the required ‘‘hard look’’ at environmental impacts, that the EA does not adequately discuss the indirect and cumulative effects of the proposed rule, and that the purpose and need statement in the EA do not fulfill NEPA instructions. INGAA also expressed concern that PHMSA did not consider sufficient regulatory alternatives, stating that the EA considered solely the proposed rule, one regulatory alternative, and the no action alternative. INGAA stated that given the many provisions of the proposed rule, this approach was too limited. jbell on DSK3GLQ082PROD with RULES2 Other Impacts Some trade associations and pipeline industry entities provided input that the PRIA failed to account for the indirect effects of operators shifting resources to comply with the proposed rule. For example, AGA stated that the PRIA did not consider the potential indirect impacts the rule might impose on distribution lines. They asserted that the magnitude and prescriptiveness of the proposed rule would require distribution companies with intrastate transmission and distribution assets to reassign their limited resources to transmission lines. Some commenters stated that PHMSA did not consider that the proposed rule would divert resources away from voluntary safety programs their companies are initiating, stating that these voluntary safety measures would be scaled back because of the proposed rule. For example, AGA stated that accelerated pipe replacement programs that replace aging cast iron, unprotected steel pipe, and vintage plastic pipe, would lose resources as operators shift staff and capital to comply with the proposed rule. They further asserted that failing to replace these pipes would delay reductions in methane emissions from old, leaky pipes. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 PHMSA Response Cost Impacts PHMSA has reviewed the comments related to the RIA for the proposed rule and has revised the final analysis consistent with the final rule and in consideration of the comments. PHMSA addressed the comments received on the RIA in two key ways. First, PHMSA revised many of the requirements in the final rule, including (a) revising or clarifying that the final provisions do not apply to gas distribution or gas gathering pipelines; (b) revising MAOP reconfirmation requirements for grandfathered pipelines to include only those lines with MAOP greater than or equal to 30 percent SMYS; (c) streamlining the process for operators to use an alternative technology for MAOP reconfirmation; (d) removing the term ‘‘occupied sites’’ in the MCA definition; and (e) revising the records provisions to remove certain proposed provisions and clarifying that the new requirements are not retroactive. These changes, as well as others made in the final rule, result in less costly and more cost-effective requirements. Second, in response to comments received, PHMSA made several revisions to the analysis conducted in the RIA for the proposed rule, discussed below. Also, in response to comments, PHMSA revised the final RIA to align more closely to the preamble organization. PHMSA acknowledges the baseline issues associated with establishing MAOP, data collection, and other provisions noted in the comments. In the final RIA, PHMSA is including estimated incremental costs to reconfirm MAOP for lines within HCAs based on a current compliance baseline. Attributing compliance to existing pipeline safety regulations would reduce both the costs and benefits of the final rule. Regarding the comments that the RIA for the proposed rule underestimated the cost impacts of material properties verification, recordkeeping, and MAOP confirmation, as discussed above, the changes to the scope and applicability of the MAOP reconfirmation, data, and recordkeeping provisions result in common-sense, cost-effective requirements. For example, PHSMA designed the final requirements for material properties verification to allow operators the option of a sampling program that opportunistically takes advantage of repairs and replacement projects to verify material properties simultaneously. The final provisions allow, over time, operators to collect enough information to gain significant PO 00000 Frm 00044 Fmt 4701 Sfmt 4700 confidence in the material properties of pipe subject to this requirement. Further, as discussed under the section regarding the material properties verification process, the final rule removes the applicability criteria of the material properties verification requirements and makes a procedure for obtaining pipeline physical properties and attributes that are not documented in traceable, verifiable, and complete records or for otherwise verifying pipeline attributes when required by MAOP reconfirmation requirements, IM requirements, repair requirements, or other code sections. Therefore, due to the changes made from the proposed rule, the material properties verification requirements mandated by section 23 of the 2011 Pipeline Safety Act represent a cost savings in comparison to existing regulations, although PHMSA has not quantified those savings. With regard to the operator-provided cost information or estimates of the proposed rule, the commenters’ estimates were not transparent enough for PHMSA to discern the assumptions and inputs underlying the estimates. As a result, PHMSA could not reliably confirm whether the cost information accurately reflected the quantity and character of the actions required by the proposed rule. To improve the transparency of the analysis and address commenters’ concerns about PHMSA’s reliance on best professional judgment in the RIA for the proposed rule, PHMSA contacted five vendors of pipeline inspection and testing services to obtain updated cost estimates for several unit costs that were based on best professional judgement in the RIA for the proposed rule. These vendors provided representative incremental costs associated with the final rule requirements. In the final RIA, PHMSA used prices provided by vendors to estimate unit costs for all MAOP reconfirmation and integrity assessment methods, as well as for upgrades to launchers and receivers. Regarding MAOP reconfirmation specifically, in the RIA for the proposed rule PHMSA assumed operators would conduct MAOP reconfirmation using either pressure testing or ILI. In the final RIA, based on feedback received during a GPAC meeting,76 PHMSA assumed that operators would reconfirm MAOP using a mix of all six available compliance methods. Additionally, in the final RIA, PHMSA analyzed the requirements for MAOP reconfirmation and integrity 76 GPAC Meeting, March 26–28, 2018. For a transcript of the meeting, see https:// primis.phmsa.dot.gov/meetings/FilGet.mtg?fil=970. E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations assessments outside HCAs for each operator individually based on the information they submitted in their Annual Reports. Based on the information in operator Annual Reports and the final rule requirements for MAOP reconfirmation, some operators will incur less of an impact than indicated by their public comments. Regarding the comment that the proposed changes to the definition of onshore gathering lines would dramatically increase the number of miles of regulated gathering wells beyond the mileage estimates in the RIA for the proposed rule, this final rule does not change the definition of gathering pipelines. With respect to pipelines located within MCAs, PHMSA confirmed the analysis of the length of gas transmission pipelines located within MCAs in the RIA for the proposed rule by integrating additional spatial data from the U.S. Census Bureau, U.S. Geological Survey, Environmental Systems Research Institute, and TeleAtlas North America, Inc. For additional details on the MCA GIS analysis, see section 5.7 of the RIA for the final rule. This allowed PHMSA to confirm the number of impacted miles. Additionally, due to existing state MAOP reconfirmation requirements, PHMSA updated the RIA to reflect that impacts in California are not attributable to the rule. Lastly, PHMSA presented all impacted mileage on a dollar-per-foot basis instead of dollars per mile, based on comments received that these pipeline segments are likely to be an aggregation of short pipeline segments that are a mile or shorter in length. Regarding the comment that PHMSA underestimated the cost impact of the proposed rule on smaller local distribution companies with combined gas transmission and gas distribution systems, PHMSA conducted an analysis of the rule’s impact on small entities by comparing entity-level cost estimates to annual entity revenues and identifying entities for which annualized costs may exceed 1 percent and 3 percent of revenue. As documented in the final Regulatory Flexibility Act (FRFA) analysis, PHMSA relied on conservative assumptions in performing this sales test, which may overstate, rather than understate, compliance costs for small entities. PHMSA found that the final rule will not have a significant economic impact on small entities. PHMSA does not agree that the final rule requirements constitute a significant energy action. PHMSA agrees with the comment that the costs would be passed on to ratepayers; however, PHMSA disagrees that these costs VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 would be immense. E.O. 13211 requires agencies to prepare a Statement of Energy Effects when undertaking certain agency actions if, among other criteria, the regulation is expected to see an increase in the cost of energy production or distribution in excess of one percent. The annualized cost of these requirements represents less than 0.1 percent of pipeline transportation of natural gas (North American Industry Classification System code 486210) industry revenues ($25 billion), adjusting the 2012 Economic Census value into 2017 dollars using the Gross Domestic Product Implicit Price Deflator Index. Therefore, in the aggregate it is extremely unlikely that these requirements would cause a significant increase in costs that utilities would pass on to the ratepayer. Available information supports that, in the baseline, operators are replacing or abandoning certain pipelines regardless of the implementation of this rule as well as taking other actions such as making lines piggable.77 As discussed above, in the final RIA, PHMSA assumed some use of pipe replacement and abandonment as a means of operators reconfirming MAOP. However, the costs of replacing infrastructure operating beyond the design useful life are not attributable to safety regulations and investment in plant, including a return on investment, are already recovered through rates. The RIA for the final rule meets all PHMSA’s requirements under applicable acts and executive orders. The analysis involves estimating a baseline scenario and changes under the regulation. PHMSA has used its judgement, available data, information, and analytical methods to develop an analysis of the baseline and incremental costs and benefits under the rule. As discussed above, some costs and benefits may be attributable to existing requirements and some may occur in the absence of the rule. Benefits Estimates PHMSA agrees that recent data is more reflective of recent improvements in pipeline safety and performance relative to current standards. For the final RIA, PHMSA used more recent data on pipeline incidents from 2010 to 77 PG&E. 2011. ‘‘Pacific Gas And Electric Company’s Natural Gas Transmission Pipeline Replacement Or Testing Implementation Plan.’’ California Public Utilities Commission; Consolidated Edison Company Of New York. 2016. ‘‘Consolidated Edison Company Of New York, Inc. 2017–2019 Gas Operations Capital Programs/ Projects.’’ New York State Department of Public Service. https://documents.dps.ny.gov/public/Matter Management/CaseMaster.aspx?MatterCaseNo=16G-0061&submit=Search. PO 00000 Frm 00045 Fmt 4701 Sfmt 4700 52223 2017 versus the 2003 to 2015 data used in the RIA for the proposed rule. PHMSA used the data from 2010 on because PHMSA updated its incident reporting methodology in 2010, and this period therefore provides the largest available sample of consistently reported incident data. Regarding the benefits analysis for the preliminary RIA developed for the NPRM potentially being skewed by one major incident (the PG&E incident at San Bruno), there is no evidence that more serious incidents are not possible in the future in the absence of the regulation, and therefore, PHMSA does not exclude this incident when qualitatively assessing benefits. At the same time, and although PHMSA developed this rule to prevent future, similar incidents, PHMSA cannot know with certainty whether a similar incident would occur again absent this rulemaking. According to the historical record, serious incidents, like the one occurring at San Bruno, occur approximately once per decade. For example, on August 19, 2000, a 30-inchdiameter natural gas transmission pipeline operated by the El Paso Natural Gas Company ruptured adjacent to the Pecos River near Carlsbad, NM. The released gas ignited and burned for 55 minutes. Twelve persons camping near the incident location were killed, and their three vehicles were destroyed.78 Similarly, on March 23, 1994, a 36-inchdiameter natural gas transmission pipeline owned and operated by Texas Eastern Transmission Corporation ruptured in Ellison Township, NJ. The incident caused at least $25 million in damages, dozens of injuries, and the evacuation of hundreds.79 More detailed data on current pipeline integrity in relation to populations and the environment would enable more detailed predictions of the benefits of regulations. Due to the speculative nature of predicting the occurrence, avoidance, and character of specific future pipeline incidents, in the final RIA, PHMSA elected not to quantify the rule’s benefits. PHMSA uses this approach rather than make highly uncertain predictions about both a specific number of future incidents avoided due to the final rule, and the character of avoided incidents with respect to effects on benefit-analysis endpoints (e.g., fatalities, injuries, evacuation). The 78 Natural Gas Pipeline Rupture and Fire Near Carlsbad, New Mexico, August 19, 2000, Pipeline Accident Report, NTSB/PAR–03/01, Washington, DC. 79 Texas Eastern Transmission Corporation Natural Gas Pipeline Explosion and Fire, Pipeline Accident Report, NTSB/PAR–95–01, Washington, DC. E:\FR\FM\01OCR2.SGM 01OCR2 52224 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations quantified benefits for each provision therefore represent the quantity of a given benefit category required to achieve a dollar value equal to the provision’s compliance cost. PHMSA does not have data on harmful air pollutants such as nitrous oxide, sulfur dioxide, particulate matter, formaldehyde, and lead associated with gas pipelines and compressor stations, or the reductions in these pollutants under the rule. Therefore, the analysis did not address the environmental costs associated with these pollutants. PHMSA did not include estimates of benefits based on the social cost of methane for the final rule. Environmental Impacts jbell on DSK3GLQ082PROD with RULES2 Regarding the comments stating that the preliminary EA did not adequately consider the air emissions that would result from hydrostatic pressure testing, inline inspections, excavations, and MAOP reconfirmation, PHMSA revised the EA to address this issue. Commenters asserted that by increasing the number of hydrostatic tests, pipeline replacements, and pipeline repairs required, the proposed provisions would increase methane ‘‘blowdown’’ emissions that result from the required purging of natural gas pipelines before conducting these actions. PHMSA revised the EA to include a discussion of the study conducted by M.J. Bradley & Associates (MJB&A) 80 that calculated the extent to which the proposed rule would result in blowdown emissions. MJB&A found that unmitigated blowdown from the miles of transmission pipeline that would be required to conduct a MAOP determination would release an average of 1,353 metric tons per year of methane to the atmosphere for the 15-year compliance period 81 proposed by PHMSA. By comparison, historical unintentional releases from natural gas transmission pipelines outside of HCAs with piggable lines greater than 30 percent SMYS (a universe of facilities that could be subject to MAOP reconfirmation in MCAs) averaged 13,500 metric tons per year from 2010 to 2017. These releases were caused by 163 incidents that released an average of 663.4 metric tons per incident.82 80 The study was commissioned by EDF and PST and is available at https://blogs.edf.org/ energyexchange/files/2016/07/PHMSA-BlowdownAnalysis-FINAL.pdf. 81 See § 192.624(b). 82 ‘‘Distribution, Transmission & Gathering, LNG, and Liquid Accident and Incident Data.’’ Phmsa.Dot.Gov. 2017. https://www.phmsa.dot.gov/ data-and-statistics/pipeline/distributiontransmission-gathering-lng-and-liquid-accidentand-incident-data. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 Therefore, if the final rule requirements avoided two average incidents per year, the rule would not result in any net methane releases. MJB&A further stated that the potential methane emissions resultant from the NPRM would increase annual methane emissions from natural gas transmission systems by less than 0.1 percent and increase annual methane emissions from transmission system routine maintenance/upsets by less than one percent. Given these factors, PHMSA does not believe that the final rule will result in a significant, if any, increase in methane releases. In response to comments, PHMSA revised the EA to also include a discussion of water-related impacts resulting from hydrostatic pressure testing as well as waste generation land disturbances from hydrostatic pressure testing and inline inspections. Operators must conduct all waste and wastewater disposal activities in accordance with federal, state, and local regulations and permit requirements, and the final rule requires processes and procedures in which pipeline operators are already familiar with respect to pipeline IM. Regarding the comments on the environmental impacts of pipe replacement, as discussed above, the impacts of replacing infrastructure that is operating beyond the design useful life are not attributable to the final rule requirements. While the final RIA assumes that operators will comply with MAOP reconfirmation using pipe replacement for approximately 300 miles of pipe, PHMSA did not consider these replacements to be incremental costs. Similarly, the environmental impacts are not attributable to the final rule requirements. Other Impacts PHMSA disagrees with the analysis of operators shifting resources away from safety programs to comply with the proposed rule. PHMSA has revised and clarified the pipeline safety and integrity applicability of the final rule such that many operators will incur lower costs than previously anticipated. The final rule also provides long compliance schedules to enable planning for efficient compliance actions. IV. GPAC Recommendations This section briefly summarizes the NPRM proposals, the GPAC’s major comments on the proposals discussed, and the recommendations of the committee regarding how those provisions should be finalized. More detail, the presentations, and the transcripts from all of the meetings are PO 00000 Frm 00046 Fmt 4701 Sfmt 4700 available in the docket for this rulemaking.83 The provisions, which are presented in the order they were discussed at the GPAC meetings, the changes the committee agreed upon, and the corresponding vote counts are as follows: 6-Month Grace Period for 7-CalendarYear Reassessment Intervals (§ 192.939(b)) In the NPRM, PHMSA proposed to allow operators to request a 6-month extension of the 7-calendar-year reassessment interval if the operator submits written notice to the Secretary with sufficient justification of the need for the extension in accordance with the technical correction at section 5 of the 2011 Pipeline Safety Act. The committee had no objections or substantial comments on this provision and voted 12–0 that it was, as published, technically feasible, reasonable, cost-effective, and practicable. Safety Features on ILI Launchers and Receivers (§ 192.750) In the NPRM, PHMSA proposed to require operators equip ILI tool launchers and receivers with a device capable of safely relieving pressure in the barrel before the insertion or removal of ILI tools, scrapers, or spheres. Further, PHMSA proposed requiring operators to use a suitable device to indicate that pressure has been relieved in the barrel or otherwise provide a means to prevent the opening of the barrel if pressure has not been relieved. The committee voted 12–0 that this provision was, as published, technically feasible, reasonable, costeffective, and practicable, as long as PHMSA clarified that the rule language does not require ‘‘relief valves’’ or use ‘‘relief valve’’ as a term. Some committee members were concerned that using language related to ‘‘relief valves’’ would bring in other code requirements, which was not PHMSA’s intent. Seismicity (§§ 192.917, 192.935(b)(2)) In the NPRM, PHMSA proposed to include seismicity in the list of factors operators must evaluate for the threat of outside force damage when considering preventative and mitigative measures, as well as include the seismicity of an area as a pipeline attribute in an operator’s data gathering and integration when performing risk analyses. The committee had no substantial comments or recommendations on this topic, and 83 https://www.regulations.gov/docket? D=PHMSA-2011-0023. E:\FR\FM\01OCR2.SGM 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES2 they voted 12–0 that this provision was, as published, technically feasible, reasonable, cost-effective, and practicable. Records (§§ 192.5(d), 192.13(e), 192.67, 192.127, 192.205, 192.227(c), 192.285(e), 192.619(f), 192.624(f), Appendix A) In the NPRM, PHMSA proposed to clarify that the records required by part 192 must be documented in a reliable, traceable, verifiable, and complete manner. PHMSA summarized the recordkeeping requirements of part 192 in a new Appendix A, and required that operators must re-establish pipeline documentation whenever records were not available and make and retain records demonstrating compliance with part 192. Issues related to records were discussed through the final 4 GPAC meetings over the course of 2017 and 2018. The committee found the assorted provisions related to records as being technically feasible, reasonable, costeffective, and practicable, if certain changes were made. Specifically, the committee recommended the word ‘‘reliable’’ be deleted from the records standard so that it reads ‘‘traceable, verifiable, and complete’’ records wherever the standard is used. Members noted that the NTSB never used the term ‘‘reliable,’’ and a PHMSA advisory bulletin reflects the language without referring to ‘‘reliable’’ records. In the class location requirements at § 192.5, the committee recommended PHMSA clarify that documentation be required to substantiate the current class location and not previous historical ones. The committee also recommended that PHMSA modify the requirements for the qualification of welders and persons joining plastic pipe to include an effective date and change the records retention provision to a period of 5 years. During the June 2017 GPAC meeting, the committee recommended PHMSA amend provisions related to the general duty clause for records and edit the corresponding reference to retention periods in Appendix A. After further discussion, during the meeting on March 2, 2018, the committee recommended PHMSA withdraw the proposed addition of § 192.13. Similarly, in the June 2017 meeting, the committee recommended PHMSA modify the proposed Appendix A to clarify that it does not apply to distribution or gathering pipelines. After considering the issue at the meeting on March 2, 2018, the committee recommended PHMSA withdraw proposed Appendix A from the rulemaking. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 Other changes the committee suggested regarding the proposed recordkeeping requirements included revising the record provisions for materials, pipe design, and components to clarify the effective date of those provisions and recommended PHMSA clarify that the recordkeeping provisions for components only applies to components greater than 2 inches in nominal diameter. The recordkeeping provisions proposed under the MAOP determination and MAOP reconfirmation sections were discussed by the GPAC separately and are expanded upon under the discussions for those specific topics below. Following those discussions over the course of multiple meetings, the committee voted unanimously that the provisions related to recordkeeping requirements in part 192 were technically feasible, reasonable, costeffective, and practicable, if PHMSA made the changes outlined above. IM Clarifications (§§ 192.917(e)(2), (e)(3) & (e)(4)) In the NPRM, PHMSA proposed several changes to provisions related to how operators use data in their IM programs and manage certain types of defects. PHMSA proposed changes regarding an operator’s analysis of cyclic fatigue and clarifying that certain pipe, such as low-frequency electric resistance welded pipe, must have been pressure tested for an operator to assume that any seam flaws are stable. PHMSA also proposed that any failures or changes to operation that could affect seam stability must be evaluated using a fracture mechanics analysis. Regarding cyclic fatigue, some GPAC members expressed concern that PHMSA proposed to require an annual analysis of cyclic fatigue even if the underpinning conditions affecting cyclic fatigue had not changed. Certain GPAC members wanted to ensure that it would be a change in conditions that would trigger an evaluation and that operators would not necessarily need to do an evaluation within a certain period otherwise. During the meeting, PHMSA suggested it would consider changing cyclic fatigue analysis from annually to periodically based on any changes to cyclic fatigue data and other changes to loading conditions since the previous analysis was completed, not to exceed 7 calendar years. Further, PHMSA would consider whether there was conflict with this section and the MAOP reconfirmation requirements, which was a concern brought up during the public comment period of the meeting. Following the discussion, the committee voted 11–0, that the provisions related PO 00000 Frm 00047 Fmt 4701 Sfmt 4700 52225 to cyclic fatigue were technically feasible, reasonable, cost-effective, and practicable if PHMSA revised the paragraph based on the GPAC member discussion and PHMSA’s proposed language at the meeting. For the provisions related to the stability of manufacturing- and construction-related defects, PHMSA proposed during the GPAC meeting to provide that an operator could consider manufacturing- and construction-related defects as stable only if the covered segment has been subjected to a subpart J pressure test of at least 1.25 times MAOP and the covered segment has not experienced a reportable incident attributed to a manufacturing or construction defect since the date of the most recent subpart J pressure test. Pipeline segments that have experienced a reportable incident since its most recent subpart J pressure test due to an original manufacturing-related defect, a construction-related defect, an installation-related defect, or a fabrication-related defect would be required to be prioritized as a high-risk segment for the purposes of a baseline assessment or a reassessment. PHMSA proposed to explicitly lay out these requirements in the regulations rather than cross-reference these requirements to the MAOP reconfirmation provisions. Additionally, PHMSA indicated it would create a stand-alone section to deal with pipeline cracking issues within the IM regulations and would delete a specific reference to ‘‘pipe body cracking’’ in the provisions related to electric resistance welded pipe. Following the discussion, the committee voted 12–0 that the provisions related to IM clarifications regarding manufacturing and construction defects were technically feasible, reasonable, cost-effective, and practicable if PHMSA made the changes it proposed during the meeting, created a new, stand-alone section for addressing pipeline cracking within the IM regulations, deleted the phrase related to ‘‘pipe body cracking,’’ and considered allowing other test procedures for determining whether manufacturing- and construction-related defects were stable. MAOP Exceedances (§§ 191.23, 191.25) In the NPRM, PHMSA proposed requiring operators to report each exceedance of the MAOP that exceeds the build-up allowed for the operation of pressure-limiting or control devices per the congressional mandate provided in the 2011 Pipeline Safety Act, which requires operators to report such exceedances on or before the 5th day E:\FR\FM\01OCR2.SGM 01OCR2 52226 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES2 following the date on which the exceedance occurs. During the public comment period of the June 7, 2017, meeting, a commenter expressed concern that being required to report an exceedance within 5 days might be problematic where an ongoing investigation might preclude an operator from being able to complete a full safety-related condition report. The GPAC considered this viewpoint but noted that the 5-day reporting requirement was prescribed by statute, and PHMSA does not have discretion when implementing that deadline. The GPAC, echoing another comment from the public, discussed whether the provision would be applicable to gathering lines. PHMSA, in response, noted that the requirement would be limited to gas transmission lines only. Following the discussion, the GPAC voted 11–0 that the provision was technically feasible, reasonable, costeffective, and practicable if PHMSA clarified that this provision does not apply to gathering lines. Verification of Pipeline Material Properties and Attributes (§ 192.607) In the NPRM, PHMSA proposed a process for operators to re-establish material properties on pipelines where those attributes may be unknown. The process was an opportunistic sampling approach that did not require any mandatory excavations and allowed operators to verify material properties of pipelines as opportunities presented themselves during normal operations and maintenance, such as excavations for the repair of anomalies. The GPAC had a robust discussion on the proposed material properties verification requirements and wanted to clarify that two separate activities— MAOP reconfirmation and the application of IM principles—drive the need for material properties verification and should be addressed separately. Overall, the GPAC was supportive of PHMSA’s opportunistic approach for verifying material properties. During the public comment period, members representing the pipeline industry suggested PHMSA allow a statistical sampling plan developed by operators instead of prescribing a specific number of samples needed. PHMSA clarified that it expected a 1 pipe-per-mile sampling standard in most cases. At the December 2017 GPAC meeting, some GPAC members expressed concern with the specific attributes PHMSA was proposing operators collect and verify. There was also some discussion regarding how the notification procedure PHMSA proposed might be cumbersome if operators would be VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 required to wait on a response or action from PHMSA every time an operator wanted to submit an alternative plan. The GPAC suggested adding language where, if PHMSA was to object to an operator notification, they would have to object within 90 days. If PHMSA did not object within 90 days, the operator would be free to go forward with the intended action. Following the discussion, the GPAC voted 12–0 that the provisions related to material properties verification were technically feasible, reasonable, costeffective, and practicable if the following changes were made: • Clarify that material properties verification applies to onshore steel transmission lines only, and not distribution or gathering lines. • Remove the applicability criteria of the section and make the material properties verification provisions a procedure that operators can use for obtaining missing or inadequate records or verifying pipeline attributes if required by the MAOP reconfirmation provisions or other code sections. The committee agreed to address the applicability of the material properties verification requirements under each of the MAOP reconfirmation methods and other sections as appropriate. • Delete the requirements for creating a material properties verification program plan. • Drop the list of mandatory attributes operators would be required to verify but require that operators keep any records developed through this material properties verification method. • Retain the opportunistic approach of obtaining unknown or undocumented material properties when excavations are performed for repairs or other reasons, using a one-per-mile standard proposed by PHMSA, but allow operators to use their own statistical approach and submit a notification to PHMSA with their method. Establish a minimum standard of a 95% confidence level for operator statistical methods submitted to PHMSA. • Retain flexibility to allow either destructive or non-destructive tests when verification is needed. • Incorporate language stating that, if an operator does not receive an objection letter from PHMSA within 90 days of notifying PHMSA of an alternative sampling approach, the operator can proceed with their method. PHMSA will notify the operator if additional review time is needed. • Revise the paragraph to accommodate situations where a single material properties verification test is needed (e.g., additional information is PO 00000 Frm 00048 Fmt 4701 Sfmt 4700 needed for an anomaly evaluation/ repair). • Drop accuracy specifications (retain requirement that test methods must be validated and that calibrated equipment be used). • Drop mandatory requirements for multiple test locations for large excavations (multiple joints within the same excavation). • Reduce number of quadrants at which NDE tests must be made from 4 to 2. • Delete specified program requirements for how to address sampling failures and replace with a requirement for operators to determine how to deal with sample failures through an expanded sample program that is specific to their system and circumstances. Require notification to provide expanded sample program to PHMSA, and require operators establish a minimum standard that sampling programs must be based on a minimum 95% confidence level. • Clarify the applicability of § 192.607 (d)(3)(i). Strengthened Assessment Requirements (Appendix F, §§ 192.493, 192.506, 192.921(a)) In the NPRM, PHMSA proposed to clarify the selection and conduct of ILI tools per updated industry standards that would be incorporated by reference, clarify the consideration of uncertainties in ILI reported results, add additional assessment methods to allow greater flexibility to operators, and allow direct assessment as a method only if the pipeline was not piggable. PHMSA also proposed to explicitly allow guided wave ultrasonic testing (GWUT) in the list of integrity assessment methods by codifying in a new Appendix F the current guidelines operators use for submitting GWUT inspection procedures. For the updated ILI standards, some GPAC members requested PHMSA delete the ‘‘requirements and recommendations’’ language in § 192.493 and other places where standards are incorporated by reference to avoid the consequence that nonmandatory recommendations in the standards would become regulatory requirements. Following the discussion, the GPAC voted 10–0 that the provisions related to strengthened assessment requirements pertaining to in-line assessment standards were technically feasible, reasonable, costeffective, and practicable if PHMSA struck the phrase ‘‘the requirements and recommendations of’’ from the appropriate paragraph in § 192.493. E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations Regarding the usage of assessment methods, certain committee members recommended PHMSA allow the direct assessment method whenever appropriate (i.e., do not restrict the use of direct assessments to unpiggable pipeline segments or when other methods are impractical) and incorporate better language to clarify when it is appropriate for operators to use direct assessments. Similarly, the GPAC suggested PHMSA clarify the regulatory language so that it was clear operators must select the appropriate assessment method based on the applicable threats. The clarification would avoid the implication that operators need to run certain tools against certain threats when there is no evidence or susceptibility of that threat for that particular pipeline segment. The GPAC also recommended that PHMSA delete the proposed requirement in the baseline assessment method that required a review of ILI results by knowledgeable individuals, since it is duplicative with other existing requirements elsewhere in the regulations. Further, some GPAC members expressed concern that all tools cannot meet the 90 percent tool tolerance that is specified in the referenced industry standard. PHMSA representatives noted that the rule would not require that every tool perform within a 90 percent specification rate, but that actual tool performance should be verified and applied when ILI data is interpreted. As in other sections of the proposed regulations, the committee also requested PHMSA adopt the same objection procedure that the GPAC discussed and approved under the material properties verification provisions for any notification under this section. Following the discussion, the GPAC voted 10–0 that the provisions related to strengthening the conduct of a baseline integrity assessment were technically feasible, reasonable, cost-effective, and practicable if PHMSA revised the requirements to clarify that operators must select assessment methods based on the threats to which the pipeline is susceptible and removed language in the provision that is duplicative with requirements elsewhere in the regulations; clarified that direct assessment is allowed where appropriate but may not be used to assess threats for which the method is not suitable; and incorporated the same objection procedure the committee approved for the material properties verification provisions and with a PHMSA review timeframe of 90 days. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 In discussing the provisions related to the ‘‘spike’’ hydrostatic pressure test method, the committee had several comments and recommendations. Specifically, some GPAC members recommended that the spike test should be performed at a pressure level of 100 percent SMYS, and not 105 percent, to account for varying elevations and test segment lengths. They also suggested that the 30-minute hold time was too long and requested PHMSA consider minimizing the duration of the spike pressure to avoid growing subcritical cracks. Further, the GPAC recommended PHMSA clarify that spike testing should be performed against the threat of ‘‘time-dependent cracking’’ and remove instances in other sections of the regulations where PHMSA listed the threats for which a spike pressure test is appropriate. Following the discussion, the committee voted 10–0 that the provisions related to the ‘‘spike’’ hydrostatic pressure test method were technically feasible, reasonable, cost-effective, and practicable if PHMSA changed the minimum spike pressure to whichever is lesser: 100 percent SMYS or 1.5 times MAOP, reduced the spike hold time to a minimum of 15 minutes after the spike pressure stabilizes, referred to ‘‘timedependent cracking’’ in the section, incorporated the same objection procedure the committee approved for the material properties verification provisions and with a PHMSA review timeframe of 90 days, and incorporated the term ‘‘qualified technical subject matter expert’’ (SME) at the SME requirements. The GPAC did not have major concerns with incorporating the GWUT procedures into the regulations and voted 13–0 that the provisions related to the GWUT process were technically feasible, reasonable, cost-effective, and practicable if PHMSA revised the objection procedure as recommended by GPAC members during the discussion on the proposed material properties verification requirements and considering certain minor technical recommendations made by the GPAC members. Moderate Consequence Area Definition (§ 192.3) In the NPRM, PHMSA proposed a new definition for ‘‘Moderate Consequence Areas’’ (MCA) which would be areas operators would have to assess per the proposed requirements for performing integrity assessments outside of HCAs. PHMSA proposed to define an MCA as an area in a ‘‘potential PO 00000 Frm 00049 Fmt 4701 Sfmt 4700 52227 impact circle’’ 84 with 5 or more buildings intended for human occupancy; an ‘‘occupied site;’’ or the right-of-way of an interstate, freeway, expressway, and other principal 4-lane arterial roadway. PHMSA proposed the definition of an ‘‘occupied site’’ to be areas or buildings occupied by 5 or more persons, which was the same as an ‘‘identified site’’ under the HCA definitions at § 192.903, except that the occupancy threshold was lowered from 20 persons to 5 persons. The GPAC, based on a comment made by a member of the public, asked if PHMSA could provide more guidance on what a ‘‘piggable’’ line is, for the purposes of this definition. The GPAC asked whether PHMSA believed that qualifier applies to pipelines that can be fully assessed by a traditional, freeswimming ILI tool without further modification to the pipeline, and PHMSA noted during the meeting that a ‘‘piggable’’ line would be one without physical or operational modifications. The GPAC then suggested PHMSA clarify that definition in the preamble of this final rule. GPAC members representing the public were concerned about PHMSA’s proposal during the meeting to eliminate the concept of an ‘‘occupied site’’ from the MCA definition. Industry members argued that, from a practicability standpoint, determining whether five people were in a location at any given time could be difficult, and there was significant overlap between ‘‘occupied sites’’ and the class locations that would need to be assessed per the proposal. The GPAC discussed whether some of these sites would be included within an operator’s HCA identification program already and, if not, whether operators would be able to otherwise incorporate ‘‘occupied sites’’ into their identification and assessment programs. Several GPAC members discussed whether PHMSA should create a database or provide other guidance on which highways should be included in the MCA definition for consistency between PHMSA, State regulators, and operators. Those comments regarding highways were made following a public comment asking whether certain elevated highways needed to be included. Following the discussion, the GPAC voted 10–0 that the MCA definition was technically feasible, reasonable, costeffective, and practicable if PHMSA 84 A ‘‘potential impact circle’’ is defined under § 192.903 as ‘‘a circle of radius equal to the potential impact radius,’’ where the ‘‘potential impact radius’’ is the radius of a circle within which the potential failure of a pipeline could have significant impact on people or property. E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 52228 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations changed the highway description to remove the reference to ‘‘rights-of-way’’ and added language so that the highway description includes ‘‘any portion of the paved surface, including shoulders;’’ clarified that highways with 4 or more lanes are included within the definition; discussed in the preamble what the definition of ‘‘piggable’’ is; and worked with the Federal Highway Administration to provide operators with clear information and discuss it in the preamble of this final rule. Additionally, the GPAC recommended PHMSA modify the term ‘‘occupied sites’’ in the definition by removing ‘‘5 or more persons’’ and the occupancy timeframe of 50 days, and tie the requirement into the HCA survey for ‘‘identified sites’’ as discussed by members and PHMSA at the meeting. Such identification could be made through publicly available databases and class location surveys, and PHMSA was to consider the sites and enforceability per direction by the committee members. MAOP Reconfirmation (§ 192.624) Assessments Outside of HCAs (§ 192.710) In the NPRM, PHMSA proposed to require operators perform integrity assessments of certain pipelines outside of HCAs. Specifically, operators would perform an initial assessment within 15 years and periodic assessments 20 years thereafter of pipelines in Class 3 and Class 4 locations as well as piggable pipelines in newly-defined ‘‘moderate consequence areas’’ as discussed above. The GPAC, based on a public comment during the meeting, questioned whether the timeframes for the initial assessment and periodic assessments were appropriate. Members debated shortening the time frames and suggested a few timeframes that could be based on a risk-based prioritization and taking into account timeframes for HCA assessments. Following the discussion, the GPAC voted 10–0 that the provisions related to assessments outside of HCAs were technically feasible, reasonable, costeffective, and practicable if PHMSA clarified that direct assessment can be used as an assessment method only if appropriate for the threat being assessed but cannot be used to assess threats for which direct assessment is not suitable; revised the initial assessment and reassessment intervals from 15 years and 20 years, respectively, to 14 years and 10 years, respectively, and with a risk-based prioritization; revised the applicability requirements to apply to lines with MAOPs of 30 percent SMYS or greater; and removed the provisions related to low-stress assessments. During the discussion on MAOP reconfirmation, some GPAC members suggested PHMSA revise the applicability of the provisions to remove pipeline segments with prior crack or seam incidents, as those issues would be dealt with in an operator’s IM program. Certain committee members recommended PHMSA restrict the scope of the MAOP reconfirmation provisions to pipeline segments with MAOPs of 30 percent SMYS or greater. These members argued that threshold was explicit in the congressional mandate as it pertained to previously untested pipe, and that it was based on the concept that lower-stress lines leak rather than rupture. Members further suggested that the benefit in addressing low-stress lines was not commensurate with the cost of doing so. Other committee members supported retaining the scope of PHMSA’s proposals in the NPRM in order to address specific NTSB recommendations. Following the discussion, the committee voted 13–0 that the provisions related to the scope for MAOP reconfirmation were technically feasible, reasonable, cost-effective, and practicable if PHMSA removed pipelines with previous reportable incidents due to crack defects from the applicability paragraph; addressed pipeline segments with crack incident history in a new paragraph under the IM requirements; withdrew the definitions for ‘‘modern pipe,’’ ‘‘legacy pipe,’’ and ‘‘legacy construction techniques;’’ revised a reference to necessary records within the applicability paragraph to VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 In the NPRM, PHMSA proposed a testing regime for (1) pipelines in HCAs, Class 3 or Class 4 locations, or ‘‘piggable’’ MCAs that experienced a reportable in-service incident due to certain types of defects since its most recent successful subpart J pressure test, (2) pipelines in HCAs or Class 3 or Class 4 locations that lacked the traceable, verifiable, and complete pressure test records necessary to substantiate the current MAOP, and (3) pipelines in HCAs, Class 3 or Class 4 locations, or piggable MCAs where the operator established the MAOP using the ‘‘grandfather’’ clause pursuant to § 192.619(c). PHMSA proposed operators of these pipelines re-confirm the MAOP of those pipelines by choosing and executing one of a variety of methods. Those methods are discussed in more detail in individual sections below. MAOP Reconfirmation Scope and Completion Date PO 00000 Frm 00050 Fmt 4701 Sfmt 4700 refer to records needed for MAOP determination and not subpart J pressure test records; and revised the applicability of the requirements for grandfathered lines to apply only to those lines with MAOPs of 30 percent or greater of SMYS. The committee also recommended PHMSA review the costs and benefits of making the requirements applicable to Class 3 and Class 4 nonHCA pipe operating below 30 percent SMYS. As for the completion date for the MAOP reconfirmation requirements, the GPAC voted 13–0 that the related provisions were technically feasible, reasonable, cost-effective, and practicable if PHMSA addressed how the completion plan and completion dates required by the section would apply to pipelines that currently do not meet the applicability conditions but may in the future. The committee suggested PHMSA could add a phrase stating that operators must complete all actions required by the section on 100 percent of the applicable pipeline mileage 15 years after the effective date of the rule or, as soon as practicable but not to exceed 4 years after the pipeline segment first meets the applicability conditions, whichever date is later. The GPAC also recommended that PHMSA consider a waiver or no-objection procedure for extending that timeline past 4 years, if necessary. MAOP Reconfirmation: Methods 1 and 2 (Pressure Test and Pressure Reduction) In the NPRM, PHMSA proposed six methods an operator could use if needing to reconfirm MAOP. Method 1, a hydrostatic pressure test, would be conducted at 1.25 times MAOP or the MAOP times the class location test factor, whichever is greater. PHMSA proposed operators use a ‘‘spike’’ test method on pipeline segments with reportable in-service incidents due to known manufacturing or construction issues, and PHMSA also proposed operators estimate the remaining life of pipeline segments with crack defects. Method 2, a pressure reduction, would allow operators to reduce the pipeline segment’s MAOP to the highest operating pressure divided by 1.25 times MAOP or the class location test factor times MAOP, whichever is greater. Similar to Method 1, PHMSA proposed operators taking a pressure reduction to reconfirm MAOP be required to estimate the remaining life of pipeline segments with crack defects. The GPAC members representing the industry argued that a ‘‘spike’’ test is more appropriate to include under IM requirements and that it is not E:\FR\FM\01OCR2.SGM 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES2 appropriate for MAOP reconfirmation. During the meeting, PHMSA noted that if the scope of the MAOP reconfirmation provisions was to be revised to delete lines with crack-like defects, the spike test requirement would not be needed. However, PHMSA would expect the spike test provisions to be utilized when otherwise required by the regulations. GPAC members also suggested adding language to address material properties verification requirements with respect to the information that is needed to conduct a pressure test. At the meeting, PHMSA suggested that the GPAC consider explicitly requiring that any information an operator does not have to perform a successful pressure test in accordance with subpart J (or that is not documented in traceable, verifiable, and complete records) be verified in accordance with the material properties verification provisions. Following the discussion, the GPAC voted 12–0 that the provisions related to the pressure test method for MAOP reconfirmation were technically feasible, reasonable, cost-effective, and practicable if PHMSA deleted the spike hydrostatic testing component for pipelines with suspected crack defects and referred to subpart J more broadly instead of certain sections within subpart J. The GPAC also recommended that if the pressure test segment does not have traceable, verifiable, and complete MAOP records, operators should use the best available information upon which the MAOP is currently based to perform the pressure test. The committee recommended PHMSA require operators of such pipeline segments add those segments to its plan for opportunistically verifying material properties in accordance with the material properties verification requirements, noting that most pressure tests will present at least two opportunities for material properties verification at the test manifolds. As for the pressure reduction method of MAOP reconfirmation, the GPAC voted 12–0 that the related provisions were technically feasible, reasonable, cost-effective, and practicable if PHMSA increased the look-back period from 18 months to 5 years and removed the requirement for operators to perform fracture mechanics analysis on those pipeline segments where the pressure is being reduced to reconfirm the MAOP. MAOP Reconfirmation: Method 3 (Engineering Critical Assessment and Fracture Mechanics) In the NPRM, PHMSA proposed allowing operators to use an engineering critical assessment (ECA) analysis in VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 conjunction with an ILI assessment to reconfirm a pipeline segment’s MAOP where the segment’s MAOP would be based upon the lowest predicted failure pressure (PFP) of the segment. This method would require specific technical documentation and material properties verification, and it would require operators analyze crack, metal loss, and interacting defects remaining in the pipe, or that could remain in the pipe, to determine the PFP. The pipeline segment’s MAOP would then be established at the lowest PFP divided by 1.25 or by the applicable class location factor listed under the MAOP determination provisions, whichever of those derating factors is greater. Most of the GPAC discussion on this portion of MAOP reconfirmation related to the specific values used in the fracture mechanics analysis portion of the ECA and whether those requirements would best be located in a section independent from the MAOP reconfirmation requirements. During the meetings, PHMSA noted it would consider creating a stand-alone fracture mechanics section that could be referenced when the procedure is needed or required by other sections of the regulations. PHMSA clarified that fracture mechanics would be needed in the context of MAOP reconfirmation only for the ECA method and ‘‘other technology’’ usage under Method 6 where the applicable pipeline segments have cracks or crack-like defects. Following the discussion, the GPAC voted 12–0 that the provisions related to the ECA method of MAOP reconfirmation and fracture mechanics were technically feasible, reasonable, cost-effective, and practicable if PHMSA moved the fracture mechanics requirements to a stand-alone section in the regulations. The GPAC recommended the section not specify when, or for which pipeline segments, fracture mechanics analysis would be required, but instead provide a procedure by which operators needing to perform fracture mechanics analysis could do so. The GPAC recommended several changes to the fracture mechanics requirements, including striking crossreferences to the MAOP reconfirmation requirements and spike hydrostatic testing requirements, as well as striking the sensitivity analysis requirements and replacing them with a requirement that operators account for model inaccuracies and tolerances. Additionally, the GPAC recommended PHMSA add a paragraph specifying that any records created through the performance of a fracture mechanics analysis must be retained. PO 00000 Frm 00051 Fmt 4701 Sfmt 4700 52229 There were several technical GPAC recommendations related to the use of Charpy V-notch toughness values in the fracture mechanics analysis. Specifically, the GPAC recommended operators have the ability to use a conservative Charpy V-notch toughness value based on the sampling requirements of the material properties verification provisions, and that operators could use Charpy V-notch toughness values from similar or the same vintage pipe until the properties are obtained through an opportunistic testing program. Further, the GPAC recommended that the default Charpy V-notch toughness values (full-size specimen, based on the lowest operational temperature) of 13-ft.-lbs. (body) and 4-ft.-lbs. (seam) only apply to pipe with suspected low-toughness properties or unknown toughness properties. Additionally, the GPAC recommended PHMSA include a requirement for operators of pipeline segments with a history of leaks or failures due to cracks to work diligently to obtain toughness data if unknown and use Charpy V-notch toughness values (full-size specimen, based on the lowest operational temperature) of 5-ft.lbs. (body) and 1-ft.-lbs. (seam) in the interim. Further, the GPAC suggested PHMSA allow operators to request the use of different default Charpy V-notch toughness values via a 90-day notification to PHMSA. For the ECA method itself, the committee recommended PHMSA add a requirement to verify material properties in accordance with the material properties verification requirements if the information needed to conduct an ECA is not documented in traceable, verifiable, and complete records. Further, the GPAC recommended that PHMSA not include default Charpy V-notch toughness values or other technical fracture mechanics requirements in the ECA method, as those items would be specified in the new stand-alone fracture mechanics section. Similarly, the GPAC recommended removing ILI tool performance specifications and replacing them with a requirement to verify tool performance using unity plots or equivalent technologies. MAOP Reconfirmation: Methods 4, 5, and 6 (Pipe Replacement, SmallDiameter & Potential Impact Radius Pressure Reduction, and Other Technology) In the NPRM, PHMSA proposed three additional methods operators could use to reconfirm a pipeline’s MAOP. Method 4, pipe replacement, would require operators to replace pipe for E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 52230 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations which they have inadequate records or pipe that was not previously tested due to the grandfather clause in § 192.619(c). Method 5, as proposed, was applicable to low-stress, small diameter, and small potential impact radius (PIR) lines,85 and would require operators to take a 10 percent pressure cut as well as perform more frequent patrols and leak surveys. Method 6, ‘‘other technology,’’ would allow operators to use an alternative method, with notification to PHMSA, to reconfirm the MAOP of their applicable pipeline segments. The GPAC had no major comments regarding Method 4, pipe replacement. For Method 5, GPAC members representing the industry questioned the need for the compensatory safety measures, such as the additional patrols and leak surveys, in conjunction with the 10 percent pressure reduction. They also supported public comments that promoted expanding the applicability of Method 5 beyond the prescribed pipe diameter of less than or equal to 8 inches and the operating pressure of below 30 percent SMYS. During the meeting, PHMSA noted it could drop the diameter and operating pressure requirements from the applicability and use the prescribed PIR of 150 feet or less as a proxy for those risk factors. Additionally, PHMSA noted it would expand the look-back period to 5 years to be consistent with committee and public comments regarding the pressure reduction method (Method 2) of MAOP reconfirmation discussed earlier. With regard to the ‘‘other technology’’ method, committee members suggested using the notification procedure developed for the material properties verification requirements, and PHMSA acknowledged it could be included here as well. Following the discussion, the committee voted 11–0 that the provisions related to the pipe replacement, pressure reduction for small PIR and diameter lines, and ‘‘other technology’’ methods of MAOP reconfirmation were technically feasible, reasonable, cost-effective, and practicable if PHMSA made certain changes. For Method 4, pipe replacement, the committee had no significant comments or changes. For Method 5, the small PIR and diameter pressure reduction method, the GPAC recommended PHMSA delete the size and pressure criteria, limiting the requirement to those lines with a PIR of 150 feet or less; remove the external corrosion direct assessment, crack 85 These lines would be lines operating below 30 percent SMYS with diameters of 8 inches or less and PIRs of 150 feet or less. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 analysis program, odorization, and fracture mechanics analysis requirements; and change the frequency of patrols and surveys to 4 times per year in Class 1 and Class 2 locations and 6 times per year in Class 3 and Class 4 locations. For Method 6, the ‘‘other technology’’ method, the GPAC recommended PHMSA incorporate the same 90-day notification and objection procedure the GPAC approved for the material properties verification requirements. MAOP Reconfirmation: Recordkeeping and Notification The GPAC also voted on the notification procedure and recordkeeping requirements of the MAOP reconfirmation requirements. As there were no substantial GPAC comments on these issues, the GPAC voted 11–0 that the provisions are technically feasible, reasonable, costeffective, and practicable if PHMSA provided guidance regarding what ‘‘traceable, verifiable, and complete’’ records are in the preamble, and if the notification procedure is retained as it was proposed in the NPRM, but incorporating the same 90-day notification and objection procedure the committee approved for the material properties verification requirements into any notification required under the MAOP reconfirmation requirements. Other MAOP Amendments (§§ 192.503, 192.605(b)(5), 192.619(a)(2), 192.619(a)(4), 192.619(e), 192.619(f)) PHMSA presented to the committee issues related to other portions of MAOP determination 86 that had crossreferences to MAOP reconfirmation methods or other areas of the proposed regulations. More specifically, the GPAC was to consider recommending PHMSA eliminate duplications in scope between the MAOP determination provisions and the MAOP reconfirmation provisions, and eliminate a duplicative revision to the subpart J pressure test general requirements that was referenced adequately elsewhere in the proposal. PHMSA also proposed that the establishment of MAOP under § 192.619 should rely on traceable, verifiable, and complete records, and therefore cross-referenced the material properties verification provisions with the MAOP determination provisions. Similarly, PHMSA added a paragraph to the existing MAOP determination provisions to more clearly specify that operators must have records to substantiate the MAOP of their pipeline segments. To address an NTSB 86 See PO 00000 § 192.619. Frm 00052 Fmt 4701 Sfmt 4700 recommendation from the PG&E incident, PHMSA also proposed requiring that the MAOP pressure limitation factor specified in the MAOP determination section of the regulations for Class 1 pipeline segments be based on the subpart J test pressure divided by 1.25, whereas the existing requirement was the test pressure divided by 1.1. Finally, PHMSA proposed adding a clarification that the requirement for overpressure protection applied to pipeline segments where the MAOP was established using one of the six methods under MAOP reconfirmation. However, PHMSA noted in response to public comment that the clarification seemed to be overly confusing and should be withdrawn. The GPAC reviewed and discussed PHMSA’s proposed changes to the other MAOP-related provisions, voting 12–0 that the provisions are technically feasible, reasonable, cost-effective, and practicable if PHMSA considered editorially restructuring the applicability of the MAOP determination provisions; clarifying that the recordkeeping requirements specified under MAOP determination only apply to onshore, steel, gas transmission pipelines; and clarifying that the MAOP recordkeeping requirements are not retroactive. The GPAC suggested this be clarified by stating existing records for pipelines installed on or before the effective date of the rule must be kept for the life of the pipeline, that pipelines installed after the effective date of the rule must make and retain records as required for the life of the pipeline, and that MAOP records are required for any pipeline placed in service after the effective date of the rule. The GPAC noted that other sections, including the MAOP reconfirmation and material properties verification requirements, would require when and for which pipeline segments where MAOP records are not documented in a traceable, verifiable, and complete manner would need to be verified. Changes From the GPAC Recommendations In this final rule, PHMSA considered the recommendations of the GPAC and adopted them as PHMSA deemed appropriate. However, there were recommendations from the GPAC that PHMSA considered but did not adopt. To summarize, the major changes PHMSA made in this rule that deviate from the GPAC recommendations are as follows: (1) When discussing the other proposed issues related to the MAOP requirements, the GPAC recommended E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations PHMSA consider moving § 192.619(e) to be a subsection of § 192.619(a) and consider referencing section § 192.624 in § 192.619(a). PHMSA did not implement this recommendation because MAOP reconfirmation for grandfathered segments is not applicable for new pipeline segments. (2) When considering the IM clarifications at § 192.917, the GPAC recommended PHMSA consider removing the term ‘‘hydrostatic’’ from the testing requirements at § 192.917(e)(3), which deals with manufacturing and construction defects, and allow other authorized testing procedures. PHMSA is not implementing this recommendation because allowing pneumatic tests would be a safety concern to the public and operating personnel. (3) When discussing the assessment requirements for non-HCAs under proposed § 192.710, the GPAC recommended PHMSA change the ‘‘discovery of condition’’ period allotted from 180 to 240 days. PHMSA is not implementing this suggestion from the GPAC and is retaining the 180-day timeframe for operators to determine whether a condition presents a potential threat to the integrity of the pipeline. (4) PHMSA added a notification requirement for the use of other technology under the non-HCA assessment requirements at § 192.710. While the GPAC did not specifically request PHMSA make this change, the GPAC was generally supportive of incorporating the notification procedure the committee agreed to under the proposed material properties verification requirements for other applications. (5) Regarding the requirements for the scope of MAOP reconfirmation, the GPAC recommended PHMSA review the costs and benefits of including Class 3 and Class 4 pipelines not located in HCAs and that operate at less than 30 percent SMYS. PHMSA did consider this as an alternative in the RIA but chose not to move forward with the proposal as suggested as it is outside the scope of the mandate. (6) Regarding the MCA definition, the GPAC recommended PHMSA consider modifying the term ‘‘occupied sites’’ within the definition by removing reference to ‘‘5 or more persons’’ and the timeframe of 50 days and tying the requirement for identifying occupied sites to the HCA ‘‘identified sites’’ survey requirement as discussed by members and PHMSA at the meeting. In this final rule, PHMSA chose to delete the term ‘‘occupied sites’’ from the MCA definition and from the general definitions section of part 192. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 (7) PHMSA moved the specific ECA requirements outside of the MAOP reconfirmation section into a new standalone § 192.632. The MAOP reconfirmation requirements regarding the ECA method at § 192.624(c)(3) and the ECA requirements in § 192.632 will cross-reference each other. PHMSA made this change to streamline the MAOP reconfirmation provisions and improve the readability of the requirements. No substantive changes were made to the procedure in connection with this reorganization; this was a stylistic change only. V. Section-by-Section Analysis § 191.23 Reporting Safety-Related Conditions Section 23 of the 2011 Pipeline Safety Act requires operators to report each exceedance of MAOP that exceeds the margin (build-up) allowed for operation of pressure-limiting or control devices. On December 21, 2012, PHMSA published advisory bulletin ADB–2012– 11, which advised operators of their responsibility under section 23 of the 2011 Pipeline Safety Act to report such exceedances. PHMSA is revising § 191.23 to codify this statutory requirement. § 191.25 Filing Safety-Related Condition Reports Section 23 of the 2011 Pipeline Safety Act requires operators to report each exceedance of the MAOP that exceeds the margin (build-up) allowed for operation of pressure-limiting or control devices. As described above, PHMSA is revising § 191.23 to codify this requirement. Section 191.25 is also revised to make conforming edits and comply with the mandatory 5-day reporting deadline specified in section 23 of the 2011 Pipeline Safety Act. § 192.3 Definitions Section 192.3 provides definitions for various terms used throughout part 192. In support of other regulations adopted in this final rule, PHMSA is amending the proposed definition of ‘‘Moderate consequence area.’’ This change will define this term as it is used throughout part 192. The definition of a ‘‘moderate consequence area,’’ or MCA, is based on similar methodology used to define ‘‘high consequence area,’’ or HCA in § 192.903. Moderate consequence areas will define the subset of non-HCA locations where integrity assessments are required (§ 192.710) and where MAOP reconfirmation is required (§ 192.624). The criteria for determining MCA locations differs from the criteria PO 00000 Frm 00053 Fmt 4701 Sfmt 4700 52231 currently used to identify HCAs in that the threshold for buildings intended for human occupancy located within the potential impact radius is lowered from 20 to 5, and identified sites are excluded. In response to NTSB recommendation P–14–01, which was issued as a result of the incident near Sissonville, WV, the MCA definition also includes locations where interstate highways, freeways, expressways, and other principal 4-or-more-lane arterial roadways are located within the potential impact radius. PHMSA is also adopting a definition of an ‘‘engineering critical assessment,’’ as that term will be used in §§ 192.624 and 192.632. More specifically, the ECA is a documented analytical procedure that operators can use to determine the maximum tolerable size for pipeline imperfections based on the MAOP of the particular pipeline segment. Operators can use an ECA in conjunction with an ILI inspection as one of the methods to reconfirm MAOP, if required. § 192.5 Class Locations Section 23 of the 2011 Pipeline Safety Act requires the Secretary of Transportation to require verification of records used to establish MAOP to ensure they accurately reflect the physical and operational characteristics of certain pipelines and to confirm the established MAOP of the pipelines. PHMSA has determined that an important aspect of compliance with this requirement is to assure that pipeline class location records are complete and accurate. This final rule adds a new paragraph, § 192.5(d), to require each operator of transmission pipelines to maintain records documenting the current class location of each pipeline segment and demonstrating how an operator determined each current class location in accordance with this section. § 192.7 What documents are incorporated by reference partly or wholly in this part? Section 192.7 lists documents that are incorporated by reference in part 192. PHMSA is making conforming amendments to § 192.7 in the rule text to reflect other changes adopted in this final rule. § 192.9 What requirements apply to gathering lines? This final rule codifies new standards for gas transmission pipelines, most of which are not intended to be applied to gas gathering pipelines. PHMSA is making conforming amendments to § 192.9 to clarify which provisions E:\FR\FM\01OCR2.SGM 01OCR2 52232 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations apply only to gas transmission pipelines and not to gas gathering pipelines. § 192.18 How To Notify PHMSA This final rule allows operators to notify PHMSA of proposed alternative approaches to achieving the objective of the minimum safety standards in several different regulatory sections. These notification procedures for alternative actions are comparable to the existing notification requirements in subpart O for the integrity management regulations. Because PHMSA is expanding the use of notifications to pipeline segments for which subpart O does not apply (i.e., to non-HCA pipeline segments), PHMSA is adding a new § 192.18 in subpart A that contains the procedure for submitting such notifications for any pipeline segment. jbell on DSK3GLQ082PROD with RULES2 § 192.67 Records: Material Properties Section 23 of the 2011 Pipeline Safety Act requires the Secretary of Transportation to require the verification of records to ensure they accurately reflect the physical and operational characteristics of certain pipelines and to confirm the established MAOP of the pipelines. PHMSA has determined that compliance requires that pipeline material properties records are complete and accurate. This final rule moves the original § 192.67 to § 192.69 and adds in its place a new § 192.67 that requires each operator of gas transmission pipelines installed after the effective date of this final rule to collect or make, and retain for the life of the pipeline, records that document the physical characteristics of the pipeline, including tests, inspections, and attributes required by the manufacturing specification in effect at the time the pipe was manufactured. The physical characteristics an operator must keep documented include diameter, yield strength, ultimate tensile strength, wall thickness, seam type, and chemical composition. These requirements also apply to any new materials or components that are put on existing pipelines. For pipelines installed prior to the effective date of this final rule, operators are required to retain for the life of the pipeline all such records in their possession as of the effective date of this final rule. These recordkeeping requirements apply to offshore gathering lines and Type A gathering lines in accordance with § 192.9. Pipelines that lack the traceable, verifiable, and complete records needed to substantiate MAOP may be subject to the MAOP reconfirmation requirements at § 192.624, as specified in that section. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 § 192.69 Storage and Handling of Plastic Pipe and Associated Components Previous § 192.67, titled ‘‘Storage and handling of plastic pipe and associated components,’’ was created as a part of the Plastic Pipe rule, which was published on November 20, 2018 (83 FR 58716). PHMSA is redesignating that section in this final rule to a new § 192.69. No other changes have been made to the section. § 192.127 Records: Pipe Design Section 23 of the 2011 Pipeline Safety Act requires the Secretary of Transportation to require the verification of records to ensure they accurately reflect the physical and operational characteristics of certain pipelines and to confirm the established MAOP of the pipelines. PHMSA has determined that compliance requires that pipe design records are complete and accurate. For pipelines installed after the effective date of this final rule, this final rule adds a new § 192.127 to require each operator of gas transmission pipelines to collect or make, and retain for the life of the pipeline, records documenting pipe design to withstand anticipated external pressures and determination of design pressure for steel pipe. For pipelines installed prior to the effective date of this final rule, operators are required to retain for the life of the pipeline all such records in their possession as of the effective date of this final rule. Pipelines that lack the traceable, verifiable, and complete records needed to substantiate MAOP may be subject to the MAOP reconfirmation requirements at § 192.624, as specified in that section. § 192.150 Passage of Internal Inspection Devices The current pipeline safety regulations in § 192.150 require that pipelines be designed and constructed to accommodate in-line inspection devices. Prior to this rulemaking, part 192 was silent on technical standards or guidelines for implementing requirements to assure pipelines are designed and constructed for in-line inspection assessments. Previously, there was no consensus industry standard that addressed design and construction requirements for in-line inspection assessments. NACE Standard Practice, NACE SP0102–2010, ‘‘In-line Inspection of Pipelines,’’ has since been published and provides guidance on this issue in section 7. The incorporation of this standard into the Federal Pipeline Safety Regulations at § 192.150 will promote a higher level of PO 00000 Frm 00054 Fmt 4701 Sfmt 4700 safety by establishing consistent standards for the design and construction of pipelines to accommodate in-line inspection devices. § 192.205 Records: Pipeline Components Section 23 of the 2011 Pipeline Safety Act requires the Secretary of Transportation to require the verification of records to ensure they accurately reflect the physical and operational characteristics of certain pipelines and to confirm the established MAOP of the pipelines. PHMSA has determined that compliance requires that pipeline component records are complete and accurate. For pipelines installed after the effective date of this final rule, this final rule adds a new § 192.205 to require each operator of gas transmission pipelines to collect or make, and retain for the operational life of the component, records documenting manufacturing and testing information for valves and other pipeline components. For pipelines installed prior to the effective date of this final rule, operators are required to retain for the life of the pipeline all such records in their possession as of the effective date of this final rule. Pipelines that lack the traceable, verifiable, and complete records needed to substantiate MAOP may be subject to the MAOP reconfirmation requirements at § 192.624, as specified in that section. § 192.227 Qualification of Welders Section 23 of the 2011 Pipeline Safety Act requires the Secretary of Transportation to require the verification of records to ensure they accurately reflect the physical and operational characteristics of certain pipelines and to confirm the established MAOP of the pipelines. PHMSA has determined that compliance requires that pipeline welding qualification records are complete and accurate. This final rule adds a new paragraph, § 192.227(c), to require each operator of gas transmission pipelines to make and retain records demonstrating each individual welder’s qualification in accordance with this section for a minimum of 5 years following construction. This requirement will apply to pipelines installed after one year from the effective date of the rule. § 192.285 Plastic Pipe: Qualifying Persons To Make Joints Section 23 of the 2011 Pipeline Safety Act requires the Secretary of Transportation to require the verification of records to ensure they accurately reflect the physical and E:\FR\FM\01OCR2.SGM 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations operational characteristics of certain pipelines and to confirm the established MAOP of the pipelines. PHMSA has determined that compliance requires that plastic pipeline qualification records are complete and accurate. This final rule adds a new paragraph, § 192.285(e), to require each operator of gas transmission pipelines to make and retain records demonstrating a person’s plastic pipe joining qualifications in accordance with this section for a minimum of 5 years following construction. This requirement will apply to pipelines installed after one year from the effective date of the rule. jbell on DSK3GLQ082PROD with RULES2 § 192.493 Pipelines In-Line Inspection of The current pipeline safety regulations at §§ 192.921 and 192.937 require that operators assess the material condition of pipelines in certain circumstances (e.g., IM assessments for pipelines in HCAs) and allow the use of ILI tools for these assessments. Operators of gas transmission pipelines are required to follow the requirements of ASME/ANSI B31.8S, ‘‘Managing System Integrity of Gas Pipelines,’’ in conducting their IM activities. ASME B31.8S provides limited guidance for conducting ILI assessments. Presently, part 192 is silent on the technical standards or guidelines for performing ILI assessments or implementing these requirements. When the IM regulations were initially promulgated, there were no uniform industry standards for ILI assessments. Three related standards have since been published: • API STD 1163–2013, ‘‘In-Line Inspection Systems Qualification Standard.’’ This Standard serves as an umbrella document to be used with and as a complement to the NACE and ASNT standards below, which are incorporated by reference in API STD 1163. • NACE Standard Practice, NACE SP0102–2010, ‘‘In-line Inspection of Pipelines.’’ • ANSI/ASNT ILI–PQ–2005 (2010), ‘‘In-line Inspection Personnel Qualification and Certification.’’ API 1163–2013 is more comprehensive and rigorous than the current requirements in 49 CFR part 192. The incorporation of this standard into the Federal Pipeline Safety Regulations will promote a higher level of safety by establishing consistent standards to qualify the equipment, people, processes, and software utilized by the ILI industry. The API standard addresses in detail each of the following aspects of ILI inspections, most of VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 which are not currently addressed in the regulations: • Systems qualification process. • Personnel qualification. • ILI system selection. • Qualification of performance specifications. • System operational validation. • System results qualification. • Reporting requirements. • Quality management system. The NACE standard covers in detail each of the following aspects of ILI assessments, most of which are not currently addressed in part 192 or in ASME B31.8S: • Tool selection. • Evaluation of pipeline compatibility with ILI. • Logistical guidelines, which includes survey acceptance criteria and reporting. • Scheduling. • New construction (planning for future ILI in new lines). • Data analysis. • Data management. The NACE standard provides a standardized questionnaire and specifies that the completed questionnaire should be provided to the ILI vendor. The questionnaire lists relevant parameters and characteristics of the pipeline section to be inspected. PHMSA determined that the consistency, accuracy, and quality of pipeline in-line inspections would be improved by incorporating the consensus NACE standard into the regulations. The NACE standard applies to ‘‘free swimming’’ inspection tools that are carried down the pipeline by the transported product. It does not apply to tethered or remotely controlled ILI tools, which can also be used in special circumstances (e.g., examination of laterals). While their use is less prevalent than free-swimming tools, some pipeline IM assessments have been conducted using tethered or remotely controlled ILI tools. PHMSA determined that many of the provisions in the NACE standard can be applied to tethered or remotely controlled ILI tools. Therefore, PHMSA is amending the Federal Pipeline Safety Regulations to allow the use of these tools, provided they comply with the applicable sections of the NACE standard. The ANSI/ASNT standard provides for qualification and certification requirements that are not addressed by 49 CFR part 192. The incorporation of this standard into the regulations will promote a higher level of safety by establishing consistent standards to qualify the equipment, people, processes and software utilized by the PO 00000 Frm 00055 Fmt 4701 Sfmt 4700 52233 ILI industry. The ANSI/ASNT standard addresses in detail each of the following aspects, which are not currently addressed in the regulations: • Requirements for written procedures. • Personnel qualification levels. • Education, training and experience requirements. • Training programs. • Examinations (testing of personnel). • Personnel certification and recertification. • Personnel technical performance evaluations. The final rule adds a new § 192.493 to require compliance with the three consensus standards discussed above when conducting ILI of pipelines. § 192.506 Transmission Lines: Spike Hydrostatic Pressure Test A pressure test that incorporates a short duration ‘‘spike’’ pressure is a proven means to confirm the strength of pipe with known or suspected threats of cracks or crack-like defects (e.g., stress corrosion cracking, longitudinal seam defects, etc.). Currently, part 192 does not include minimum standards for such a spike hydrostatic pressure test. This final rule adds a new § 192.506 to codify the minimum standards for performing spike hydrostatic pressure tests when operators are required to, or elect to, use this assessment method. Under the spike hydrostatic pressure test requirements, an operator may use other technologies or processes equivalent to a spike hydrostatic pressure test with justification and notification in accordance with § 192.18. § 192.517 Records: Tests Section 192.517 prescribes the recordkeeping requirements for each test performed under §§ 192.505 and 192.507. PHMSA is making conforming amendments to § 192.517 to add the recordkeeping requirements for the new § 192.506. § 192.607 Verification of Pipeline Material Properties and Attributes: Onshore Steel Transmission Pipelines Section 23 of the 2011 Pipeline Safety Act mandates the Secretary of Transportation to require operators of gas transmission pipelines in Class 3 and Class 4 locations and Class 1 and Class 2 locations in HCAs to verify records to ensure the records accurately reflect the physical and operational characteristics of the pipelines and confirm the MAOP of the pipelines established by the operator (49 U.S.C. 60139). PHMSA issued Advisory Bulletin 11–01 on January 10, 2011 (76 E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 52234 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations FR 1504), and Advisory Bulletin 12–06 on May 7, 2012 (77 FR 26822), to inform operators of this requirement. Operators have submitted information in their Annual Reports (starting for calendar year 2012) indicating that a portion of transmission pipeline segments do not have adequate records to establish MAOP and that some operators do not have traceable, verifiable, and complete records that accurately reflect the physical and operational characteristics of the pipeline. Therefore, PHMSA has determined that additional regulations are needed to implement the 2011 Pipeline Safety Act. This final rule promulgates specific criteria for determining which pipeline segments must undergo examinations and tests to understand and document physical and material properties and reconfirm a proper MAOP. For operators that do not have traceable, verifiable, and complete documentation for the physical pipeline characteristics and attributes of a pipeline segment, PHMSA is adding a new § 192.607 that contains the procedure for verifying and documenting pipeline physical properties and attributes that are not documented in traceable, verifiable, and complete records and to establish standards for performing these actions. For operators of certain pipelines lacking the necessary records to substantiate MAOP, PHMSA is also adding § 192.624, which provides operators several methods for reconfirming a pipeline segment’s MAOP. The new material properties verification requirements at § 192.607 include the scope of information needed and the methodology for verifying material properties and attributes of pipelines. The most difficult information to obtain, from a technical perspective, is the strength of the pipeline’s steel. Conventional techniques to obtain that data would include cutting out a piece of pipe and destructively testing it to determine the yield and ultimate tensile strength. In this final rule, PHMSA is providing operators with flexibility by allowing the use of non-destructive techniques that have been validated to produce accurate results for the grade and type of pipe being evaluated (see § 192.624). Another issue regarding material properties verification is the cost associated with excavating the pipeline to verify material properties and determining how much pipeline needs to be exposed and tested to have assurance of the accuracy of the verification. PHMSA addresses these issues within this final rule by specifying that operators can take VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 advantage of opportunities when the pipeline is already being exposed, such as when maintenance activity is occurring and when anomaly repairs are being made, to verify material properties that are not documented in traceable, verifiable, and complete records. For example, PHMSA considers excavations associated with the direct examination of anomalies, pipeline relocations at road crossings and river or stream crossings, pipe upgrades for class location changes, pipe cut-outs for hydrostatic pressure tests, and excavations where pipe is replaced due to anomalies to be opportunities to perform material properties verification. Over time, pipeline operators will develop a substantial set of traceable, verifiable, and complete material properties data, which will provide assurance that material properties are reliably known for the population of segments that did not have pipeline physical properties and attributes documented in traceable, verifiable, and complete records previously. Through this final rule, PHMSA is requiring that operators continue this opportunistic material properties verification process until the operator has completed enough verifications to obtain a high level of confidence that only a small percentage of pipeline segments have physical pipeline characteristics and attributes that are not verified or are otherwise inconsistent with all available information or operators’ past assumptions. This final rule specifies the number of excavations required for operators to achieve this level of confidence. Operators may use an alternative sampling approach that differs from the sampling approach specified in the requirements if they notify PHMSA in advance of using an alternative sampling approach in accordance with § 192.18. Requirements are also included in the material properties verification section to ensure that operators document the results of the material properties verification process in records that must be retained for the life of the pipeline. § 192.619 Maximum Allowable Operating Pressure: Steel or Plastic Pipelines The NTSB report on the PG&E incident included a recommendation (P–11–15) that PHMSA amend its regulations so that manufacturing-and construction-related defects can only be considered ‘‘stable’’ if a gas pipeline has been subjected to a post-construction hydrostatic pressure test of at least 1.25 times the MAOP. This final rule revises the test pressure factors in PO 00000 Frm 00056 Fmt 4701 Sfmt 4700 § 192.619(a)(2)(ii) to correspond to at least 1.25 times MAOP for pipelines installed after the effective date of this rule. The NTSB also recommended repealing § 192.619(c), commonly referred to as the ‘‘grandfather clause,’’ and requiring that all gas transmission pipelines constructed before 1970 be subjected to a hydrostatic pressure test that incorporates a spike test (recommendation P–11–14). Similarly, section 23 of the 2011 Pipeline Safety Act requires that selected pipeline segments in certain locations with previously untested pipe (i.e., the MAOP is established under § 192.619(c)) or without MAOP records be tested with a pressure test or equivalent means to reconfirm the pipeline’s MAOP. These requirements are addressed in the new § 192.624 and are described in more detail in the following section. This final rule also makes conforming changes to § 192.619 to require that operators of pipeline segments to which § 192.624 applies establish and document the segment’s MAOP in accordance with § 192.624. § 192.624 Maximum Allowable Operating Pressure Reconfirmation: Onshore Steel Transmission Pipelines Section 23 of the 2011 Pipeline Safety Act requires the verification of records for pipe in Class 3 and Class 4 locations, and high-consequence areas in Class 1 and Class 2 locations, to ensure they accurately reflect the physical and operational characteristics of the pipelines and confirm the established MAOP of the pipelines. Operators have submitted information in annual reports (beginning in calendar year 2012) indicating that some gas transmission pipeline segments do not have adequate material properties records or testing records to confirm physical and operational characteristics and to establish MAOP. For these pipelines, the 2011 Pipeline Safety Act requires that PHMSA promulgate regulations to require operators to reconfirm MAOP as expeditiously as economically feasible. The statute also requires PHMSA to issue regulations that require previously untested pipeline segments located in HCAs and operating at greater than 30 percent SMYS be tested to confirm the material strength of the pipelines. Such tests must be performed by pressure testing or other methods determined by the Secretary to be of equal or greater effectiveness. As a result of its investigation of the PG&E incident, the NTSB issued two related recommendations. NTSB recommended that PHMSA repeal § 192.619(c), commonly referred to as E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations the ‘‘grandfather clause,’’ and require that all gas transmission pipelines constructed before 1970 be subjected to a hydrostatic pressure test that incorporates a spike test (P–11–14). The NTSB also recommended that PHMSA amend the Federal Pipeline Safety Regulations so that manufacturing- and construction-related defects can only be considered stable if a pipeline has been subjected to a post-construction hydrostatic pressure test of at least 1.25 times the MAOP (P–11–15). Through this final rule, PHMSA is finalizing a new § 192.624 to address these mandates and recommendations. This final rule requires that operators reconfirm and document MAOP for certain onshore steel gas transmission pipelines located in HCAs or MCAs that meet one or more of the criteria specified in § 192.624(a). More specifically, this section applies to (1) pipelines in HCAs or Class 3 or Class 4 locations lacking traceable, verifiable, and complete records necessary to establish the MAOP (per § 192.619(a)) for the pipeline segment, including, but not limited to, hydrostatic pressure test records required by § 192.517(a); and (2) pipelines where the MAOP was established in accordance with § 192.619(c), the pipeline segment’s MAOP is greater than or equal to 30 percent of SMYS, and the pipeline is located in an HCA, a Class 3 or Class 4 location, or an MCA that can accommodate inspection by means of instrumented inline inspection tools (i.e., ‘‘smart pigs’’). This approach implements the mandate in the 2011 Pipeline Safety Act for pipeline segments in HCAs and Class 3 and Class 4 locations (49 U.S.C. 60139). In addition, the scope includes pipeline segments in the newly defined MCAs. This approach is intended to address the NTSB recommendations and to provide increased safety in areas where a pipeline rupture would have a significant impact on the public or the environment. Though PHMSA is subjecting certain grandfathered pipeline segments to the MAOP reconfirmation requirements of § 192.624, PHMSA is not repealing § 192.619(c) for pipeline segments located outside of HCAs, Class 3 or Class 4 locations, or MCAs that can accommodate inspection by means of instrumented ILI tools. Previously grandfathered pipelines that reconfirm MAOP using one of the methods of § 192.624 that operate above 72 percent SMYS may continue to operate at the reconfirmed pressure. The methods to reconfirm MAOP are specified in § 192.624 and are as follows: VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 Method 1—Pressure test. The pressure test method as specified in section 23 of the 2011 Pipeline Safety Act. Operators choosing to pressure test must also verify material property records in accordance with § 192.607. PHMSA notes that a pressure test requires the cutout of pipe at test manifold sites and those pipe cutouts would be a prime example of pipe that could and should be tested through the material properties verification procedure, if necessary. In accordance with the statute, PHMSA determined that the following methods (2) through (6) are equally effective as a pressure test for the purposes of reconfirming MAOP. Method 2—Pressure reduction. Derating the pipeline segment so that the new MAOP is less than the historical actual sustained operating pressure by using a pressure test safety factor of 0.80 (for Class 1 and Class 2 locations) or 0.67 (for Class 3 and Class 4 locations) times the sustained operating pressure (equivalent to a pressure test using gas or water as the test medium with a test pressure of 1.25 times MAOP for Class 1 and Class 2 locations and 1.5 times MAOP for Class 3 and Class 4 locations). Method 3—Engineering critical assessment. An in-line inspection, previously performed pressure test, or alternative technology and engineering critical assessment process using technical analysis with acceptance criteria to establish a safety margin equivalent to that provided by a new pressure test. PHMSA organized the ECA process requirements under a new § 192.632 and established the technical requirements for analyzing the predicted failure pressure as a part of the ECA analysis in a new § 192.712. If an operator chooses the ECA method for MAOP reconfirmation but does not have any of the material properties necessary to perform an ECA analysis (diameter, wall thickness, seam type, grade, and Charpy V-notch toughness values, if applicable), the operator must include the pipeline segment in its program to verify the undocumented information in accordance with the material properties verification requirements at § 192.607. Method 4—Pipe replacement. Replacement of the pipe, which would require a new pressure test that conforms with subpart J before the pipe is placed into service. Method 5—Pressure reduction for pipeline segments with small potential impact radii. For pipeline segments with a potential impact radius of less than or equal to 150 feet, a pressure reduction using a safety factor of 0.90 times the sustained operating pressure is allowed (equivalent to a pressure test PO 00000 Frm 00057 Fmt 4701 Sfmt 4700 52235 of 1.11 times MAOP), supplemented with additional preventive and mitigative measures specified in this final rule. Method 6—Alternative technology. Other technology that the operator demonstrates provides an equivalent or greater level of safety, provided PHMSA is notified in advance in accordance with § 192.18. Lastly, this final rule includes a new paragraph, § 192.624(f), to clearly specify that records created while reconfirming MAOP must be retained for the life of the pipeline. § 192.632 Engineering Critical Assessment for Maximum Allowable Operating Pressure Reconfirmation: Onshore Steel Transmission Pipelines The requirements for reconfirming MAOP in the new § 192.624 include an option for operators to perform an engineering critical assessment, or ECA, to reconfirm MAOP in lieu of pressure testing and the other methods provided. The requirements for conducting such an ECA were proposed under the MAOP reconfirmation requirements at § 192.624(c)(3); however, PHMSA has moved the ECA requirements to a new, stand-alone section and cross-referenced those requirements in order to improve the readability of the MAOP reconfirmation requirements. Operators choosing the ECA method for MAOP reconfirmation may perform an in-line inspection and a technical analysis with acceptance criteria to establish a safety margin equivalent to that provided by a pressure test. PHMSA established the technical requirements for analyzing the predicted failure pressure as a part of the ECA analysis in a new § 192.712, and those requirements are crossreferenced within this ECA process. Although PHMSA expects that most operators will use an ECA in conjunction with in-line inspection, PHMSA would also allow operators with past, valid pressure tests to calculate the largest defects that could have survived the pressure test and analyze the postulated defects to calculate a predicted failure pressure with which to establish MAOP. This approach might be desirable for operators in certain circumstances, such as for line segments that have valid pressure test records, but that lack other records (such as material strength or pipe wall thickness) necessary to determine design pressure and establish MAOP under the existing § 192.619(a). Another situation for which operators could use this approach would be if the operator has a valid pressure test, but it was not conducted at a test pressure that E:\FR\FM\01OCR2.SGM 01OCR2 52236 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations jbell on DSK3GLQ082PROD with RULES2 was high enough to establish the current MAOP. Operators with pressure test records meeting the subpart J test requirements may use an ECA by calculating the largest defect that could have survived the pressure test and estimating the flaw growth between the date of the test and the date of the ECA. The ECA is then performed using these postulated defect sizes. In addition, operators must calculate the remaining life of the most severe defects that could have survived the pressure test and establish an appropriate re-assessment interval in accordance with new § 192.712. If an operator chooses to use ILI to characterize the defects remaining in the pipe segment and the ECA method for MAOP reconfirmation but does not have one or more of the material properties necessary to perform an ECA analysis (diameter, wall thickness, seam type, grade, and Charpy V-notch toughness values, if applicable), the operator must use conservative assumptions and include the pipeline segment in its program to verify the undocumented information in accordance with the material properties verification requirements at § 192.607. § 192.710 Transmission Lines: Assessments Outside of High Consequence Areas Section 5 of the 2011 Pipeline Safety Act requires, if appropriate, the Secretary of Transportation to issue regulations expanding IM system requirements, or elements thereof, beyond HCAs. Currently, part 192 does not contain any requirement for operators to conduct integrity assessments of onshore transmission pipelines that are not HCA segments, as defined in § 192.903, and are therefore not subject to subpart O. However, only approximately 7 percent of onshore gas transmission pipelines are located in HCAs. Through this final rule, operators are required to periodically assess Class 3 locations, Class 4 locations, and MCAs that can accommodate inspection by means of an instrumented inline inspection tool. The periodic assessment requirements under this section apply to pipelines in these locations with MAOPs greater than or equal to 30 percent of SMYS. Industry has, as a practical matter, assessed portions of pipelines in nonHCA segments coincident with integrity assessments of HCA pipeline segments. For example, INGAA has noted in comment submissions that approximately 90 percent of Class 3 and Class 4 mileage not in HCAs are presently assessed during IM assessments. This is because, in large VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 part, ILI or pressure testing, by their nature, assess large continuous pipeline segments that may contain some HCA segments but that could also contain significant amounts of non-HCA segments. While INGAA does not represent all pipeline operators subject to part 192, it does represent the majority of gas transmission operators. PHMSA has determined that, given this level of assessment, it is appropriate and consistent with industry direction to codify requirements for operators to periodically assess certain gas transmission pipelines outside of HCAs to monitor for, detect, and remediate pipeline defects and anomalies. Additionally, to achieve the desired outcome of performing assessments in areas where people live, work, or congregate, while minimizing the cost of identifying such locations, PHMSA is basing the requirements for identifying those locations on processes already being implemented by pipeline operators. More specifically, the MCA definition assumes a similar process used for identifying HCAs, with the exception that the threshold for buildings intended for human occupancy located within the potential impact circle is reduced from 20 to 5. Because significant non-HCA pipeline mileage has been previously assessed in conjunction with the regular assessment of HCA pipeline segments, PHMSA is allowing operators to count those prior assessments as compliant with the new § 192.710 for the purposes of assessing non-HCAs if those assessments were conducted, and threats remediated, in conjunction with an integrity assessment required by subpart O. This final rule also requires that the assessment required by the new § 192.710 be conducted using the same methods as adopted for HCAs (see § 192.921, below). Operators may use ‘‘other technology’’ as an assessment method, provided the operator notifies PHMSA in accordance with § 192.18. § 192.712 Analysis of Predicted Failure Pressure The new requirements for reconfirming MAOP in the new § 192.624 include an option for operators to perform an engineering critical assessment, or ECA, to reconfirm MAOP in lieu of pressure testing and the other methods provided. A key aspect of the ECA analysis is the detailed analysis of the remaining strength of pipe with known or assumed defects. The current Federal Pipeline Safety Regulations in subparts I and O refer to methods for predicting the failure pressure for pipe with corrosion PO 00000 Frm 00058 Fmt 4701 Sfmt 4700 metal loss defects. However, the regulations are silent on performing such analysis for pipe with cracks (including crack-like defects such as selective seam weld corrosion). Therefore, in this final rule, PHMSA is inserting a new section to address the techniques and procedures for analyzing the predicted failure pressures for pipe with corrosion metal loss and cracks or crack-like defects. Examples of technically proven models for calculating predicted failure pressures include: For the brittle failure mode, the Newman-Raju Model 87 and PipeAssess PITM software; 88 and for the ductile failure mode, Modified Log-Secant Model,89 API RP 579–1 90—Level II or Level III, CorLasTM software,91 PAFFC Model,92 and PipeAssess PITM software. All failure models used for the ECA analysis must be used within its technical parameters for the defect type and the pipe or weld material properties. Conforming changes are being made to applicable sections in subparts I and O to refer to this new section, for consistency, but the basic techniques are unchanged. As a part of this section, PHMSA is including a new paragraph to address cracks and crack-like defects, which as stated above is a critical function of the ECA analysis. The ECA analysis requires the conservative analysis of any in-service cracks, crack-like defects remaining in the pipe, or the largest possible crack that could remain in the pipe, including crack dimensions (length and depth) to determine the predicted failure pressure (PFP) of each defect; the failure mode (ductile, brittle, or both) for the microstructure; the defect’s location and type; the pipeline’s operating conditions (including pressure cycling); and failure stress and 87 Newman, J.C., and Raju; ‘‘Stress Intensity Factors for Cracks in Three Dimensional Finite Bodies Subjected to Tension and Bending Loads;’’ Computational Methods in the Mechanics of Fracture; Elsevier; 1986; pp. 311–334. 88 Interim Report for Phase II—Task 5 of the Comprehensive Study to Understand Longitudinal ERW Seam Failures, ‘‘Summary Report for an Integrity Management Software Tool,’’ May 2017. https://primis.phmsa.dot.gov/matrix/FilGet.rdm? fil=11469. 89 ASTM International, ASTM STP 536, ‘‘Failure Stress Levels of Flaws in Pressurized Cylinders,’’ 1973. 90 American Petroleum Institute and American Society of Mechanical Engineers, API 579–1/ASME FFS–1, ‘‘Fitness-For-Service,’’ Second Edition, June 2007. 91 NACE International, NACE Corrosion 96 Paper 255, ‘‘Effect of Stress Corrosion Cracking on Integrity and Remaining Life of Natural Gas Pipelines,’’ March 1996. 92 Pipeline Research Council International, Inc., Topical Report NG–18 No. 193, ‘‘Development and Validation of a Ductile Flaw Growth Analysis for Gas Transmission Line Pipe,’’ June 1991. E:\FR\FM\01OCR2.SGM 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations crack growth analysis to determine the remaining life of the pipeline. An ECA must use the techniques and procedures developed and confirmed through the research findings provided by PHMSA and other reputable technical sources for longitudinal seam and crack growth, such as the Comprehensive Study to Understand Longitudinal ERW Seam Research & Development study task reports: Battelle Final Reports (‘‘Battelle’s Experience with ERW and Flash Weld Seam Failures: Causes and Implications’’—Task 1.4), Report No. 13–002 (‘‘Models for Predicting Failure Stress Levels for Defects Affecting ERW and Flash-Welded Seams’’—Subtask 2.4), Report No. 13–021 (‘‘Predicting Times to Failure for ERW Seam Defects that Grow by Pressure-Cycle-Induced Fatigue’’—Subtask 2.5), and ‘‘Final Summary Report and Recommendations for the Comprehensive Study to Understand Longitudinal ERW Seam Failures—Phase 1’’—Task 4.5), which can be found online at: https:// primis.phmsa.dot.gov/matrix/ PrjHome.rdm?prj=390. Operators wanting to use assumed Charpy V-notch toughness values differing from the prescribed values as a part of fracture mechanics analysis must notify PHMSA in accordance with § 192.18. jbell on DSK3GLQ082PROD with RULES2 § 192.750 Launcher and Receiver Safety PHMSA has determined that more explicit requirements are needed for safety when performing maintenance activities that use launchers and receivers to insert and remove maintenance tools and devices, as such facilities are subject to pipeline system pressures. The current regulations for hazardous liquid pipelines at 49 CFR part 195 have, since 1981, contained such safety requirements for scraper and sphere facilities (§ 195.426). However, the regulations for natural gas pipelines do not similarly require controls or instrumentation to protect against inadvertent breaches of system integrity due to the incorrect operation of launchers and receivers for ILI tools, scraper, and sphere facilities. Accordingly, this final rule is adding a new § 192.750 to require a suitable means to relieve pressure in the barrel and either a means to indicate the pressure in the barrel or a means to prevent opening if pressure has not been relieved. § 192.805 Qualification Program PHMSA is revising the Federal Pipeline Safety Regulations to include a new § 192.18 that provides instructions for submitting notifications to PHMSA whenever required by part 192. PHMSA VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 is making conforming changes to § 192.805 to refer to the new § 192.18. § 192.909 How can an operator change its integrity management program? PHMSA is revising the Federal Pipeline Safety Regulations to include a new § 192.18 that provides instructions for submitting notifications to PHMSA whenever required by part 192. PHMSA is making conforming changes to § 192.909 to refer to the new § 192.18. § 192.917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program? Section 29 of the 2011 Pipeline Safety Act requires operators to consider seismicity when evaluating threats. Accordingly, PHMSA is revising § 192.917(a)(3) to include seismicity of the area in evaluating the threat of outside force damage. To address NTSB recommendation P–11–15, PHMSA is also revising the criteria in § 192.917(e)(3) for addressing the threat of manufacturing and construction defects by requiring that a pipeline segment must have been pressure tested to a minimum of 1.25 times MAOP to conclude latent defects are stable. Section 192.917(e)(4) has additional requirements for the assessment of lowfrequency ERW pipe with seam failures. It now requires usage of the appropriate technology to assess low-frequency ERW pipe, including seam cracking and selective seam weld corrosion. Pipe with seam cracks must be evaluated using fracture mechanics modeling for failure stress pressures and cyclic fatigue crack growth analysis to estimate the remaining life of the pipe in accordance with § 192.712. Lastly, the integrity management requirements to address specific threats in § 192.917(e) include requirements for the major causes of pipeline incidents, such as corrosion, third-party damage, cyclic fatigue, manufacturing and construction defects, and electric resistance welded pipe. However, § 192.917(e) does not address cracks and crack-like defects. Therefore, PHMSA is adding a new paragraph, § 192.917(e)(6), to include specific IM requirements for addressing the threat of cracks and crack-like defects (including, but not limited to, stress corrosion cracking or other environmentally assisted cracking, seam defects, selective seam weld corrosion, girth weld cracks, hook cracks, and fatigue cracks) comparable to the other types of threats addressed in § 192.917(e). PO 00000 Frm 00059 Fmt 4701 Sfmt 4700 52237 § 192.921 How is the baseline assessment to be conducted? Section 192.921 requires that pipelines subject to the IM regulations have an integrity assessment. The current regulations allow operators to use ILI tools; pressure testing in accordance with subpart J; direct assessment for the threats of external corrosion, internal corrosion, and stress corrosion cracking; and other technology that the operator demonstrates provides an equivalent level of understanding of the condition of the pipeline. Following the PG&E incident, PHMSA determined that the baseline assessment methods should be clarified and strengthened to emphasize ILI use and pressure testing over direct assessment. At San Bruno, PG&E relied heavily on direct assessment under circumstances for which direct assessment was not effective nor appropriate for the pipeline seam type and the threats to the pipeline. Therefore, this final rule requires that direct assessment only be allowed to assess the threats for which the specific direct assessment process is appropriate. This final rule also adds three additional assessment methods for operators to use: (1) A ‘‘spike’’ hydrostatic pressure test, which is particularly well-suited to address timedependent threats, such as stress corrosion cracking and other cracking or crack-like defects that can include manufacturing- and construction-related defects; (2) guided wave ultrasonic testing (GWUT), which is particularly appropriate in cases where short pipeline segments, such as road or railroad crossings, are difficult to assess; and (3) excavation with direct in situ examination. Based upon the threat assessed, examples of appropriate nondestructive examination methods for in situ examination can include ultrasonic testing, phased array ultrasonic testing, inverse wave field extrapolation, radiography, or magnetic particle inspection. The current regulations indicate that ILI tools are an acceptable assessment method for the threats that the particular ILI tool type can assess. PHMSA is clarifying in this final rule that the use of ILI tools is appropriate for threats such as corrosion, deformation and mechanical damage (including dents, gouges, and grooves), material cracking and crack-like defects (e.g., stress corrosion cracking, selective seam weld corrosion, environmentally assisted cracking, and girth weld cracks), and hard spots with cracking. As discussed above, this final rule E:\FR\FM\01OCR2.SGM 01OCR2 52238 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations strengthens guidance in this area by adding a new § 192.493 to require compliance with the requirements and recommendations of API STD 1163– 2005, NACE SP0102–2010, and ANSI/ ASNT ILI–PQ–2005 when conducting in-line inspection of pipelines. Accordingly, PHMSA revises § 192.921(a)(1) in this final rule to require compliance with § 192.493 instead of ASME B31.8S for baseline ILI assessments for covered segments. GWUT has been used by pipeline operators for several years. Previously, operators were required by § 192.921(a)(4) to submit a notification to PHMSA as an ‘‘other technology’’ assessment method to use GWUT. In 2007, PHMSA developed guidelines for how it would evaluate notifications for the use of GWUT. These guidelines have been effectively used for over 9 years, and PHMSA has confidence that operators can use GWUT to assess the integrity of short segments of pipe against corrosion threats. In this final rule, PHMSA is incorporating these guidelines into a new Appendix F, which is referenced in § 192.921. Therefore, operators would no longer be required to notify PHMSA to use GWUT. ASME B31.8S, section 6.1, describes both excavation and direct in situ examination as specialized integrity assessment methods applicable to particular circumstances: jbell on DSK3GLQ082PROD with RULES2 It is important to note that some of the integrity assessment methods discussed in para. 6 only provide indications of defects. Examination using visual inspection and a variety of nondestructive examination (NDE) techniques are required, followed by evaluation of these inspection results in order to characterize the defect. The operator may choose to go directly to examination and evaluation for the entire length of the pipeline segment being assessed, in lieu of conducting inspections. For example, the operator may wish to conduct visual examination of aboveground piping for the external corrosion threat. Since the pipe is accessible for this technique and external corrosion can be readily evaluated, performing in-line inspection is not necessary. PHMSA is clarifying its requirements to explicitly add excavation and direct in situ examination as an acceptable assessment method. As previously discussed under § 192.710, PHMSA intends for operators to assess non-HCA pipe with the same methods as HCA pipe. Therefore, PHMSA has standardized the assessment methods between both the IM and non-IM sections. Operators wishing to use ‘‘other technology’’ differing from the prescribed acceptable assessment VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 methods must notify PHMSA in accordance with § 192.18. § 192.933 What actions must be taken to address integrity issues? PHMSA is revising the Federal Pipeline Safety Regulations to include a new § 192.18 that provides instructions for submitting notifications to PHMSA whenever required by part 192. PHMSA is making conforming changes to § 192.933 to refer to the new § 192.18. § 192.935 What additional preventive and mitigative measures must an operator take? Section 29 of the 2011 Pipeline Safety Act requires operators to consider seismicity when evaluating threats. Accordingly, PHMSA is revising § 192.935(b)(2) to include seismicity of the area when evaluating preventive and mitigative measures with respect to the threat of outside force damage. § 192.937 What is a continual process of evaluation and assessment to maintain a pipeline’s integrity? Section 192.937 requires that operators continue to periodically assess HCA pipeline segments and periodically evaluate the integrity of each covered pipeline segment. PHMSA determined that conforming amendments would be needed to implement, and be consistent with, the changes discussed above for § 192.921. Accordingly, this final rule requires that reassessments use the same assessment methods specified in § 192.921. Operators wishing to use ‘‘other technology’’ differing from the prescribed acceptable assessment methods must notify PHMSA in accordance with § 192.18. § 192.939 What are the required reassessment intervals? Section 192.939 specifies reassessment intervals for pipelines subject to IM requirements. Section 5 of the 2011 Pipeline Safety Act includes a technical correction that clarified that periodic reassessments must occur at a minimum of once every 7 calendar years, but that the Secretary may extend such deadline for an additional 6 months if the operator submits written notice to the Secretary with sufficient justification of the need for the extension. PHMSA expects that any justification, at a minimum, must demonstrate that the extension does not pose a safety risk. In this final rule, PHMSA is codifying this technical correction. As explained in PHMSA IM FAQ–41, the maximum interval for reassessment may be set using the specified number of calendar years. The use of calendar PO 00000 Frm 00060 Fmt 4701 Sfmt 4700 years is specific to gas pipeline reassessment interval years and does not alter the actual year interval requirements which appear elsewhere in the code for various inspection and maintenance requirements. Additionally, PHMSA is revising § 192.939 to include a new § 192.18 that provides instructions for submitting notifications to PHMSA whenever required by part 192. PHMSA is making conforming changes to § 192.939 to refer to the new § 192.18. § 192.949 How does an operator notify PHMSA? (Removed and Reserved) This rulemaking includes several requirements that allow operators to notify PHMSA of proposed alternative approaches to achieving the objective of the minimum safety standards. This is comparable to existing notification requirements in subpart O for pipelines subject to the IM regulations. Because PHMSA is expanding the use of notifications to pipeline segments for which subpart O does not apply (i.e., to non-HCA pipeline segments), PHMSA is adding a new § 192.18 that contains the procedure for submitting such notifications. As such, § 192.949 is no longer needed and is being removed and reserved. Appendix F to Part 192—Criteria for Conducting Integrity Assessments Using Guided Wave Ultrasonic Testing (GWUT) As discussed under § 192.921 above, a new Appendix F to part 192 is needed to provide specific requirements and acceptance criteria for the use of GWUT as an integrity assessment method. Operators must apply all 18 criteria defined in Appendix F to use GWUT as an integrity assessment method. If an operator applies GWUT technology in a manner that does not conform with the guidelines in Appendix F, it would be considered ‘‘other technology’’ for the purposes of §§ 192.710, 192.921, and 192.937. VI. Standards Incorporated by Reference A. Summary of New and Revised Standards Consistent with the amendments in this document, PHMSA is incorporating by reference several standards as described below. Some of these standards are already incorporated by reference into the Federal Pipeline Safety Regulations and are being extended to other sections of the regulations. Other standards provide a technical basis for corresponding regulatory changes in this final rule. E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations • API STD 1163, ‘‘In-Line Inspection Systems Qualification,’’ Second edition, April 2013, Reaffirmed August 2018. This standard covers the use of ILI systems for onshore and offshore gas and hazardous liquid pipelines. This includes, but is not limited to, tethered, self-propelled, or free-flowing systems for detecting metal loss, cracks, mechanical damage, pipeline geometries, and pipeline location or mapping. The standard applies to both existing and developing technologies. This standard is an umbrella document that provides performance-based requirements for ILI systems, including procedures, personnel, equipment, and associated software. The incorporation of this standard into the Federal Pipeline Safety Regulations will provide rigorous processes for qualifying the equipment, people, processes, and software used in in-line inspections. • ANSI/ASNT ILI–PQ–2005(2010), ‘‘In-line Inspection Personnel Qualification and Certification,’’ Reapproved October 11, 2010. This standard establishes minimum requirements for the qualification and certification of in-line inspection personnel whose jobs demand specific knowledge of the technical principles of in-line inspection technologies, operations, regulatory requirements, and industry standards as those are applicable to pipeline systems. The employer-based standard includes qualification and certification for Levels I, II, and III. The incorporation of this standard into the Federal Pipeline Safety Regulations provides for certification and qualification requirements that are not otherwise addressed in part 192 and will promote a higher level of safety by establishing consistent standards to qualify the equipment, people, processes, and software used in in-line inspections. • NACE Standard Practice 0102– 2010, ‘‘In-Line Inspection of Pipelines,’’ Revised 2010–03–13. This standard outlines a process of related activities that a pipeline operator can use to plan, organize, and execute an ILI project, and it includes guidelines pertaining to ILI data management and data analysis. This standard is intended for individuals and teams, including engineers, O&M personnel, technicians, specialists, construction personnel, and inspectors, involved in planning, implementing, and managing ILI projects and programs. The incorporation of this standard into the Federal Pipeline Safety Regulations would promote a higher level of safety by establishing consistent standards to qualify the equipment, people, VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 processes, and software used in in-line inspections. PHMSA is also extending the applicability of the following three currently incorporated-by-reference standards to new sections of the Federal Pipeline Safety Regulations: • ASME/ANSI B16.5–2003, ‘‘Pipe Flanges and Flanged Fittings,’’ October 2004, IBR approved for § 192.607(f). This standard covers pressuretemperature ratings, materials, dimensions, tolerances, marking, testing, and methods of designating openings for pipe flanges and flanged fittings. The standard includes requirements and recommendations regarding flange bolting, flange gaskets, and flange joints. This standard is intended for manufacturers, owners, employers, users, and others concerned with the specification, buying, maintenance, training, and safe use of valves with pressure equipment. The incorporation of this standard promotes industry best practices and operational, cost, and safety benefits. • ASME/ANSI B31G–1991 (Reaffirmed 2004), ‘‘Manual for Determining the Remaining Strength of Corroded Pipelines,’’ 2004, IBR approved for §§ 192.632(a) and 192.712(b). This document provides guidance for the evaluation of metal loss in pressurized pipelines and piping systems. It is applicable to all pipelines and piping systems that are part of the scope of the transportation pipeline codes that are part of ASME B31 Code for Pressure Piping, namely: ASME B31.4, Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids; ASME B31.8, Gas Transmission and Distribution Piping Systems; ASME B31.11, Slurry Transportation Piping Systems; and ASME B31.12, Hydrogen Piping and Pipelines, Part PL. • AGA, Pipeline Research Committee Project, PR–3–805, ‘‘A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe,’’ (December 22, 1989), IBR approved for §§ 192.632(a) and 192.712(b). This document was developed from the Modified B31G method to allow assessment of a river bottom profile of a corroded area on a pipeline to provide more accurate predictions of the pipeline’s remaining strength, and it was adapted into a software program known as RSTRENG. Pipeline operators can use RSTRENG to calculate a pipeline’s predicted failure pressure and safe pressure when determining operating pressures and anomaly response times. The incorporation by reference of ASME/ANSI B31.8S was approved for PO 00000 Frm 00061 Fmt 4701 Sfmt 4700 52239 §§ 192.921 and 192.937 as of January 14, 2004. That approval is unaffected by the section revisions in this final rule. B. Availability of Standards Incorporated by Reference PHMSA currently incorporates by reference into 49 CFR parts 192, 193, and 195 all or parts of more than 60 standards and specifications developed and published by standard developing organizations (SDO). In general, SDOs update and revise their published standards every 2 to 5 years to reflect modern technology and best technical practices. ASTM often updates some of its more widely used standards every year, and sometimes multiple editions of standards are published in a given year. In accordance with the National Technology Transfer and Advancement Act of 1995 (Pub. L. 104–113), PHMSA has the responsibility for determining which currently referenced standards should be updated, revised, or removed, and which standards should be added to 49 CFR parts 192, 193, and 195. Revisions to incorporated by reference materials in parts 192, 193, and 195 are handled via the rulemaking process, which allows for the public and regulated entities to provide input. During the rulemaking process, PHMSA must also obtain approval from the Office of the Federal Register to incorporate by reference any new materials. On January 3, 2012, President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, Public Law 112–90. Section 24 of that law states: ‘‘Beginning 1 year after the date of enactment of this subsection, the Secretary may not issue guidance or a regulation pursuant to this chapter that incorporates by reference any documents or portions thereof unless the documents or portions thereof are made available to the public, free of charge, on an internet website.’’ 49 U.S.C. 60102(p). On August 9, 2013, Public Law 113– 30 revised 49 U.S.C. 60102(p) to replace ‘‘1 year’’ with ‘‘3 years’’ and remove the phrases ‘‘guidance or’’ and, ‘‘on an internet website.’’ This resulted in the current language in 49 U.S.C. 60102(p), which now reads as follows: Beginning 3 years after the date of enactment of this subsection, the Secretary may not issue a regulation pursuant to this chapter that incorporates by reference any documents or portions thereof unless the documents or portions thereof are made available to the public, free of charge. E:\FR\FM\01OCR2.SGM 01OCR2 52240 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations On November 7, 2014, the Office of the Federal Register issued a final rule that revised 1 CFR 51.5 to require that Federal agencies include a discussion in the preamble of the final rule ‘‘the ways the materials it incorporates by reference are reasonably available to interested parties and how interested parties can obtain the materials.’’ 79 FR 66278. In relation to this rulemaking, PHMSA has contacted each SDO and has requested free public access of each standard that has been incorporated by reference. The SDOs agreed to make viewable copies of the incorporated standards available to the public at no cost. Pipeline operators interested in purchasing these standards can contact the individual and applicable standards organizations. The contact information is provided in this rulemaking action, see § 192.7. In addition, PHMSA will provide individual members of the public temporary access to any standard that is incorporated by reference that is not otherwise available for free. Requests for access can be sent to the following email address: PHMSAPHPStandards@ dot.gov. VII. Regulatory Analysis and Notices A. Statutory/Legal Authority for This Rulemaking This final rule is published under the authority of the Federal Pipeline Safety Statutes (49 U.S.C. 60101 et seq.). Section 60102 authorizes the Secretary of Transportation to issue regulations governing design, installation, inspection, emergency plans and procedures, testing, construction, extension, operation, replacement, and maintenance of pipeline facilities, as delegated to the PHMSA Administrator under 49 CFR 1.97. PHMSA is revising the ‘‘Authority’’ entry for parts 191 and 192 to include a citation to a provision of the Mineral Leasing Act (MLA), specifically, 30 U.S.C. 185(w)(3). Section 185(w)(3) provides that ‘‘[p]eriodically, but at least once a year, the Secretary of the Department of Transportation shall cause the examination of all pipelines and associated facilities on Federal lands and shall cause the prompt reporting of any potential leaks or safety problems.’’ The Secretary has delegated this responsibility to PHMSA (49 CFR 1.97). PHMSA has traditionally complied with § 185(w)(3) through the issuance of its pipeline safety regulations, which require annual examinations and prompt reporting for all or most of the pipelines they cover. PHMSA is making this change to be consistent with and make clear its longstanding position that the agency complies with the MLA through the issuance of pipeline safety regulations. B. Executive Orders 12866 and 13771, and DOT Regulatory Policies and Procedures Executive Order 12866 requires agencies to regulate in the ‘‘most costeffective manner,’’ to make a ‘‘reasoned determination that the benefits of the intended regulation justify its costs,’’ and to develop regulations that ‘‘impose the least burden on society.’’ This action has been determined to be significant under Executive Order 12866. It is also considered significant under the Regulatory Policies and Procedures of the Department of Transportation because of substantial congressional, State, industry, and public interest in pipeline safety. The final rule has been reviewed by the Office of Management and Budget in accordance with Executive Order 12866 (Regulatory Planning and Review) and is consistent with the Executive Order 12866 requirements and 49 U.S.C. 60102(b)(5)– (6). Pursuant to the Congressional Review Act (5 U.S.C. 801 et seq., the Office of Information and Regulatory Affairs designated this rule as not a ‘‘major rule,’’ as defined by 5 U.S.C. 804(2). This final rule is considered an Executive Order 13771 regulatory action. Details on the estimated costs of this final rule can be found in the rule’s RIA. The table below summarizes the annualized costs for the provisions in the final rule. These estimates reflect the timing of the compliance actions taken by operators and are annualized, where applicable, over 21 years and discounted to 2017 using rates of 3 percent and 7 percent. PHMSA estimates incremental costs for the final requirements in Section 5 of the RIA. PHMSA finds that the other final rule requirements will not result in an incremental cost. Additionally, PHMSA did not quantify the cost savings from the material properties verification provisions under this final rule compared to the existing regulations. The costs of this final rule reflect incremental integrity assessments, MAOP reconfirmation actions, and ILI launcher and receiver upgrades; PHMSA estimates the annualized cost of this rule is $32.7 million at a 7 percent discount rate. SUMMARY OF ANNUALIZED COSTS, 2019–2039 [$2017 thousands] Annualized cost Provision jbell on DSK3GLQ082PROD with RULES2 1. 2. 3. 4. 5. 6. 7. 8. 3% Discount rate 7% Discount rate MAOP Reconfirmation & Material Properties Verification ................................................................................... Seismicity ............................................................................................................................................................. Six-Month Grace Period for Seven Calendar-Year Reassessment Intervals ..................................................... In-Line Inspection Launcher/Receiver Safety ..................................................................................................... MAOP Exceedance Reports ............................................................................................................................... Strengthening Requirements for Assessment Methods ...................................................................................... Assessments Outside HCAs ............................................................................................................................... Related Records Provisions ................................................................................................................................ $25.9 0 0 0.03 0 0 5.48 0 $27.9 0 0 0.04 0 0 4.71 0 Total .................................................................................................................................................................. 31.4 32.7 The benefits of the final rule will depend on the degree to which compliance actions result in additional safety measures, relative to the current baseline, and the effectiveness of these VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 measures in preventing or mitigating future pipeline releases or other incidents. For the final rule RIA, PHMSA did not monetize benefits. The PO 00000 Frm 00062 Fmt 4701 Sfmt 4700 rule’s benefits are discussed qualitatively instead. For more information, please see the RIA in the docket for this rulemaking. E:\FR\FM\01OCR2.SGM 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations C. Regulatory Flexibility Act The Regulatory Flexibility Act (RFA), as amended by the Small Business Regulatory Flexibility Fairness Act of 1996, requires Federal regulatory agencies to prepare a Final Regulatory Flexibility Analysis (FRFA) for any final rule subject to notice-and-comment rulemaking under the Administrative Procedure Act unless the agency head certifies that the rule will not have a significant economic impact on a substantial number of small entities. PHMSA prepared a FRFA which is available in the docket for the rulemaking. D. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments PHMSA analyzed this final rule per the principles and criteria in Executive Order 13175, ‘‘Consultation and Coordination with Indian Tribal Governments.’’ Because this final rule would not significantly or uniquely affect the communities of the Indian tribal governments or impose substantial direct compliance costs, the funding and consultation requirements of Executive Order 13175 do not apply. jbell on DSK3GLQ082PROD with RULES2 E. Paperwork Reduction Act Pursuant to 5 CFR 1320.8(d), PHMSA is required to provide interested members of the public and affected agencies with an opportunity to comment on information collection and recordkeeping requests. On April 18, 2016, PHMSA published an NPRM seeking public comments on the revision of the Federal Pipeline Safety Regulations applicable to the safety of gas transmission pipelines and gas gathering pipelines. During that time, PHMSA proposed changes to information collections that are no longer included in this final rule. PHMSA determined it would be more effective to advance a rulemaking that focuses on the mandates from the 2011 Pipeline Safety Act and split out the other provisions contained in the NPRM into two other separate rules. As such, PHMSA has removed all references to those collections previously contained in the NPRM and will submit information collection revision requests to OMB based on the requirements solely contained within this final rule. PHMSA estimates that the proposals in this final rule will impact the information collections described below. These information collections are contained in the PSR, 49 CFR parts 190–199. The following information is provided for each information collection: (1) Title of the information VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 collection, (2) OMB control number, (3) Current expiration date, (4) Type of request, (5) Abstract of the information collection activity, (6) Description of affected public, (7) Estimate of total annual reporting and recordkeeping burden, and (8) Frequency of collection. The information collection burden for the following information collections are estimated to be revised as follows: 1. Title: Recordkeeping Requirements for Gas Pipeline Operators. OMB Control Number: 2137–0049. Current Expiration Date: 09/30/2021. Abstract: A person owning or operating a natural gas pipeline facility is required to maintain records, make reports, and provide information to the Secretary of Transportation at the Secretary’s request. Based on the proposed revisions in this rule, 25 new recordkeeping requirements are being added to the pipeline safety regulations for owners and operators of natural gas pipelines. Therefore, PHMSA expects to add 24,609 responses and 3,740 hours to this information collection because of the provisions in this final rule. Affected Public: Natural Gas Pipeline Operators. Annual Reporting and Recordkeeping Burden: Total Annual Responses: 3,861,470. Total Annual Burden Hours: 1,674,810. Frequency of Collection: On occasion. 2. Title: Notification Requirements for Gas Transmission Pipeline Operators. OMB Control Number: New Collection. Will Request from OMB. Current Expiration Date: TBD. Abstract: A person owning or operating a natural gas pipeline facility is required to provide information to the Secretary of Transportation at the Secretary’s request. Based on the proposed revisions in this rule, 10 new notification requirements are being added to the pipeline safety regulations for owners and operators of natural gas pipelines. Therefore, PHMSA expects to add 721 responses and 1,070 hours because of the notification requirements in this final rule. Affected Public: Gas Transmission operators. Annual Reporting and Recordkeeping Burden: Total Annual Responses: 721. Total Annual Burden Hours: 1,070. Frequency of Collection: On occasion. 3. Title: Annual Reports for Gas Pipeline Operators. OMB Control Number: 2137–0522. Current Expiration Date: 8/31/2020. Abstract: This information collection covers the collection of annual report data from natural gas pipeline operators. PO 00000 Frm 00063 Fmt 4701 Sfmt 4700 52241 PHMSA is revising the Gas Transmission and Gas Gathering Annual Report (form PHMSA F7 100.2–1) to collect additional information including mileage of pipe subject to the MAOP reconfirmation and MCA criteria. Based on the proposed revisions, PHMSA estimates that the Annual Report will take an additional 5 hours per report to complete to include the newly required data, increasing the burden for each report to 47 burden hours for an overall burden increase of 7,200 burden hours across all operators. Affected Public: Natural Gas Pipeline Operators. Annual Reporting and Recordkeeping Burden: Total Annual Responses: 10,852. Total Annual Burden Hours: 83,151. Frequency of Collection: On occasion. 4. Title: Incident for Natural Gas Pipeline Operators. OMB Control Number: 2137–0635. Current Expiration Date: 4/30/2022. Abstract: This information collection covers the collection of incident report data from natural gas pipeline operators. PHMSA is revising the Gas Transmission Incident Report to have operators indicate whether incidents occur inside Moderate Consequence Areas. PHMSA does not expect there to be an increase in burden for the reporting of Gas Transmission incident data. Affected Public: Natural Gas Pipeline Operators. Annual Reporting and Recordkeeping Burden: Total Annual Responses: 301. Total Annual Burden Hours: 3,612. Frequency of Collection: On occasion. Requests for copies of these information collections should be directed to Angela Hill or Cameron Satterthwaite, Office of Pipeline Safety (PHP–30), Pipeline Hazardous Materials Safety Administration (PHMSA), 2nd Floor, 1200 New Jersey Avenue SE, Washington, DC 20590–0001, Telephone (202) 366–4595. Comments are invited on: (a) The need for the proposed collection of information for the proper performance of the functions of the agency, including whether the information will have practical utility; (b) The accuracy of the agency’s estimate of the burden of the revised collection of information, including the validity of the methodology and assumptions used; (c) Ways to enhance the quality, utility, and clarity of the information to be collected; and (d) Ways to minimize the burden of the collection of information on those E:\FR\FM\01OCR2.SGM 01OCR2 52242 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques. Those desiring to comment on these information collections should send comments directly to the Office of Management and Budget, Office of Information and Regulatory Affairs, Attn: Desk Officer for the Department of Transportation, 725 17th Street NW, Washington, DC 20503. Comments should be submitted on or prior to October 31, 2019. Comments may also be sent via email to the Office of Management and Budget at the following address: oira_submissions@ omb.eop.gov. OMB is required to make a decision concerning the collection of information requirements contained in this final rule between 30 and 60 days after publication of this document in the Federal Register. Therefore, a comment to OMB is best assured of having its full effect if received within 30 days of publication. F. Unfunded Mandates Reform Act of 1995 An evaluation of Unfunded Mandates Reform Act (UMRA) considerations is performed as part of the Final Regulatory Impact Assessment. PHMSA determined that this final rule does not impose enforceable duties on State, local, or tribal governments or on the private sector of $100 million or more, adjusted for inflation, in any one year and therefore does not have implications under Section 202 of the UMRA of 1995. A copy of the RIA is available for review in the docket. jbell on DSK3GLQ082PROD with RULES2 G. National Environmental Policy Act PHMSA analyzed this final rule in accordance with the National Environmental Policy Act (42 U.S.C. 4332) and determined this action will not significantly affect the quality of the human environment. The Environmental Assessment for this final rule is in the docket. H. Executive Order 13132: Federalism PHMSA analyzed this final rule in accordance with Executive Order 13132 (‘‘Federalism’’). The final rule does not have a substantial direct effect on the States, the relationship between the national government and the States, or the distribution of power and responsibilities among the various levels of government. This rulemaking action does not impose substantial direct compliance costs on State and local governments. The pipeline safety laws, specifically 49 U.S.C. 60104(c), prohibits State safety regulation of interstate pipelines. Under the pipeline VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 safety law, States have the ability to augment pipeline safety requirements for intrastate pipelines regulated by PHMSA, but may not approve safety requirements less stringent than those required by Federal law. A State may also regulate an intrastate pipeline facility PHMSA does not regulate. It is these statutory provisions, not the rule, that govern preemption of State law. Therefore, the consultation and funding requirements of Executive Order 13132 do not apply. PART 191—TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE; ANNUAL, INCIDENT, AND OTHER REPORTING 1. The authority citation for part 191 is revised to read as follows: ■ Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5121, 60101 et. seq., and 49 CFR 1.97. 2. In § 191.23, paragraph (a)(6) is revised, paragraph (a)(10) is added, and paragraph (b)(4) is revised to read as follows: ■ I. Executive Order 13211 § 191.23 Reporting safety-related conditions. This final rule is not a ‘‘significant energy action’’ under Executive Order 13211 (Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use). It is not likely to have a significant adverse effect on supply, distribution, or energy use. Further, the Office of Information and Regulatory Affairs has not designated this final rule as a significant energy action. (a) * * * (6) Any malfunction or operating error that causes the pressure—plus the margin (build-up) allowed for operation of pressure limiting or control devices— to exceed either the maximum allowable operating pressure of a distribution or gathering line, the maximum well allowable operating pressure of an underground natural gas storage facility, or the maximum allowable working pressure of an LNG facility that contains or processes gas or LNG. * * * * * (10) For transmission pipelines only, each exceedance of the maximum allowable operating pressure that exceeds the margin (build-up) allowed for operation of pressure-limiting or control devices as specified in the applicable requirements of §§ 192.201, 192.620(e), and 192.739. The reporting requirement of this paragraph (a)(10) is not applicable to gathering lines, distribution lines, LNG facilities, or underground natural gas storage facilities (See paragraph (a)(6) of this section). (b) * * * (4) Is corrected by repair or replacement in accordance with applicable safety standards before the deadline for filing the safety-related condition report. Notwithstanding this exception, a report must be filed for: (i) Conditions under paragraph (a)(1) of this section, unless the condition is localized corrosion pitting on an effectively coated and cathodically protected pipeline; and (ii) Any condition under paragraph (a)(10) of this section. * * * * * ■ 3. Section 191.25 is revised to read as follows: J. Privacy Act Statement Anyone may search the electronic form of all comments received for any of our dockets. You may review DOT’s complete Privacy Act Statement, published on April 11, 2000 (65 FR 19476), in the Federal Register at: https://www.govinfo.gov/content/FR2000-04-11/pdf/00-8505.pdf. K. Regulation Identifier Number (RIN) A regulation identifier number (RIN) is assigned to each regulatory action listed in the Unified Agenda of Federal Regulations. The Regulatory Information Service Center publishes the Unified Agenda in April and October of each year. The RIN number contained in the heading of this document can be used to cross-reference this action with the Unified Agenda. List of Subjects 49 CFR Part 191 MAOP exceedance, Pipeline reporting requirements. 49 CFR Part 192 Incorporation by reference, Integrity assessments, Material properties verification, MAOP reconfirmation, Pipeline safety, Predicted failure pressure, Recordkeeping, Risk assessment, Safety devices. In consideration of the foregoing, PHMSA is amending 49 CFR parts 191 and 192 as follows: PO 00000 Frm 00064 Fmt 4701 Sfmt 4700 § 191.25 reports. Filing safety-related condition (a) Each report of a safety-related condition under § 191.23(a)(1) through (9) must be filed (received by the Associate Administrator) in writing E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations within 5 working days (not including Saturday, Sunday, or Federal holidays) after the day a representative of an operator first determines that the condition exists, but not later than 10 working days after the day a representative of an operator discovers the condition. Separate conditions may be described in a single report if they are closely related. Reporting methods and report requirements are described in paragraph (c) of this section. (b) Each report of a maximum allowable operating pressure exceedance meeting the requirements of criteria in § 191.23(a)(10) for a gas transmission pipeline must be filed (received by the Associate Administrator) in writing within 5 calendar days of the exceedance using the reporting methods and report requirements described in paragraph (c) of this section. (c) Reports must be filed by email to InformationResourcesManager@dot.gov or by facsimile to (202) 366–7128. For a report made pursuant to § 191.23(a)(1) through (9), the report must be headed ‘‘Safety-Related Condition Report.’’ For a report made pursuant to § 191.23(a)(10), the report must be headed ‘‘Maximum Allowable Operating Pressure Exceedances.’’ All reports must provide the following information: (1) Name, principal address, and operator identification number (OPID) of the operator. (2) Date of report. (3) Name, job title, and business telephone number of person submitting the report. (4) Name, job title, and business telephone number of person who determined that the condition exists. (5) Date condition was discovered and date condition was first determined to exist. (6) Location of condition, with reference to the State (and town, city, or county) or offshore site, and as appropriate, nearest street address, offshore platform, survey station number, milepost, landmark, or name of pipeline. (7) Description of the condition, including circumstances leading to its discovery, any significant effects of the condition on safety, and the name of the commodity transported or stored. (8) The corrective action taken (including reduction of pressure or shutdown) before the report is submitted and the planned follow-up or future corrective action, including the anticipated schedule for starting and concluding such action. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 PART 192—TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM FEDERAL SAFETY STANDARDS 4. The authority citation for part 192 is revised to read as follows: ■ Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et. seq., and 49 CFR 1.97. 5. In § 192.3, the definitions for ‘‘Engineering critical assessment (ECA)’’ and ‘‘Moderate consequence area’’ are added in alphabetical order to read as follows: ■ § 192.3 Definitions. * * * * * Engineering critical assessment (ECA) means a documented analytical procedure based on fracture mechanics principles, relevant material properties (mechanical and fracture resistance properties), operating history, operational environment, in-service degradation, possible failure mechanisms, initial and final defect sizes, and usage of future operating and maintenance procedures to determine the maximum tolerable sizes for imperfections based upon the pipeline segment maximum allowable operating pressure. * * * * * Moderate consequence area means: (1) An onshore area that is within a potential impact circle, as defined in § 192.903, containing either: (i) Five or more buildings intended for human occupancy; or (ii) Any portion of the paved surface, including shoulders, of a designated interstate, other freeway, or expressway, as well as any other principal arterial roadway with 4 or more lanes, as defined in the Federal Highway Administration’s Highway Functional Classification Concepts, Criteria and Procedures, Section 3.1 (see: https:// www.fhwa.dot.gov/planning/processes/ statewide/related/highway_functional_ classifications/fcauab.pdf), and that does not meet the definition of high consequence area, as defined in § 192.903. (2) The length of the moderate consequence area extends axially along the length of the pipeline from the outermost edge of the first potential impact circle containing either 5 or more buildings intended for human occupancy; or any portion of the paved surface, including shoulders, of any designated interstate, freeway, or expressway, as well as any other principal arterial roadway with 4 or more lanes, to the outermost edge of the last contiguous potential impact circle that contains either 5 or more buildings PO 00000 Frm 00065 Fmt 4701 Sfmt 4700 52243 intended for human occupancy, or any portion of the paved surface, including shoulders, of any designated interstate, freeway, or expressway, as well as any other principal arterial roadway with 4 or more lanes. * * * * * ■ 6. In § 192.5, paragraph (d) is added to read as follows: § 192.5 Class locations. * * * * * (d) An operator must have records that document the current class location of each pipeline segment and that demonstrate how the operator determined each current class location in accordance with this section. ■ 7. Amend § 192.7 as follows: ■ a. Revise paragraph (a)(1)(ii); ■ b. Add paragraph (b)(12); ■ c. Revise paragraphs (c)(2) and (4); ■ d. Re-designate paragraphs (d) through (j) as paragraphs (e) through (k), respectively; ■ e. Add new paragraphs (d) and (h)(2); and ■ f. Revise newly redesignated paragraph (j)(1). The revisions and additions read as follows: § 192.7 What documents are incorporated by reference partly or wholly in this part? (a) * * * (1) * * * (ii) The National Archives and Records Administration (NARA). For information on the availability of this material at NARA, email fedreg.legal@ nara.gov or go to www.archives.gov/ federal-register/cfr/ibr-locations.html. (b) * * * (12) API STANDARD 1163, ‘‘In-Line Inspection Systems Qualification,’’ Second edition, April 2013, Reaffirmed August 2018, (API STD 1163), IBR approved for § 192.493. (c) * * * (2) ASME/ANSI B16.5–2003, ‘‘Pipe Flanges and Flanged Fittings,’’ October 2004, (ASME/ANSI B16.5), IBR approved for §§ 192.147(a), 192.279, and 192.607(f). * * * * * (4) ASME/ANSI B31G–1991 (Reaffirmed 2004), ‘‘Manual for Determining the Remaining Strength of Corroded Pipelines,’’ 2004, (ASME/ ANSI B31G), IBR approved for §§ 192.485(c), 192.632(a), 192.712(b), and 192.933(a). * * * * * (d) American Society for Nondestructive Testing (ASNT), P.O. Box 28518, 1711 Arlingate Lane, Columbus, OH 43228, phone: 800–222– 2768, website: https://www.asnt.org/. E:\FR\FM\01OCR2.SGM 01OCR2 52244 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations (1) ANSI/ASNT ILI–PQ–2005(2010), ‘‘In-line Inspection Personnel Qualification and Certification,’’ Reapproved October 11, 2010, (ANSI/ ASNT ILI–PQ), IBR approved for § 192.493. (2) [Reserved] * * * * * (h) * * * (2) NACE Standard Practice 0102– 2010, ‘‘In-Line Inspection of Pipelines,’’ Revised 2010–03–13, (NACE SP0102), IBR approved for §§ 192.150(a) and 192.493. * * * * * (j) * * * (1) AGA, Pipeline Research Committee Project, PR–3–805, ‘‘A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe,’’ (December 22, 1989), (PRCI PR–3–805 (R–STRENG)), IBR approved for §§ 192.485(c); 192.632(a); 192.712(b); 192.933(a) and (d). * * * * * ■ 8. In § 192.9, paragraphs (b), (c), and (d)(1), (2), and (6) are revised to read as follows: § 192.9 What requirements apply to gathering lines? jbell on DSK3GLQ082PROD with RULES2 * * * * * (b) Offshore lines. An operator of an offshore gathering line must comply with requirements of this part applicable to transmission lines, except the requirements in §§ 192.150, 192.285(e), 192.493, 192.506, 192.607, 192.619(e), 192.624, 192.710, 192.712, and in subpart O of this part. (c) Type A lines. An operator of a Type A regulated onshore gathering line must comply with the requirements of this part applicable to transmission lines, except the requirements in §§ 192.150, 192.285(e), 192.493, 192.506, 192.607, 192.619(e), 192.624, 192.710, 192.712, and in subpart O of this part. However, operators of Type A regulated onshore gathering lines in a Class 2 location may demonstrate compliance with subpart N by describing the processes it uses to determine the qualification of persons performing operations and maintenance tasks. (d) * * * (1) If a line is new, replaced, relocated, or otherwise changed, the design, installation, construction, initial inspection, and initial testing must be in accordance with requirements of this part applicable to transmission lines except the requirements in §§ 192.67, 192.127, 192.205, 192.227(c), 192.285(e), and 192.506; (2) If the pipeline is metallic, control corrosion according to requirements of VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 subpart I of this part applicable to transmission lines except the requirements in § 192.493; * * * * * (6) Establish the MAOP of the line under § 192.619(a), (b), and (c); * * * * * ■ 9. Section 192.18 is added to read as follows: § 192.18 How to notify PHMSA. (a) An operator must provide any notification required by this part by— (1) Sending the notification by electronic mail to InformationResourcesManager@dot.gov; or (2) Sending the notification by mail to ATTN: Information Resources Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22–321, 1200 New Jersey Ave. SE, Washington, DC 20590. (b) An operator must also notify the appropriate State or local pipeline safety authority when an applicable pipeline segment is located in a State where OPS has an interstate agent agreement, or an intrastate applicable pipeline segment is regulated by that State. (c) Unless otherwise specified, if the notification is made pursuant to § 192.506(b), § 192.607(e)(4), § 192.607(e)(5), § 192.624(c)(2)(iii), § 192.624(c)(6), § 192.632(b)(3), § 192.710(c)(7), § 192.712(d)(3)(iv), § 192.712(e)(2)(i)(E), § 192.921(a)(7), or § 192.937(c)(7) to use a different integrity assessment method, analytical method, sampling approach, or technique (i.e., ‘‘other technology’’) that differs from that prescribed in those sections, the operator must notify PHMSA at least 90 days in advance of using the other technology. An operator may proceed to use the other technology 91 days after submittal of the notification unless it receives a letter from the Associate Administrator for Pipeline Safety informing the operator that PHMSA objects to the proposed use of other technology or that PHMSA requires additional time to conduct its review. § 192.67 [Redesignated as § 192.69] 10. Redesignate § 192.67 as § 192.69. 11. Section 192.67 is added to read as follows: ■ ■ § 192.67 Records: Material properties. (a) For steel transmission pipelines installed after [July 1, 2020, an operator must collect or make, and retain for the life of the pipeline, records that document the physical characteristics of the pipeline, including diameter, yield strength, ultimate tensile strength, wall thickness, seam type, and chemical PO 00000 Frm 00066 Fmt 4701 Sfmt 4700 composition of materials for pipe in accordance with §§ 192.53 and 192.55. Records must include tests, inspections, and attributes required by the manufacturing specifications applicable at the time the pipe was manufactured or installed. (b) For steel transmission pipelines installed on or before July 1, 2020], if operators have records that document tests, inspections, and attributes required by the manufacturing specifications applicable at the time the pipe was manufactured or installed, including diameter, yield strength, ultimate tensile strength, wall thickness, seam type, and chemical composition in accordance with §§ 192.53 and 192.55, operators must retain such records for the life of the pipeline. (c) For steel transmission pipeline segments installed on or before July 1, 2020], if an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of § 192.624 according to the terms of that section. ■ 12. Section 192.127 is added to read as follows: § 192.127 Records: Pipe design. (a) For steel transmission pipelines installed after July 1, 2020], an operator must collect or make, and retain for the life of the pipeline, records documenting that the pipe is designed to withstand anticipated external pressures and loads in accordance with § 192.103 and documenting that the determination of design pressure for the pipe is made in accordance with § 192.105. (b) For steel transmission pipelines installed on or before July 1, 2020, if operators have records documenting pipe design and the determination of design pressure in accordance with §§ 192.103 and 192.105, operators must retain such records for the life of the pipeline. (c) For steel transmission pipeline segments installed on or before July 1, 2020, if an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of § 192.624 according to the terms of that section. ■ 13. In § 192.150, paragraph (a) is revised to read as follows: § 192.150 devices. Passage of internal inspection (a) Except as provided in paragraphs (b) and (c) of this section, each new transmission line and each replacement of line pipe, valve, fitting, or other line component in a transmission line, must E:\FR\FM\01OCR2.SGM 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations be designed and constructed to accommodate the passage of instrumented internal inspection devices in accordance with NACE SP0102, section 7 (incorporated by reference, see § 192.7). * * * * * ■ 14. Section 192.205 is added to read as follows: § 192.205 (e) For transmission pipe installed after July 1, 2021, records demonstrating each person’s plastic pipe joining qualifications at the time of construction in accordance with this section must be retained for a minimum of 5 years following construction. 17. Section 192.493 is added to read as follows: ■ Records: Pipeline components. (a) For steel transmission pipelines installed after July 1, 2020, an operator must collect or make, and retain for the life of the pipeline, records documenting the manufacturing standard and pressure rating to which each valve was manufactured and tested in accordance with this subpart. Flanges, fittings, branch connections, extruded outlets, anchor forgings, and other components with material yield strength grades of 42,000 psi (X42) or greater and with nominal diameters of greater than 2 inches must have records documenting the manufacturing specification in effect at the time of manufacture, including yield strength, ultimate tensile strength, and chemical composition of materials. (b) For steel transmission pipelines installed on or before July 1, 2020, if operators have records documenting the manufacturing standard and pressure rating for valves, flanges, fittings, branch connections, extruded outlets, anchor forgings, and other components with material yield strength grades of 42,000 psi (X42) or greater and with nominal diameters of greater than 2 inches, operators must retain such records for the life of the pipeline. (c) For steel transmission pipeline segments installed on or before July 1, 2020, if an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of § 192.624 according to the terms of that section. ■ 15. In § 192.227, paragraph (c) is added to read as follows: § 192.227 Qualification of welders. jbell on DSK3GLQ082PROD with RULES2 * * * * * (c) For steel transmission pipe installed after July 1, 2021, records demonstrating each individual welder qualification at the time of construction in accordance with this section must be retained for a minimum of 5 years following construction. ■ 16. In § 192.285, paragraph (e) is added to read as follows: § 192.285 Plastic pipe: Qualifying persons to make joints. * * * VerDate Sep<11>2014 * * 18:29 Sep 30, 2019 Jkt 250001 § 192.493 In-line inspection of pipelines. When conducting in-line inspections of pipelines required by this part, an operator must comply with API STD 1163, ANSI/ASNT ILI–PQ, and NACE SP0102, (incorporated by reference, see § 192.7). Assessments may be conducted using tethered or remotely controlled tools, not explicitly discussed in NACE SP0102, provided they comply with those sections of NACE SP0102 that are applicable. 18. Section 192.506 is added to read as follows: ■ § 192.506 Transmission lines: Spike hydrostatic pressure test. (a) Spike test requirements. Whenever a segment of steel transmission pipeline that is operated at a hoop stress level of 30 percent or more of SMYS is spike tested under this part, the spike hydrostatic pressure test must be conducted in accordance with this section. (1) The test must use water as the test medium. (2) The baseline test pressure must be as specified in the applicable paragraphs of § 192.619(a)(2) or § 192.620(a)(2), whichever applies. (3) The test must be conducted by maintaining a pressure at or above the baseline test pressure for at least 8 hours as specified in § 192.505. (4) After the test pressure stabilizes at the baseline pressure and within the first 2 hours of the 8-hour test interval, the hydrostatic pressure must be raised (spiked) to a minimum of the lesser of 1.5 times MAOP or 100% SMYS. This spike hydrostatic pressure test must be held for at least 15 minutes after the spike test pressure stabilizes. (b) Other technology or other technical evaluation process. Operators may use other technology or another process supported by a documented engineering analysis for establishing a spike hydrostatic pressure test or equivalent. Operators must notify PHMSA 90 days in advance of the assessment or reassessment requirements of this subchapter. The notification must be made in accordance with § 192.18 and must include the following information: PO 00000 Frm 00067 Fmt 4701 Sfmt 4700 52245 (1) Descriptions of the technology or technologies to be used for all tests, examinations, and assessments; (2) Procedures and processes to conduct tests, examinations, assessments, perform evaluations, analyze defects, and remediate defects discovered; (3) Data requirements, including original design, maintenance and operating history, anomaly or flaw characterization; (4) Assessment techniques and acceptance criteria; (5) Remediation methods for assessment findings; (6) Spike hydrostatic pressure test monitoring and acceptance procedures, if used; (7) Procedures for remaining crack growth analysis and pipeline segment life analysis for the time interval for additional assessments, as required; and (8) Evidence of a review of all procedures and assessments by a qualified technical subject matter expert. ■ 19. In § 192.517, paragraph (a) introductory text is revised to read as follows: § 192.517 Records: Tests. (a) An operator must make, and retain for the useful life of the pipeline, a record of each test performed under §§ 192.505, 192.506, and 192.507. The record must contain at least the following information: * * * * * ■ 20. Section 192.607 is added to read as follows: § 192.607 Verification of Pipeline Material Properties and Attributes: Onshore steel transmission pipelines. (a) Applicability. Wherever required by this part, operators of onshore steel transmission pipelines must document and verify material properties and attributes in accordance with this section. (b) Documentation of material properties and attributes. Records established under this section documenting physical pipeline characteristics and attributes, including diameter, wall thickness, seam type, and grade (e.g., yield strength, ultimate tensile strength, or pressure rating for valves and flanges, etc.), must be maintained for the life of the pipeline and be traceable, verifiable, and complete. Charpy v-notch toughness values established under this section needed to meet the requirements of the ECA method at § 192.624(c)(3) or the fracture mechanics requirements at § 192.712 must be maintained for the life of the pipeline. E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 52246 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations (c) Verification of material properties and attributes. If an operator does not have traceable, verifiable, and complete records required by paragraph (b) of this section, the operator must develop and implement procedures for conducting nondestructive or destructive tests, examinations, and assessments in order to verify the material properties of aboveground line pipe and components, and of buried line pipe and components when excavations occur at the following opportunities: Anomaly direct examinations, in situ evaluations, repairs, remediations, maintenance, and excavations that are associated with replacements or relocations of pipeline segments that are removed from service. The procedures must also provide for the following: (1) For nondestructive tests, at each test location, material properties for minimum yield strength and ultimate tensile strength must be determined at a minimum of 5 places in at least 2 circumferential quadrants of the pipe for a minimum total of 10 test readings at each pipe cylinder location. (2) For destructive tests, at each test location, a set of material properties tests for minimum yield strength and ultimate tensile strength must be conducted on each test pipe cylinder removed from each location, in accordance with API Specification 5L. (3) Tests, examinations, and assessments must be appropriate for verifying the necessary material properties and attributes. (4) If toughness properties are not documented, the procedures must include accepted industry methods for verifying pipe material toughness. (5) Verification of material properties and attributes for non-line pipe components must comply with paragraph (f) of this section. (d) Special requirements for nondestructive Methods. Procedures developed in accordance with paragraph (c) of this section for verification of material properties and attributes using nondestructive methods must: (1) Use methods, tools, procedures, and techniques that have been validated by a subject matter expert based on comparison with destructive test results on material of comparable grade and vintage; (2) Conservatively account for measurement inaccuracy and uncertainty using reliable engineering tests and analyses; and (3) Use test equipment that has been properly calibrated for comparable test materials prior to usage. (e) Sampling multiple segments of pipe. To verify material properties and VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 attributes for a population of multiple, comparable segments of pipe without traceable, verifiable, and complete records, an operator may use a sampling program in accordance with the following requirements: (1) The operator must define separate populations of similar segments of pipe for each combination of the following material properties and attributes: Nominal wall thicknesses, grade, manufacturing process, pipe manufacturing dates, and construction dates. If the dates between the manufacture or construction of the pipeline segments exceeds 2 years, those segments cannot be considered as the same vintage for the purpose of defining a population under this section. The total population mileage is the cumulative mileage of pipeline segments in the population. The pipeline segments need not be continuous. (2) For each population defined according to paragraph (e)(1) of this section, the operator must determine material properties at all excavations that expose the pipe associated with anomaly direct examinations, in situ evaluations, repairs, remediations, or maintenance, except for pipeline segments exposed during excavation activities pursuant to § 192.614, until completion of the lesser of the following: (i) One excavation per mile rounded up to the nearest whole number; or (ii) 150 excavations if the population is more than 150 miles. (3) Prior tests conducted for a single excavation according to the requirements of paragraph (c) of this section may be counted as one sample under the sampling requirements of this paragraph (e). (4) If the test results identify line pipe with properties that are not consistent with available information or existing expectations or assumed properties used for operations and maintenance in the past, the operator must establish an expanded sampling program. The expanded sampling program must use valid statistical bases designed to achieve at least a 95% confidence level that material properties used in the operation and maintenance of the pipeline are valid. The approach must address how the sampling plan will be expanded to address findings that reveal material properties that are not consistent with all available information or existing expectations or assumed material properties used for pipeline operations and maintenance in the past. Operators must notify PHMSA in advance of using an expanded sampling approach in accordance with § 192.18. PO 00000 Frm 00068 Fmt 4701 Sfmt 4700 (5) An operator may use an alternative statistical sampling approach that differs from the requirements specified in paragraph (e)(2) of this section. The alternative sampling program must use valid statistical bases designed to achieve at least a 95% confidence level that material properties used in the operation and maintenance of the pipeline are valid. The approach must address how the sampling plan will be expanded to address findings that reveal material properties that are not consistent with all available information or existing expectations or assumed material properties used for pipeline operations and maintenance in the past. Operators must notify PHMSA in advance of using an alternative sampling approach in accordance with § 192.18. (f) Components. For mainline pipeline components other than line pipe, an operator must develop and implement procedures in accordance with paragraph (c) of this section for establishing and documenting the ANSI rating or pressure rating (in accordance with ASME/ANSI B16.5 (incorporated by reference, see § 192.7)), (1) Operators are not required to test for the chemical and mechanical properties of components in compressor stations, meter stations, regulator stations, separators, river crossing headers, mainline valve assemblies, valve operator piping, or crossconnections with isolation valves from the mainline pipeline. (2) Verification of material properties is required for non-line pipe components, including valves, flanges, fittings, fabricated assemblies, and other pressure retaining components and appurtenances that are: (i) Larger than 2 inches in nominal outside diameter, (ii) Material grades of 42,000 psi (Grade X–42) or greater, or (iii) Appurtenances of any size that are directly installed on the pipeline and cannot be isolated from mainline pipeline pressures. (3) Procedures for establishing material properties of non-line pipe components must be based on the documented manufacturing specification for the components. If specifications are not known, usage of manufacturer’s stamped, marked, or tagged material pressure ratings and material type may be used to establish pressure rating. Operators must document the method used to determine the pressure rating and the findings of that determination. (g) Uprating. The material properties determined from the destructive or nondestructive tests required by this E:\FR\FM\01OCR2.SGM 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations section cannot be used to raise the grade or specification of the material, unless the original grade or specification is unknown and MAOP is based on an assumed yield strength of 24,000 psi in accordance with § 192.107(b)(2). 21. In § 192.619, the introductory text of paragraphs (a) introductory text and (a)(2) and (4) are revised and paragraphs (e) and (f) are added to read as follows: ■ § 192.619 Maximum allowable operating pressure: Steel or plastic pipelines. (a) No person may operate a segment of steel or plastic pipeline at a pressure that exceeds a maximum allowable operating pressure (MAOP) determined under paragraph (c), (d), or (e) of this section, or the lowest of the following: * * * * * (2) The pressure obtained by dividing the pressure to which the pipeline 52247 segment was tested after construction as follows: (i) For plastic pipe in all locations, the test pressure is divided by a factor of 1.5. (ii) For steel pipe operated at 100 psi (689 kPa) gage or more, the test pressure is divided by a factor determined in accordance with the Table 1 to paragraph (a)(2)(ii): TABLE 1 TO PARAGRAPH (a)(2)(ii) Factors,1 segment— Installed before (Nov. 12, 1970) Class location 1 2 3 4 ............................................................................................... ............................................................................................... ............................................................................................... ............................................................................................... Installed after (Nov. 11, 1970) and before July 1, 2020 1.1 1.25 1.4 1.4 Installed on or after July 1, 2020 1.1 1.25 1.5 1.5 1.25 1.25 1.5 1.5 Converted under § 192.14 1.25 1.25 1.5 1.5 1 For offshore pipeline segments installed, uprated or converted after July 31, 1977, that are not located on an offshore platform, the factor is 1.25. For pipeline segments installed, uprated or converted after July 31, 1977, that are located on an offshore platform or on a platform in inland navigable waters, including a pipe riser, the factor is 1.5. jbell on DSK3GLQ082PROD with RULES2 * * * * * (4) The pressure determined by the operator to be the maximum safe pressure after considering and accounting for records of material properties, including material properties verified in accordance with § 192.607, if applicable, and the history of the pipeline segment, including known corrosion and actual operating pressure. * * * * * (e) Notwithstanding the requirements in paragraphs (a) through (d) of this section, operators of onshore steel transmission pipelines that meet the criteria specified in § 192.624(a) must establish and document the maximum allowable operating pressure in accordance with § 192.624. (f) Operators of onshore steel transmission pipelines must make and retain records necessary to establish and document the MAOP of each pipeline segment in accordance with paragraphs (a) through (e) of this section as follows: (1) Operators of pipelines in operation as of [July 1, 2020 must retain any existing records establishing MAOP for the life of the pipeline; (2) Operators of pipelines in operation as of July 1, 2020 that do not have records establishing MAOP and are required to reconfirm MAOP in accordance with § 192.624, must retain the records reconfirming MAOP for the life of the pipeline; and (3) Operators of pipelines placed in operation after July 1, 2020 must make and retain records establishing MAOP for the life of the pipeline. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 22. Section 192.624 is added to read as follows: ■ § 192.624 Maximum allowable operating pressure reconfirmation: Onshore steel transmission pipelines. (a) Applicability. Operators of onshore steel transmission pipeline segments must reconfirm the maximum allowable operating pressure (MAOP) of all pipeline segments in accordance with the requirements of this section if either of the following conditions are met: (1) Records necessary to establish the MAOP in accordance with § 192.619(a), including records required by § 192.517(a), are not traceable, verifiable, and complete and the pipeline is located in one of the following locations: (i) A high consequence area as defined in § 192.903; or (ii) A Class 3 or Class 4 location. (2) The pipeline segment’s MAOP was established in accordance with § 192.619(c), the pipeline segment’s MAOP is greater than or equal to 30 percent of the specified minimum yield strength, and the pipeline segment is located in one of the following areas: (i) A high consequence area as defined in § 192.903; (ii) A Class 3 or Class 4 location; or (iii) A moderate consequence area as defined in § 192.3, if the pipeline segment can accommodate inspection by means of instrumented inline inspection tools. (b) Procedures and completion dates. Operators of a pipeline subject to this PO 00000 Frm 00069 Fmt 4701 Sfmt 4700 section must develop and document procedures for completing all actions required by this section by July 1, 2021. These procedures must include a process for reconfirming MAOP for any pipelines that meet a condition of § 192.624(a), and for performing a spike test or material verification in accordance with §§ 192.506 and 192.607, if applicable. All actions required by this section must be completed according to the following schedule: (1) Operators must complete all actions required by this section on at least 50% of the pipeline mileage by July 3, 2028. (2) Operators must complete all actions required by this section on 100% of the pipeline mileage by July 2, 2035 or as soon as practicable, but not to exceed 4 years after the pipeline segment first meets a condition of § 192.624(a) (e.g., due to a location becoming a high consequence area), whichever is later. (3) If operational and environmental constraints limit an operator from meeting the deadlines in § 192.624, the operator may petition for an extension of the completion deadlines by up to 1 year, upon submittal of a notification in accordance with § 192.18. The notification must include an up-to-date plan for completing all actions in accordance with this section, the reason for the requested extension, current status, proposed completion date, outstanding remediation activities, and E:\FR\FM\01OCR2.SGM 01OCR2 52248 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations any needed temporary measures needed to mitigate the impact on safety. (c) Maximum allowable operating pressure determination. Operators of a pipeline segment meeting a condition in paragraph (a) of this section must reconfirm its MAOP using one of the following methods: (1) Method 1: Pressure test. Perform a pressure test and verify material properties records in accordance with § 192.607 and the following requirements: (i) Pressure test. Perform a pressure test in accordance with subpart J of this part. The MAOP must be equal to the test pressure divided by the greater of either 1.25 or the applicable class location factor in § 192.619(a)(2)(ii). (ii) Material properties records. Determine if the following material properties records are documented in traceable, verifiable, and complete records: Diameter, wall thickness, seam type, and grade (minimum yield strength, ultimate tensile strength). (iii) Material properties verification. If any of the records required by paragraph (c)(1)(ii) of this section are not documented in traceable, verifiable, and complete records, the operator must obtain the missing records in accordance with § 192.607. An operator must test the pipe materials cut out from the test manifold sites at the time the pressure test is conducted. If there is a failure during the pressure test, the operator must test any removed pipe from the pressure test failure in accordance with § 192.607. (2) Method 2: Pressure Reduction. Reduce pressure, as necessary, and limit MAOP to no greater than the highest actual operating pressure sustained by the pipeline during the 5 years preceding October 1, 2019, divided by the greater of 1.25 or the applicable class location factor in § 192.619(a)(2)(ii). The highest actual sustained pressure must have been reached for a minimum cumulative duration of 8 hours during a continuous 30-day period. The value used as the highest actual sustained operating pressure must account for differences between upstream and downstream pressure on the pipeline by use of either the lowest maximum pressure value for the entire pipeline segment or using the operating pressure gradient along the entire pipeline segment (i.e., the location-specific operating pressure at each location). (i) Where the pipeline segment has had a class location change in accordance with § 192.611, and records documenting diameter, wall thickness, seam type, grade (minimum yield strength and ultimate tensile strength), and pressure tests are not documented in traceable, verifiable, and complete records, the operator must reduce the pipeline segment MAOP as follows: (A) For pipeline segments where a class location changed from Class 1 to Class 2, from Class 2 to Class 3, or from Class 3 to Class 4, reduce the pipeline MAOP to no greater than the highest actual operating pressure sustained by the pipeline during the 5 years preceding October 1, 2019, divided by 1.39 for Class 1 to Class 2, 1.67 for Class 2 to Class 3, and 2.00 for Class 3 to Class 4. (B) For pipeline segments where a class location changed from Class 1 to Class 3, reduce the pipeline MAOP to no greater than the highest actual operating pressure sustained by the pipeline during the 5 years preceding October 1, 2019, divided by 2.00. (ii) Future uprating of the pipeline segment in accordance with subpart K is allowed if the MAOP is established using Method 2. (iii) If an operator elects to use Method 2, but desires to use a less conservative pressure reduction factor or longer look-back period, the operator must notify PHMSA in accordance with § 192.18 no later than 7 calendar days after establishing the reduced MAOP. The notification must include the following details: (A) Descriptions of the operational constraints, special circumstances, or other factors that preclude, or make it impractical, to use the pressure reduction factor specified in § 192.624(c)(2); (B) The fracture mechanics modeling for failure stress pressures and cyclic fatigue crack growth analysis that complies with § 192.712; (C) Justification that establishing MAOP by another method allowed by this section is impractical; (D) Justification that the reduced MAOP determined by the operator is safe based on analysis of the condition of the pipeline segment, including material properties records, material properties verified in accordance § 192.607, and the history of the pipeline segment, particularly known corrosion and leakage, and the actual operating pressure, and additional compensatory preventive and mitigative measures taken or planned; and (E) Planned duration for operating at the requested MAOP, long-term remediation measures and justification of this operating time interval, including fracture mechanics modeling for failure stress pressures and cyclic fatigue growth analysis and other validated forms of engineering analysis that have been reviewed and confirmed by subject matter experts. (3) Method 3: Engineering Critical Assessment (ECA). Conduct an ECA in accordance with § 192.632. (4) Method 4: Pipe Replacement. Replace the pipeline segment in accordance with this part. (5) Method 5: Pressure Reduction for Pipeline Segments with Small Potential Impact Radius. Pipelines with a potential impact radius (PIR) less than or equal to 150 feet may establish the MAOP as follows: (i) Reduce the MAOP to no greater than the highest actual operating pressure sustained by the pipeline during 5 years preceding October 1, 2019, divided by 1.1. The highest actual sustained pressure must have been reached for a minimum cumulative duration of 8 hours during one continuous 30-day period. The reduced MAOP must account for differences between discharge and upstream pressure on the pipeline by use of either the lowest value for the entire pipeline segment or the operating pressure gradient (i.e., the location specific operating pressure at each location); (ii) Conduct patrols in accordance with § 192.705 paragraphs (a) and (c) and conduct instrumented leakage surveys in accordance with § 192.706 at intervals not to exceed those in the following table 1 to § 192.624(c)(5)(ii): jbell on DSK3GLQ082PROD with RULES2 TABLE 1 TO § 192.624(c)(5)(ii) Class locations Patrols Leakage surveys (A) Class 1 and Class 2 ...... (B) Class 3 and Class 4 ...... 3 ⁄ months, but at least four times each calendar year 3 months, but at least six times each calendar year ...... 3 ⁄ months, but at least four times each calendar year. 3 months, but at least six times each calendar year. VerDate Sep<11>2014 18:29 Sep 30, 2019 12 Jkt 250001 PO 00000 Frm 00070 Fmt 4701 Sfmt 4700 12 E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations (iii) Under Method 5, future uprating of the pipeline segment in accordance with subpart K is allowed. (6) Method 6: Alternative Technology. Operators may use an alternative technical evaluation process that provides a documented engineering analysis for establishing MAOP. If an operator elects to use alternative technology, the operator must notify PHMSA in advance in accordance with § 192.18. The notification must include descriptions of the following details: (i) The technology or technologies to be used for tests, examinations, and assessments; the method for establishing material properties; and analytical techniques with similar analysis from prior tool runs done to ensure the results are consistent with the required corresponding hydrostatic test pressure for the pipeline segment being evaluated; (ii) Procedures and processes to conduct tests, examinations, assessments and evaluations, analyze defects and flaws, and remediate defects discovered; (iii) Pipeline segment data, including original design, maintenance and operating history, anomaly or flaw characterization; (iv) Assessment techniques and acceptance criteria, including anomaly detection confidence level, probability of detection, and uncertainty of the predicted failure pressure quantified as a fraction of specified minimum yield strength; (v) If any pipeline segment contains cracking or may be susceptible to cracking or crack-like defects found through or identified by assessments, leaks, failures, manufacturing vintage histories, or any other available information about the pipeline, the operator must estimate the remaining life of the pipeline in accordance with paragraph § 192.712; (vi) Operational monitoring procedures; (vii) Methodology and criteria used to justify and establish the MAOP; and (vii) Documentation of the operator’s process and procedures used to implement the use of the alternative technology, including any records generated through its use. (d) Records. An operator must retain records of investigations, tests, analyses, assessments, repairs, replacements, alterations, and other actions taken in accordance with the requirements of this section for the life of the pipeline. 23. Section 192.632 is added to read as follows: ■ VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 § 192.632 Engineering Critical Assessment for Maximum Allowable Operating Pressure Reconfirmation: Onshore steel transmission pipelines. When an operator conducts an MAOP reconfirmation in accordance with § 192.624(c)(3) ‘‘Method 3’’ using an ECA to establish the material strength and MAOP of the pipeline segment, the ECA must comply with the requirements of this section. The ECA must assess: Threats; loadings and operational circumstances relevant to those threats, including along the pipeline right-of way; outcomes of the threat assessment; relevant mechanical and fracture properties; in-service degradation or failure processes; and initial and final defect size relevance. The ECA must quantify the interacting effects of threats on any defect in the pipeline. (a) ECA Analysis. (1) The material properties required to perform an ECA analysis in accordance with this paragraph are as follows: Diameter, wall thickness, seam type, grade (minimum yield strength and ultimate tensile strength), and Charpy v-notch toughness values based upon the lowest operational temperatures, if applicable. If any material properties required to perform an ECA for any pipeline segment in accordance with this paragraph are not documented in traceable, verifiable and complete records, an operator must use conservative assumptions and include the pipeline segment in its program to verify the undocumented information in accordance with § 192.607. The ECA must integrate, analyze, and account for the material properties, the results of all tests, direct examinations, destructive tests, and assessments performed in accordance with this section, along with other pertinent information related to pipeline integrity, including close interval surveys, coating surveys, interference surveys required by subpart I of this part, cause analyses of prior incidents, prior pressure test leaks and failures, other leaks, pipe inspections, and prior integrity assessments, including those required by §§ 192.617, 192.710, and subpart O of this part. (2) The ECA must analyze and determine the predicted failure pressure for the defect being assessed using procedures that implement the appropriate failure criteria and justification as follows: (i) The ECA must analyze any cracks or crack-like defects remaining in the pipe, or that could remain in the pipe, to determine the predicted failure pressure of each defect in accordance with § 192.712. PO 00000 Frm 00071 Fmt 4701 Sfmt 4700 52249 (ii) The ECA must analyze any metal loss defects not associated with a dent, including corrosion, gouges, scrapes or other metal loss defects that could remain in the pipe, to determine the predicted failure pressure. ASME/ANSI B31G (incorporated by reference, see § 192.7) or R–STRENG (incorporated by reference, see § 192.7) must be used for corrosion defects. Both procedures and their analysis apply to corroded regions that do not penetrate the pipe wall over 80 percent of the wall thickness and are subject to the limitations prescribed in the equations’ procedures. The ECA must use conservative assumptions for metal loss dimensions (length, width, and depth). (iii) When determining the predicted failure pressure for gouges, scrapes, selective seam weld corrosion, crackrelated defects, or any defect within a dent, appropriate failure criteria and justification of the criteria must be used and documented. (iv) If SMYS or actual material yield and ultimate tensile strength is not known or not documented by traceable, verifiable, and complete records, then the operator must assume 30,000 p.s.i. or determine the material properties using § 192.607. (3) The ECA must analyze the interaction of defects to conservatively determine the most limiting predicted failure pressure. Examples include, but are not limited to, cracks in or near locations with corrosion metal loss, dents with gouges or other metal loss, or cracks in or near dents or other deformation damage. The ECA must document all evaluations and any assumptions used in the ECA process. (4) The MAOP must be established at the lowest predicted failure pressure for any known or postulated defect, or interacting defects, remaining in the pipe divided by the greater of 1.25 or the applicable factor listed in § 192.619(a)(2)(ii). (b) Assessment to determine defects remaining in the pipe. An operator must utilize previous pressure tests or develop and implement an assessment program to determine the size of defects remaining in the pipe to be analyzed in accordance with paragraph (a) of this section. (1) An operator may use a previous pressure test that complied with subpart J to determine the defects remaining in the pipe if records for a pressure test meeting the requirements of subpart J of this part exist for the pipeline segment. The operator must calculate the largest defect that could have survived the pressure test. The operator must predict how much the defects have grown since the date of the pressure test in E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 52250 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations accordance with § 192.712. The ECA must analyze the predicted size of the largest defect that could have survived the pressure test that could remain in the pipe at the time the ECA is performed. The operator must calculate the remaining life of the most severe defects that could have survived the pressure test and establish a reassessment interval in accordance with the methodology in § 192.712. (2) Operators may use an inline inspection program in accordance with paragraph (c) of this section. (3) Operators may use ‘‘other technology’’ if it is validated by a subject matter expert to produce an equivalent understanding of the condition of the pipe equal to or greater than pressure testing or an inline inspection program. If an operator elects to use ‘‘other technology’’ in the ECA, it must notify PHMSA in advance of using the other technology in accordance with § 192.18. The ‘‘other technology’’ notification must have: (i) Descriptions of the technology or technologies to be used for all tests, examinations, and assessments, including characterization of defect size used in the crack assessments (length, depth, and volumetric); and (ii) Procedures and processes to conduct tests, examinations, assessments and evaluations, analyze defects, and remediate defects discovered. (c) In-line inspection. An inline inspection (ILI) program to determine the defects remaining the pipe for the ECA analysis must be performed using tools that can detect wall loss, deformation from dents, wrinkle bends, ovalities, expansion, seam defects, including cracking and selective seam weld corrosion, longitudinal, circumferential and girth weld cracks, hard spot cracking, and stress corrosion cracking. (1) If a pipeline has segments that might be susceptible to hard spots based on assessment, leak, failure, manufacturing vintage history, or other information, then the ILI program must include a tool that can detect hard spots. (2) If the pipeline has had a reportable incident, as defined in § 191.3, attributed to a girth weld failure since its most recent pressure test, then the ILI program must include a tool that can detect girth weld defects unless the ECA analysis performed in accordance with this section includes an engineering evaluation program to analyze and account for the susceptibility of girth weld failure due to lateral stresses. (3) Inline inspection must be performed in accordance with § 192.493. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 (4) An operator must use unity plots or equivalent methodologies to validate the performance of the ILI tools in identifying and sizing actionable manufacturing and construction related anomalies. Enough data points must be used to validate tool performance at the same or better statistical confidence level provided in the tool specifications. The operator must have a process for identifying defects outside the tool performance specifications and following up with the ILI vendor to conduct additional in-field examinations, reanalyze ILI data, or both. (5) Interpretation and evaluation of assessment results must meet the requirements of §§ 192.710, 192.713, and subpart O of this part, and must conservatively account for the accuracy and reliability of ILI, in-the-ditch examination methods and tools, and any other assessment and examination results used to determine the actual sizes of cracks, metal loss, deformation and other defect dimensions by applying the most conservative limit of the tool tolerance specification. ILI and in-the-ditch examination tools and procedures for crack assessments (length and depth) must have performance and evaluation standards confirmed for accuracy through confirmation tests for the defect types and pipe material vintage being evaluated. Inaccuracies must be accounted for in the procedures for evaluations and fracture mechanics models for predicted failure pressure determinations. (6) Anomalies detected by ILI assessments must be remediated in accordance with applicable criteria in §§ 192.713 and 192.933. (d) Defect remaining life. If any pipeline segment contains cracking or may be susceptible to cracking or cracklike defects found through or identified by assessments, leaks, failures, manufacturing vintage histories, or any other available information about the pipeline, the operator must estimate the remaining life of the pipeline in accordance with § 192.712. (e) Records. An operator must retain records of investigations, tests, analyses, assessments, repairs, replacements, alterations, and other actions taken in accordance with the requirements of this section for the life of the pipeline. ■ 24. Section 192.710 is added to read as follows: § 192.710 Transmission lines: Assessments outside of high consequence areas. (a) Applicability: This section applies to onshore steel transmission pipeline PO 00000 Frm 00072 Fmt 4701 Sfmt 4700 segments with a maximum allowable operating pressure of greater than or equal to 30% of the specified minimum yield strength and are located in: (1) A Class 3 or Class 4 location; or (2) A moderate consequence area as defined in § 192.3, if the pipeline segment can accommodate inspection by means of an instrumented inline inspection tool (i.e., ‘‘smart pig’’). (3) This section does not apply to a pipeline segment located in a high consequence area as defined in § 192.903. (b) General—(1) Initial assessment. An operator must perform initial assessments in accordance with this section based on a risk-based prioritization schedule and complete initial assessment for all applicable pipeline segments no later than July 3, 2034, or as soon as practicable but not to exceed 10 years after the pipeline segment first meets the conditions of § 192.710(a) (e.g., due to a change in class location or the area becomes a moderate consequence area), whichever is later. (2) Periodic reassessment. An operator must perform periodic reassessments at least once every 10 years, with intervals not to exceed 126 months, or a shorter reassessment interval based upon the type of anomaly, operational, material, and environmental conditions found on the pipeline segment, or as necessary to ensure public safety. (3) Prior assessment. An operator may use a prior assessment conducted before July 1, 2020 as an initial assessment for the pipeline segment, if the assessment met the subpart O requirements of part 192 for in-line inspection at the time of the assessment. If an operator uses this prior assessment as its initial assessment, the operator must reassess the pipeline segment according to the reassessment interval specified in paragraph (b)(2) of this section calculated from the date of the prior assessment. (4) MAOP verification. An integrity assessment conducted in accordance with the requirements of § 192.624(c) for establishing MAOP may be used as an initial assessment or reassessment under this section. (c) Assessment method. The initial assessments and the reassessments required by paragraph (b) of this section must be capable of identifying anomalies and defects associated with each of the threats to which the pipeline segment is susceptible and must be performed using one or more of the following methods: (1) Internal inspection. Internal inspection tool or tools capable of detecting those threats to which the E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations pipeline is susceptible, such as corrosion, deformation and mechanical damage (e.g., dents, gouges and grooves), material cracking and cracklike defects (e.g., stress corrosion cracking, selective seam weld corrosion, environmentally assisted cracking, and girth weld cracks), hard spots with cracking, and any other threats to which the covered segment is susceptible. When performing an assessment using an in-line inspection tool, an operator must comply with § 192.493; (2) Pressure test. Pressure test conducted in accordance with subpart J of this part. The use of subpart J pressure testing is appropriate for threats such as internal corrosion, external corrosion, and other environmentally assisted corrosion mechanisms; manufacturing and related defect threats, including defective pipe and pipe seams; and stress corrosion cracking, selective seam weld corrosion, dents and other forms of mechanical damage; (3) Spike hydrostatic pressure test. A spike hydrostatic pressure test conducted in accordance with § 192.506. A spike hydrostatic pressure test is appropriate for time-dependent threats such as stress corrosion cracking; selective seam weld corrosion; manufacturing and related defects, including defective pipe and pipe seams; and other forms of defect or damage involving cracks or crack-like defects; (4) Direct examination. Excavation and in situ direct examination by means of visual examination, direct measurement, and recorded nondestructive examination results and data needed to assess all applicable threats. Based upon the threat assessed, examples of appropriate non-destructive examination methods include ultrasonic testing (UT), phased array ultrasonic testing (PAUT), Inverse Wave Field Extrapolation (IWEX), radiography, and magnetic particle inspection (MPI); (5) Guided Wave Ultrasonic Testing. Guided Wave Ultrasonic Testing (GWUT) as described in Appendix F; (6) Direct assessment. Direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking. The use of use of direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking is allowed only if appropriate for the threat and pipeline segment being assessed. Use of direct assessment for threats other than the threat for which the direct assessment method is suitable is not allowed. An operator must conduct the direct assessment in accordance with the requirements listed in § 192.923 and VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 with the applicable requirements specified in §§ 192.925, 192.927 and 192.929; or (7) Other technology. Other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe for each of the threats to which the pipeline is susceptible. An operator must notify PHMSA in advance of using the other technology in accordance with § 192.18. (d) Data analysis. An operator must analyze and account for the data obtained from an assessment performed under paragraph (c) of this section to determine if a condition could adversely affect the safe operation of the pipeline using personnel qualified by knowledge, training, and experience. In addition, when analyzing inline inspection data, an operator must account for uncertainties in reported results (e.g., tool tolerance, detection threshold, probability of detection, probability of identification, sizing accuracy, conservative anomaly interaction criteria, location accuracy, anomaly findings, and unity chart plots or equivalent for determining uncertainties and verifying actual tool performance) in identifying and characterizing anomalies. (e) Discovery of condition. Discovery of a condition occurs when an operator has adequate information about a condition to determine that the condition presents a potential threat to the integrity of the pipeline. An operator must promptly, but no later than 180 days after conducting an integrity assessment, obtain sufficient information about a condition to make that determination, unless the operator demonstrates that 180 days is impracticable. (f) Remediation. An operator must comply with the requirements in §§ 192.485, 192.711, and 192.713, where applicable, if a condition that could adversely affect the safe operation of a pipeline is discovered. (g) Analysis of information. An operator must analyze and account for all available relevant information about a pipeline in complying with the requirements in paragraphs (a) through (f) of this section. ■ 25. Section 192.712 is added to read as follows: § 192.712 Analysis of predicted failure pressure. (a) Applicability. Whenever required by this part, operators of onshore steel transmission pipelines must analyze anomalies or defects to determine the predicted failure pressure at the location of the anomaly or defect, and the PO 00000 Frm 00073 Fmt 4701 Sfmt 4700 52251 remaining life of the pipeline segment at the location of the anomaly or defect, in accordance with this section. (b) Corrosion metal loss. When analyzing corrosion metal loss under this section, an operator must use a suitable remaining strength calculation method including, ASME/ANSI B31G (incorporated by reference, see § 192.7); R–STRENG (incorporated by reference, see § 192.7); or an alternative equivalent method of remaining strength calculation that will provide an equally conservative result. (c) [Reserved] (d) Cracks and crack-like defects—(1) Crack analysis models. When analyzing cracks and crack-like defects under this section, an operator must determine predicted failure pressure, failure stress pressure, and crack growth using a technically proven fracture mechanics model appropriate to the failure mode (ductile, brittle or both), material properties (pipe and weld properties), and boundary condition used (pressure test, ILI, or other). (2) Analysis for crack growth and remaining life. If the pipeline segment is susceptible to cyclic fatigue or other loading conditions that could lead to fatigue crack growth, fatigue analysis must be performed using an applicable fatigue crack growth law (for example, Paris Law) or other technically appropriate engineering methodology. For other degradation processes that can cause crack growth, appropriate engineering analysis must be used. The above methodologies must be validated by a subject matter expert to determine conservative predictions of flaw growth and remaining life at the maximum allowable operating pressure. The operator must calculate the remaining life of the pipeline by determining the amount of time required for the crack to grow to a size that would fail at maximum allowable operating pressure. (i) When calculating crack size that would fail at MAOP, and the material toughness is not documented in traceable, verifiable, and complete records, the same Charpy v-notch toughness value established in paragraph (e)(2) of this section must be used. (ii) Initial and final flaw size must be determined using a fracture mechanics model appropriate to the failure mode (ductile, brittle or both) and boundary condition used (pressure test, ILI, or other). (iii) An operator must re-evaluate the remaining life of the pipeline before 50% of the remaining life calculated by this analysis has expired. The operator must determine and document if further pressure tests or use of other assessment E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 52252 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations methods are required at that time. The operator must continue to re-evaluate the remaining life of the pipeline before 50% of the remaining life calculated in the most recent evaluation has expired. (3) Cracks that survive pressure testing. For cases in which the operator does not have in-line inspection crack anomaly data and is analyzing potential crack defects that could have survived a pressure test, the operator must calculate the largest potential crack defect sizes using the methods in paragraph (d)(1) of this section. If pipe material toughness is not documented in traceable, verifiable, and complete records, the operator must use one of the following for Charpy v-notch toughness values based upon minimum operational temperature and equivalent to a full-size specimen value: (i) Charpy v-notch toughness values from comparable pipe with known properties of the same vintage and from the same steel and pipe manufacturer; (ii) A conservative Charpy v-notch toughness value to determine the toughness based upon the material properties verification process specified in § 192.607; (iii) A full size equivalent Charpy vnotch upper-shelf toughness level of 120 ft.-lbs.; or (iv) Other appropriate values that an operator demonstrates can provide conservative Charpy v-notch toughness values of the crack-related conditions of the pipeline segment. Operators using an assumed Charpy v-notch toughness value must notify PHMSA in accordance with § 192.18. (e) Data. In performing the analyses of predicted or assumed anomalies or defects in accordance with this section, an operator must use data as follows. (1) An operator must explicitly analyze and account for uncertainties in reported assessment results (including tool tolerance, detection threshold, probability of detection, probability of identification, sizing accuracy, conservative anomaly interaction criteria, location accuracy, anomaly findings, and unity chart plots or equivalent for determining uncertainties and verifying tool performance) in identifying and characterizing the type and dimensions of anomalies or defects used in the analyses, unless the defect dimensions have been verified using in situ direct measurements. (2) The analyses performed in accordance with this section must utilize pipe and material properties that are documented in traceable, verifiable, and complete records. If documented data required for any analysis is not available, an operator must obtain the undocumented data through § 192.607. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 Until documented material properties are available, the operator shall use conservative assumptions as follows: (i) Material toughness. An operator must use one of the following for material toughness: (A) Charpy v-notch toughness values from comparable pipe with known properties of the same vintage and from the same steel and pipe manufacturer; (B) A conservative Charpy v-notch toughness value to determine the toughness based upon the ongoing material properties verification process specified in § 192.607; (C) If the pipeline segment does not have a history of reportable incidents caused by cracking or crack-like defects, maximum Charpy v-notch toughness values of 13.0 ft.-lbs. for body cracks and 4.0 ft.-lbs. for cold weld, lack of fusion, and selective seam weld corrosion defects; (D) If the pipeline segment has a history of reportable incidents caused by cracking or crack-like defects, maximum Charpy v-notch toughness values of 5.0 ft.-lbs. for body cracks and 1.0 ft.-lbs. for cold weld, lack of fusion, and selective seam weld corrosion; or (E) Other appropriate values that an operator demonstrates can provide conservative Charpy v-notch toughness values of crack-related conditions of the pipeline segment. Operators using an assumed Charpy v-notch toughness value must notify PHMSA in advance in accordance with § 192.18 and include in the notification the bases for demonstrating that the Charpy v-notch toughness values proposed are appropriate and conservative for use in analysis of crack-related conditions. (ii) Material strength. An operator must assume one of the following for material strength: (A) Grade A pipe (30,000 psi), or (B) The specified minimum yield strength that is the basis for the current maximum allowable operating pressure. (iii) Pipe dimensions and other data. Until pipe wall thickness, diameter, or other data are determined and documented in accordance with § 192.607, the operator must use values upon which the current MAOP is based. (f) Review. Analyses conducted in accordance with this section must be reviewed and confirmed by a subject matter expert. (g) Records. An operator must keep for the life of the pipeline records of the investigations, analyses, and other actions taken in accordance with the requirements of this section. Records must document justifications, deviations, and determinations made for the following, as applicable: PO 00000 Frm 00074 Fmt 4701 Sfmt 4700 (1) The technical approach used for the analysis; (2) All data used and analyzed; (3) Pipe and weld properties; (4) Procedures used; (5) Evaluation methodology used; (6) Models used; (7) Direct in situ examination data; (8) In-line inspection tool run information evaluated, including any multiple in-line inspection tool runs; (9) Pressure test data and results; (10) In-the-ditch assessments; (11) All measurement tool, assessment, and evaluation accuracy specifications and tolerances used in technical and operational results; (12) All finite element analysis results; (13) The number of pressure cycles to failure, the equivalent number of annual pressure cycles, and the pressure cycle counting method; (14) The predicted fatigue life and predicted failure pressure from the required fatigue life models and fracture mechanics evaluation methods; (15) Safety factors used for fatigue life and/or predicted failure pressure calculations; (16) Reassessment time interval and safety factors; (17) The date of the review; (18) Confirmation of the results by qualified technical subject matter experts; and (19) Approval by responsible operator management personnel. ■ 26. Section 192.750 is added to read as follows: § 192.750 Launcher and receiver safety. Any launcher or receiver used after July 1, 2021, must be equipped with a device capable of safely relieving pressure in the barrel before removal or opening of the launcher or receiver barrel closure or flange and insertion or removal of in-line inspection tools, scrapers, or spheres. An operator must use a device to either: Indicate that pressure has been relieved in the barrel; or alternatively prevent opening of the barrel closure or flange when pressurized, or insertion or removal of in-line devices (e.g. inspection tools, scrapers, or spheres), if pressure has not been relieved. ■ 27. In § 192.805, paragraph (i) is revised to read as follows: § 192.805 Qualification Program. * * * * * (i) After December 16, 2004, notify the Administrator or a state agency participating under 49 U.S.C. Chapter 601 if an operator significantly modifies the program after the administrator or state agency has verified that it complies E:\FR\FM\01OCR2.SGM 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations with this section. Notifications to PHMSA must be submitted in accordance with § 192.18. ■ 28. In § 192.909, paragraph (b) is revised to read as follows: § 192.909 How can an operator change its integrity management program? * * * * * (b) Notification. An operator must notify OPS, in accordance with § 192.18, of any change to the program that may substantially affect the program’s implementation or may significantly modify the program or schedule for carrying out the program elements. An operator must provide notification within 30 days after adopting this type of change into its program. ■ 29. In § 192.917, paragraphs (a)(3) and (e)(2) through (4) are revised, and paragraph (e)(6) is added to read as follows: jbell on DSK3GLQ082PROD with RULES2 § 192.917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program? (a) * * * (3) Time independent threats such as third party damage, mechanical damage, incorrect operational procedure, weather related and outside force damage to include consideration of seismicity, geology, and soil stability of the area; and * * * * * (e) * * * (2) Cyclic fatigue. An operator must analyze and account for whether cyclic fatigue or other loading conditions (including ground movement, and suspension bridge condition) could lead to a failure of a deformation, including a dent or gouge, crack, or other defect in the covered segment. The analysis must assume the presence of threats in the covered segment that could be exacerbated by cyclic fatigue. An operator must use the results from the analysis together with the criteria used to determine the significance of the threat(s) to the covered segment to prioritize the integrity baseline assessment or reassessment. Failure stress pressure and crack growth analysis of cracks and crack-like defects must be conducted in accordance with § 192.712. An operator must monitor operating pressure cycles and periodically, but at least every 7 calendar years, with intervals not to exceed 90 months, determine if the cyclic fatigue analysis remains valid or if the cyclic fatigue analysis must be revised based on changes to operating pressure cycles or other loading conditions. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 (3) Manufacturing and construction defects. An operator must analyze the covered segment to determine and account for the risk of failure from manufacturing and construction defects (including seam defects) in the covered segment. The analysis must account for the results of prior assessments on the covered segment. An operator may consider manufacturing and construction related defects to be stable defects only if the covered segment has been subjected to hydrostatic pressure testing satisfying the criteria of subpart J of at least 1.25 times MAOP, and the covered segment has not experienced a reportable incident attributed to a manufacturing or construction defect since the date of the most recent subpart J pressure test. If any of the following changes occur in the covered segment, an operator must prioritize the covered segment as a high-risk segment for the baseline assessment or a subsequent reassessment. (i) The pipeline segment has experienced a reportable incident, as defined in § 191.3, since its most recent successful subpart J pressure test, due to an original manufacturing-related defect, or a construction-, installation-, or fabrication-related defect; (ii) MAOP increases; or (iii) The stresses leading to cyclic fatigue increase. (4) Electric Resistance Welded (ERW) pipe. If a covered pipeline segment contains low frequency ERW pipe, lap welded pipe, pipe with longitudinal joint factor less than 1.0 as defined in § 192.113, or other pipe that satisfies the conditions specified in ASME/ANSI B31.8S, Appendices A4.3 and A4.4, and any covered or non-covered segment in the pipeline system with such pipe has experienced seam failure (including seam cracking and selective seam weld corrosion), or operating pressure on the covered segment has increased over the maximum operating pressure experienced during the preceding 5 years (including abnormal operation as defined in § 192.605(c)), or MAOP has been increased, an operator must select an assessment technology or technologies with a proven application capable of assessing seam integrity and seam corrosion anomalies. The operator must prioritize the covered segment as a high-risk segment for the baseline assessment or a subsequent reassessment. Pipe with seam cracks must be evaluated using fracture mechanics modeling for failure stress pressures and cyclic fatigue crack growth analysis to estimate the PO 00000 Frm 00075 Fmt 4701 Sfmt 4700 52253 remaining life of the pipe in accordance with § 192.712. * * * * * (6) Cracks. If an operator identifies any crack or crack-like defect (e.g., stress corrosion cracking or other environmentally assisted cracking, seam defects, selective seam weld corrosion, girth weld cracks, hook cracks, and fatigue cracks) on a covered pipeline segment that could adversely affect the integrity of the pipeline, the operator must evaluate, and remediate, as necessary, all pipeline segments (both covered and non-covered) with similar characteristics associated with the crack or crack-like defect. Similar characteristics may include operating and maintenance histories, material properties, and environmental characteristics. An operator must establish a schedule for evaluating, and remediating, as necessary, the similar pipeline segments that is consistent with the operator’s established operating and maintenance procedures under this part for testing and repair. ■ 30. In § 192.921, revise paragraph (a) and add paragraph (i) to read as follows: § 192.921 How is the baseline assessment to be conducted? (a) Assessment methods. An operator must assess the integrity of the line pipe in each covered segment by applying one or more of the following methods for each threat to which the covered segment is susceptible. An operator must select the method or methods best suited to address the threats identified to the covered segment (See § 192.917). (1) Internal inspection tool or tools capable of detecting those threats to which the pipeline is susceptible. The use of internal inspection tools is appropriate for threats such as corrosion, deformation and mechanical damage (including dents, gouges and grooves), material cracking and cracklike defects (e.g., stress corrosion cracking, selective seam weld corrosion, environmentally assisted cracking, and girth weld cracks), hard spots with cracking, and any other threats to which the covered segment is susceptible. When performing an assessment using an in-line inspection tool, an operator must comply with § 192.493. In addition, an operator must analyze and account for uncertainties in reported results (e.g., tool tolerance, detection threshold, probability of detection, probability of identification, sizing accuracy, conservative anomaly interaction criteria, location accuracy, anomaly findings, and unity chart plots or equivalent for determining uncertainties and verifying actual tool E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 52254 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations performance) in identifying and characterizing anomalies; (2) Pressure test conducted in accordance with subpart J of this part. The use of subpart J pressure testing is appropriate for threats such as internal corrosion; external corrosion and other environmentally assisted corrosion mechanisms; manufacturing and related defects threats, including defective pipe and pipe seams; stress corrosion cracking; selective seam weld corrosion; dents; and other forms of mechanical damage. An operator must use the test pressures specified in Table 3 of section 5 of ASME/ANSI B31.8S (incorporated by reference, see § 192.7) to justify an extended reassessment interval in accordance with § 192.939. (3) Spike hydrostatic pressure test conducted in accordance with § 192.506. The use of spike hydrostatic pressure testing is appropriate for timedependent threats such as stress corrosion cracking; selective seam weld corrosion; manufacturing and related defects, including defective pipe and pipe seams; and other forms of defect or damage involving cracks or crack-like defects; (4) Excavation and in situ direct examination by means of visual examination, direct measurement, and recorded non-destructive examination results and data needed to assess all threats. Based upon the threat assessed, examples of appropriate non-destructive examination methods include ultrasonic testing (UT), phased array ultrasonic testing (PAUT), inverse wave field extrapolation (IWEX), radiography, and magnetic particle inspection (MPI); (5) Guided wave ultrasonic testing (GWUT) as described in Appendix F. The use of GWUT is appropriate for internal and external pipe wall loss; (6) Direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking. The use of direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking is allowed only if appropriate for the threat and the pipeline segment being assessed. Use of direct assessment for threats other than the threat for which the direct assessment method is suitable is not allowed. An operator must conduct the direct assessment in accordance with the requirements listed in § 192.923 and with the applicable requirements specified in §§ 192.925, 192.927 and 192.929; or (7) Other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe for each of the threats to which the pipeline is susceptible. An operator must notify PHMSA in advance of using VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 the other technology in accordance with § 192.18. * * * * * (i) Baseline assessments for pipeline segments with a reconfirmed MAOP. An integrity assessment conducted in accordance with the requirements of § 192.624(c) may be used as a baseline assessment under this section. ■ 31. In § 192.933, paragraphs (a)(1) and (2) are revised to read as follows: § 192.933 What actions must be taken to address integrity issues? (a) * * * (1) Temporary pressure reduction. If an operator is unable to respond within the time limits for certain conditions specified in this section, the operator must temporarily reduce the operating pressure of the pipeline or take other action that ensures the safety of the covered segment. An operator must determine any temporary reduction in operating pressure required by this section using ASME/ANSI B31G (incorporated by reference, see § 192.7); R–STRENG (incorporated by reference, see § 192.7); or by reducing the operating pressure to a level not exceeding 80 percent of the level at the time the condition was discovered. An operator must notify PHMSA in accordance with § 192.18 if it cannot meet the schedule for evaluation and remediation required under paragraph (c) of this section and cannot provide safety through a temporary reduction in operating pressure or through another action. (2) Long-term pressure reduction. When a pressure reduction exceeds 365 days, an operator must notify PHMSA under § 192.18 and explain the reasons for the remediation delay. This notice must include a technical justification that the continued pressure reduction will not jeopardize the integrity of the pipeline. * * * * * ■ 32. In § 192.935, paragraph (b)(2) is revised to read as follows: § 192.935 What additional preventive and mitigative measures must an operator take? * * * * * (b) * * * (2) Outside force damage. If an operator determines that outside force (e.g., earth movement, loading, longitudinal, or lateral forces, seismicity of the area, floods, unstable suspension bridge) is a threat to the integrity of a covered segment, the operator must take measures to minimize the consequences to the covered segment from outside force damage. These measures include increasing the frequency of aerial, foot PO 00000 Frm 00076 Fmt 4701 Sfmt 4700 or other methods of patrols; adding external protection; reducing external stress; relocating the line; or inline inspections with geospatial and deformation tools. * * * * * ■ 33. In § 192.937, revise paragraph (c) and add paragraph (d) to read as follows: § 192.937 What is a continual process of evaluation and assessment to maintain a pipeline’s integrity? * * * * * (c) Assessment methods. In conducting the integrity reassessment, an operator must assess the integrity of the line pipe in each covered segment by applying one or more of the following methods for each threat to which the covered segment is susceptible. An operator must select the method or methods best suited to address the threats identified on the covered segment (see § 192.917). (1) Internal inspection tools. When performing an assessment using an inline inspection tool, an operator must comply with the following requirements: (i) Perform the in-line inspection in accordance with § 192.493; (ii) Select a tool or combination of tools capable of detecting the threats to which the pipeline segment is susceptible such as corrosion, deformation and mechanical damage (e.g. dents, gouges and grooves), material cracking and crack-like defects (e.g. stress corrosion cracking, selective seam weld corrosion, environmentally assisted cracking, and girth weld cracks), hard spots with cracking, and any other threats to which the covered segment is susceptible; and (iii) Analyze and account for uncertainties in reported results (e.g., tool tolerance, detection threshold, probability of detection, probability of identification, sizing accuracy, conservative anomaly interaction criteria, location accuracy, anomaly findings, and unity chart plots or equivalent for determining uncertainties and verifying actual tool performance) in identifying and characterizing anomalies. (2) Pressure test conducted in accordance with subpart J of this part. The use of pressure testing is appropriate for threats such as: Internal corrosion; external corrosion and other environmentally assisted corrosion mechanisms; manufacturing and related defects threats, including defective pipe and pipe seams; stress corrosion cracking; selective seam weld corrosion; dents; and other forms of mechanical damage. An operator must use the test E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations pressures specified in table 3 of section 5 of ASME/ANSI B31.8S (incorporated by reference, see § 192.7) to justify an extended reassessment interval in accordance with § 192.939. (3) Spike hydrostatic pressure test in accordance with § 192.506. The use of spike hydrostatic pressure testing is appropriate for time-dependent threats such as: Stress corrosion cracking; selective seam weld corrosion; manufacturing and related defects, including defective pipe and pipe seams; and other forms of defect or damage involving cracks or crack-like defects; (4) Excavation and in situ direct examination by means of visual examination, direct measurement, and recorded non-destructive examination results and data needed to assess all threats. Based upon the threat assessed, examples of appropriate non-destructive examination methods include ultrasonic testing (UT), phased array ultrasonic testing (PAUT), inverse wave field extrapolation (IWEX), radiography, or magnetic particle inspection (MPI); (5) Guided wave ultrasonic testing (GWUT) as described in Appendix F. The use of GWUT is appropriate for internal and external pipe wall loss; (6) Direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking. The use of direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking is allowed only if appropriate for the threat and pipeline segment being assessed. Use of direct assessment for threats other than the threat for which the direct assessment method is suitable is not allowed. An operator must conduct the direct assessment in accordance with the requirements listed in § 192.923 and with the applicable requirements specified in §§ 192.925, 192.927, and 192.929; (7) Other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe for each of the threats to which the pipeline is susceptible. An operator must notify PHMSA in advance of using the other technology in accordance with § 192.18; or (8) Confirmatory direct assessment when used on a covered segment that is scheduled for reassessment at a period longer than 7 calendar years. An operator using this reassessment method must comply with § 192.931. (d) MAOP reconfirmation assessments. An integrity assessment conducted in accordance with the requirements of § 192.624(c) may be used as a reassessment under this section. VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 34. In § 192.939, paragraphs (a) introductory text, (b) introductory text, and (b)(1) are revised to read as follows: ■ § 192.939 What are the required reassessment intervals? * * * * * (a) Pipelines operating at or above 30% SMYS. An operator must establish a reassessment interval for each covered segment operating at or above 30% SMYS in accordance with the requirements of this section. The maximum reassessment interval by an allowable reassessment method is 7 calendar years. Operators may request a 6-month extension of the 7-calendaryear reassessment interval if the operator submits written notice to OPS, in accordance with § 192.18, with sufficient justification of the need for the extension. If an operator establishes a reassessment interval that is greater than 7 calendar years, the operator must, within the 7-calendar-year period, conduct a confirmatory direct assessment on the covered segment, and then conduct the follow-up reassessment at the interval the operator has established. A reassessment carried out using confirmatory direct assessment must be done in accordance with § 192.931. The table that follows this section sets forth the maximum allowed reassessment intervals. * * * * * (b) Pipelines Operating below 30% SMYS. An operator must establish a reassessment interval for each covered segment operating below 30% SMYS in accordance with the requirements of this section. The maximum reassessment interval by an allowable reassessment method is 7 calendar years. Operators may request a 6-month extension of the 7-calendar-year reassessment interval if the operator submits written notice to OPS in accordance with § 192.18. The notice must include sufficient justification of the need for the extension. An operator must establish reassessment by at least one of the following— (1) Reassessment by pressure test, internal inspection or other equivalent technology following the requirements in paragraph (a)(1) of this section except that the stress level referenced in paragraph (a)(1)(ii) of this section would be adjusted to reflect the lower operating stress level. If an established interval is more than 7 calendar years, an operator must conduct by the seventh calendar year of the interval either a confirmatory direct assessment in accordance with § 192.931, or a low stress reassessment in accordance with § 192.941. * * * * * PO 00000 Frm 00077 Fmt 4701 Sfmt 4700 § 192.949 52255 [Removed and Reserved] 35. Remove and reserve § 192.949. ■ 36. Appendix F is added to read as follows: ■ Appendix F to Part 192–Criteria for Conducting Integrity Assessments Using Guided Wave Ultrasonic Testing (GWUT) This appendix defines criteria which must be properly implemented for use of guided wave ultrasonic testing (GWUT) as an integrity assessment method. Any application of GWUT that does not conform to these criteria is considered ‘‘other technology’’ as described by §§ 192.710(c)(7), 192.921(a)(7), and 192.937(c)(7), for which OPS must be notified 90 days prior to use in accordance with §§ 192.921(a)(7) or 192.937(c)(7). GWUT in the ‘‘Go-No Go’’ mode means that all indications (wall loss anomalies) above the testing threshold (a maximum of 5% of cross sectional area (CSA) sensitivity) be directly examined, in-line tool inspected, pressure tested, or replaced prior to completing the integrity assessment on the carrier pipe. I. Equipment and Software: Generation. The equipment and the computer software used are critical to the success of the inspection. Computer software for the inspection equipment must be reviewed and updated, as required, on an annual basis, with intervals not to exceed 15 months, to support sensors, enhance functionality, and resolve any technical or operational issues identified. II. Inspection Range. The inspection range and sensitivity are set by the signal to noise (S/N) ratio but must still keep the maximum threshold sensitivity at 5% cross sectional area (CSA). A signal that has an amplitude that is at least twice the noise level can be reliably interpreted. The greater the S/ N ratio the easier it is to identify and interpret signals from small changes. The signal to noise ratio is dependent on several variables such as surface roughness, coating, coating condition, associated pipe fittings (T’s, elbows, flanges), soil compaction, and environment. Each of these affects the propagation of sound waves and influences the range of the test. It may be necessary to inspect from both ends of the pipeline segment to achieve a full inspection. In general, the inspection range can approach 60 to 100 feet for a 5% CSA, depending on field conditions. III. Complete Pipe Inspection. To ensure that the entire pipeline segment is assessed there should be at least a 2 to 1 signal to noise ratio across the entire pipeline segment that is E:\FR\FM\01OCR2.SGM 01OCR2 jbell on DSK3GLQ082PROD with RULES2 52256 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations inspected. This may require multiple GWUT shots. Double-ended inspections are expected. These two inspections are to be overlaid to show the minimum 2 to 1 S/N ratio is met in the middle. If possible, show the same near or midpoint feature from both sides and show an approximate 5% distance overlap. IV. Sensitivity. The detection sensitivity threshold determines the ability to identify a cross sectional change. The maximum threshold sensitivity cannot be greater than 5% of the cross sectional area (CSA). The locations and estimated CSA of all metal loss features in excess of the detection threshold must be determined and documented. All defect indications in the ‘‘Go-No Go’’ mode above the 5% testing threshold must be directly examined, in-line inspected, pressure tested, or replaced prior to completing the integrity assessment. V. Wave Frequency. Because a single wave frequency may not detect certain defects, a minimum of three frequencies must be run for each inspection to determine the best frequency for characterizing indications. The frequencies used for the inspections must be documented and must be in the range specified by the manufacturer of the equipment. VI. Signal or Wave Type: Torsional and Longitudinal. Both torsional and longitudinal waves must be used and use must be documented. VII. Distance Amplitude Correction (DAC) Curve and Weld Calibration. The distance amplitude correction curve accounts for coating, pipe diameter, pipe wall and environmental conditions at the assessment location. The DAC curve must be set for each inspection as part of establishing the effective range of a GWUT inspection. DAC curves provide a means for evaluating the cross-sectional area change of reflections at various distances in the test range by assessing signal to noise ratio. A DAC curve is a means of taking apparent attenuation into account along the time base of a test signal. It is a line of equal sensitivity along the trace which allows the amplitudes of signals at different axial distances from the collar to be compared. VIII. Dead Zone. The dead zone is the area adjacent to the collar in which the transmitted signal blinds the received signal, making it impossible to obtain reliable results. Because the entire line must be inspected, inspection procedures must account for the dead zone by requiring the movement of the collar for additional inspections. An alternate method of obtaining valid VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 readings in the dead zone is to use Bscan ultrasonic equipment and visual examination of the external surface. The length of the dead zone and the near field for each inspection must be documented. IX. Near Field Effects. The near field is the region beyond the dead zone where the receiving amplifiers are increasing in power, before the wave is properly established. Because the entire line must be inspected, inspection procedures must account for the near field by requiring the movement of the collar for additional inspections. An alternate method of obtaining valid readings in the near field is to use Bscan ultrasonic equipment and visual examination of the external surface. The length of the dead zone and the near field for each inspection must be documented. X. Coating Type. Coatings can have the effect of attenuating the signal. Their thickness and condition are the primary factors that affect the rate of signal attenuation. Due to their variability, coatings make it difficult to predict the effective inspection distance. Several coating types may affect the GWUT results to the point that they may reduce the expected inspection distance. For example, concrete coated pipe may be problematic when well bonded due to the attenuation effects. If an inspection is done and the required sensitivity is not achieved for the entire length of the pipe, then another type of assessment method must be utilized. XI. End Seal. When assessing cased carrier pipe with GWUT, operators must remove the end seal from the casing at each GWUT test location to facilitate visual inspection. Operators must remove debris and water from the casing at the end seals. Any corrosion material observed must be removed, collected and reviewed by the operator’s corrosion technician. The end seal does not interfere with the accuracy of the GWUT inspection but may have a dampening effect on the range. XII. Weld Calibration to set DAC Curve. Accessible welds, along or outside the pipeline segment to be inspected, must be used to set the DAC curve. A weld or welds in the access hole (secondary area) may be used if welds along the pipeline segment are not accessible. In order to use these welds in the secondary area, sufficient distance must be allowed to account for the dead zone and near field. There must not be a weld between the transducer collar and the calibration weld. A conservative estimate of the predicted amplitude for the weld is 25% CSA (cross sectional area) and can be used if welds are not accessible. PO 00000 Frm 00078 Fmt 4701 Sfmt 4700 Calibrations (setting of the DAC curve) should be on pipe with similar properties such as wall thickness and coating. If the actual weld cap height is different from the assumed weld cap height, the estimated CSA may be inaccurate and adjustments to the DAC curve may be required. Alternative means of calibration can be used if justified by a documented engineering analysis and evaluation. XIII. Validation of Operator Training. Pipeline operators must require all guided wave service providers to have equipment-specific training and experience for all GWUT Equipment Operators which includes training for: A. Equipment operation, B. field data collection, and C. data interpretation on cased and buried pipe. Only individuals who have been qualified by the manufacturer or an independently assessed evaluation procedure similar to ISO 9712 (Sections: 5 Responsibilities; 6 Levels of Qualification; 7 Eligibility; and 10 Certification), as specified above, may operate the equipment. A senior-level GWUT equipment operator with pipeline specific experience must provide onsite oversight of the inspection and approve the final reports. A senior-level GWUT equipment operator must have additional training and experience, including training specific to cased and buried pipe, with a quality control program which that conforms to Section 12 of ASME B31.8S (for availability, see § 192.7). XIV. Training and Experience Minimums for Senior Level GWUT Equipment Operators: • Equipment Manufacturer’s minimum qualification for equipment operation and data collection with specific endorsements for casings and buried pipe • Training, qualification and experience in testing procedures and frequency determination • Training, qualification and experience in conversion of guided wave data into pipe features and estimated metal loss (estimated crosssectional area loss and circumferential extent) • Equipment Manufacturer’s minimum qualification with specific endorsements for data interpretation of anomaly features for pipe within casings and buried pipe. XV. Equipment: Traceable from vendor to inspection company. An operator must maintain documentation of the version of the GWUT software used and the serial number of the other E:\FR\FM\01OCR2.SGM 01OCR2 Federal Register / Vol. 84, No. 190 / Tuesday, October 1, 2019 / Rules and Regulations equipment such as collars, cables, etc., in the report. XVI. Calibration Onsite. The GWUT equipment must be calibrated for performance in accordance with the manufacturer’s requirements and specifications, including the frequency of calibrations. A diagnostic check and system check must be performed on-site each time the equipment is relocated to a different casing or pipeline segment. If on-site diagnostics show a discrepancy with the manufacturer’s requirements and specifications, testing must cease until the equipment can be restored to manufacturer’s specifications. XVII. Use on Shorted Casings (direct or electrolytic). GWUT may not be used to assess shorted casings. GWUT operators must have operations and maintenance procedures (see § 192.605) to address the effect of shorted casings on the GWUT signal. The equipment operator must clear any evidence of interference, other than some slight dampening of the GWUT signal from the shorted casing, according to their operating and maintenance procedures. All shorted casings found while conducting GWUT inspections must be addressed by the operator’s standard operating procedures. XVIII. Direct examination of all indications above the detection sensitivity threshold. The use of GWUT in the ‘‘Go-No Go’’ mode requires that all indications (wall loss anomalies) above the testing threshold (5% of CSA sensitivity) be directly examined (or 52257 replaced) prior to completing the integrity assessment on the cased carrier pipe or other GWUT application. If this cannot be accomplished, then alternative methods of assessment (such as hydrostatic pressure tests or ILI) must be utilized. XIV. Timing of direct examination of all indications above the detection sensitivity threshold. Operators must either replace or conduct direct examinations of all indications identified above the detection sensitivity threshold according to the table below. Operators must conduct leak surveys and reduce operating pressure as specified until the pipe is replaced or direct examinations are completed. REQUIRED RESPONSE TO GWUT INDICATIONS GWUT criterion Over the detection sensitivity threshold (maximum of 5% CSA). Operating pressure less than or equal to 30% SMYS Operating pressure over 30 and less than or equal to 50% SMYS Operating pressure over 50% SMYS Replace or direct examination within 12 months, and instrumented leak survey once every 30 calendar days. Replace or direct examination within 6 months, instrumented leak survey once every 30 calendar days, and maintain MAOP below the operating pressure at time of discovery. Replace or direct examination within 6 months, instrumented leak survey once every 30 calendar days, and reduce MAOP to 80% of operating pressure at time of discovery. Fmt 4701 01OCR2 Issued in Washington, DC, on September 16, 2019, under authority delegated in 49 CFR part 1.97. Howard R. Elliott, Administrator. [FR Doc. 2019–20306 Filed 9–30–19; 8:45 am] jbell on DSK3GLQ082PROD with RULES2 BILLING CODE 4910–60–P VerDate Sep<11>2014 18:29 Sep 30, 2019 Jkt 250001 PO 00000 Frm 00079 Sfmt 9990 E:\FR\FM\01OCR2.SGM

Agencies

[Federal Register Volume 84, Number 190 (Tuesday, October 1, 2019)]
[Rules and Regulations]
[Pages 52180-52257]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2019-20306]

[[Page 52179]]

Vol. 84

Tuesday,

No. 190

October 1, 2019

Part II

Department of Transportation

-----------------------------------------------------------------------

Pipeline and Hazardous Materials Safety Administration

-----------------------------------------------------------------------

49 CFR Parts 191 and 192

Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP
Reconfirmation, Expansion of Assessment Requirements, and Other Related
Amendments; Final Rule

Federal Register / Vol. 84 , No. 190 / Tuesday, October 1, 2019 /
Rules and Regulations

[[Page 52180]]

-----------------------------------------------------------------------

DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Parts 191 and 192

[Docket No. PHMSA-2011-0023; Amdt. Nos. 191-26; 192-125]
RIN 2137-AE72

Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP
Reconfirmation, Expansion of Assessment Requirements, and Other Related
Amendments

AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
DOT.

ACTION: Final rule.

-----------------------------------------------------------------------

SUMMARY: PHMSA is revising the Federal Pipeline Safety Regulations to
improve the safety of onshore gas transmission pipelines. This final
rule addresses congressional mandates, National Transportation Safety
Board recommendations, and responds to public input. The amendments in
this final rule address integrity management requirements and other
requirements, and they focus on the actions an operator must take to
reconfirm the maximum allowable operating pressure of previously
untested natural gas transmission pipelines and pipelines lacking
certain material or operational records, the periodic assessment of
pipelines in populated areas not designated as ``high consequence
areas,'' the reporting of exceedances of maximum allowable operating
pressure, the consideration of seismicity as a risk factor in integrity
management, safety features on in-line inspection launchers and
receivers, a 6-month grace period for 7-calendar-year integrity
management reassessment intervals, and related recordkeeping
provisions.

DATES: The effective date of this final rule is July 1, 2020. The
incorporation by reference of certain publications listed in the rule
is approved by the Director of the Federal Register as of July 1, 2020.
The incorporation by reference of ASME/ANSI B31.8S was approved by the
Director of the Federal Register as of January 14, 2004.

FOR FURTHER INFORMATION CONTACT: Technical questions: Steve Nanney,
Project Manager, by telephone at 713-272-2855. General information:
Robert Jagger, Senior Transportation Specialist, by telephone at 202-
366-4361.

SUPPLEMENTARY INFORMATION:

I. Executive Summary
A. Purpose of the Regulatory Action
B. Summary of the Major Provisions of the Regulatory Action in
Question
C. Costs and Benefits
II. Background
A. Detailed Overview
B. Pacific Gas and Electric Incident of 2010
C. Advance Notice of Proposed Rulemaking
D. National Transportation Safety Board Recommendations
E. Pipeline Safety, Regulatory Certainty, and Job Creation Act
of 2011
F. Notice of Proposed Rulemaking
III. Analysis of Comments, GPAC Recommendations and PHMSA Response
A. Verification of Pipeline Material Properties and Attributes--
Sec. 192.607
i. Applicability
ii. Method
B. MAOP Reconfirmation--Sec. Sec. 192.624, 192.632
i. Applicability
ii. Methods
iii. Spike Test--Sec. 192.506
iv. Fracture Mechanics--Sec. 192.712
v. Legacy Construction Techniques/Legacy Pipe
C. Seismicity and Other Integrity Management Clarifications--
Sec. 192.917
D. 6-Month Grace Period for 7-Calendar-Year Reassessment
Intervals--Sec. 192.939
E. ILI Launcher and Receiver Safety--Sec. 192.750
F. MAOP Exceedance Reporting--Sec. Sec. 191.23, 191.25
G. Strengthening Assessment Requirements--Sec. Sec. 192.150,
192.493, 192.921, 192.937, Appendix F
i. Industry Standards for ILI--Sec. Sec. 192.150, 192.493
ii. Expand Assessment Methods Allowed for IM--Sec. Sec.
192.921(a) and 192.937(c)
iii. Guided Wave Ultrasonic Testing--Appendix F
H. Assessing Areas Outside of HCAs--Sec. Sec. 192.3, 192.710
i. MCA Definition--Sec. 192.3
ii. Non-HCA Assessments--Sec. 192.710
I. Miscellaneous Issues
i. Legal Comments
ii. Records
iii. Cost/Benefit Analysis, Information Collection, and
Environmental Impact Issues
IV. GPAC Recommendations
V. Section-by-Section Analysis
VI. Standards Incorporated by Reference
A. Summary of New and Revised Standards
B. Availability of Standards Incorporated by Reference
VII. Regulatory Analysis and Notices

I. Executive Summary

A. Purpose of the Regulatory Action

PHMSA believes that the current regulatory requirements applicable
to gas pipeline systems have increased the level of safety associated
with the transportation of gas. Still, incidents continue to occur on
gas pipeline systems resulting in serious risks to life and property.
One such incident occurred in San Bruno, CA, on September 9, 2010,
killing 8 people, injuring 51, destroying 38 homes, and damaging
another 70 homes (PG&E incident). In its investigation of the incident,
the National Transportation Safety Board (NTSB) found among several
causal factors that the operator, Pacific Gas and Electric (PG&E), had
an inadequate integrity management (IM) program that failed to detect
and repair or remove the defective pipe section. PG&E was basing its IM
program on incomplete and inaccurate pipeline information, which led
to, among other things, faulty risk assessments, improper assessment
method selection, and internal assessments of the program that were
superficial and resulted in no meaningful improvement in the integrity
of the pipeline system nor the IM program itself.
The PG&E incident underscored the need for PHMSA to extend IM
requirements and address other issues related to pipeline system
integrity. In response, PHMSA published an ANPRM seeking comment on
whether IM and other requirements should be strengthened or expanded,
and other related issues, on August 25, 2011 (76 FR 53086).
The NTSB adopted its report on the PG&E incident on August 30,
2011, and issued several safety recommendations to PHMSA and other
entities. Several of these NTSB recommendations related directly to the
topics addressed in the 2011 ANPRM and are addressed in this final
rule. Also, the Pipeline Safety, Regulatory Certainty, and Job Creation
Act of 2011 (2011 Pipeline Safety Act) was enacted on January 3, 2012.
Several of the 2011 Pipeline Safety Act's statutory requirements
related directly to the topics addressed in the 2011 ANPRM and are a
focus of this rulemaking.
Another incident that influenced this rulemaking was the rupture of
a gas transmission pipe operated by Columbia Gas near Sissonville, WV,
on December 11, 2012. The escaping gas ignited, and fire damage
extended nearly 1,100 feet along the pipeline right-of-way and covered
an area roughly 820 feet wide. While there were no fatalities or
serious injuries, three houses were destroyed by the fire, and several
other houses were damaged. The ruptured pipe was one of three in the
area that cross Interstate 77, and the incident closed the highway in
both directions for 19 hours until a section of thermally damaged road
surface approximately 800 feet long could be replaced. Following this
incident, the NTSB finalized an accident report on February 19, 2014,
issuing recommendations to PHMSA to include principal arterial
roadways,

[[Page 52181]]

including interstates, other freeways and expressways, and other
principal arterial roadways as defined by the Federal Highway
Administration, to the list of ``identified sites'' that establish a
high consequence area (HCA) for the purposes of an operator's IM
program.
On April 8, 2016, PHMSA published an NPRM to seek public comments
on proposed changes to the gas transmission pipeline safety regulations
(81 FR 20722). A summary of those proposed changes, and PHMSA's
response to stakeholder feedback on the individual provisions, is
provided below in section IV of this document (Analysis of Comments and
PHMSA Response).
The purpose of this final rule is to increase the level of safety
associated with the transportation of gas. PHMSA is finalizing
requirements that address the causes of several recent incidents,
including the PG&E incident, by clarifying and enhancing existing
requirements. PHMSA is also addressing certain statutory mandates of
the 2011 Pipeline Safety Act and NTSB recommendations. While the NPRM
addressed 16 major topic areas, PHMSA believes the most efficient way
to manage the proposals in the NPRM is to divide them into three
rulemaking actions. PHMSA is finalizing the provisions in this final
rule as a first step. PHMSA anticipates completing a second rulemaking
to address the topics in the NPRM regarding repair criteria in HCAs and
the creation of new repair criteria for non-HCAs, requirements for
inspecting pipelines following extreme events, updates to pipeline
corrosion control requirements, codification of a management of change
process, clarification of certain other IM requirements, and
strengthening IM assessment requirements.\1\ A third rulemaking is
expected to address requirements related to gas gathering lines that
were proposed in the NPRM.\2\
---------------------------------------------------------------------------

\1\ RIN 2137-AF39.
\2\ RIN 2137-AF38.
---------------------------------------------------------------------------

B. Summary of the Major Provisions of the Regulatory Action in Question

Several of the amendments made in this rule are related to
congressional legislation from the 2011 Pipeline Safety Act. The Act
provides a 6-month grace period, with written notice, for the
completion of periodic integrity management reassessments that
otherwise would be completed no later than every 7 calendar years.\3\
Another requirement is that operators explicitly consider and account
for seismicity in identifying and evaluating potential threats.\4\ The
Act also requires operators to report exceedances of the maximum
allowable operating pressure (MAOP) of gas transmission
pipelines.^{5 6} PHMSA is incorporating these changes into the
PSR at 49 CFR parts 190-199 in this final rule.
---------------------------------------------------------------------------

\3\ 2011 Pipeline Safety Act Sec. 5(e).
\4\ 2011 Pipeline Safety Act Sec. 29.
\5\ 2011 Pipeline Safety Act Sec. 23.
\6\ MAOP means the maximum pressure at which a pipeline or
segment of a pipeline may be operated under this part.
---------------------------------------------------------------------------

This rule also requires operators of certain onshore steel gas
transmission pipeline segments to reconfirm the MAOP of those segments
and gather any necessary material property records they might need to
do so, where the records needed to substantiate the MAOP are not
traceable, verifiable, and complete. This includes previously untested
pipelines, which are commonly referred to as ``grandfathered''
pipelines, operating at or above 30 percent of specified minimum yield
strength (SMYS). Records to confirm MAOP include pressure test records
or material property records (mechanical properties) that verify the
MAOP is appropriate for the class location.\7\ Operators with missing
records can choose one of six methods to reconfirm their MAOP and must
keep the record that is generated by this exercise for the life of the
pipeline. PHMSA has also created an opportunistic method by which
operators with insufficient material property records can obtain such
records. These physical material property and attribute records include
the pipeline segment's diameter, wall thickness, seam type, grade (the
minimum yield strength and ultimate tensile strength of the pipe), and
Charpy V-notch toughness values (full-size specimen and based on the
lowest operational temperatures),\8\ if applicable or required. PHMSA
considers ``insufficient'' material property records to be those
records where the pipeline's physical material properties and
attributes are not documented in traceable, verifiable, and complete
records.
---------------------------------------------------------------------------

\7\ PHMSA uses class locations throughout part 192 to provide
safety margins and standards commensurate with the potential
consequence of a pipeline failure based on the surrounding
population. Class locations are defined at Sec. 192.5. A Class 1
location is an offshore area or a class location unit with 10 or
fewer buildings intended for human occupancy. A Class 2 location is
a class location unit with more than 10 but fewer than 46 buildings
intended for human occupancy. A Class 3 location is a class location
unit with 46 or more buildings intended for human occupancy, and a
Class 4 location is where buildings with 4-or-more stories above
ground are prevalent.
\8\ A Charpy V-notch impact test and its values indicate the
toughness of a given material at a specified temperature and is used
in fracture mechanics analysis.
---------------------------------------------------------------------------

PHMSA is requiring operators to perform integrity assessments on
certain pipelines outside of HCAs, whereas prior to this rule's
publication, integrity assessments were only required for pipelines in
HCAs. Pipelines in Class 3 locations, Class 4 locations, and in the
newly defined ``moderate consequence areas'' (MCA) \9\ must be assessed
initially within 14 years of this rule's publication date and then must
be reassessed at least once every 10 years thereafter. These
assessments will provide important information to operators about the
conditions of their pipelines, including the existence of internal and
external corrosion and other anomalies, and will provide an elevated
level of safety for the populations in MCAs while continuing to allow
operators to prioritize the safety of HCAs. This action fulfills the
section 5 mandate from the 2011 Pipeline Safety Act to expand elements
of the IM requirements beyond HCAs where appropriate.
---------------------------------------------------------------------------

\9\ A MCA is defined in Sec. 191.3 as an onshore area within a
potential impact circle, as that term is defined in Sec. 192.903,
containing either (1) 5 or more buildings intended for human
occupancy or (2) any portion of the paved surface, including
shoulders, of a designated interstate, other freeway, or expressway,
as well as any other principal arterial roadway with 4 or more
lanes, as defined in the Federal Highway Administration's Highway
Functional Classification Concepts, Criteria and Procedures, Section
3.1.
---------------------------------------------------------------------------

This rule also explicitly requires devices on in-line inspection
(ILI), launcher or receiver facilities that can safely relieve pressure
in the barrel before inserting or removing ILI tools, and requires the
use of a device that can indicate whether the pressure has been
relieved in the barrel or can otherwise prevent the barrel from being
opened if the pressure is not relieved. PHMSA is finalizing this
requirement in this final rule because it is aware of incidents where
operator personnel have been killed or seriously injured due to
pressure build-up at these stations.

C. Costs and Benefits

Consistent with Executive Order 12866, PHMSA has prepared an
assessment of the benefits and costs of the final rule as well as
reasonable alternatives. PHMSA estimates the annual costs of the rule
to be approximately $32.7 million, calculated using a 7 percent
discount rate. The costs reflect additional integrity assessments, MAOP
reconfirmation, and ILI launcher and receiver upgrades.
PHMSA is publishing the Regulatory Impact Analysis (RIA) for this
rule in the public docket. The table below

[[Page 52182]]

provides a summary of the estimated costs for the major provisions in
this rulemaking (see the RIA for further detail on these estimates).
PHMSA finds that the other final rule requirements will not result in
incremental costs. PHMSA did not quantify the cost savings from
material properties verification under the final rule compared to
existing regulations. PHMSA also elected to not quantify the benefits
of this rulemaking and instead discusses them qualitatively. PHMSA
estimated total annual costs of the rule of $31.4 million using a 3
percent discount rate, and $32.7 million using a 7 percent discount
rate.

Summary of Annualized Costs, 2019-2039
[$2017 thousands]
------------------------------------------------------------------------
Annualized cost
-------------------------------
Provision 3% Discount 7% Discount
rate rate
------------------------------------------------------------------------
1. MAOP Reconfirmation & Material $25,848 $27,899
Properties Verification................
2. Seismicity........................... 0.00 0.00
3. Six-Month Grace Period for Seven 0.00 0.00
Calendar-Year Reassessment Intervals...
4. In-Line Inspection Launcher/Receiver 27.4 37.5
Safety.................................
5. MAOP Exceedance Reports.............. 0.00 0.00
6. Strengthening requirements for 0.00 0.00
assessment methods.....................
7. Assessments outside HCAs............. 5,482 4,713
8. Related Records Provisions........... 0.00 0.00
-------------------------------
Total............................... 31,357 32,650
------------------------------------------------------------------------

II. Background

A. Detailed Overview

Introduction
Recent significant growth in the nation's production and use of
natural gas is placing unprecedented demands on the Nation's pipeline
system, underscoring the importance of moving this energy product
safely and efficiently. Changing spatial patterns of natural gas
production and use and an aging pipeline network has made improved
documentation and data collection increasingly necessary for the
industry to make reasoned safety choices and for preserving public
confidence in its ability to do so. Congress recognized these needs
when passing the 2011 Pipeline Safety Act, calling for an examination
of issues pertaining to the safety of the Nation's pipeline network,
including a thorough application of the risk-based integrity
assessment, repair, and validation system known as IM.\10\
---------------------------------------------------------------------------

\10\ The IM regulations specify how pipeline operators must
identify, prioritize, assess, evaluate, repair, and validate the
integrity of gas transmission pipelines in HCAs that could, in the
event of a leak or failure, affect high consequence areas in the
United States. These areas include certain populated and occupied
areas. See Sec. 192.903.
---------------------------------------------------------------------------

This final rule advances the goals established by Congress in the
2011 Pipeline Safety Act and is consistent with the emerging needs of
the natural gas pipeline system. This final rule also advances the
important discussion about the need to adapt and expand risk-based
safety practices. As some severe pipeline incidents have occurred in
areas outside HCAs \11\ where the application of IM principles are not
required, and as gas pipelines continue to experience failures from
causes that IM was intended to address, this conversation is
increasingly important.
---------------------------------------------------------------------------

\11\ HCAs are defined at Sec. 192.903. There are two methods
that can be used to determine and HCA, the specific differences of
which we do not address here. Very broadly and regardless of which
method used, operators must calculate the potential impact radius
for all points along their pipelines and evaluate corresponding
impact circles to identify what populations are contained within
each circle. Potential impact circles with 20 or more structures
intended for human occupancy, or those circles with ``identified
sites'' such as stadiums, playgrounds, office buildings, and
religious centers, are defined as HCAs.
---------------------------------------------------------------------------

This final rule strengthens IM requirements, including to ensure
operators select the appropriate inspection tool or tools to address
the pertinent identified threats to their pipeline segments, and
clarifies and expands recordkeeping requirements to ensure operators
have and retain the basic physical and operational attributes and
characteristics of their pipelines. Further, this final rule
establishes requirements to periodically assess pipeline segments in
locations outside of HCAs where the surrounding population is expected
to potentially be at risk from an incident, which are defined in the
rule as MCAs. Even though these pipeline segments are not within
currently defined HCAs, they could be located in areas with significant
populations. This change facilitates prompt identification and
remediation of potentially hazardous defects while still allowing
operators to make risk-based decisions on where to allocate their
maintenance and repair resources.
Natural Gas Infrastructure Overview
The U.S. natural gas pipeline network is designed to transport
natural gas to and from most locations in the lower 48 States.
Approximately two-thirds of the lower 48 States depend almost entirely
on the interstate transmission pipeline system for their supply of
natural gas.\12\ One can consider the Nation's natural gas pipeline
infrastructure as three interconnected parts--gathering, transmission,
and distribution--that together transport natural gas from the
production field, where gas is extracted from underground, to its end
users, where the gas is used as an energy fuel or chemical feedstock.
This final rule applies only to gas transmission lines and does not
address gas gathering or natural gas distribution infrastructure and
its associated issues. Currently, there are over 300,000 miles of
onshore gas transmission pipelines throughout the U.S.\13\
---------------------------------------------------------------------------

\12\ U.S. Department of Energy, ``Appendix B: Natural Gas,''
Quadrennial Energy Review Report: Energy Transmission, Storage, and
Distribution Infrastructure, p. NG-28, April 2015.
\13\ U.S. DOT Pipeline and Hazardous Materials Safety
Administration Data as of 4/26/2018.
---------------------------------------------------------------------------

Transmission pipelines primarily transport natural gas from gas
treatment plants and gathering systems to bulk customers, local
distribution networks, and storage facilities. Transmission pipelines
can range in size from several inches to several feet in diameter. They
can operate over a wide range of pressures, from a relatively low 200
pounds per square inch gage (psig) to

[[Page 52183]]

over 1,500 psig. They can be hundreds of miles long, and can operate
within the geographic boundaries of a single State, or cross one or
more State lines.
Regulatory History
PHMSA and its State partners regulate and enforce the minimum
Federal safety standards authorized by statute \14\ and codified in the
PSR for jurisdictional \15\ gas gathering, transmission, and
distribution systems.
---------------------------------------------------------------------------

\14\ Title 49, United States Code, Subtitle VIII, Pipelines,
Sections 60101, et. seq.
\15\ Typically, onshore pipelines involved in the
``transportation of gas''--see 49 CFR 192.1 and 192.3 for detailed
applicability.
---------------------------------------------------------------------------

Federal regulation of gas pipeline safety began in 1968 with the
creation of the Office of Pipeline Safety and the passage of the
Natural Gas Pipeline Safety Act of 1968 (Pub. L. 90-481). The Office of
Pipeline Safety issued interim minimum Federal safety standards for gas
pipeline facilities and the transportation of natural and other gas by
pipeline on November 13, 1968, and subsequently codified broad-based
gas pipeline regulations on August 19, 1970 (35 FR 13248). The PSR were
revised several times over the following decades to address different
aspects of natural gas transportation by pipeline, including
construction standards, pipeline materials, design standards, class
locations, corrosion control, and MAOP.
In the mid-1990s, following models from other industries such as
nuclear power, PHMSA started to explore whether a risk-based approach
to regulation could improve safety of the public and reduce damage to
the environment. During this time, PHMSA found that many operators were
performing forms of IM that varied in scope and sophistication but that
there were no uniform standards or requirements.
PHMSA began developing minimum IM regulations for both hazardous
liquid and gas transmission pipelines in response to a hazardous liquid
accident in Bellingham, WA, in 1999 that killed 3 people and a gas
transmission incident in Carlsbad, NM, in 2000 that killed 12. PHMSA
finalized IM regulations for gas transmission pipelines in a 2003 final
rule.\16\ The IM regulations are intended to provide a structure to
operators to focus resources on improving pipeline integrity in the
areas where a failure would have the greatest impact on public safety.
The IM final rule accelerated the integrity assessment of pipelines in
HCAs, improved IM systems, and improved the government's ability to
review the adequacy of IM plans.
---------------------------------------------------------------------------

\16\ ``Pipeline Safety: Pipeline Integrity Management in High
Consequence Areas (Gas Transmission Pipelines).'' 68 FR 69778;
December 15, 2003. Corrected April 6, 2004 (69 FR 18227) and May 26,
2004 (69 FR 29903).
---------------------------------------------------------------------------

The IM regulations require that operators conduct comprehensive
analyses to identify, prioritize, assess, evaluate, repair, and
validate the integrity of gas transmission pipelines in HCAs.
Approximately 7 percent of onshore gas transmission pipeline mileage is
located in HCAs.\17\ PHMSA and State inspectors review operators' IM
programs and associated records to verify that the operators have used
all available information about their pipelines to assess risks and
take appropriate actions to mitigate those risks.
---------------------------------------------------------------------------

\17\ Per PHMSA's 2018 Annual Report, accessed April 9, 2019,
20,435 of the 301,227 miles of gas transmission pipelines are
classified as being in HCAs.
---------------------------------------------------------------------------

Since the implementation of the IM regulations, sweeping changes in
the natural gas industry have caused significant shifts in supply and
demand, and the Nation's pipeline network faces increased pressures
from these changes as well as from the increased exposure caused by a
growing and geographically dispersing population. Also, long-identified
pipeline safety issues, some of which IM set out to address, remain
problems. A records search following the PG&E incident required by
Congress in the 2011 Pipeline Safety Act, showed that some pipeline
operators do not have the records they need to substantiate the current
MAOP of their pipelines, as required under existing regulations, and
lacked other critical information needed to properly assess risks and
threats and perform effective IM.\18\ PHMSA's inspection experience
indicates pipelines continue to be vulnerable to failures stemming from
outdated construction methods or materials. Finally, some severe
pipeline incidents have occurred in areas outside HCAs where the
application of IM principles is not required.
---------------------------------------------------------------------------

\18\ An effective IM program requires operators to analyze many
data points regarding threats to their systems in addition to pipe
attributes, including, but not limited to, construction data (year
of installation, pipe bending method, joining method, depth of
cover, coating type, pressure test records, etc.), operational data
(maximum and minimum operating pressures, leak and failure history,
corrosion monitoring, excavation data, corrosion surveys, ILI data,
etc.).
---------------------------------------------------------------------------

Following the significant pipeline incident in 2010 at San Bruno,
CA, in which 8 people died and more than 50 people were injured,
Congress charged PHMSA with improving the IM regulations. Additionally,
the NTSB and Government Accountability Office (GAO) issued
recommendations regarding IM.\19\ Comments in response to a 2011 ANPRM
on these and related topics suggested there were many common-sense
improvements that could be made to IM, as well as a clear need to
extend certain IM provisions to pipelines outside of HCAs that were not
covered by the IM regulations. A large portion of the transmission
pipeline industry has voluntarily committed to extending certain IM
provisions to non-HCA pipe, which demonstrates a common understanding
of the need for this strategy.
---------------------------------------------------------------------------

\19\ More information on the NTSB recommendations being
addressed in this rule are discussed in further detail in Section
II. D. of this document ``National Transportation Safety Board
Recommendations.'' See also, GAO-06-946, Natural Gas Pipeline
Safety: Integrity Management Benefits Public Safety, but Consistency
of Performance Measures Should be Improved,'' September 8, 2006.
---------------------------------------------------------------------------

Through this final rule, PHMSA is making improvements to IM and is
improving the ability of operators to engage in a long-range review of
risk management and information needs, while also accounting for a
changing landscape and a changing population.
Supply Changes
The U.S. natural gas industry increased production dramatically
between 2005 and 2017, from 19.5 trillion cubic feet per year to 28.8
trillion cubic feet per year.\20\ This growth was enabled by the
production of ``unconventional'' natural gas supplies using improved
technology to extract gas from low permeability shales. The increased
use of directional drilling \21\ and improvements to a long-existing
industrial technique--hydraulic fracturing,\22\ which began as an
experiment in 1947--made the recovery of unconventional natural gas
easier and economically viable. This has led to decreased prices and
increased use of natural gas, despite a reduction in the production of
conventional natural gas of about 14 billion cubic feet per day.
Unconventional shale gas production now accounts for nearly 70 percent
of overall gas production in the U.S.
---------------------------------------------------------------------------

\20\ U.S. Department of Energy, Energy Information
Administration, ``U.S. Natural Gas marketed Production'' https://www.eia.gov/dnav/ng/hist/n9050us2a.htm, accessed 6/28/18.
\21\ Directional drilling is the practice of drilling non-
vertical wells.
\22\ The extraction of oil or gas deposits performed by forcing
open fissures in subterranean rocks by introducing liquid at high
pressures.
---------------------------------------------------------------------------

Growth in unconventional natural gas production has shifted
production away from traditionally gas-rich regions towards inland
shale gas regions. To illustrate, in 2004, wells in the Gulf of
Mexico's produced 5,066,000 million

[[Page 52184]]

cubic feet of natural gas per year (Mcf/year), approximately 20 percent
of the Nation's natural gas production at the time. By 2016, that
number had fallen to 1,220,000 Mcf/year, and approximately 4 percent of
natural gas production in the U.S. During that same period,
Pennsylvania's share of production grew from 197,217 Mcf/year to
5,463,783 Mcf/year, or approximately 17 percent of total natural gas
production in the U.S.^{23 24} An analysis conducted by the
Department of Energy's Office of Energy Policy and Systems Analysis
projects that the most significant increases in production through 2030
will occur in the Marcellus and Utica Basins in the Appalachian
Basin,\25\ and natural gas production is projected to grow from the
2015 levels of 66.5 Bcf/d to more than 93.5 Bcf/d.\26\
---------------------------------------------------------------------------

\23\ U.S. Department of Energy, Energy Information
Administration, ``Gulf of Mexico--Offshore Natural Gas
Withdrawals,'' https://www.eia.gov/dnav/ng/hist/na1060_r3fmtf_2a.htm, accessed 6/28/18.
\24\ U.S. Department of Energy, Energy Information
Administration, ``Pennsylvania Natural Gas Gross Withdrawals,''
https://www.eia.gov/dnav/ng/hist/n9010pa2a.htm, accessed 6/28/18.
\25\ U.S. Department of Energy, ``Appendix B: Natural Gas,''
Quadrennial Energy Review Report: Energy Transmission, Storage, and
Distribution Infrastructure, p. NG-28, April 2015.
\26\ Id., at NG-6.
---------------------------------------------------------------------------

Demand Changes
The increase in domestic natural gas production has led to lower
average natural gas prices.\27\ In 2004, the outlook for natural gas
production and demand growth was weak. Monthly average spot prices at
Henry Hub \28\ were high based on historic comparison of prices,
fluctuating between $4 per million British thermal units (Btu) and $7
per million Btu. Prices rose above $11 per million Btu for several
months in both 2005 and 2008.\29\ Since 2008, after production shifted
to onshore unconventional shale resources, and price volatility fell
away following the Great Recession, natural gas has traded between
about $2 per million Btu and $5 per million Btu.\30\
---------------------------------------------------------------------------

\27\ Id., at NG-11.
\28\ Henry Hub is a Louisiana natural gas distribution hub where
conventional Gulf of Mexico natural gas can be directed to gas
transmission lines running to different parts of the country. Gas
bought and sold at the Henry hub serves as the national benchmark
for U.S. natural gas prices. (Id., at NG-29, NG-30).
\29\ Energy Information Administration, Natural Gas Spot and
Futures Prices, https://www.eia.gov/dnav/ng/ng_pri_fut_s1_m.htm,
retrieved August 2018.
\30\ U.S. Department of Energy, ``Appendix B: Natural Gas,''
Quadrennial Energy Review Report: Energy Transmission, Storage, and
Distribution Infrastructure, p. NG-11, April 2015.
---------------------------------------------------------------------------

These low prices have fueled consumption growth and changes in
markets and spatial patterns of consumption. A shift towards natural
gas-fueled electric power generation, cleaner than other types of
fossil fuels, is helping to serve the needs of the Nation's growing
population, and increased gas production and lower domestic prices have
created opportunities for international export.
Plentiful domestic natural gas supply and comparatively low natural
gas prices have changed the economics of electric power markets.\31\ To
accommodate recent growth and expected future growth in natural gas-
fueled power, changes in pipeline infrastructure will be needed,
including flow reversals of existing pipelines; additional lines to
gas-fired generators; looping of existing networks, where multiple
pipelines are laid parallel to one another along a single right-of-way
to increase the capacity of a single system; and, potentially, new
pipelines as well.
---------------------------------------------------------------------------

\31\ Id., at NG-9.
---------------------------------------------------------------------------

Increasing Pressures on the Existing Pipeline System Due to Supply and
Demand Changes
Despite the significant increase in domestic gas production and the
widespread distribution of domestic gas demand, significant flexibility
and capacity in the existing transmission system mitigates the level of
pipeline expansion and investment required. Some of the new gas
production is located near existing or emerging sources of demand,
which reduces the need for additional natural gas pipeline
infrastructure. In many instances where new natural gas transmission
capacity is needed, the network is being expanded by pipeline
investments to enhance network capacity on existing lines rather than
increasing coverage through new infrastructure. Additionally, operators
have avoided building new pipelines by increasing pipeline diameters or
operating pressures. In short, the nation's existing pipeline system is
facing the brunt of this dramatic increase in natural gas supply and
the shifting energy needs of the country.
In cases where use of the existing pipeline network is high, the
next most cost-effective solution is to add capacity to existing lines
via compression.\32\ Compression requires infrastructure investment in
the form of more compressor stations along the pipeline route, but it
can be less costly, faster, and simpler for market participants in
comparison to building a new pipeline. Adding compression, however,
raises pipeline operating pressures and can expose previously hidden
defects.
---------------------------------------------------------------------------

\32\ Gas can be reduced in volume by increasing its pressure.
Therefore, operators can pack more gas into their lines if they can
increase the pressure of the gas being transported.
---------------------------------------------------------------------------

New pipeline projects have been proposed to address pending supply
constraints and higher prices. However, gaining public acceptance for
natural gas pipeline construction has proved to be a substantial
challenge. Pipeline expansion and construction projects often face
significant challenges in determining feasible right-of-ways and
developing community support for the projects.
Data Challenges
Operators and regulators must have an intimate understanding of the
threats to, and operations of, their entire pipeline system. Data
gathering and integration are important elements of good IM practices,
and while operators have made many strides over the years to collect
more and better data, several data gaps still exist. Ironically, the
comparatively positive safety record of the Nation's gas transmission
pipelines to date makes it harder to quantify some of these gaps. Over
the 20-year period of 1998-2017, transmission facilities accounted for
50 fatalities and 179 injuries, or about one-sixth to one-seventh of
the total fatalities and injuries caused by natural gas pipeline
incidents in the U.S.\33\ Given the relatively limited number of
significant incidents that occur, it can be challenging to project the
possible impact of low-probability but high-consequence events. See the
RIA included in the public docket for a more detailed analysis of key
types of incidents that may be mitigated by this final rule.
---------------------------------------------------------------------------

\33\ PHMSA, Pipeline Incident 20-Year Trends, https://www.phmsa.dot.gov/pipeline/library/data-stats/pipelineincidenttrends.
---------------------------------------------------------------------------

On September 9, 2010, a 30-inch-diameter segment of an intrastate
natural gas transmission pipeline owned and operated by PG&E ruptured
in a residential area of San Bruno, CA. The natural gas that was
released subsequently ignited, resulting in a fire that destroyed 38
homes and damaged 70. Eight people were killed, many were injured, and
many more were evacuated from the area.
The PG&E incident exposed several problems in the way data on
pipeline conditions is collected and managed, showing that the operator
had inadequate records regarding the physical and operational
characteristics of their pipelines. These records are necessary for the
correct setting and validation of MAOP, which is critically

[[Page 52185]]

important for providing an appropriate margin of safety to the public.
Much of operator data is obtained through the assessments and other
safety inspections required by IM regulations. However, this testing
can be expensive, and the approaches to obtaining data that are most
efficient over the long term may require significant upfront costs to
modernize pipes and make them suitable for automated inspection. As a
result, there continue to be data gaps that make it hard to fully
understand the risks to and the integrity of the Nation's pipeline
system.
To evaluate a pipeline's integrity, operators generally choose
between three methods of testing a pipeline: Inline inspection (ILI),
pressure testing, and direct assessment (DA). In 2017, PHMSA estimates
that about two-thirds of gas transmission interstate pipeline mileage
was suitable for ILI, compared to only about half of intrastate
pipeline mileage, and therefore, intrastate operators use more pressure
testing and DA than interstate operators.
ILIs are performed using tools, referred to as ``smart pigs,''
which are usually pushed through a pipeline by the pressure of the
product being transported. As the tool travels through the pipeline, it
identifies and records potential pipe defects or anomalies. Because
these tests can be performed with product in the pipeline, the pipeline
does not have to be taken out of service for testing to occur, which
can prevent excessive cost to the operator and possible service
disruptions to consumers. Further, unlike pressure testing, ILI does
not risk destroying the pipe, and it is typically less costly to
perform on a per-unit basis than other assessment methods.
Pressure tests, also known as hydrostatic tests, are used by
pipeline operators as a means to determine the integrity (or strength)
of the pipeline immediately after construction and before placing the
pipeline in service, as well as periodically during a pipeline's
operating life. In a pressure test, water or an alternative test medium
inside the pipeline is pressurized to a level greater than the normal
operating pressure of the pipeline. This test pressure is held for a
number of hours to ensure there are no leaks in the pipeline.
Direct assessment is the visual evaluation of a pipeline at a
sample of locations along the line to detect corrosion threats, dents,
and stress corrosion cracking of the pipe body and seams. In general,
corrosion direct assessments are carried out by performing four steps.
Operators will review records and other data, then inspect the pipeline
through assessments that do not require excavation or use mathematical
models and environmental surveys to find likely locations on a pipeline
where corrosion is most likely to occur. For external corrosion,
operators must use two or more complementary indirect assessment tools,
including, for example, close interval surveys, direct current voltage
gradient surveys, and alternating current voltage gradient surveys, to
determine potential areas of corrosion to examine. For internal
corrosion, operators must analyze data to establish whether water was
present in the pipe, determine the locations where water would likely
accumulate, and provide for a detailed examination and evaluation of
those locations. Areas identified where corrosion may be occurring are
then excavated, examined visually, and remediated as necessary.
Operators also perform a post-assessment on segments where corrosion
direct assessments are used to evaluate the effectiveness of the
technique and determine re-assessment intervals as needed.\34\
---------------------------------------------------------------------------

\34\ See PHMSA's fact sheet on DA at https://primis.phmsa.dot.gov/Comm/FactSheets/FSdirectAssessmentGas.htm.
---------------------------------------------------------------------------

For cracking, operators collect and analyze data to determine
whether the conditions for stress corrosion cracking are present,
prioritize potentially susceptible segments of pipelines, and select
specific sites for examination and evaluation. A DA would then evaluate
the presence of stress corrosion cracking and determine its severity
and prevalence. Operators are required to repair anomalies, if found,
and determine further mitigation requirements as necessary.
Direct assessment can be prohibitively expensive to use on a wide
scale and may not give an accurate representation of the condition of
lengths of entire pipeline segments when the high expense leads the
operator to select an insufficient number of observations. Further, as
DA can only be used to validate specific threats, an operator that
relies solely on a DA without performing a thorough risk analysis or
running multiple tools specific to multiple threats might be leaving
other threats unremediated in their pipelines.
Ongoing research and industry response to the ANPRM \35\ and NPRM
\36\ indicate that ILI and spike hydrostatic pressure testing \37\ is
more effective than DA for identifying pipe conditions that are related
to stress corrosion cracking defects. Regulators and operators agree
that improving ILI methods as an alternative to hydrostatic testing is
better for risk evaluation and management of pipeline safety.
Hydrostatic pressure testing can result in substantial costs,
occasional disruptions in service, and substantial methane emissions
due to the routine evacuation of natural gas from pipelines prior to
tests. Further, many operators prefer not to use hydrostatic pressure
tests because it can be destructive.\38\ ILI testing can obtain data
along a pipeline not otherwise obtainable via other assessment methods,
although this method also has certain limitations.\39\
---------------------------------------------------------------------------

\35\ ``Pipeline Safety: Safety of Gas Transmission Pipelines--
Advanced Notice of Proposed Rulemaking,'' 76 FR 5308; August 25,
2011.
\36\ ``Pipeline Safety: Safety of Gas Transmission and Gathering
Pipelines,'' 81 FR 20722; April 8, 2016.
\37\ A ``spike'' hydrostatic pressure test is typically used to
resolve cracks that might otherwise grow during pressure reductions
after hydrostatic tests or as the result of operational pressure
cycles.
\38\ National Transportation Safety Board, ``Pacific Gas and
Electric Company; Natural Gas Transmission Pipeline Rupture and
Fire; San Bruno, California; September 9, 2010,'' Pipeline Accident
Report NTSB/PAR-11-01, Page 96, 2011.
\39\ For example, ILI tools are ideal for gathering certain
information about the physical condition of the pipe, including
corrosion, deformations, or cracking. However, ILI technology cannot
reliably detect other conditions, such as coating damage or
environmental issues.
---------------------------------------------------------------------------

This final rule expands the range of permissible assessment methods
and incorporates new guidelines to help operators in the selection of
appropriate assessment methods. Promoting the use of ILI technologies,
combined with further research and development by PHMSA as well as
stakeholders to make ILI testing more accurate, is expected to drive
innovation in pipeline integrity testing technologies that leads to
improved safety and system reliability through better data collection
and assessment.
Flow Reversals, Product Changes, and Manufacturing Defects
Significant growth of production outside the Gulf Coast region--
especially in Pennsylvania and Ohio \40\--is causing a reorientation of
the Nation's transmission pipeline network. The most significant of
these changes will require reversing flows on pipelines to move gas
from the Marcellus and Utica shale formations to the southeastern
Atlantic region and the Midwest.
---------------------------------------------------------------------------

\40\ U.S. Energy Information Administration, ``Annual Energy
Outlook 2019,'' p. 78--Dry shale gas production by region. https://www.eia.gov/outlooks/aeo/pdf/aeo2019.pdf
---------------------------------------------------------------------------

Reversing a pipeline's flow can cause added stress on the system
due to changes in gas pipeline pressure and temperature, which can
increase the risk

[[Page 52186]]

of internal corrosion. Occasional failures on natural gas transmission
pipelines have followed operational changes that include flow reversals
and product changes.\41\ Operators have recently submitted proposed
flow reversals and product changes on gas transmission lines. In
response to this phenomenon, PHMSA issued an Advisory Bulletin in 2014
notifying operators of the potentially significant impacts such changes
may have on the integrity of a pipeline and recommended additional
actions operators should consider performing before, during, and after
flow reversals, product changes, and conversions to service, including
notifications, operations and maintenance requirements, and IM
requirements.\42\
---------------------------------------------------------------------------

\41\ On September 29, 2013, the Tesoro High Plains pipeline
leaked 20,000 barrels of crude oil in a North Dakota field. The
location of pressure and flow monitoring equipment had not been
changed to account for the reversed flow. On March 19, 2013, Exxon's
Pegasus pipeline failed; the flow on that pipeline was reversed in
2006.
\42\ ``Pipeline Safety: Guidance for Pipeline Flow Reversals,
Product Changes, and Conversion to Service,'' ADB PHMSA-2014-0040,
79 FR 56121; September 18, 2014.
---------------------------------------------------------------------------

Data indicates that some pipelines are vulnerable to issues
stemming from outdated construction methods or materials. Some gas
transmission infrastructure was made before the 1970s using techniques
that have proven to contain latent defects due to the manufacturing
process. For example, pipe manufactured using low frequency electric
resistance welding is susceptible to seam failure. Because these
pipelines were installed before the Federal gas regulations were
issued, many of those pipes were exempted from certain regulations,
most notably the requirement to pressure test the pipeline segment
immediately after construction and before placing the pipeline into
service. A substantial amount of this type of pipe is still in
service.\43\ The IM regulations include specific requirements for
evaluating such pipe if located in HCAs, but infrequent-yet-severe
failures that are attributed to longitudinal seam defects continue to
occur. The NTSB's investigation of the PG&E incident in San Bruno
determined that the pipe failed due to a similar defect, a fracture
originating in the partially welded longitudinal seam of the pipe.
According to PHMSA's accident and incident database, between 2010 and
2017, 30 other reportable incidents were attributed to seam failures,
resulting in over $18 million of reported property damage.
---------------------------------------------------------------------------

\43\ Currently, PHMSA's data shows that roughly 168,000 of the
Nation's 301,000 miles of onshore gas transmission pipelines were
installed prior to the 1970 requirement for hydrostatic pressure
testing. See https://hip.phmsa.dot.gov/analyticsSOAP/saw.dll?PortalPages.
---------------------------------------------------------------------------

Protecting the Safety and Integrity of the Nation's Pipeline System
Beyond HCAs
The current IM program improves pipeline operators' ability to
identify and mitigate the risks to their pipeline systems. IM
regulations require that operators adopt procedures and processes to
identify HCAs; determine likely threats to the pipeline within the HCA;
evaluate the physical integrity of the pipe within the HCA; and repair,
remediate, or monitor any pipeline defects found based on severity.
Because these procedures and processes are complex and interconnected,
effective implementation of an IM program relies on continual
evaluation and data integration.
HCAs were first defined on August 6, 2002,\44\ providing
concentrations of populations with corridors of protection spanning
300, 660, or 1,000 feet, depending on the diameter and MAOP of the
particular pipeline.\45\ In a later NPRM,\46\ PHMSA proposed changes to
the definition of a HCA by introducing the concept of a covered
segment, which PHMSA defined as the length of gas transmission pipeline
that could potentially impact an HCA.\47\ Previously, only distances
from the pipeline centerline related to HCA definitions. PHMSA also
proposed using Potential Impact Circles (PIC), Potential Impact Zones,
and Potential Impact Radii (PIR) to identify covered segments instead
of a fixed corridor width. The final Gas Transmission Pipeline
Integrity Management Rule, incorporating the new HCA definition using
the PIR and PIC concepts, was issued on December 15, 2003.\48\
---------------------------------------------------------------------------

\44\ ``Pipeline Safety: High Consequence Areas for Gas
Transmission Pipelines,'' Final rule, 67 FR 50824; August 6, 2002.
\45\ The influence of the existing class location concept on the
early definition of HCAs is evident from the use of class locations
themselves in the definition, and the use of fixed 660 ft.
distances, which corresponds to the corridor width used in the class
location definition. This concept was later significantly revised,
as discussed later, in favor of a variable corridor width based on
case-specific pipe size and operating pressure.
\46\ ``Pipeline Safety: Pipeline Integrity Management in High
Consequence Areas (Gas Transmission Pipelines),'' Notice of Proposed
Rulemaking, 68 FR 4278; January 28, 2003.
\47\ HCA and PIR definitions are in 49 CFR 192.903.
\48\ ``Pipeline Safety: Pipeline Integrity Management in High
Consequence Areas (Gas Transmission Pipelines),'' Final rule, 68 FR
69778; December 15, 2003.
---------------------------------------------------------------------------

The PG&E incident in 2010 motivated a comprehensive reexamination
of gas transmission pipeline safety. In response to the PG&E incident,
Congress passed the 2011 Pipeline Safety Act, which directed PHMSA to
reexamine many of its safety requirements, including the expansion of
IM regulations for transmission pipelines.
Further, both the NTSB and the GAO issued several recommendations
to PHMSA to improve its IM program and pipeline safety. The NTSB noted
in a 2015 study \49\ that IM requirements have reduced the rate of
failures due to deterioration of pipe welds, corrosion, and material
failures. However, the NTSB noted that pipeline incidents in HCAs due
to other factors increased between 2010 and 2013, and the overall
occurrence of gas transmission pipeline incidents in HCAs has remained
stable. Since 2013 there have been an average of 9 incidents within
HCAs, which is below a peak of 12 incidents per year in 2012 and 2013,
but still higher than the number of incidents in 2010 and 2011. The
NTSB also found many types of basic data necessary to support
comprehensive probabilistic modeling of pipeline risks are not
currently available.
---------------------------------------------------------------------------

\49\ National Transportation Safety Board, ``Safety Study:
Integrity Management of Gas Transmission Pipelines in High
Consequence Areas,'' NTSB SS-15/01, January 27, 2015.
---------------------------------------------------------------------------

Looking at Risk Beyond HCAs
PHMSA posed a series of questions to the public in the context of
an August 25, 2011, ANPRM titled ``Safety of Gas Transmission
Pipelines'' (76 FR 53086), including whether the regulations governing
the safety of gas transmission pipelines needed changing. In
particular, PHMSA asked whether to add prescriptive language to IM
requirements, and whether other issues related to system integrity
should be addressed by strengthening or expanding non-IM requirements.
PHMSA sought comment on the definition of an HCA and whether additional
restrictions should be placed on the use of DA as an IM assessment
method. PHMSA also requested comment on non-IM requirements, including
valve spacing and installation, corrosion control, and whether
regulations for gathering lines needed to be modified.
PHMSA received 103 submissions containing thousands of comments in
response to the ANPRM, which are summarized in more detail below. This
feedback helped identify a series of proposed improvements to IM,
including improvements to assessment goals such as integrity
verification, MAOP verification, and material documentation; adjusted
repair criteria; clarified protocol for identifying threats,

[[Page 52187]]

risk assessments and management, and prevention and mitigation
measures; expanded and enhanced corrosion control; requirements for
inspecting pipelines after incidents of extreme weather; and new
guidance on how to calculate MAOP in order to set operating parameters
more accurately and predict the risks of an incident. PHMSA published
an NPRM on April 8, 2016 (81 FR 20722), which is discussed in more
detail below.
Many of these aspects of IM have been an integral part of PHMSA's
expectations since the inception of the IM program. As specified in the
first IM rule, PHMSA expects operators to start with an IM framework,
evolve a more detailed and comprehensive IM program, and continually
improve their IM programs as they learn more about the IM process and
the material condition of their pipelines through integrity
assessments.
Section 23 of the 2011 Pipeline Safety Act required PHMSA to have
pipeline operators conduct a records verification to ensure that their
records accurately reflect the physical and operational characteristics
of their pipelines in certain HCAs and class locations, and to confirm
the established MAOP of those pipelines. Based on the data received
from operators following the records verification, incidents that have
occurred in non-HCA areas, and other knowledge gained since the 2011
Pipeline Safety Act was passed, PHMSA has become increasingly concerned
that a rupture on the scale of San Bruno, with the potential to cause
death and serious injury, as well as damage to the environment or the
disruption of commerce, could occur elsewhere on the Nation's pipeline
system in both HCA and non-HCA pipeline segments. There have been
several recent incidents in non-HCAs that show significant incidents
can occur in non-HCAs. For example, on December 14, 2007, two men were
driving in a pickup truck on Interstate 20 near Delhi, LA, when a 30-
inch gas transmission pipeline owned by Columbia Gulf Transmission
Company ruptured. One of the men was killed, and the other was injured.
Further, on December 11, 2012, a 20-inch-diameter gas transmission
line operated by Columbia Gas Transmission Company ruptured about 106
feet west of Interstate 77 (I-77) in Sissonville, WV. An area of fire
damage about 820 feet wide extended nearly 1,100 feet along the
pipeline right-of-way. Three houses were destroyed by the fire, and
several other houses were damaged. Reported losses, repairs, and
upgrades from this incident totaled over $8.5 million, and major
transportation delays occurred. I-77 was closed in both directions
because of the fire and resulting damage to the road surface. The
northbound lanes were closed for approximately 14 hours, and the
southbound lanes were closed for approximately 19 hours while the road
was resurfaced, causing delays to both travelers and commercial
shipping.
Finally, on April 29, 2016, an incident occurred on a Texas Eastern
Transmission Corporation gas transmission line operated by Spectra
Energy near Delmont, PA, which is approximately 25 miles away from
Pittsburgh, PA. The explosion seriously injured one person, destroyed a
house, damaged three other homes and vehicles outside, and caused the
evacuation of nine other homes in the area. Even though the pipeline
was in a Class 1 rural area, it still had a significant impact on the
local population.
The Nation's population is growing, moving, and dispersing, leading
to changes in population density that can affect the class location of
a pipeline segment, as well as whether it is in an HCA. The definition
of HCA is not necessarily an accurate reflection of whether an incident
will have an impact on people. Requiring assessment and repair criteria
for pipelines that, if ruptured, could pose a threat to areas where any
people live, work, or congregate would improve public safety and would
improve public confidence in the Nation's natural gas pipeline system.
Some pipeline operators have said they are already moving towards
expanding the protections of IM beyond HCAs. In 2012, the Interstate
Natural Gas Association of America (INGAA) issued a ``Commitment to
Pipeline Safety,'' \50\ underscoring its efforts towards a goal of zero
incidents, a committed safety culture, a pursuit of constant
improvement, and applying IM principles on a system-wide basis. To
accomplish this goal, INGAA's members committed to performing actions
that include applying risk management beyond HCAs; raising the
standards for corrosion management; demonstrating ``fitness for
service'' on pre-regulation pipelines; and evaluating, refining, and
improving operators' ability to assess and mitigate safety threats.
These actions aim to extend protection to people who live near
pipelines but not within defined HCAs. Further, this final rule takes
important steps toward developing a comprehensive approach for the
entire industry by finalizing requirements for assessments outside of
HCAs.
---------------------------------------------------------------------------

\50\ Letter from Terry D. Boss, Senior Vice President of
Environment, Safety and Operations to Mike Israni, Pipeline and
Hazardous Materials Safety Administration, U.S. Department of
Transportation, dated January 20, 2012, ``Safety of Gas Transmission
Pipelines, Docket No. PHMSA-2011-0023.'' INGAA represents companies
that operate approximately 65 percent of the gas transmission
pipelines, but INGAA does not represent all pipeline operators
subject to 49 CFR part 192.
---------------------------------------------------------------------------

This final rule implements risk management standards that most
accurately target the safety of communities while also providing
sufficient ability to prioritize areas of greatest possible risk and
impact.
Given the results of incident investigations, IM considerations,
and the feedback from the ANPRM and the NPRM, PHMSA has determined it
is appropriate to improve aspects of the current IM program and codify
requirements for additional gas transmission pipelines to receive
integrity assessments on a periodic basis to monitor for, detect, and
remediate pipeline defects and anomalies. In addition, to achieve the
desired outcome of performing assessments in areas where people live,
work, or congregate, while balancing the cost of identifying such
locations, PHMSA based the requirements for identifying those locations
on effective processes already being implemented by pipeline operators
and that protect people on a risk-prioritized basis.
Establishing integrity assessment requirements for non-HCA pipeline
segments is important for providing safety to the public. Although
those pipeline segments are not within defined HCAs, they will usually
be in populated areas, and pipeline accidents in these areas may cause
fatalities, significant property damage, or disrupt livelihoods. This
final rule adopts a newly defined definition for MCAs to identify
additional non-HCA pipeline segments that would require integrity
assessments, thus assuring the timely discovery and repair of pipeline
defects in MCA segments that could potentially impact people, property,
or the environment. At the same time, operators can allocate their
resources to HCAs on a higher-priority basis.

B. Pacific Gas and Electric Incident of 2010

On September 9, 2010, a 30-inch-diameter segment of a gas
transmission pipeline owned and operated by PG&E ruptured in a
residential neighborhood in San Bruno, CA, producing a crater
approximately 72 feet long by 26 feet wide. The segment of pipe that
ruptured weighed approximately 3,000 pounds, was 28 feet long, and was
found 100 feet

[[Page 52188]]

south of the crater. Over the course of the incident, 47.6 million
standard cubic feet of natural gas was released. The escaping gas
ignited, and the resultant fire destroyed 38 homes, damaged another 70,
killed 8 people, injured approximately 60 people (10 seriously),
destroyed or damaged 74 vehicles, and caused the evacuation of over 300
more people. The initial 911 calls described the fire as a ``gas
station explosion'' and a ``possible airplane crash.'' After 91
minutes, PG&E was able to shut off the flow of gas to the rupture site,
which allowed firefighters to approach the rupture site and begin
containment efforts. Firefighting operations continued for 2 days; more
than 900 emergency responders from San Bruno and surrounding areas were
part of the emergency response, 600 of which were firefighters and
emergency medical services personnel.\51\
---------------------------------------------------------------------------

\51\ National Transportation Safety Board. 2011. Pacific Gas and
Electric Company Natural Gas Transmission Pipeline Rupture and Fire,
San Bruno, California, September 9, 2010. Pipeline Accident Report
NTSB/PAR-11/01. Washington, DC.
---------------------------------------------------------------------------

The NTSB, in its pipeline accident report for the incident,
determined that the probable cause of the accident was PG&E's
inadequate quality assurance and control when it relocated the line in
1956 and an inadequate IM program. The NTSB determined that PG&E's IM
program was deficient and ineffective because it was based on
incomplete and inaccurate pipeline information, did not consider the
pipeline's design and materials contribution to the risk of a pipeline
failure, and failed to consider the presence of previously identified
welded seam cracks as part of its risk assessment. These deficiencies
resulted in the selection of an examination method that could not
detect welded seam defects and led to internal assessments of PG&E's IM
program that were superficial and resulted in no improvements.
Ultimately, this inadequate IM program failed to detect and repair or
remove the defective pipe section.
The NTSB found that PG&E's inaccurate geographic information system
records at the time of the incident indicated that the ruptured segment
was constructed from 30-inch-diameter seamless API 5L X42 steel pipe.
However, seamless pipe has never been available in 30-inch diameter.
According to PG&E employees who testified during the investigation, all
30-inch pipe purchased by PG&E at that time would have been double
submerged arc welded, which has been found in cases to be susceptible
to weld failure. This inaccuracy was compounded with the discovery that
the material code from the journal voucher that PG&E's records were
originally composed from erroneously indicated the ruptured segment was
X52 grade pipe (52,000 pounds per square inch (psi)), not X42 grade
pipe (42,000 psi). X52 pipe has a higher minimum yield strength than
X42 pipe,\52\ and incorporating such values into MAOP calculations
would produce values that would be inconsistent with the pipeline's
actual MAOP. PG&E also could not produce any design, material, or
construction specifications from the 1956 construction project. In
short, no one from PG&E could reliably determine what type of pipe was
in the ground that ruptured.
---------------------------------------------------------------------------

\52\ 52,000 psi vs. 42,000 psi.
---------------------------------------------------------------------------

The NTSB also noted that PHMSA's exemption of pipelines installed
before 1970 from the regulatory requirement for pressure testing, which
likely would have detected the installation defects, was a contributing
factor to the accident. When the initial Federal minimum safety
standards for natural gas transmission pipelines were finalized in
1970, an exemption was carved out for pre-1970s pipelines from the
requirement for a post-construction hydrostatic pressure test. This
exemption was not proposed in any of the NPRMs that preceded the
initial regulations and was based on an assertion from the Federal
Power Commission \53\ that ``there are thousands of miles of
jurisdictional interstate pipelines installed prior to 1952,\54\ in
compliance with the then-existing codes, that could not continue to
operate at their present pressure levels and be in compliance with [the
proposed MAOP determination requirements].'' \55\ Upon reviewing the
operating record of interstate pipeline companies, the Commission found
``no evidence that would indicate a material increase in safety would
result from requiring wholesale reductions in the pressure of existing
pipelines which have been proven capable of withstanding present
operating pressures through actual operation.'' The Office of Pipeline
Safety, at the time, determined it ``[did] not now have enough
information to determine that existing operating pressures are
unsafe,'' and taking into account the statements from the Federal Power
Commission, included the ``grandfather'' clause in the final rule to
permit the continued operation of pipelines at the highest pressure to
which the pipeline had been subjected during the 5 years preceding July
1, 1970.^{56 57} The 5-year limit was prescribed so that
operators would be prevented from ``using a theoretical MAOP which may
have been determined under some formula used 20, 30, or 40 years ago.''
\58\
---------------------------------------------------------------------------

\53\ The predecessor of the Federal Energy Regulatory
Commission.
\54\ Between 1935 and 1951, the B31 Code only required a
pipeline be tested to a pressure of 50 psig in excess of the
pipeline's proposed MAOP. The 1970 regulations required pressure
testing to 125 percent in excess of the proposed MAOP.
\55\ ``Transportation of Natural and Other Gas by Pipeline:
Minimum Federal Safety Standards,'' 35 FR 13248; August 19, 1970.
\56\ 35 FR 13248.
\57\ This requirement is currently under Sec. 192.619(c).
\58\ 35 FR 13248.
---------------------------------------------------------------------------

The NTSB noted in its investigation that the ``grandfathering'' of
the ruptured line resulted in missed opportunities to detect the
defective pipe, as a hydrostatic pressure test to the prescribed levels
for a Class 3 location would likely have exposed the defective pipe
that led to the accident. Following the PG&E incident, the California
Public Utilities Commission (CPUC) required PG&E and other gas
transmission pipeline operators regulated by CPUC to either
hydrostatically pressure test or replace certain transmission pipelines
with grandfathered MAOPs, stating that gas transmission pipelines
``must be brought into compliance with modern standards for safety''
and that ``historic exemptions must come to an end.'' \59\ Currently,
PHMSA's data shows that roughly 168,000 of the Nation's 301,000 miles
of onshore gas transmission pipelines were installed prior to the 1970
requirement for hydrostatic pressure testing.\60\
---------------------------------------------------------------------------

\59\ ``Decision Determining Maximum Allowable Operating Pressure
Methodology and Requiring Filing of Natural Gas Transmission
Pipeline Replacement or Testing Implementation Plans;'' California
Public Utilities Commission Order; June 9, 2011.
\60\ https://hip.phmsa.dot.gov/analyticsSOAP/saw.dll?PortalPages.
---------------------------------------------------------------------------

On April 1, 2014, the Department of Justice indicted PG&E for
multiple criminal violations of part 192 for the 2010 incident in San
Bruno, CA. The trial began on June 14, 2016, and after a 5 \1/2\ week
trial, a Federal jury found PG&E guilty of knowingly and willingly
violating 5 sections of PHMSA's IM regulations and obstructing the NTSB
investigation.
Specifically, with respect to the Federal Pipeline Safety
Regulations, the jury found that between 2007 and 2010, PG&E knowingly
and willfully failed to: (1) Gather and integrate existing data and
information that could be relevant to identifying and evaluating
potential threats on covered pipeline segments; (2) identify and
evaluate all potential

[[Page 52189]]

threats to each covered pipeline segment; (3) include in its baseline
assessment plan all potential threats on a covered segment and to
select the most suitable assessment method; (4) prioritize high-risk
pipeline segments for assessment where certain changed circumstances
rendered the manufacturing threats on those segments unstable; and (5)
prioritize pipeline segments containing low-frequency ERW pipe or other
similar pipe as a high-risk segment for assessment if certain changed
circumstances rendered a manufacturing seam threat on that segment
unstable.
Congress required PHMSA, per the 2011 Pipeline Safety Act, to issue
regulations to confirm the material strength of previously untested
natural gas transmission pipelines located in HCAs and operating at a
pressure greater than 30 percent of SMYS. Through this final rule,
PHMSA is implementing that congressional directive and other safety
measures. This final rule will improve the safety and public confidence
of the Nation's onshore natural gas transmission pipeline system.

C. Advance Notice of Proposed Rulemaking

On August 25, 2011, PHMSA published an ANPRM to seek public
comments regarding the revision of the Federal Pipeline Safety
Regulations applicable to the safety of gas transmission pipelines. In
the 2011 ANPRM, PHMSA requested comments on 122 questions spread
through 15 broad topic areas covering both IM and non-IM requirements.
Among the issues related to IM that PHMSA considered included whether
the definition of an HCA should be revised and whether additional
restrictions should be placed on the use of certain pipeline assessment
methods. PHMSA also requested comment on non-IM regulations, including
whether revised requirements are needed for mainline valve spacing and
actuation, whether requirements for corrosion control should be
strengthened, and whether new regulations are needed to govern the
safety of gas gathering lines and underground natural gas storage
facilities. Based on the comments received on several of the ANPRM
topics, PHMSA developed proposals for some of those topics in a NPRM
that is the basis for this final rule. That NPRM and the comments
received, are discussed below. PHMSA did not find it appropriate to
address all the topics in a single rulemaking. Those topics that were
not discussed further in the NPRM for this final rule have been
discussed or will be discussed in other rulemakings.

D. National Transportation Safety Board Recommendations

On August 30, 2011, following the issuance of the ANPRM, the NTSB
adopted its report on the gas pipeline incident that occurred on
September 9, 2010, in San Bruno, CA. On September 26, 2011, the NTSB
issued safety recommendations P-11-8 through -20 to PHMSA. Several of
the NTSB's recommendations related directly to the topics discussed in
the 2011 ANPRM and 2016 NPRM, and they shaped the direction of this
final rule. The NTSB recommendations addressed in this final rule
include:
Exemption of Facilities Installed Prior to the
Regulations. NTSB Recommendation P-11-14: Amend Title 49 Code of
Federal Regulations 192.619 to repeal exemptions from pressure test
requirements and require that all gas transmission pipelines
constructed before 1970 be subjected to a hydrostatic pressure test
that incorporates a spike test.''
Pipe Manufactured Using Longitudinal Weld Seams. NTSB
Recommendation P-11-15: ``Amend Title 49 Code of Federal Regulations
Part 192 of the Federal pipeline safety regulations so that
manufacturing- and construction-related defects can only be considered
stable if a gas pipeline has been subjected to a post-construction
hydrostatic pressure test of at least 1.25 times the maximum allowable
operating pressure.''
Incorporating interstates, highways, etc., into the list
of ``identified sites'' that establish a HCA. NTSB Recommendation P-14-
1: ``Revise Title 49 CFR Section 903, Subpart O, Gas Transmission
Pipeline Integrity Management, to add principal arterial roadways
including interstates, other freeways and expressways, and other
principal arterial roadways as defined in the Federal Highway
Administration's ``Highway Functional Classification Concepts, Criteria
and Procedures'' to the list of ``identified sites'' that establish an
HCA.
Increase the use of ILI tools. NTSB Recommendation P-15-
20: ``Identify all operational complications that limit the use of in-
line inspection tools in piggable pipelines, develop methods to
eliminate the operational complications, and require operators to use
these methods to increase the use of in-line inspection tools.''

E. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011

The 2011 Pipeline Safety Act relates directly to the topics
addressed in PHMSA's ANPRM of August 25, 2011, and the NPRM issued on
April 8, 2016. The related topics and statutory citations include, but
are not limited to:
Section 5(e)--Allow periodic reassessments to be extended
for an additional 6 months if the operator submits sufficient
justification.
Section 5(f)--Requires the expansion of IM system
requirements, or elements thereof, beyond HCAs, if appropriate.
Section 23--Requires the reporting of each exceedance of
the MAOP that exceeds the build-up allowed for the operation of
pressure-limiting or -control devices.
Section 23--Requires testing to confirm the material
strength of previously untested natural gas transmission pipelines and
pipelines lacking records that accurately reflect the pipeline's
physical and operational characteristics.
Section 29--Requires consideration of seismicity when
evaluating pipeline threats.

F. Notice of Proposed Rulemaking

On April 8, 2016, PHMSA published an NPRM seeking public comments
on the revision of the Federal Pipeline Safety Regulations applicable
to the safety of gas transmission pipelines and gas gathering pipelines
(81 FR 20721).\61\ When developing the NPRM, PHMSA considered the
comments it received from the ANPRM and proposed new pipeline safety
requirements and revisions of existing requirements in several major
topic areas, including those topics addressing congressional mandates
and related NTSB recommendations. A summary of the NPRM proposals and
topics pertinent to this rulemaking, the comments received on those
specific proposals, and PHMSA's response to the comments received is
below under the ``Analysis of Comments and PHMSA Response'' section.
---------------------------------------------------------------------------

\61\ https://www.regulations.gov/document?D=PHMSA-2011-0023-0118.
---------------------------------------------------------------------------

PHMSA determined it could more quickly move a rulemaking that
focuses on the mandates from the 2011 Pipeline Safety Act by splitting
out the other provisions contained in the NPRM into two other, separate
rules. Promptly issuing a final rule focused on mandates will improve
safety and respond to Congress, industry, and public safety groups.

[[Page 52190]]

As such, not all the topics from the NPRM nor the comments received
on those topics are discussed as a part of this rulemaking. PHMSA
intends to issue two additional final rules to address the remaining
topics from the NPRM.

III. Analysis of NPRM Comments, GPAC Recommendations, and PHMSA
Response

On April 8, 2016, PHMSA published an NPRM (81 FR 20722) proposing
several amendments to 49 CFR part 192. The NPRM proposed amendments
addressing topiic areas including verification of pipeline material
properties, MAOP reconfirmation, IM clarifications, MAOP exceedance
reports, ILI launcher and receiver safety, assessing areas outside of
HCAs, and recordkeeping. The comment period for the NPRM ended on July
7, 2016. PHMSA received approximately 300 submissions containing
thousands of comments on the NPRM. Submissions were received from
groups representing the regulated pipeline industry; groups
representing public interests, including environmental groups; State
utility commissions and regulators; members of Congress; specific
pipeline operators; and private citizens.
Some of the comments PHMSA received in response to the NPRM were
comments beyond the scope or authority of the proposed regulations. The
absence of amendments in this proceeding involving other pipeline
safety issues (including several topics listed in the ANPRM) does not
mean that PHMSA determined additional rules or amendments on those
other issues are not needed. Such issues may be the subject of other
existing rulemaking proceedings or future rulemaking proceedings.
The remaining comments reflect a wide variety of views on the
merits of particular sections of the proposed regulations. PHMSA read
and considered all the comments posted to the docket for this
rulemaking.
The Technical Pipeline Safety Standards Committee, commonly known
as the Gas Pipeline Advisory Committee (GPAC; the committee), is a
statutorily mandated advisory committee that advises PHMSA on proposed
safety standards, risk assessments, and safety policies for natural gas
pipelines.\62\ The GPAC is one of two pipeline advisory committees that
focus on technical safety standards that were established under the
Federal Advisory Committee Act (Pub. L. 92-463, 5 U.S.C. App. 1-16) and
section 60115 of the Federal Pipeline Safety Statutes (49 U.S.C. Chap.
601). Each committee consists of 15 members, with membership divided
among Federal and State agencies, regulated industry, and the public.
The committees consider the ``technical feasibility, reasonableness,
cost-effectiveness, and practicability'' of each proposed pipeline
safety standard and provide PHMSA with recommended actions pertaining
to those proposals.
---------------------------------------------------------------------------

\62\ 49 U.S.C. 60115.
---------------------------------------------------------------------------

Due to the size and technical detail of this rulemaking, the GPAC
met five times to discuss this rulemaking throughout 2017 and 2018.\63\
During those meetings, the GPAC considered the specific regulatory
proposals of the NPRM and discussed various comments made on the NPRM's
proposal by stakeholders, including the pipeline industry at large,
public interest groups, and government entities. To assist the GPAC in
its deliberations, PHMSA presented a description and summary of the
major proposals in the NPRM and the comments received on those issues.
PHMSA also assisted the committee by fostering discussion and
developing recommendations by providing direction on which issues were
most pressing.
---------------------------------------------------------------------------

\63\ Specifically, the GPAC met on January 11-12, 2017; June 6-
7, 2017; December 14-15, 2017; March 2, 2018; and March 26-28, 2018.
Information on these meetings can be found at regulations.gov under
docket PHMSA-2011-0023 and at PHMSA's public meeting page: https://primis.phmsa.dot.gov/meetings/.
---------------------------------------------------------------------------

For the proposals finalized in this rulemaking, the committee came
to consensus when voting on the technical feasibility, reasonableness,
cost-effectiveness, and practicability of the NPRM's provisions. In
many instances, the committee recommended changes to certain proposals
that the committee found would make certain proposals more feasible,
reasonable, cost-effective, or practicable.
The substantive comments received on the NPRM as well as the GPAC's
recommendations are organized by topic below and are discussed in the
appropriate section with PHMSA's response and resolution to those
comments.

A. Verification of Pipeline Material Properties and Attributes--Sec.
192.607

i.--Applicability

1. Summary of PHMSA's Proposal
Section 23 of the 2011 Pipeline Safety Act requires the Secretary
of Transportation to require the verification of records used to
establish MAOP to ensure they accurately reflect the physical and
operational characteristics of the pipelines and to confirm the
established MAOP of gas transmission pipelines. Since 2012, operators
have submitted information indicating that a portion of transmission
pipeline segments do not have adequate records to establish MAOP or
that accurately reflect the physical and operational characteristics of
the pipeline. Therefore, PHMSA determined that additional regulations
are needed to implement this requirement of the 2011 Pipeline Safety
Act. Specifically, PHMSA proposed that operators conduct tests and
other actions needed to confirm and document the physical and
operational characteristics for those pipeline segments where adequate
records are not available, and PHMSA proposed standards for performing
these actions. PHMSA sought to appropriately address pipeline risk
without extending the requirement to all pipelines where risk and
potential consequences are not as significant, such as pipelines in
remote, sparsely-populated areas. As a result, PHMSA proposed criteria
that would require material properties verification for higher-risk
locations through a new Sec. 192.607; specifically, by adding
requirements for the verification of pipeline material properties for
existing onshore, steel, gas transmission pipelines that are located in
HCAs or Class 3 or Class 4 locations.
2. Summary of Public Comment
Several citizen and public safety groups, including Pipeline Safety
Trust (PST), Pipeline Safety Coalition, National Association of
Pipeline Safety Representatives (NAPSR), Coalition to Reroute Nexus,
Earthworks, and The Michigan Coalition to Protect Public Rights-of-Way,
supported the proposed provisions for establishing adequate material
properties documentation and records. Some of these groups noted that
the need for this section in the regulations would suggest poor
operator implementation of the IM requirements since the inception of
subpart O back in 2003.
Trade associations and pipeline industry entities were largely
opposed to the material properties verification requirements for
several reasons outlined below.
Many trade association and pipeline industry commenters expressed
concern that the material properties verification requirements were
potentially retroactive. American Petroleum Institute (API) and
American Gas Association (AGA) asserted that this proposal would
require operators to document and verify the material properties of
existing pipelines beyond

[[Page 52191]]

what was required by the regulations that were in place at the time
those pipelines were put into service. These commenters stated that
this retroactive requirement extends beyond the congressional authority
provided to PHMSA. Several commenters, including AGL Resources,
Dominion East Ohio, and New Jersey Natural Gas, expressed concern with
the proposed provisions for verifying specific physical characteristics
of pipelines, fittings, valves, flanges, and components for existing
transmission pipelines. These stakeholders stated that it might be
impossible to achieve ``reliable, traceable, verifiable, and complete''
records on a retroactive basis for existing pipelines. Some commenters,
including AGA, stated that a pipeline's MAOP should be considered
confirmed and there should be no need to further document material
properties to verify the MAOP if operators had a pressure test record
of a test conducted at 1.25 times MAOP for the pipeline segment.
Commenters also expressed concern about PHMSA's proposed new
references to the material properties verification requirements under
Sec. 192.607 throughout part 192, which could be interpreted as being
applicable not only to a subset of transmission pipelines but also to
distribution pipelines. Commenters stated that PHMSA did not provide
justification within the NPRM for applying material properties
verification requirements to distribution systems, and such
requirements would significantly impact distribution systems. These
commenters requested that PHMSA explicitly exclude distribution
pipelines from the proposed material properties verification
requirements. Similarly, some commenters urged PHMSA to restrict these
requirements only to gas transmission lines operating at greater than
30 percent SMYS based on the premise that lines operating below 30
percent SMYS, in most cases, tend to leak before rupture and are
therefore less risky to the public. Additionally, commenters suggested
that PHMSA review the various cross-references in the NPRM and
eliminate those that would expand the applicability of the material
properties verification requirements beyond onshore steel gas
transmission pipelines in HCAs and Class 3 and Class 4 locations.
Some commenters recommended changing the size limit for small
components that might trigger the material properties verification
requirements from greater-than-or-equal-to 2 inches to greater-than 2
inches. A further comment on components discussed how the material
properties verification provisions, as proposed, require the operator
to know the weld-end bevel conditions for in-service valves and
flanges. Operators noted, however, that once a weld-end is welded to a
piece of pipe or other component, there is no method that can be
employed to determine the condition of that bevel. Accordingly, the
commenters requested this requirement be deleted or clarified. There
was also a comment to delete the sampling requirement and not perform
material properties verification if, when the applicable pipeline is
excavated for repairs, a repair sleeve is installed. Other commenters
felt that the proposed material properties verification requirements
would not deliver clear, identifiable safety benefits and would lead to
several unintended consequences that would decrease the integrity of
pipeline systems and cause energy supply disruption. Accordingly, these
commenters suggested PHMSA withdraw the proposed requirements for
material properties verification.
Multiple commenters also expressed concerns that the revised
provisions for establishing MAOP under Sec. 192.619, specifically the
requirement for operators to maintain all records necessary to
establish and document a pipeline's MAOP as long as the pipeline
remains in service, would impose extensive new recordkeeping
requirements applicable to operators of distribution pipelines,
including retroactive recordkeeping requirements. Commenters requested
that PHMSA clarify that the new recordkeeping requirements in Sec.
192.619(f) are applicable only to gas transmission pipelines.
Pipeline industry entities also provided comments on the
relationship of the material properties verification requirements in
Sec. 192.607 and the MAOP reconfirmation requirements in Sec.
192.624. The Gas Piping Technology Committee (GPTC) suggested that the
proposed material properties verification requirements be revised to
include an option of using the provisions of Sec. 192.619(a)(1) for
establishing MAOP when traceable, verifiable, and complete material
property records are not available for calculating design pressure.
Similarly, commenters suggested operators should be allowed to
establish design yield strengths for unknown pipe grade as described at
Sec. 192.107(b)(1). Xcel Energy also stated that if an operator has
previously established MAOP as per the Sec. 192.619(a)(2) strength
test requirements or will do so per the proposed Sec. 192.624
methodology for pressure test or pressure reduction, the verification
of pipeline material proposed in Sec. 192.607 is not necessary for the
purpose of ensuring safe operation.
Over the course of the meetings on June 7, 2017, and December 14,
2017, the GPAC had a robust discussion regarding the applicability of
the material properties verification requirements. More specifically,
the GPAC discussed the fact that two separate activities drive the need
for material properties verification: (1) MAOP reconfirmation for
pipelines lacking traceable, verifiable, and complete records to
support the pipeline's current MAOP; and (2) the application of IM
principles, especially where anomaly response and remediation
calculations are concerned. The GPAC believed these aspects needed to
be addressed separately in the final rule.
Subsequently, on December 14, 2017, the GPAC recommended that PHMSA
modify the proposed rule by removing the applicability criteria of the
material properties verification requirements and make material
properties verification a procedure for obtaining missing or inadequate
records or otherwise verifying pipeline attributes if and when required
by MAOP reconfirmation requirements or by other code sections. In
discussing the issue, the GPAC recognized that the broad applicability
of the material properties verification requirements in the proposed
rule was PHMSA's attempt to address the issue of inadequate records for
MAOP verification, IM requirements and standard pipeline operations.
The GPAC believed amending the proposed rule to remove the proposed
applicability and instead explicitly refer back to the material
properties verification requirements, when needed, in various
regulatory sections, would more closely follow Congress' direction in
the 2011 Pipeline Safety Act.
This change would also obviate the need for operators to create a
material properties verification program plan per the originally
proposed requirements, so the GPAC recommended PHMSA remove that
requirement from the rule. Further, the committee recommended during a
later meeting that PHMSA consider modifying the rule in both Sec. Sec.
192.607 and 192.619 to clarify that the material properties
verification requirements apply to onshore steel gas transmission lines
and not to distribution or gathering pipelines.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding the scope and requirements for

[[Page 52192]]

reconfirming the material properties of pipelines with unknown or
undocumented properties. PHMSA agrees that the need for this rule is
caused, in part, by poor implementation of existing IM requirements.
However, PHMSA disagrees that the requirements would not deliver safety
benefits or would lead to decreased integrity of pipeline systems and
cause energy supply disruption. The basic knowledge of pipeline
material properties is essential to pipeline safety.
PHMSA disagrees that material properties verification is not needed
if the pipeline segment has been pressure tested to 1.25 times MAOP.
Other reasons for needing documented, confirmed material properties
(e.g., wall thickness, yield strength, and seam type) include IM
program requirements, implementation of pipe repair criteria and
determination of the design pressure of the pipeline segment. This rule
supplements existing IM requirements by providing operators a method to
reconfirm material properties without necessarily performing
destructive testing of the pipe material. Operators can use this method
in their IM programs, to reconfirm MAOP where needed, to implement
repair requirements, and to otherwise comply with part 192 where
necessary. Indeed, PHMSA hopes that operators will use this method for
material properties verification even when not specifically required by
part 192 because it provides a common-sense, opportunistic, and
practical approach for gathering the records necessary to substantiate
safe MAOPs, properly implement IM, and otherwise ensure the safe
operation of the nation's pipeline network.
PHMSA also disagrees that material properties verification is only
needed for pipeline segments operating at pressure greater than 30
percent of SMYS. IM requirements apply to all gas transmission pipeline
segments in HCAs, including those that operate at less than 30 percent
of SMYS. Moreover, the gas transmission subpart O integrity management
regulations at Sec. 192.917(b), Data gathering and integration,
require operators to gather pipe attributes including pipe wall
thickness, diameter, seam type and joint factor, manufacturer,
manufacturing date, and material properties. These physical properties
and attributes are explicitly outlined in ASME/ANSI B31.8S--2004
Edition, section 4, table 1--Data Elements for Prescriptive Pipeline
Integrity Program, which is incorporated by reference in Sec. 192.7.
PHMSA did not intend that the requirements proposed in Sec.
192.607 would be retroactive or would apply to distribution or
gathering lines. Therefore, PHMSA is clarifying the final rule to
assure that the provisions finalized in Sec. 192.607 are not
retroactive \64\ and apply only to transmission lines. However, PHMSA
believes that operators with IM programs that are properly following
subpart O, specifically Sec. 192.917(b), should already have this pipe
information.
---------------------------------------------------------------------------

\64\ The material properties verification requirements are not
retroactive as they mandate the creation and retention of records as
operators execute the methodology in Sec. 192.607 on a prospective
basis. Operators who have not verified their records in accordance
with this methodology before the effective date of this rule will
not be subject to enforcement action based on Sec. 192.607. After
the effective date of the rule, operators with missing or inadequate
records must follow the verification methodology in Sec. 192.607.
---------------------------------------------------------------------------

Regarding material properties verification for non-line pipe
components, PHMSA is revising this final rule to apply the requirements
to components greater than 2 inches and is removing the requirement to
know the weld-end bevel conditions. PHMSA agrees with the GPAC members
who commented that 2-inch pipe is not used in mainline applications and
need not be subject to additional regulatory requirements to maintain
safety. Also, fittings and flanges will have an ANSI class rating that
will confirm whether the components meet or exceed the MAOP of the
pipeline, so further regulatory requirements for components under 2
inches are not necessary to maintain safety.
To further address comments and the GPAC recommendations related to
the scope and applicability of the material properties verification
requirements, PHMSA is modifying this final rule to address MAOP
reconfirmation and material properties verification separately from the
application of IM principles. PHMSA believes this change will improve
the organization of the rule. PHMSA is accomplishing this by removing
the applicability criteria of the material properties verification
requirements and making material properties verification a procedure
for obtaining records for physical pipeline properties and attributes
that are not documented in traceable, verifiable, and complete records
or otherwise verifying physical pipeline properties and attributes when
required by MAOP reconfirmation requirements, IM requirements, repair
requirements, or other code sections. This obviates the need for all
operators to create a material properties verification program plan per
the originally proposed requirements, so PHMSA is removing that
requirement from the rule as well. Instead, only operators who do not
have traceable, verifiable, and complete records will be required to
create such a plan.

A. Verification of Pipeline Material Properties and Attributes--Sec.
192.607

ii.--Method

1. Summary of PHMSA's Proposal
The conventional method for determining the properties of unknown
steel pipe material is to cut test specimens known as ``coupons'' out
of the pipe and perform destructive testing. Because of the large
amount of pipe operators reported in Annual Report submissions for
which there are unknown or inadequately documented properties, the cost
of such a conventional approach would likely be onerous. Therefore,
PHMSA proposed standards in Sec. 192.607 by which operators could
develop a material properties verification plan and use an
opportunistic sampling technique to re-constitute and document material
properties in a more cost-effective manner. More specifically, PHMSA
proposed to allow operators to use recently developed technology to
perform in situ, non-destructive examinations for determining the
properties of unknown steel pipe material.
While PHMSA acknowledged in the preamble of the NPRM that such
techniques may not be possible in every situation, PHMSA stated that it
was aware that this option is already being widely deployed in the
pipeline industry. Secondly, PHMSA proposed to allow operators to
determine pipe properties at a sampling of similar locations and apply
those results to the entire population of pipeline segments. PHMSA
proposed to allow operators to take advantage of opportunities when the
pipeline is exposed for other reasons, such as during maintenance and
repair excavations, by requiring that material properties be verified
whenever the pipe is exposed. This would reduce the number of
excavations that might otherwise be required. Excavations are a large
portion of the cost of re-constituting material properties for unknown
pipe.
2. Summary of Public Comment
Several commenters suggested that the data required by the material
properties verification process proposed by PHMSA can be obtained only
through destructive pipe testing. These commenters asserted that the
proposed requirements would lead to unnecessary service outages,
increased methane emissions, and increased personnel

[[Page 52193]]

safety risks due to unnecessary excavation activities. Black Hills
Energy stated that their pipeline system consists of mainly smaller-
diameter transmission pipelines and that the proposed provisions would
force them to take lines out of service to perform costly cutouts. API
asserted that the expense and risk required for the excavations
necessary to comply with the proposed provisions outweigh the value of
obtaining and documenting material pipe properties. Some commenters
suggested that it would be less costly for operators to simply replace
pipe rather than obtain the material properties for pipe already in the
ground. A commenter asserted that the proposed requirements would
require unnecessary breaching of the pipeline coating, which is
important for effective cathodic protection. API suggested that rather
than requiring operators to gather documentation on material properties
that may only be of marginal value for assessing pipeline safety, PHMSA
should require a combination of hydrostatic pressure testing and ILI.
API stated that, as opposed to the proposed rule's focus on the precise
documentation of materials, this would appropriately shift the emphasis
of the proposed regulations to confirming MAOP and away from material
properties verification.
Several commenters stated that some of the data that PHMSA proposed
operators verify is unnecessary for MAOP reconfirmation or other
operational reasons. For example, the Interstate Natural Gas
Association of America (INGAA) stated that several of the data elements
that would need to be verified pursuant to the proposed material
properties verification requirements are unnecessary for integrity
management-related activities. Commenters suggested that PHMSA limit
the required records to what is needed to calculate design pressure in
order to determine MAOP. Commenters noted that the proposed
requirements would require testing for stress corrosion cracking (SCC)
in all cases, and that the requirement should be limited to only
pipelines that are susceptible to SCC. Some commenters disagreed with
the requirement to determine and keep a record for the chemical
composition of steel transmission pipeline segments installed prior to
the effective date of the final rule, suggesting that this information
has not been previously required. Another commenter stated that the
basis for having accurate chemical composition records is unclear. PG&E
recommended that PHMSA recognize that chemical composition and
manufacturing specifications provide limited information that can be
used to evaluate the safety of an existing pipeline system. Piedmont
Natural Gas stated that any requirement to retroactively obtain
ultimate tensile strength and chemical composition is unnecessarily
burdensome and detracts from the ultimate goal of pipeline safety by
diverting valuable resources away from other risk-reduction efforts. A
similar comment asserted there was no benefit in determining pipeline
chemical compositions, as there is a high probability that many
pipelines that might otherwise have adequate material documentation
would fail the recordkeeping requirements because of a lack of existing
chemical composition records and would subsequently be subject to the
entire material properties verification process.
Pipeline industry entities also commented on the proposed sampling
and testing requirements that would occur during excavations.
Commenters asserted that the sampling requirements should be removed,
and the number of excavations should not be specified. One commenter
stated that the minimum number of excavations should be determined by
the operator in their material properties verification plan and through
statistical analysis aimed at achieving targeted confidence levels.
Texas Pipeline Association (TPA) stated that there is no technical
justification for the number of material properties tests being
required at each test location by the proposed rule, and that the
requirement of five tests in each circumferential quadrant for non-
destructive tests and one test in each circumferential quadrant for
destructive tests is unsupported in the proposal. TPA further stated
that they are unaware of any indication that there is great variability
in material properties within the body of a pipe, and that presently,
material properties verification involves a single test per cylinder.
Additionally, commenters stated this requirement could be unnecessarily
costly and have a negative impact on pipeline safety, as the integrity
of the pipeline would need to be compromised to perform these
evaluations and a new joint of pipe would need to be welded onto the
existing pipeline. Lastly, Spectra Energy Partners objected to the
requirement that non-destructive testing be validated with unity plots
comparing the results from non-destructive and destructive testing.
They stated that this severely limits the value of non-destructive
testing since the operator will have to remove samples for destructive
testing to create the unity plots.
CenterPoint Energy stated that the definition of excavation is
unclear, and that pipe may be excavated to a point for many operational
activities, including spotting for construction safety and installing
cathodic protection tests or current source wires. CenterPoint Energy
stated that they do not view these types of excavations as
opportunities for material properties verification data gathering
because that would require the full exposure of a pipeline segment and
the removal of good coating from the pipe. Another commenter suggested
that confidence specifications for non-destructive testing would add
significant cost due to inherently inaccurate test results.
Similarly, there were comments that encouraged consistency between
the material properties verification requirements and the requirements
for recordkeeping for materials, pipe design, and pipeline components.
These comments suggested that inconsistencies between the documentation
and the recordkeeping requirements could create scenarios where
operators meet the recordkeeping requirements but do not have adequate
documentation to prevent the material properties verification
requirements from triggering.
Some commenters opposed the proposed requirement to obtain a ``no
objection'' letter from PHMSA in order to use a new or other
technology. PG&E recommended that PHMSA provide additional regulatory
language to allow an operator to proceed with the new technology if a
``no objection letter'' to PHMSA is not received within 45 days prior
to the planned use of technology. They stated that operators put in
considerable time to set up contracts, schedule work, acquire permits,
and that waiting on an approval or disapproval from PHMSA can
dramatically impact schedule and costs. Further, commenters suggested
that PHMSA's enforcement and regulatory procedures do not provide for
``no objection'' letters, and adding a new process that is not well-
defined could cause additional confusion.
AGA proposed an alternative approach to material properties
verification, MAOP reconfirmation, and integrity assessments outside of
HCAs, which other pipeline industry entities supported. The approach
included requiring operators to either pressure test or utilize an
alternative technology that is determined to be of equal effectiveness
on high-risk gas transmission pipelines that do not have

[[Page 52194]]

a record of a subpart J pressure test or are currently utilizing the
grandfather clause for MAOP determination (Sec. 192.619(c)). AGA
suggested a three-tiered approach that prioritized pipelines located in
HCAs and operating at pressures greater than 30 percent SMYS. The
approach also included the use of ILI tools on all gas transmission
pipelines that are able to accommodate inspection by means of an
instrumented ILI tool. The ILI tool used would be qualified to find
defects that would fail a subpart J pressure test. Commenters stated
that this alternative approach is simpler and would allow operators to
focus resources on the areas of highest risk within pipeline systems.
In conjunction with AGA's approach, commenters recommended including
language that would allow the use of advanced ILI and non-destructive
evaluations to comply with the proposed material properties
verification requirements.
Certain commenters also suggested PHMSA provide a deadline by which
operators must implement their material properties verification plan,
as it was unclear in the proposal. Following committee discussion and
PHMSA feedback, industry groups also recommended to allow operators to
use their own statistical sampling plans when undertaking material
properties verification rather than have PHMSA specify the number of
samples that must be obtained.
At the GPAC meeting on December 14, 2017, the committee recommended
that PHMSA modify the method for material properties verification by
clarifying that operators are only required to confirm attributes
pertinent to the goal of MAOP reconfirmation, integrity management, or
other reasons when the material properties verification is being
performed. The GPAC also recommended that PHMSA require operators keep
records developed using the material properties verification method.
The GPAC recommended that PHMSA retain the opportunistic approach of
obtaining unknown or undocumented material properties when excavations
are performed for repairs or other reasons, using a one-per-mile
standard proposed by PHMSA, but allow operators to propose an
alternative statistical approach and submit a notification to PHMSA
with justification for their method. The GPAC also recommended that if
operators notify PHMSA of an alternative sampling approach, and the
operator does not receive an objection letter from PHMSA within 90 days
of such a notification, the operator can proceed with their chosen
method unless PHMSA notifies the operator that additional review time
or additional information from the operator is needed for PHMSA to
complete its review.
Similarly, the committee recommended PHMSA delete specified program
requirements for how to address sampling failures and replace that with
a requirement for operators to determine how to deal with sample
failures through an expanded sample program that is specific to their
system and circumstances. They further recommended that PHMSA require
operators to notify PHMSA of the expanded sample program and establish
a minimum standard that sampling programs must be based on a minimum 95
percent confidence level.
Further, the committee recommended that PHMSA retain the
flexibility for operators to conduct either destructive or non-
destructive tests when material properties verification is needed and
requested PHMSA drop accuracy specifications but retain the requirement
that any test methods used be validated and be performed with
calibrated equipment. The GPAC also recommended PHMSA reduce the number
of quadrants at which non-destructive evaluation tests be made from
four to two.
Regarding the number of test locations and the number of
excavations that must be performed, the GPAC recommended PHMSA
accommodate situations where a single material properties verification
test is needed (e.g., additional information is needed for an anomaly
evaluation/repair) and drop the mandatory requirements for testing
multiple joints for large excavations. The GPAC also recommended PHMSA
clarify the applicability of the requirements for developing and
implementing procedures for conducting material properties verification
tests on populations of undocumented or inadequately documented
pipeline segments and the minimum number of excavations and tests that
must be performed for those pipeline segments.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding the method for material properties verification. PHMSA
disagrees with implementing the alternative approach proposed by AGA,
but the underlying comments of AGA and others related to having an
alternative approach are discussed in this rulemaking and are addressed
below. PHMSA strongly believes that knowledge of pipeline physical
properties and attributes are essential for a modern IM program (see
Sec. 192.917(b)--Data gathering and integration) as well as effective
pipeline and public safety. The PG&E incident at San Bruno, CA, was
caused, in part, by PG&E mistakenly classifying the pipe that failed as
seamless pipe. That pipe was welded seam pipe, and the failure occurred
at a partially welded seam.
The NPRM included a list of material properties that could be
confirmed using the material properties verification process. One of
them in particular, steel toughness, is conventionally obtained only
through destructive testing. It was not PHMSA's intent that toughness
would need to be confirmed every time an operator was performing
material properties verification, thus in effect requiring destructive
testing for every location. Therefore, PHMSA is modifying this final
rule to address toughness properties in a separate paragraph and is
allowing the use of techniques that are reliable without specifying
destructive testing. This is intended to accommodate new, non-
destructive techniques currently under development. The new paragraph
with these requirements also makes it clear that toughness is required
only where needed and not necessarily in every case. PHMSA is also
modifying other sections of this final rule to provide reasonably
conservative default toughness values so that operators may achieve the
goals of IM and MAOP reconfirmation using assumed values without the
need for destructive testing. These changes will be discussed further
in subsequent sections of this document.
Similarly, PHMSA is modifying the verbiage related to the listing
of material properties to which the material properties verification
process would apply. The clarification will make it clear that the
material properties verification process only applies to the pertinent
properties needed to achieve the goals of the activity for which
material properties verification is needed, such as MAOP reconfirmation
or IM. This avoids the potential for requiring that all properties be
documented each time an operator goes out to perform material
properties verification when only a subset of properties is needed.
PHMSA is also replacing the prescriptive accuracy specifications
and unity plot validation for non-destructive testing with more general
verbiage that requires that methods are validated and that operators
account for the accuracy of the method used. This change will help
accommodate new technology and techniques currently under development
and avoid situations that

[[Page 52195]]

might require destructive testing to validate the non-destructive
methods.
In response to the comments, PHMSA is relaxing the number of test
points for non-destructive tests from four quadrants to two quadrants.
This allows the operator to perform material properties verification on
the top half of the pipe and would avoid the need to access the bottom
half of the pipe when the repair or maintenance activity would not
otherwise require it. PHMSA is also removing the proposed requirement
to conduct material verification at multiple locations within a single
large excavation based on the number of joints of line pipe exposed.
PHMSA believes the methods described in this final rule will provide
operators accurate material properties information without requiring
more excavation activities than necessary.
In this final rule, PHMSA is modifying Sec. 192.607 to
specifically list the types of excavations where operators that need to
verify material properties should seek to conduct material properties
verification. This revision intends to avoid requiring operators
perform the material properties verification process at partial
excavations that do not expose the pipeline segment. For example, PHMSA
considers excavations associated with direct examinations of anomalies
to be an opportunity to perform material properties verification.
Similarly, PHMSA is modifying the language to acknowledge the need to
perform one-time material properties verification activities at
specific locations, such as when performing repairs. An operator who
has complete material documentation for a particular pipeline segment
would not need to undertake the sampling program at excavations on that
particular segment. The sampling program is specifically required when
the operator needs to document material properties for entire segments
of pipelines.
PHMSA disagrees with the removal of the number of samples needed
and is maintaining the minimum standard to define the number of
excavations in the sampling program as 1 per mile or 150 if the
population of pipeline segments is more than 150 miles, whichever is
less. However, PHMSA is modifying the rule to provide operators the
option of proposing an alternative sampling program if they send a
notification and justification of the alternative program to PHMSA in
accordance with the new notification procedures at Sec. 192.18.
Operators may use an alternative sampling program 91 days after
submitting a notification per Sec. 192.18 to PHMSA if the operator has
not received a letter of objection or a request from PHMSA for more
time to review.
PHMSA is also withdrawing the expanded sampling requirements to
address cases where operators identify problems in the initial sampling
program. Instead, operators may use an alternative sampling approach
that addresses how the operator's sampling plan will address findings
that reveal physical pipeline properties and attributes that are not
consistent with all available information or existing expectations or
assumed physical pipeline properties and attributes used for pipeline
operations and maintenance in the past. Operators taking such an
approach must notify PHMSA of the adverse findings and provide PHMSA
with specific details of the alternative sampling plan with a
justification for such a plan in a notification to PHMSA. The
alternative sampling program must be designed to achieve a 95 percent
confidence level. In accordance with the new notification procedures at
Sec. 192.18, operators may use an alternative sampling plan 91 days
after submitting a notification to PHMSA if the operator has not
received a letter of objection or a request from PHMSA for more time to
review.
In response to committee discussion, PHMSA is modifying its
notification process broadly throughout part 192 to allow operators to
propose using methods and technologies by notifying PHMSA in accordance
with the new procedures in Sec. 192.18. If an operator does not
receive a letter of objection or a request from PHMSA for more time to
review within 90 days of the notification, then the operator may use
the proposed method or technology. Some committee members were
concerned that some provisions throughout the NPRM would require action
from PHMSA in the form of a ``no objection'' letter. Members noted that
such a process can leave companies unable to proceed until PHMSA
provided affirmative approval of the request. Committee members
suggested that it may be more efficient and less burdensome for PHMSA
to issue letters to operators only when they specifically object to
proposed plans or solutions, and otherwise allow the operator to
proceed as planned in the absence of such a letter. Other members were
concerned that PHMSA might authorize sub-optimal plans or technologies
by missing a deadline. To this end, members recommended an approach
where PHMSA could request additional time for review beyond the 90-day
period. PHMSA noted at the meeting that this is a similar process that
is used by PHMSA for state waivers and the change should improve
regulatory efficiency.
PHMSA's letter or email of objection will specify the reasons PHMSA
does not approve of the proposed method or technology, while a request
from PHMSA for more time to review the notification will extend the
review period beyond 90 days. Further, to establish a verifiable
record, it will be PHMSA's policy to send a ``no objection'' letter or
email, either before or after the 90-day review period, when PHMSA does
not object to an operator's proposed method or technology. PHMSA is
applying this approach to other places in this rulemaking that require
notifications and has created a general notification provision in
subpart A of part 192.
PHMSA is modifying the recordkeeping requirement for the material
properties verification provisions to avoid potential conflicts with
other provisions in this rulemaking, such as MAOP reconfirmation, to
clarify that operators are required to keep any records created, for
the life of the pipeline, when verifying specific properties using the
methods in Sec. 192.607. These records must also be traceable,
verifiable, and complete. These recordkeeping requirements are not
retroactive, as they mandate the creation and retention of records as
operators execute the methodology in Sec. 192.607 on a prospective
basis.
PHMSA disagrees with commenters that asked for PHMSA to establish a
deadline for operators to complete the sampling programs. The
opportunistic approach PHMSA proposed and retained for this final rule
requires material properties verification activities to occur at
excavation sites where operators are directly examining anomalies;
performing in-situ evaluations; or are performing repairs, remediation,
or maintenance. PHMSA does not expect operators to perform material
properties verification for unknown pipe properties on pipeline
segments exposed during one-call excavations. PHMSA has determined this
approach is reasonable and will minimize the cost impacts of this final
rule. A deadline for the material properties verification requirements
of this rulemaking is not practical because it is impossible to
forecast the rate or timing at which opportunities would arise to
perform material properties verification for a given population of
pipe.
Lastly, operators should have most of the required pipe information
from following Sec. 192.917(b) since subpart O of part 192 was
codified over 15 years

[[Page 52196]]

ago in 2003. Section 192.917(b) requires operators to identify and
evaluate the potential threats to pipeline segments by gathering and
integrating existing data and information on the entire pipeline that
could be relevant to the pipeline segment. In performing this
identification and evaluation, operators must follow the requirements
in ASME/ANSI B31.8S, section 4, and at a minimum gather and evaluate
the set of data specified in Appendix A to ASME/ANSI B31.8S. The
material properties needed to establish and substantiate MAOP are
included in these lists.

B. MAOP Reconfirmation--Sec. Sec. 192.624 & 192.632

i.--Applicability

1. Summary of PHMSA's Proposal
In the NPRM, PHMSA proposed to require operators reconfirm MAOP for
the following three categories of pipeline:
(1) Grandfathered pipe, in direct response to section 23(d) of the
2011 Pipeline Safety Act and NTSB recommendation P-11-14;
(2) Pipe for which documentation is inadequate to support the MAOP,
in direct response to section 23(c) of the 2011 Pipeline Safety Act;
and
(3) Pipe that has experienced a reportable in-service incident
since its most recent successful subpart J pressure test due to an
original manufacturing-related defect; a construction-, installation-,
or fabrication-related defect; or a cracking-related defect, including,
but not limited to, seam cracking, girth weld cracking, selective seam
weld corrosion, hard spots, or stress corrosion cracking.
It is important to note that a given pipeline segment for which the
MAOP reconfirmation process would apply might fit into one, two, or all
three of these proposed categories. For pipeline segments where records
of the pipeline physical properties and attributes to substantiate the
current MAOP are not documented in traceable, verifiable, and complete
records, only those segments located within an HCA or a Class 3 or
Class 4 location would be subject to the MAOP reconfirmation process
under the NPRM.
This proposal directly correlates to section 23 of the 2011
Pipeline Safety Act and NTSB recommendation P-11-14 regarding the need
for spike hydrostatic testing where in-service incidents have occurred.
The NTSB recommended such testing for all pipe manufactured before
1970.
For pipeline segments where operators established the MAOP in
accordance with the grandfather clause at Sec. 192.619(c) (i.e.,
pipeline segments where the MAOP is based upon the highest actual
operating pressure records from a 5-year interval between July 1, 1965,
to July 1, 1970, and where operators therefore do not have pressure
test or material property records) or for segments with a history of
in-service incidents caused by cracks or crack-like defects, PHMSA
proposed to restrict the applicability of MAOP reconfirmation to HCAs,
Class 3 or Class 4 locations, or MCAs, if the MCA segment can
accommodate an ILI tool. The proposed inclusion of pipeline segments in
these locations and with these traits slightly expand on the mandate
contained in section 23 of the 2011 Pipeline Safety Act, which applied
only to previously untested pipeline segments operating at a pressure
greater than 30 percent SMYS located in an HCA.
In recommendation P-11-14, the NTSB recommended that all pipe
manufactured before 1970 be subjected to a hydrostatic pressure test
that would include a spike hydrostatic test, which PHMSA considered in
its process for reconfirming MAOP. PHMSA's preliminary evaluation
concluded that doing so may not be cost-effective, since a large amount
of such pipe could be in remote locations where the likelihood of
personal injury or property damage as a result of an incident would be
low.
PHMSA's proposal expanded the applicability of MAOP reconfirmation
beyond the minimum required by the congressional mandate to include
pipe operating at less than 30 percent SMYS. In addition, the NPRM
expanded the location criteria to include some non-HCA locations in the
form of MCAs and Class 3 and Class 4 locations. As PHMSA proposed in
the definitions section of the NPRM, MCAs are areas that, while not
meeting the HCA criteria, include 5 or more persons or dwellings
intended for human occupation or are otherwise locations where people
congregate, including the right-of-ways of major roadways. See section
H of this final rule for additional background on the MCA definition.
The NPRM also specified that the MAOP reconfirmation process would
apply only to MCA pipeline segments able to accommodate an ILI tool.
This provision would not preclude an operator from choosing to conduct
a pressure test, but it would avoid forcing operators to conduct a
pressure test because the pipeline segment was not ``piggable.''
2. Summary of Public Comment
Many stakeholders provided input on the proposed provisions in
Sec. 192.624 that require MAOP reconfirmation for pipeline segments
previously excluded from testing by the grandfather clause, pipeline
segments without adequate documentation to substantiate the current
MAOP, and pipeline segments that have experienced a reportable in-
service incident.
Regarding the first criterion above, several commenters, including
INGAA, AGA, and NAPSR, generally supported the provision requiring
operators of pipeline segments where the MAOP was established via the
grandfather clause to reconfirm the MAOP of those segments. Several of
the pipeline industry trade associations and industry entities,
however, did not support the proposed application of these criteria to
all grandfathered pipeline segments within HCAs, Class 3 and Class 4
locations, and Class 1 and Class 2 piggable segments within MCAs. Gas
Processors Association's Midstream Association (GPA) and AGA stated
that while they support the congressional mandate to conduct testing to
confirm the material strength of previously untested gas transmission
pipelines in HCAs that operate at a pressure above 30 percent SMYS,
they oppose the proposed provisions which extend to additional pipeline
segments. INGAA and Washington Gas supported the applicability of MAOP
reconfirmation in MCAs for pipelines operating at greater than or equal
to 30 percent SMYS but disagreed with the proposed provisions that
included MCA pipelines operating at less than 30 percent SMYS.
Some citizen groups, including PST, expressed concern that the
proposed changes regarding the grandfather clause did not go far enough
and suggested that PHMSA should fully implement the recommendations set
forth by the NTSB. They stated that PHMSA should eliminate the
grandfather clause given that the proposed provisions would not include
the following groups of pipelines: (1) Pipelines in non-HCA areas
within Class 1 and Class 2 locations; and (2) pipeline segments for
which there is an inadequate record of a hydrostatic pressure test in
areas newly designated as an MCA that are not capable of being assessed
by an in-line tool. Conversely, Northeast Gas Association (NGA) stated
that PHMSA should retain the grandfather clause as it prevents
existing, historically safe, and maintained pipelines from being
subjected to unwarranted requirements.
For pipeline segments where operators do not have adequate
documentation to support the current MAOP and that PHMSA proposed would
be subject to the new MAOP reconfirmation requirements, some commenters
stated that they support the

[[Page 52197]]

requirement to the extent that it is consistent with the congressional
mandate to reconfirm MAOP for pipeline segments with insufficient
records within Class 3 and Class 4 locations and Class 1 and Class 2
HCAs. These commenters further stated that Sec. 192.624(a)(2) within
the proposed MAOP reconfirmation requirements should be revised to
clarify that it applies only to those gas transmission pipeline
segments in HCAs and Class 3 and Class 4 locations that were
constructed and put into operation since the adoption of the Federal
Pipeline Safety Regulations in 1970, stating that otherwise Sec.
192.624(a)(2) would apply to those pipelines put into service prior to
the implementation of Federal regulations where the requirement to
maintain a pressure test record does not apply. Some commenters also
stated that PHMSA should revise Sec. 192.624(a) within the proposed
MAOP reconfirmation requirements to make clear that operators that have
used one of the proposed allowable methods for establishing MAOP in
Sec. 192.624(b) other than the pressure test method are not required
to have a pressure test record to comply with the record requirements
of the section. Washington Gas asserted that the MAOP reconfirmation
requirements should apply to only pipeline segments in HCAs that
operate at a pressure of greater than or equal to 30 percent SMYS.
Other commenters, including Xcel Energy, stated that the proposed
provisions should allow operator discretion regarding what constitutes
a reliable, traceable, verifiable, and complete record to determine the
necessary documentation to support a pressure test record and the
necessary material properties for MAOP verification. Additionally, AGA
recommended the deletion of the phrase ``reliable, traceable,
verifiable, and complete'' from the proposed MAOP reconfirmation
provisions in Sec. 192.624(a)(2). Similarly, other commenters,
including INGAA, recommended omitting ``reliable'' from the phrase and
provided a suggested definition for ``traceable, verifiable, and
complete.''
Lastly, with regard to the third category of applicable pipeline
segments to the proposed MAOP reconfirmation requirements, many
commenters either disagreed or requested clarification for the
requirement that MAOP must be reconfirmed in cases where an in-service
incident occurred due to a manufacturing defect listed under Sec.
192.624(a)(1). For example, INGAA stated that an operator can evaluate
such manufacturing defects more effectively through ongoing operations
and maintenance activities rather than through MAOP reconfirmation, and
that the defects PHMSA is concerned with are already addressed through
integrity management. Similarly, Boardwalk Pipeline stated that
pipelines that have experienced an in-service incident because of the
listed defects in Sec. 192.624(a)(1) should be subject to integrity
management measures rather than MAOP reconfirmation. TransCanada and
TPA recommended adding text to the applicability section of the MAOP
reconfirmation requirements that would exclude a pipeline segment from
such requirements if the operator has already acted to address the
cause of the reported incident. Additionally, one commenter suggested
that this requirement should apply only to pipelines in HCAs. Some
commenters, including AGA and Consolidated Edison of New York (Con Ed),
also requested additional time to comply with the proposed MAOP
reconfirmation provisions, asserting that operators would be required
to replace many of their transmission mains to comply with the new
requirements because their current records would not be satisfactory.
Due to the urban density and scale of the service areas of certain
operators, AGA and Con Ed stated that this replacement process would
take longer than the 15-year schedule provided in the rule. One
commenter suggested that if the applicability criteria for pipeline
segments with in-service incidents and manufacturing defects remains in
the rule, it should be limited to a more contemporary time frame, such
as a rolling 15-year window or those in-service incidents that have
occurred since 2003. Pipeline Safety Trust, on the other hand, stated
that the proposed timeframe of 15 years is too long for operators to
reconfirm MAOP in HCAs and complete critical safety work, and they
urged PHMSA to adopt significantly shorter timelines in the final rule.
Additionally, AGA asserted that the proposed MAOP provisions do not
address how the completion plan and completion dates of the section
would apply to pipelines that might experience a failure in the future
and would then be subject to the proposed MAOP reconfirmation
requirements, or for pipelines that are not currently located in a MCA
but may be in the future. Lastly, INGAA stated that section 23 of the
2011 Pipeline Safety Act requires that PHMSA consult with the Chairman
of the Federal Energy Regulatory Commission (FERC) and State regulators
before establishing timeframes for the testing of previously untested
pipes, and it is not evident that PHMSA has complied with this
requirement.
As a general comment, several stakeholders, including AGA,
Louisville Gas & Electric, New Mexico Gas Company, National Grid, NW
Natural, PECO Energy, TECO Pipeline Gas, and New York State Electric
and Gas (NYSEG), proposed an alternative method for MAOP reconfirmation
where operators would execute two separate sets of actions that they
stated could be performed simultaneously or separately. First,
operators would either assess high-risk gas transmission pipelines
using a pressure test or an alternative technology that is determined
to be of equal effectiveness. Operators would categorize these
pipelines in three tiers and schedule them for testing depending on the
pipeline's SMYS and class location. Second, operators would use an ILI
tool on all gas transmission pipelines, regardless of class location,
that are capable of accommodating ILI tools. The ILI tool used would be
qualified to find defects that would fail a subpart J pressure test.
These commenters stated that this alternative methodology was necessary
because the proposed provisions would create operational inefficiencies
that would likely result in excessive cost and limited public benefit.
In addition to providing this alternative proposal, many of these
commenters provided other assorted comments on the proposed provisions.
At the GPAC meeting on March 26, 2018, the GPAC recommended that
PHMSA revise the scope of the proposed MAOP reconfirmation provisions
by excluding lines with previously reported incidents due to crack
defects. To go along with this, the GPAC also recommended PHMSA create
a new section in subpart O of part 192, the natural gas IM regulations,
to address pipeline segments with crack-related incident histories.
Doing these actions would eliminate the need for the proposed
definitions of ``modern pipe,'' ``legacy pipe,'' and ``legacy
construction techniques,'' and the impact of this is discussed later in
this document.
The GPAC also recommended that the MAOP reconfirmation provisions
be revised to apply to pipeline segments in HCAs or Class 3 or Class 4
locations that do not have traceable, verifiable, and complete records
necessary to establish MAOP under Sec. 192.619. Previously, the
provisions were applicable to those pipeline segments without
traceable, verifiable, and complete subpart J pressure test records.
Similarly, the GPAC recommended that the MAOP

[[Page 52198]]

reconfirmation provisions only apply to grandfathered pipelines in
HCAs, Class 3 or Class 4 locations, or MCAs able to accommodate
inspection with ILI tools, and that have MAOPs producing a hoop stress
greater than or equal to 30 percent SMYS. In the NPRM, the provisions
applied to all grandfathered pipelines in those locations regardless of
SMYS. In making this recommendation, the GPAC also suggested PHMSA
review the costs and benefits of applying the MAOP reconfirmation
provisions to non-HCA Class 3 and Class 4 grandfathered pipe with MAOPs
less than 30 percent SMYS.
During the meeting on March 27, 2018, the GPAC also recommended
revisions to other sections related to the applicability of MAOP
reconfirmation provisions, including withdrawing the proposed revisions
to Sec. 192.503, which tied general requirements of the subpart J
pressure test to alternative MAOP and MAOP reconfirmation provisions,
and withdrawing the proposed revisions to Sec. 192.605(b)(5), which
cross-referenced several sections related to the MAOP reconfirmation
requirements to the requirements regarding an operator's procedural
manuals.
The GPAC also examined the provisions related to the completion
date of these actions and recommended that PHMSA revise the appropriate
paragraph to account for pipelines that may be subject to these
requirements in the future, such as for pipelines that are not in an
HCA or Class 3 or Class 4 location now, but due to population growth or
development may be in such a location in the future. More specifically,
the GPAC recommended that an operator would have to complete all
actions required by the MAOP reconfirmation provisions on 100 percent
of their pipelines that meet the applicability requirements by 15 years
after the effective date of the rule or as soon as practicable but no
later than 4 years after the pipeline segment first meets the
applicability conditions, whichever is later. The GPAC also recommended
PHMSA consider a waiver or no-objection procedure if operators cannot
meet the requirements within 4 years under this scenario.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding the applicability of MAOP reconfirmation. After considering
these comments and as recommended by the GPAC input, PHMSA is modifying
the rule to address many of these comments.
Regarding the applicability of the new MAOP reconfirmation
requirements at Sec. 192.624, PHMSA notes that a simplistic repeal of
the ``grandfather clause'' at Sec. 192.619(c) is not practical because
it applies to gathering and distribution lines. As the proposed rule
was primarily focused on the safety of gas transmission pipelines, a
broad repeal of the grandfather clause was not contemplated in the
proposed rule. Further, a major expansion of the MAOP reconfirmation
requirements beyond the scope of the congressional mandate in the 2011
Pipeline Safety Act would be costly, and the GPAC noted at the meeting
on March 26, 2018, that there may be cost-benefit concerns to test all
grandfathered pipelines. The GPAC recommended PHMSA analyze requiring
operators to reconfirm the MAOP of all grandfathered lines, and PHMSA
considered this as an alternative in the RIA.\65\
---------------------------------------------------------------------------

\65\ See section 5.9.1 of the RIA for further details.
---------------------------------------------------------------------------

In response to the comments received and the recommendations of the
GPAC, PHMSA is modifying the applicability of the MAOP reconfirmation
requirements as follows: (1) The applicability related to pipeline
segments with past in-service incidents is being eliminated. As
commenters mentioned, operational failures are already addressed within
integrity management and other subparts of part 192. Section 192.617,
for example, would require an operator of a gas transmission line that
had an in-service incident caused by an incorrect MAOP to determine the
proper MAOP of the segment before placing it back into service. Causes
of in-service failures are also already incorporated into the risk
analyses required by the current IM regulations. If the cause of an
incident is an incorrect MAOP, for example, then operators would be
required to reconfirm it following the incident within their IM
program. However, PHMSA is adding a new paragraph to strengthen the IM
requirements at Sec. 192.917(e)(6) to specifically include actions
operators must take to address pipeline segments susceptible to cracks
and crack-like defects. (2) PHMSA is also modifying the applicability
of these requirements by specifying the MAOP reconfirmation
requirements are applicable to pipeline segments that do not have the
pipeline physical properties and attributes needed to establish MAOP
documented in traceable, verifiable, and complete records, specifically
those records required to establish and substantiate the MAOP in
accordance with Sec. 192.619(a), including those records required
under Sec. 192.517(a). More specifically, these requirements to verify
MAOP would apply to such pipelines without traceable, verifiable, and
complete records in HCAs and Class 3 and Class 4 locations as specified
in the congressional mandate. Further, PHMSA is dropping the word
``reliable'' from the applicability section of the regulatory text to
be consistent with previous PHMSA advisory bulletins on this topic.\66\
(3) PHMSA is modifying the applicability of the MAOP reconfirmation
provisions for ``grandfathered'' pipeline segments to pipelines with an
MAOP greater than or equal to 30 percent of SMYS, as specified in the
congressional mandate. In addition to these requirements applying to
grandfathered pipelines in HCAs, PHMSA is retaining the MAOP
reconfirmation applicability requirement for grandfathered pipeline
segments in Class 3 and Class 4 locations and in piggable MCAs to
address the NTSB recommendation on this topic. As per the committee's
suggestion, PHMSA analyzed whether it would be feasible to make the
MAOP reconfirmation requirements applicable to non-HCA Class 3 and
Class 4 pipe operating below 30 percent SMYS. This analysis is
presented as an alternative in the RIA for this rulemaking. Ultimately,
PHMSA did not choose to include these categories of pipelines in the
scope for the applicability of the MAOP reconfirmation requirements
because the GPAC recommended it was cost-effective for the provision to
only apply to pipe operating above 30 percent SMYS in Class 3 and 4
locations and because those pipelines present the greatest risk to
safety.
---------------------------------------------------------------------------

\66\ Pipeline Safety: Verification of Records; 77 FR 26822; May
7, 2012; https://www.govinfo.gov/content/FR-2012-05-07/pdf/2012-10866.pdf.
---------------------------------------------------------------------------

With respect to the completion date, PHMSA acknowledges the
comments received stating that pipeline segments could meet
applicability criteria at some point in the future such that it would
be difficult or impossible to meet the 15-year deadline for completion.
Therefore, PHMSA agrees with the GPAC recommendation discussed above
and is modifying the requirements in this final rule to include an
alternative completion deadline of 4 years for pipeline segments that
meet the applicability standards at some point in the future, for
example for those pipeline segments that were in non-HCA locations that
later become HCA locations. However, PHMSA emphasizes that this 4-year
timeframe does not supersede, invalidate, or otherwise modify the
existing requirements in Sec. 192.611 for operators to confirm or
revise the MAOP of

[[Page 52199]]

segments within 24 months of a change in class location.
PHMSA also acknowledges that some commenters thought the 15-year
compliance timeframe for MAOP reconfirmation was too long. PHMSA
believes a 15-year timeframe is necessary to be consistent with Sec.
192.939, which allows operators to use a confirmatory direct assessment
to confirm their MAOP in two, 7-year inspection cycles. This timeframe
was discussed by the GPAC and was approved by unanimous vote. PHMSA
will note that operators are required to have 50 percent of the
applicable mileage completed within 8 years of the effective date of
the rule. PHMSA would expect operators to prioritize and reconfirm the
MAOP of the highest-risk segments first.
PHMSA is also withdrawing miscellaneous revisions to Sec. 192.503,
which tied general requirements of the subpart J pressure test to
alternative MAOP and MAOP reconfirmation provisions, and miscellaneous
revisions from Sec. 192.605(b)(5), which cross-referenced several
sections related to MAOP requirements to the requirements regarding an
operator's procedural manuals. These changes were made to simplify the
regulations.
Additionally, because PHMSA has eliminated pipeline segments with
past in-service incident history from the scope of the MAOP
reconfirmation requirements, PHMSA is striking the proposed references
within the MAOP reconfirmation requirements to the alternative MAOP
requirements at Sec. 192.620(a)(ii). Operators who used the
alternative requirements to establish the MAOP of their pipelines were
required to have complete documentation \67\ and therefore would not be
subject to the MAOP reconfirmation requirements. If an operator had
previously established the MAOP of a pipeline segment under the
alternative MAOP requirements, but has since lost the records necessary
to validate the alternative, they would have to reconfirm MAOP using
the alternative MAOP requirements, or apply for a special permit to
continue operation.
---------------------------------------------------------------------------

\67\ ``Pipeline Safety: Standards for Increasing the Maximum
Allowable Operating Pressure for Gas Transmission Pipelines; Final
Rule;'' October 17, 2008; 73 FR 62148. The effective date of the
rule was November 17, 2008.
---------------------------------------------------------------------------

Per the requirement in section 23 of the 2011 Pipeline Safety Act,
PHMSA consulted with members of FERC and State regulators, including
representatives from NAPSR and the National Association of Regulatory
Utility Commissioners, as appropriate, to establish the timeframes for
completing MAOP reconfirmation. As a part of this consultation, which
occurred as a function of the GPAC meetings from 2017 through 2018,
PHMSA accounted for potential consequences to public safety and the
environment while also accounting for minimal costs and service
disruptions. These representatives provided both input and positive
votes that the provisions surrounding MAOP reconfirmation were
technically feasible, reasonable, cost-effective, and practicable if
certain changes were made. As previously discussed, PHMSA has taken the
GPAC's input into consideration when drafting this final rule and made
the according changes to the provisions.

B. MAOP Reconfirmation--Sec. Sec. 192.624 & 192.632

ii.--Methods

In developing regulations to reconfirm MAOP where necessary,
Congress mandated that PHMSA consider safety testing methodologies that
include pressure testing and other alternative methods, including in-
line inspections, determined to be of equal or greater effectiveness.
The NTSB recommended an expansive pressure test approach to address the
safety issues identified in their investigation of the PG&E incident
through recommendations P-11-14 and P-11-15. In response to the
congressional mandate, PHMSA evaluated other methodologies and
identified five additional methods that could provide an equivalent or
greater level of safety. Therefore, PHMSA proposed to allow the
following six methods for MAOP reconfirmation, including the
conventional pressure test method.
Summary of PHMSA's Proposal: Method 1--Pressure Test
A pressure test is the most conventional assessment method by which
an operator may reconfirm a pipeline segment's MAOP. PHMSA proposed
standards for conducting pressure tests for MAOP reconfirmation in part
to meet the intent of NTSB recommendations P-11-14 and P-11-15. First,
PHMSA proposed minimum test pressure standards where a pipeline
segment's MAOP would be equal to the test pressure divided by the
greater of either 1.25 or the applicable class location factor. Second,
if the pipeline segment might be susceptible to cracks or crack-like
defects,\68\ then the operator must incorporate a spike pressure
feature into the pressure test procedure. PHMSA proposed standards for
the spike hydrostatic test in Sec. 192.506. If the operator has reason
to believe any pipeline segment may be susceptible to cracks or crack-
like defects, the operator would be required to also estimate the
remaining life of the pipeline in accordance with the same standards
specified in Method 3, the engineering critical assessment method.
---------------------------------------------------------------------------

\68\ These pipelines can include pipelines constructed with
``legacy pipe'' or using ``legacy construction techniques;''
pipelines with evidence or risk of stress corrosion cracking or
girth weld cracks; or pipelines that have experienced an incident
due to an original manufacturing-related defects, construction-
related defects, installation-related defects, or fabrication-
related defects.
---------------------------------------------------------------------------

Summary of Public Comment: Method 1--Pressure Test
Several commenters opposed the proposed provisions requiring a
spike test to be conducted as part of the pressure test for the
purposes of MAOP reconfirmation, and these comments are discussed
further under the ``spike test'' portion of the proposal and comment
summary of this rulemaking.
API suggested that a pipeline segment's MAOP can be best
established through performing a combination of pressure tests and ILI
examinations, and they discussed how operators could conduct
hydrostatic pressure testing to determine the in-place yield strength
of a segment of pipeline by conducting a ``spike'' test pressure held
for a few minutes followed by a subpart J pressure test approximately
10 percent below the spike level. API further stated that using ILI
tools in conjunction with this method would further substantiate the
results, as geometry ILI tools capable of measuring inside diameter to
detect yielding could further substantiate and quantify the results of
the pressure test.
AGA stated that while they believe that pressure testing is a
straightforward and well-established method, the proposed Method 1 MAOP
reconfirmation requirements are unnecessarily complex. AGA further
stated that subpart J provides different requirements and
specifications for pressure tests based on the type of pipe being
tested, and that Method 1 should refer to subpart J rather than to
Sec. 192.505(c) specifically, which requires unnecessarily stringent
requirements. PG&E supported the proposed provisions and committed to
pressure testing all pipes.
INGAA stated that since the basic strength properties of steel pipe
do not change over time, PHMSA should not limit allowable tests to only
those conducted after July 1, 1965, as was proposed in Sec.
192.619(a)(2)(ii). They emphasized that the test parameters, not

[[Page 52200]]

the test date, should be considered for MAOP reconfirmation. Further,
INGAA stated that recognizing the validity of earlier tests would not
necessarily mean that no further pressure tests would be conducted, as
periodic testing may be required to ensure the continued integrity of
the pipeline segment under the operator's integrity management program.
However, such additional tests are managed under IM, which is separate
from MAOP reconfirmation.
Certain commenters stated that a spike test is not required to
establish an adequate margin of safety for MAOP reconfirmation and
suggested PHMSA eliminate spike testing from the pressure test method
of MAOP reconfirmation.
Regarding the proposed definitions of ``legacy pipe'' and ``legacy
construction,'' AGA and Xcel Energy commented that as proposed, the
definitions could be interpreted to apply to distribution pipelines as
well as gas transmission pipelines. Commenters requested that PHMSA
explicitly exclude distribution pipelines from these definitions, which
would be applicable to all part 192.
On March 26, 2018, the GPAC recommended that PHMSA delete the spike
test requirements from the pressure test method of MAOP reconfirmation.
The GPAC also recommended that PHMSA require operators to perform a
pressure test in accordance with subpart J of part 192 rather than
refer to specific requirements in Sec. 192.505. Further, and as
discussed during the meetings of December 2017 and March 26, 2018, if
the applicable pressure test segment does not have traceable,
verifiable, and complete MAOP records, the operator must use the best
available information upon which the MAOP is currently based to conduct
the pressure test. The GPAC recommended PHMSA create a requirement for
the operator of such a pipeline segment to add the test segment to its
plan for opportunistically verifying material properties in accordance
with the material properties verification provisions. During the
meeting, PHMSA noted that most pressure tests would present at least
two opportunities for material properties verification at the test
manifolds.
PHMSA Response: Method 1--Pressure Test
PHMSA appreciates the information provided by the commenters
regarding the pressure test method of MAOP reconfirmation (Method 1).
After considering these comments and as recommended by the GPAC, PHMSA
is eliminating the spike testing requirement as part of the pressure
test method of MAOP reconfirmation. As commenters stated, spike testing
is primarily used for the mitigation of cracks and crack-like defects,
and PHMSA has determined it would therefore be more appropriate to be
placed within the context of threat management under IM. Additionally,
PHMSA is removing the definitions for and related references to
``legacy pipe'' and ``legacy construction'' in this final rule because
the applicability to pipe with ``legacy pipe or construction'' leaks or
failures was dropped from the applicability criteria for MAOP
reconfirmation. PHMSA also modified the rule to refer to subpart J
pressure tests rather than paragraph Sec. 192.505(c), specifically,
and to recognize the validity of earlier pressure tests. Lastly, if an
operator does not have traceable, verifiable, and complete records for
the material properties needed to establish MAOP by pressure testing,
PHMSA is requiring that operators test, in accordance with the material
verification requirements, the pipe materials cut out from the test
manifold sites at the time the pressure test is conducted. Further, if
there is a failure during the pressure test, the operator must test any
removed pipe from the pressure test failure in accordance with the
material properties verification requirements to ensure that the
segment of pipe is consistent with operator's sampling program
established under Sec. 192.607. This will avoid issues where operators
may not have the documented and verified physical pipeline material
properties and attributes that would otherwise be necessary to perform
a hydrostatic pressure test to reconfirm MAOP.
Summary of Proposal: Method 2--Pressure Reduction
In the NPRM, PHMSA proposed that pipeline operators could choose to
reduce the MAOP of the applicable pipeline segment to reconfirm the
segment's MAOP. This approach would use the recent operating pressure
as a de facto pressure test, and then an operator would set the
pipeline segment's MAOP at a slightly lower pressure. PHMSA proposed
that operators using this method set the pipeline's MAOP to no greater
than the highest actual operating pressure sustained by the pipeline
during the 18 months preceding the effective date of the final rule
divided by the greater of either 1.25 or the applicable class location,
which are the same safety factors as used for the pressure testing in
Method 1. PHMSA included standards for establishing the highest actual
sustained pressure for the purposes of reconfirming MAOP under this
method and included standards for addressing class location changes.
Additionally, PHMSA proposed that, if the operator has reason to
believe any pipeline segment contains or may be susceptible to cracks
or crack-like defects, the operator would be required to estimate the
remaining life of the pipeline.
Summary of Public Comment: Method 2--Pressure Reduction
AGA commented that the 18-month look-back time frame listed in the
pressure reduction MAOP reconfirmation method is a much too narrow time
frame for consideration and that the section should be rewritten to
clarify that the pressure reduction should be taken from either (1) the
immediate past 18 months, or (2) 5 years from the time the last
pressure reduction was taken, stating that tying the baseline pressure
to the effective date of the rule is arbitrary. Enterprise Products
recommended that PHMSA clarify the derating criteria used for pipes
that use this method of reconfirming MAOP. Further, Piedmont expressed
concern that this method does not account for the actual gap that can
occur between MAOP and operating pressure. Some commenters questioned
whether the MAOP from which to take a pressure reduction was based on
the most recent pressure test or the historical highest-pressure test,
and some commenters suggested PHMSA revise this provision to allow
operators to reconfirm the MAOP based on the existing MAOP and not
using an 18-month look-back period unless an incident caused by a
material-related or construction-related defect has occurred on the
pipeline since its last subpart J pressure test.
TPA stated that using this method unfairly penalizes operators in
situations where the operator has prepared for future needs and has not
operated at MAOP for a period greater than 18 months. Similarly,
another commenter suggested that operators who have already reduced
MAOP on pipeline segments to be proactive should not be penalized by
having to take an additional reduction in MAOP.
Some commenters recommended limiting the applicability of this
method to those pipelines operating at 30 percent SMYS or greater.
Regarding the pressure reduction method for MAOP reconfirmation,
the GPAC recommended PHMSA increase the look-back period from 18 months
to 5 years and remove the requirements for operators selecting to take
the pressure reduction to reconfirm MAOP to

[[Page 52201]]

perform fracture mechanics analysis on those pipeline segments.
PHMSA Response: Method 2--Pressure Reduction
PHMSA appreciates the information provided by the commenters
regarding the pressure reduction method of MAOP reconfirmation (Method
2). After considering these comments and as recommended by the GPAC,
PHMSA is increasing the look-back period to 5 years from the
publication date of the rule and is removing the requirements for
operators to perform fracture mechanics analysis on those pipeline
segments where the operator has selected Method 2. PHMSA made this
change because the 5-year look-back period is consistent with IM
requirements regarding MAOP confirmation.
Summary of PHMSA's Proposal: Method 3--Engineering Critical Assessment
Method 3 directly addresses the congressional mandate for PHMSA to
consider safety testing methodologies that include other alternative
methods, including ILI, determined to be of equal or greater
effectiveness. Demonstrating that knowledge gained from an ILI
assessment provides an equivalent level of safety as a pressure test is
technically challenging. PHMSA used best safety practices gained from
implementation of integrity management since 2003; development of class
location special permits; and technical research on related topics,
such as analysis of crack defects and seam defects. PHMSA applied these
principles and analytical methods to develop an engineering critical
assessment (ECA) methodology, which applies state-of-the-art fracture
mechanics analysis to analyze defects in the pipe and determine if
those defects would or would not survive a hydrostatic pressure test at
the test pressure needed to establish MAOP. In addition, PHMSA proposed
that if the operator has reason to believe any pipeline segment
contains or may be susceptible to cracks or crack-like defects, the
operator would be required to estimate the remaining life of the
pipeline using the fracture mechanics standards PHMSA specified.
Summary of Public Comment: Method 3--Engineering Critical Assessment
Several trade associations and pipeline industry entities stated
that ILI is the best and most practical method for MAOP reconfirmation
due to its cost-effectiveness and environmentally friendly nature, and
that PHMSA should allow operators to use ILI as a reconfirmation
method. These commenters, however, also stated that the requirements
proposed for the usage of ILI with an ECA are overly complicated and
burdensome, and they specifically recommended that the final rule
should be simplified so that this method will play a greater role in
MAOP reconfirmation in lieu of a pressure test. For example, INGAA
asserted that PHMSA should remove the requirements in the ECA related
to operations, maintenance, and integrity management, arguing that
these requirements do not factor into MAOP reconfirmation and would be
covered elsewhere in part 192. Further, INGAA proposed additional
alternatives for using the ECA method to obtain necessary data for MAOP
reconfirmation, asserting that these alternatives would be less
burdensome and equally effective. More specifically, INGAA suggested
removing duplicate regulatory language, removing the pre-approval
process for ILI, and adding unity plots as a method for operators to
demonstrate that ILI is reliable for identifying and sizing actionable
anomalies. TransCanada and PECO Energy Co. stated that for the ECA
method to be used by industry, the detailed requirements listed under
this method in the proposed rule should be replaced with the use of
standard ECA best practices.
Some commenters suggested that operators have long relied on sound
engineering judgments and conservative assumptions to account for
record gaps. Commenters stated that, if stripped of the ability to use
sound engineering judgment and conservative assumptions, operators
would need to substantially invest in processes, procedures, tests, and
project engineering and support to develop and implement a
comprehensive material properties verification plan as outlined in the
proposed regulations. Another commenter asked for clarification on
using assumptions of Grade A pipe (30,000 psi) versus the use of 24,000
psi as noted in Sec. 192.107(b)(2) if the SMYS or actual material
yield strength and ultimate tensile strength is unknown or is not
documented in traceable, verifiable, and complete records.
Another commenter suggested that in cases where a pipeline has been
pressure tested, but not to the level of 1.25 times MAOP, PHMSA should
allow operators to augment the original test with an ECA and other
analysis to reconfirm the pipeline segment's MAOP under method 3.
The PST stated that there are certain cases in which the ECA method
should not be allowed as an alternative to pressure testing. Citing a
white paper prepared by Accufacts, Inc. on ECA methodology, the PST
recommended that PHMSA prohibit the use of the ECA method for
determining the strength of a pipeline segment in cases where there are
girth weld crack threats, significant stress corrosion cracking
threats, or dents with stress concentrator threats.
During the GPAC meeting on March 27, 2018, the GPAC recommended
that PHMSA remove the fracture mechanics analysis for failure stress
and crack growth analysis requirements from the ECA method of MAOP
reconfirmation and move them to a stand-alone section in the
regulations. Further, the GPAC recommended that such a section should
not specify when, or for which pipeline segments, fracture mechanics
analysis would be required. The GPAC suggested that this new fracture
mechanics section outline a procedure by which operators perform
fracture mechanics analysis when required or allowed by other sections
of part 192, which was similar to its treatment of the proposed
material properties verification procedures at Sec. 192.607. Under the
GPAC's proposal, the ECA method for MAOP reconfirmation would not
contain any specific technical fracture mechanics requirements or
Charpy V-notch toughness values but would instead refer to the new
fracture mechanics section. Other recommendations related specifically
to the new fracture mechanics section are discussed in that area of the
proposal and comment summary section of this document.
The GPAC also recommended PHMSA add a requirement to verify
material properties in accordance with the rule's material properties
verification provisions if the information needed to conduct a
successful ECA is not documented in traceable, verifiable, and complete
records.
PHMSA Response: Method 3--Engineering Critical Assessment
PHMSA appreciates the information provided by the commenters
regarding the ECA method of MAOP reconfirmation (Method 3). As
recommended by the GPAC, PHMSA is removing the fracture mechanics
analysis requirements from the ECA method of MAOP reconfirmation and
moving them to a new stand-alone Sec. 192.712. PHMSA agrees this
change will improve comprehension of the regulations. This new section
does not specify when, or for which pipeline segments, fracture
mechanics analysis would be required but instead outlines a procedure
by which operators perform

[[Page 52202]]

fracture mechanics analysis when required by other sections of part
192. Section 192.712 is referenced in the pressure reduction, ECA, and
``other technology'' methods of MAOP reconfirmation under Sec.
192.624, as well as in Sec. 192.917 for cyclic fatigue loading.
Therefore, the ECA method for MAOP reconfirmation does not contain any
specific technical fracture mechanics requirements or Charpy V-notch
toughness values (full-size specimen, based on the lowest operational
temperature) but instead refers to the new Sec. 192.712. Comments
related to the assumptions an operator can use when material properties
are unknown are addressed in the discussion on Sec. 192.712 below.
PHMSA also added a requirement to verify material properties in
accordance with the rule's material properties verification provisions
at Sec. 192.607 if the information needed to conduct a successful ECA
is not documented in traceable, verifiable, and complete records.
PHMSA disagrees that the additional analytical requirements, beyond
ILI, are overly complicated or burdensome. To conclude that an ECA is
of equal or greater effectiveness as a pressure test for the purposes
of MAOP reconfirmation, as mandated by Congress, more than an ILI and
repair program is required. A pressure test proves that any flaws in
the pipe are small enough to hold the test pressure without leaking.
Such subcritical flaws must be analyzed to prove that they would pass a
pressure test, even if the pressure test is not conducted. A fracture
mechanics analysis is capable of reliably drawing such conclusions but
must be carefully and capably performed. Such an analysis also requires
accurate data. In the absence of reliable data for key parameters, such
as fracture toughness, PHMSA allows the use of appropriately
conservative assumptions. This is discussed in more detail in the
sections below.
Based on an ASME report and research sponsored by PHMSA,\69\ the
ECA analysis can be reliably used to ascertain if a pipeline segment
would pass a pressure test, even if it has seam weld cracking, and the
final rule includes requirements for conducting ILI using tools capable
of detecting girth weld cracks. The ECA must analyze any cracks or
crack-like defects remaining in the pipe, or that could remain in the
pipe, to determine the predicted failure pressure (PFP) of each defect.
---------------------------------------------------------------------------

\69\ See: American Society of Mechanical Engineers (ASME)
Standards Technology Report ``Integrity Management of Stress
Corrosion Cracking in Gas Pipeline High Consequence Areas'' (STP-PT-
011), and ``Final Summary Report and Recommendations for the
Comprehensive Study to Understand Longitudinal ERW Seam Failures--
Phase 1'' (Task 4.5); https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390.
---------------------------------------------------------------------------

PHMSA also notes that the final rule addresses cases where a
pipeline has been pressure tested, but not to the level of 1.25 times
MAOP, by allowing operators to account for those test results and
augment the original test with an ECA, or conduct an ILI tool
assessment program to characterize defects remaining in the pipe along
with using an ECA to establish MAOP, to reconfirm the pipeline
segment's MAOP using Method 3. Detailed ILI requirements are addressed
in new Sec. 192.493, which is discussed in more detail below.
PHMSA is moving the ECA process requirements in this final rule to
a new stand-alone Sec. 192.632. Section 192.624(c)(3) (ECA method of
MAOP reconfirmation) and the new Sec. 192.632 will cross-reference
each other. PHMSA decided to make this change when finalizing this
rulemaking only to improve the readability of the regulations. No
substantive changes were made to the requirements in connection with
this organizational change.
Summary of PHMSA's Proposal: Method 4--Pipe Replacement
When reconfirming MAOP on certain pipeline segments, some operators
may face significant technical challenges or costs when performing
either a pressure test or an ILI examination, and it may be more
economically viable to replace the pipeline. Therefore, PHMSA proposed
to allow pipe replacement for operators to reconfirm their MAOP. In
such cases, the replacement pipeline would be designed, constructed,
and pressure tested according to current standards to establish MAOP.
Summary of Public Comment: Method 4--Pipe Replacement
Commenters, including Mid-American Energy Company and Paiute
Pipeline, stated their support for this method. The GPAC similarly
supported this method and did not recommend any changes for this aspect
of MAOP reconfirmation.
PHMSA Response: Method 4--Pipe Replacement
PHMSA appreciates the information provided by the commenters
regarding the pipe replacement method of MAOP reconfirmation (Method
4). After considering these comments and as recommended by the GPAC,
PHMSA is retaining the proposed rule text for Method 4 in the final
rule.
Summary of PHMSA's Proposal: Method 5--Pressure Reduction for Small,
Low-Pressure Pipelines
For low-pressure, smaller-diameter pipeline segments with small
potential impact radii (PIR), PHMSA proposed an MAOP reconfirmation
method similar to the pressure reduction under Method 2. Operators of
pipeline segments for which (1) the MAOP is less than 30 percent SMYS,
(2) the PIR is less than or equal to 150 feet, (3) the nominal diameter
is equal to or less than 8 inches,\70\ and (4) which cannot be assessed
using ILI or a pressure test, may reconfirm the MAOP as the highest
actual operating pressure sustained by the pipeline segment 18 months
preceding the effective date of the final rule, divided by 1.1. In
addition to this pressure reduction, operators of these lines would be
required to perform external corrosion direct assessments in accordance
with the IM provisions, develop and implement procedures to evaluate
and mitigate any cracking defects, conduct a specified number of line
patrols at certain intervals, conduct periodic leak surveys, and
odorize the gas transported in the pipeline segment.
---------------------------------------------------------------------------

\70\ 8.625 inches actual diameter.
---------------------------------------------------------------------------

Summary of Public Comment: Method 5--Pressure Reduction for Small, Low-
Pressure Pipelines
AGA stated that PHMSA did not provide enough justification for
imposing the additional pressure reduction requirements listed under
this method, asserting that this method should require either a 10
percent pressure reduction or the implementation of additional
preventative actions that are feasible and practical, but not both. TPA
stated that the 18-month criterion penalizes operators who may have
operated pipelines at lower capacities to anticipate future needs.
Furthermore, TPA urged PHMSA to limit the requirements for MAOP
reconfirmation under Method 5 to the reduction in MAOP and not impose
additional safety requirements, stating that these pipelines are
generally considered low-stress pipelines and that their risk of
rupture is very low. Similarly, API stated that the proposed
requirements for odorization and frequent instrumented leak surveys are
impractical. Some commenters felt that the terms for small potential
impact radius and the applicable diameters should be defined.

[[Page 52203]]

On March 27, 2018, the GPAC recommended PHMSA delete the size and
pressure criteria of this method and base the applicability solely on a
potential impact radius of less than or equal to 150 feet. The GPAC
also recommended increasing the look-back period to 5 years from 18
months. Further, the GPAC recommended PHMSA strike the additional
requirements in this method related to external corrosion direct
assessment, crack analysis, gas odorization, and fracture mechanics
analysis. They also recommended PHMSA change the frequency of patrols
and surveys to 4 times a year for Class 1 and Class 2 locations, and 6
times per year for Class 3 and Class 4 locations.
PHMSA Response: Method 5--Pressure Reduction for Small, Low-Pressure
Pipelines
PHMSA appreciates the information provided by the commenters
regarding the pressure reduction method of MAOP reconfirmation for
small, low-pressure pipelines (Method 5). After considering these
comments and as recommended by the GPAC, PHMSA is deleting the pipeline
segment size and pressure criteria of this method and basing the
applicability solely on a potential impact radius of less than or equal
to 150 feet. PHMSA believes this change streamlines the regulations
while maintaining pipeline safety. PHMSA is increasing the look-back
period to 5 years, which is consistent with other sections of part 192,
including integrity management. Additionally, PHMSA is deleting the
requirements in this method related to external corrosion direct
assessment, crack analysis, gas odorization, and fracture mechanics
analysis. PHMSA is also changing the frequency of patrols and surveys
to 4 times a year for Class 1 and Class 2 locations, and 6 times per
year for Class 3 and Class 4 locations. PHMSA believes these changes
increase regulatory flexibility while maintaining pipeline safety.
Summary of Proposal: Method 6--Alternative Technology
PHMSA proposed that operators may use an alternative technical
evaluation process that provides a documented engineering analysis for
the purposes of MAOP reconfirmation. If an operator elects to use an
alternative method for MAOP reconfirmation, it would have to notify
PHMSA and provide a detailed fracture mechanics analysis--including the
safety factors--to justify the establishment of the MAOP using the
proposed alternative method. The notification would have to demonstrate
that the proposed alternative method would provide an equivalent or
greater level of safety than a pressure test. PHMSA included this
option to allow and encourage the continual research and development
needed to improve state-of-the-art fracture mechanics analysis,
integrity assessment methods, advances in metallurgical engineering,
and new techniques.
Summary of Public Comment: Method 6--Alternative Technology
For the alternative technologies method of MAOP reconfirmation,
several stakeholders opposed the timeframes, case-by-case approval
process, and procedural barriers PHMSA proposed for using this method.
Several commenters, including Cheniere Energy, Delmarva Power & Light,
and INGAA, suggested that the procedural hurdles required by the
proposed provisions would make this option difficult for operators to
use for MAOP reconfirmation as well as for any other provisions PHMSA
allows alternative technology use with notification. More specifically,
these commenters suggested that a process whereby PHMSA could object to
the use of an alternative technology at any time during a project's
lifecycle does not provide the level of certainty necessary for
operators to move forward with using alternative technologies. That
uncertainty would deter the development of what could be better or
safer alternatives.
Piedmont stated that it does not believe that the role of PHMSA
includes determining the appropriate technologies to be used to
reconfirm MAOP. Piedmont further stated that currently under subpart O,
operators are required to obtain approval from PHMSA to use alternative
technologies for integrity assessment, and that operators have waited
more than 180 days for PHMSA to respond to these requests. Piedmont
stated that this uncertainty cannot be reconciled with the planning and
business considerations that an operator must consider when evaluating
how to invest in technology and which methods to use for establishing
MAOP. The PST stated that the approval process should be similar to the
process used for special permits and that before these methods are
approved by PHMSA, they should be subject to public review and comment
under the National Environmental Policy Act of 1969 (NEPA).
At the meeting on March 27, 2018, the GPAC recommended PHMSA
incorporate the 90-day notification and objection procedure for the use
of alternative technology. To summarize, operators would have to notify
PHMSA of its intent to use other technology, and PHMSA would have 90
days to respond with an objection if PHMSA had one, or a need for more
review time. Otherwise, the operator would be free to use the proposed
method or technology.
PHMSA Response: Method 6--Alternative Technology
PHMSA appreciates the information provided by the commenters
regarding the other technology method of MAOP reconfirmation (Method
6). After considering these comments and as recommended by the GPAC,
PHMSA is modifying the rule to incorporate the 90-day notification and
objection procedure the committee recommended. Operators would have to
notify PHMSA of its intent to use other technology to reconfirm MAOP in
accordance with Sec. 192.18, and PHMSA would have 90 days to respond
with an objection if PHMSA had one or a notice that PHMSA required more
time for its review, which would extend the timeframe. Without a notice
of objection or additional review by PHMSA, the operator would be
allowed to use the alternative technology. PHMSA has successfully
applied the notification process to other technology assessments under
subpart O since its inception and does not believe a special permit
process is warranted for every notification for alternative technology.
PHMSA believes the changes made in the final rule will address the
concerns about timeliness of notification reviews by PHMSA.

B. MAOP Reconfirmation--Sec. 192.624

iii.--Spike Test

1. Summary of PHMSA's Proposal
The ``spike'' hydrostatic pressure test is a special feature of the
pressure testing method of MAOP reconfirmation. PHMSA intends this
aspect of the MAOP reconfirmation process to address the intent of NTSB
recommendations P-11-14 (related to spike testing for grandfathered
pipe) and P-11-15 (related to pressure testing to show that
manufacturing and construction-related defects are stable).
PHMSA proposed that a spike test would be required for cases where
a pipeline segment might be susceptible to cracks or crack-like
defects. Such pipe may include ``legacy pipe;'' pipe constructed using
``legacy'' construction techniques; pipelines that have experienced an
incident due to an original manufacturing-related defect, a
construction-, installation-, or fabrication-related defect; or pipe
with

[[Page 52204]]

stress corrosion cracking or girth weld cracks. Cracks and crack-like
defects in some cases may be susceptible to a phenomenon called
``pressure reversal,'' which is the failure of a defect at a pressure
less than a pressure level that the flaw has previously experienced and
survived. The increased stress from the test pressure may cause latent
cracks that are almost, but not quite, large enough to fail to grow
during the test. If the crack does not fail before the test is
completed, the resultant crack that remains in the pipe may be large
enough to no longer be able to pass another pressure test. The spike
portion of the pressure test is designed to cause such marginal crack
defects to fail during the early, spike phase of the pressure test. The
post-spike, long-duration test pressure validates the operational
strength of the pipe. Using a short-duration, very high spike pressure
followed by a long-duration integrity verification pressure provides
greater assurance that the test is not ``growing cracks'' that could
fail in-service after the test is completed. PHMSA proposed standards
for the spike hydrostatic test in Sec. 192.506. PHMSA used several
technical reports and studies, including PHMSA-sponsored research, to
inform the standards proposed for the spike test. Those materials
include, American Society of Mechanical Engineers Standards Technology
Report ``Integrity Management of Stress Corrosion Cracking in Gas
Pipeline High Consequence Areas'' (STP-PT-011), and ``Final Summary
Report and Recommendations for the Comprehensive Study to Understand
Longitudinal ERW Seam Failures--Phase 1'' (Task 4.5).\71\
---------------------------------------------------------------------------

\71\ https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390.
---------------------------------------------------------------------------

2. Summary of Public Comment
Some commenters supported the concept of requiring the use of a
spike hydrostatic pressure test as part of the MAOP reconfirmation
process for establishing MAOP but expressed concern over specific
aspects of the provision. For example, AGA urged PHMSA to allow
pneumatic pressure tests as well as hydrostatic pressure tests. In
addition, AGA disagreed with the allotted test duration provided in the
proposal. Similarly, other operators who commented, such as CenterPoint
Energy and Dominion East Ohio, stated that the proposed spike test
target hold pressure of 30 minutes exceeds the time needed to determine
the mechanical integrity of the pipeline test segment and will cause
pre-existing crack-like defects to grow. Alternatively, Dominion
Transmission, Tallgrass Energy Partners, SoCalGas, and Paiute Pipelines
stated that a test level of 100 percent SMYS, not 105 percent SMYS,
would be sufficient to remediate cracking threats. Enterprise Products
stated that the requirements for the design of a spike test should be
based on integrity science, such as fatigue life and reassessment
intervals, and suggested PHMSA's proposed spike test pressure limits
were set at an arbitrary level. Enterprise further stated that the
utility of stressing a pipe beyond 100 percent of its yield strength is
questionable and potentially damages the pipe. Other commenters,
including MidAmerican Energy Co., requested that pneumatic spike tests
to 1.5 times MAOP be allowed when the resultant pressure complies with
the limitations stated in the table in Sec. 192.503(c).
Trade associations and pipeline industry entities, including INGAA,
GPA, and TPA, asserted that PHMSA should eliminate the spike test
requirement for establishing MAOP entirely. These commenters stated
that the proposed provisions went beyond what was required to reconfirm
MAOP for an accepted margin of safety. These commenters further
asserted that spike testing is not an appropriate technique for MAOP
reconfirmation, and it could result in unintended negative consequences
without improving pipeline safety. They stated that spike testing is an
aggressive and destructive technique that should be used only in cases
in which time-dependent threats, such as a significant risk of stress
corrosion cracking, exist.
INGAA and other commenters agreed with PHMSA that the use of spike
hydrostatic testing is appropriate for time-dependent threats, such as
stress corrosion cracking. INGAA, however, suggested changes to the
proposed spike hydrostatic pressure test provisions and the cross-
reference to those provisions in the proposed IM assessment method
revisions to limit the spike testing requirement to time-dependent
threats, to test to a minimum of 100 percent SMYS instead of 105
percent, and to provide an alternative for use of an instrumented leak
survey. INGAA agreed that spike testing is the best means of testing a
pipeline with a history of environmental cracking, such as stress
corrosion cracking that has developed while a pipeline is in service,
and noted that a spike test may be of value for in-service pipelines
where metallurgical fatigue is of concern. INGAA further stated that
pressure cycling should not need to be included in the proposed spike
test provisions and that PHMSA should amend the proposed rule to limit
spike testing only to those pipeline segments with stress corrosion
cracking.
An additional commenter suggested PHMSA should allow operators to
use the short-duration spike portion of a spike pressure test to
determine the lower bound of the yield strength of the test section,
including all pipe and components that are subjected to the test
pressure. Such a test, if used for this purpose, must also confirm that
yielding beyond that experienced in a standard tensile test to
determine yield strength, typically on the order of 0.5 percent, has
not occurred. This confirmation may be demonstrated by data from a
pressure-volume plot of the test or a post-test geometry tool in-line
inspection.
Public interest and other groups, including Pipeline Safety
Coalition, Environmental Defense Fund (EDF), and NAPSR, expressed
support for spike testing, stating that it would provide for increased
pipeline safety. NAPSR further stated that the option of applying to
use alternative technology or an alternative technological evaluation
process would allow for some flexibility in cases in which a
hydrostatic test is impractical. EDF also suggested additional measures
to mitigate emissions from methane gas lost during testing.
At the GPAC meeting on March 2, 2018, the GPAC recommended that
PHMSA revise the spike test requirements to change the minimum spike
pressure to the lesser of 100 percent SMYS or 1.5 times MAOP, reduce
the spike hold time to a minimum of 15 minutes after the spike pressure
stabilizes, revise the applicable language to refer specifically to
``time-dependent'' cracking, incorporate the 90-day notification and
objection procedure discussed for other sections, and adjust the SME
requirements by adding language describing a ``qualified technical
subject matter expert'' where applicable.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding the requirements for spike pressure testing. After
considering these comments and as recommended by the GPAC, PHMSA is
modifying the rule to change the minimum spike pressure to the lesser
of 100 percent SMYS or 1.5 times MAOP, as PHMSA believes these
pressures are sufficient to maintain pipeline safety. PHMSA is
specifying a spike hold time of a minimum of 15 minutes after the spike
pressure stabilizes, rather than a 30-minute overall hold time, to be
consistent with pipeline safety. Additionally, PHMSA is

[[Page 52205]]

modifying the rule to revise the applicable language to refer
specifically to ``time-dependent'' cracking, incorporate the same
notification procedure under Sec. 192.18 with the 90-day timeframe for
objections or requests for more review time, and adjust the SME
requirements by using broader language describing a ``qualified
technical subject matter expert'' where applicable instead of
specifying technical fields of expertise such as metallurgy or fracture
mechanics. PHMSA believes these changes increase regulatory flexibility
while maintaining pipeline safety.
In addition, as stated above, the spike test is being removed from
the MAOP reconfirmation requirements. The spike test procedure in the
new Sec. 192.506 would be used whenever required by other requirements
in part 192 to address crack remediation and the integrity threat of
cracks and crack-like defects.
PHMSA disagrees with allowing pneumatic spike tests to 1.5 times
MAOP based on safety concerns. Pneumatic pressure tests are allowed in
Sec. 192.503(c), with certain limitations, for new, relocated, or
replaced pipe. For new, relocated, or replaced pipe, there is knowledge
that the pipe is likely sound and is usually manufactured with recent
mill pressure tests to confirm the pipe meets applicable standards. A
spike test to perform an integrity assessment on in-situ pipe with
known or suspected cracks or crack-like defects presents a much higher
likelihood of the pipeline segment experiencing a leak or rupture
during the test with resultant consequences, including the possibility
of fire or explosion. PHMSA notes that conducting a pneumatic test
using a compressible gas, such as air, nitrogen, or methane, would be a
safety concern for the public and operating personnel. Gas that is
highly compressed has stored energy that would be suddenly released
should there be a flaw in the pipe. Liquids, such as water, do not have
the stored energy release that a compressible gas has should the pipe
have a flaw that either leaks or ruptures. Therefore, the safety risk
of performing a hydrostatic pressure test (with water) is much lower
due to the less-compressible nature of liquids. Compressed gas would be
a fire or explosion hazard to the public. However, as specified in the
proposed and final rules, operators that desire to use a pneumatic
spike test may propose using such a test, with justification, by
submitting a notification to PHMSA.

B. MAOP Reconfirmation--Sec. 192.624

iv.--Fracture Mechanics

1. Summary of PHMSA's Proposal
In the proposal, PHMSA determined that fracture mechanics analysis
is a key aspect of meeting the congressional mandate to consider safety
testing methodologies for MAOP reconfirmation of equal or greater
effectiveness as a pressure test, including other alternative methods
such as ILI. Demonstrating that knowledge gained from an ILI assessment
provides an equivalent level of safety as a pressure test is
technically challenging. An ILI assessment might reveal the presence of
crack flaws and crack-like defects and characterize them within the
accuracy of tool performance capabilities, but determining whether
those cracks would survive a pressure test to reconfirm MAOP requires
very in-depth and highly technical analysis. Such an analysis not only
requires an accurate characterization of cracks, it also requires
accurate and known metallurgical properties of the pipe. To address
these aspects, PHMSA proposed more detailed requirements in Sec.
192.921 for evaluating defects discovered during ILI to account for
tool accuracy and other factors to accurately characterize flaw
dimensions and support accurate fracture mechanics analysis. In
addition, the material properties verification and documentation
requirements PHMSA proposed are critical to performing fracture
mechanics analysis of ILI-discovered defects that would be accurate
enough to establish MAOP in a way that is demonstrably equivalent in
safety to a pressure test. In the MAOP reconfirmation provisions, PHMSA
proposed new requirements for fracture mechanics analysis for failure
stress and cracks, listing specific requirements, standards, and data
operators must use when performing a fracture mechanics analysis.
2. Summary of Public Comment
Most industry stakeholders were opposed to the proposed fracture
mechanics requirements. AGA, New Mexico Gas Co., and TPA suggested that
fracture mechanics have a limited place in preventing pipeline failures
or predicting them accurately and should not be a component of MAOP
reconfirmation. AGA stated that the rule should not prescriptively
require fracture mechanics calculations to be performed for a broad
range of applications but should be narrowed to include only
transmission pipelines operating at a hoop stress greater than 30
percent SMYS, given that pipelines that operate below 30 percent SMYS
have a strong tendency to leak rather than rupture.
Commenters also stated that requiring fracture mechanics as any
part of the MAOP reconfirmation process was overly burdensome and
unclear. Specifically, API stated that some of the requirements listed
under the MAOP reconfirmation requirements were overly conservative and
burdensome for most situations where this technique would be used. For
instance, a commenter noted that there is no non-destructive evaluation
(NDE) methodology for obtaining Charpy V-notch toughness values.
Therefore, PHMSA's requirement to obtain Charpy V-notch toughness
values eliminates the availability of non-destructive testing. Further,
a commenter noted that the proposed ECA analysis prescribed a body
toughness of 5-ft.-lbs. and a seam toughness of 1-ft.-lbs., which are
arbitrary and very conservative. Vintage pipelines will not have Charpy
V-notch toughness data, and requiring an overly conservative assumption
of toughness is not reasonable. Toughness can vary depending on the
manufacturer, the manufacturing method, and the pipe vintage, and it
should not be prescribed in the regulations. The commenter further
noted that using the conservative defaults, especially the overly
conservative defaults PHMSA proposed, may result in an unacceptably
short remaining life of the pipeline.
Similarly, commenters recommended PHMSA allow alternative methods
of assessing strength properties that provide a suitable lower bound to
the actual strengths. Allowing alternative methods will provide
flexibility to consider conservative, but realistic, estimates of
material properties. Commenters also stated that SMEs in both
metallurgy and fracture mechanics are not needed to validate non-
destructive test (NDT) methods. Engineers with knowledge in test
validation methods but not necessarily metallurgy and fracture
mechanics are capable of validating NDT methods.
More broadly, Energy Transfer Partners suggested that the proposed
language for fracture mechanics is misplaced in MAOP reconfirmation and
should be moved to the proposed requirements for non-HCA assessments,
or elsewhere, since this text more closely resembles an ``assessment.''
Other commenters agreed with that concept, suggesting fracture
mechanics is more appropriate under the IM measures for threat
mitigation rather than for MAOP reconfirmation.
As previously discussed in this document, the GPAC recommended

[[Page 52206]]

PHMSA move the fracture mechanics analysis requirements out of the ECA
method of MAOP reconfirmation and into a new stand-alone section in the
regulations, making it a process for performing fracture mechanics
analysis whenever required or allowed by part 192. The committee
therefore recommended that PHMSA delete any cross-references to the
MAOP reconfirmation and the spike pressure test provisions. The GPAC
also recommended that operators make and retain specific records to
document fracture mechanics analyses performed.
Along with moving the fracture mechanics analysis requirements to a
stand-alone section, the GPAC had several specific recommendations
related to how the requirements would function. The GPAC recommended
PHMSA remove ILI tool performance specifications and replace them with
a requirement for operators to verify tool performance using unity
plots or equivalent technologies, and also recommended revisions to the
fracture mechanics requirements by striking the sensitivity analysis
requirements and replacing them with a requirement for operators to
account for model inaccuracies and tolerances.
As it pertains to the Charpy V-notch toughness values (full-size
specimen, based on the lowest operational temperatures) used in
fracture mechanics analysis, the GPAC recommended that operators could
use a conservative Charpy V-notch toughness value based on the sampling
requirements of the material properties verification provisions or use
Charpy V-notch toughness values from similar-vintage pipe until the
actual properties are obtained through the operator's opportunistic
testing program. The GPAC recommended that PHMSA clarify that default
Charpy V-notch toughness values of 13-ft.-lbs. for pipe body and 4-ft.-
lbs. for pipe seam only apply to pipe with suspected low-toughness
properties or unknown toughness properties. Further, if a pipeline
segment has a history of leaks or failures due to cracks, the GPAC
recommended PHMSA require the operator to work diligently to obtain any
unknown toughness data. In the interim, operators of such pipeline
segments must use Charpy V-notch toughness values of 5-ft.-lbs. for
pipe body and 1-ft.-lbs. for pipe seam. The GPAC also recommended PHMSA
include a 90-day notification procedure similar to the previously
agreed-upon procedure if operators wanted to request the use of
differing Charpy V-notch toughness values.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding the proposed fracture mechanics requirements. After
considering these comments and as recommended by the GPAC, PHMSA is
moving the fracture mechanics analysis requirements out of the ECA
method of MAOP reconfirmation and into a new stand-alone Sec. 192.712
in the regulations, making it a process by which operators must perform
fracture mechanics analysis whenever required by part 192. This change
was made to increase the readability of the regulations. As a part of
making these provisions into a stand-alone section in the regulations,
PHMSA is also deleting the references within Sec. 192.712 to the MAOP
reconfirmation and the spike pressure test provisions. PHMSA is adding
a requirement for operators to make and retain specific records
documenting any fracture mechanics analyses performed. PHMSA is also
removing ILI tool performance specifications and sensitivity analysis
requirements and replacing them with a requirement for operators to
verify tool performance using unity plots or equivalent technologies
and to account for model inaccuracies and tolerances. This change will
increase regulatory flexibility while maintaining pipeline safety.
Regarding the default Charpy V-notch toughness values (full-size
specimen, based on the lowest operational temperatures) used in
fracture mechanics analysis when actual values are not known, industry
and the GPAC had significant comments. PHMSA is aware of pipe
manufactured per API Specification 5L in this decade (2010-2019) with
Charpy V-notch toughness values for the weld seam as low as 1-ft. lbs.
that has been used in gas transmission pipelines. Furthermore, API 5L
does not contain required minimum Charpy V-notch toughness values for
the weld seam.
A single default assumed toughness value might be inappropriate or
overly conservative under some circumstances, or it might be a proper
choice under other circumstances. To address this issue in this final
rule, PHMSA is allowing the use of: (1) Charpy V-notch toughness values
(full-size specimen, based on the lowest operational temperatures) from
the same vintage and the same steel pipe manufacturers with known
properties; (2) a conservative Charpy V-notch toughness value to
determine the toughness based upon the ongoing material properties
verification process specified in Sec. 192.607; (3) maximum Charpy V-
notch toughness values of 13.0 ft.-lbs. for body cracks and 4.0 ft.-
lbs. for cold weld, lack of fusion, and selective seam weld corrosion
defects if the pipeline segment does not have a history of reportable
incidents caused by cracking or crack-like defects; (4) maximum Charpy
V-notch toughness values of 5.0 ft.-lbs. for body cracks and 1.0 ft.-
lbs. for cold weld, lack of fusion, and selective seam weld corrosion
if the pipeline segment has a history of reportable incidents caused by
cracking or crack-like defects; or (5) other appropriate Charpy V-notch
toughness values that an operator demonstrates can provide conservative
Charpy V-notch toughness values for the analysis of the crack-related
conditions of the line pipe upon submittal of a notification to PHMSA.
These modifications will provide flexibility to operators for
considering conservative but realistic estimates of material
properties.
PHMSA is also clarifying that operators do not need to use distinct
metallurgy and fracture mechanics subject matter experts to review
fracture mechanics analyses. In this final rule, PHMSA is replacing
that requirement with a general requirement stating that fracture
mechanics analyses must be reviewed and confirmed by a qualified
subject matter expert. PHMSA expects a qualified subject matter expert
to be an individual with formal or on-the-job technical training in the
technical or operational area being analyzed, evaluated, or assessed.
The operator must be able to document that the individual is
appropriately knowledgeable and experienced in the subject being
assessed.

B. MAOP Reconfirmation--Sec. 192.624

v.--Legacy Construction Techniques/Legacy Pipe

1. Summary of PHMSA's Proposal
PHMSA proposed to add a definition to part 192 for ``legacy
construction techniques,'' which defined historical practices used to
construct or repair transmission pipeline segments that are no longer
recognized as acceptable. In addition, PHMSA proposed a definition for
``legacy pipe'' that is defined by the presence of specific legacy
manufacturing, welding, and joining techniques.
2. Summary of Public Comment
AGA expressed significant concerns with the proposed definitions of
legacy pipe and legacy construction techniques for the purposes of part
192, commenting that PHMSA should eliminate the use of the terms
entirely or otherwise revise these definitions to

[[Page 52207]]

exclude currently acceptable manufacturing and construction techniques.
AGA stated if PHMSA were to codify the definitions of legacy pipe and
legacy construction techniques, then PHMSA should limit its catch-all
provisions within the language of the definitions to pipes with a
longitudinal joint factor of less than 1.0. Doing so would ultimately
include pipes with unknown joint factors, as Sec. 192.113 requires a
default longitudinal joint factor of 0.80 for any pipe with an unknown
longitudinal joint factor. Similarly, AGL Resources, Alliant Energy,
Atmos Energy, and TECO Peoples Gas supported AGA's suggested revisions
to the definitions of legacy construction techniques and legacy pipe.
API commented that PHMSA's proposed definition of legacy construction
technique inappropriately includes the repair technique of puddle welds
and recommended PHMSA clarify the definitions of wrought iron and pipe
made from Bessemer steel. Dominion Transmission commented there may be
instances where the longitudinal seam for modern day pipe is unknown,
yet the pipe is not a high-risk seam type. They stated that such pipe
does not present an integrity threat and should be excluded from the
``legacy pipe'' definition.
Gas Piping Technology Committee commented that the proposed
definition of legacy construction techniques seems to contain some
erroneous information. They asserted that the proposed definition went
too far by implying that all the listed methods are no longer used to
construct or repair pipelines, stating that while wrinkle bends may no
longer be a common construction technique, they are still allowed under
Sec. 192.315 for steel pipe operating at a pressure producing a hoop
stress of less than 30 percent of SMYS. Similarly, Oleksa and
Associates commented that some operators are still installing Dresser
couplings.
The Michigan Public Service Commission staff suggested that PHMSA
add to the definition of ``legacy construction techniques'' a
subsection that addresses other legacy construction techniques that are
not in the current list and include within this subsection language
referencing ``all other'' techniques. Northern Natural Gas proposed
PHMSA eliminate the phrase ``including any of the following
techniques'' from the definition of legacy construction techniques as
it implies the list is not complete. They suggested that the definition
of legacy pipe should differentiate between ductile and brittle pipe by
toughness values in both the seam and the pipe body. Lastly, SoCalGas
thought it would be more appropriate to reference these definitions
under the IM regulations in subpart O instead of defining the terms in
the context of the entire part.
These definitions were taken up by the GPAC in the context of the
scope of MAOP reconfirmation, and they recommended in the meeting on
March 26, 2018, that the definitions be withdrawn. Because the GPAC
recommended to revise the scope of MAOP confirmation to not include
pipelines with previous reportable incidents due to crack defects,
these definitions would no longer be needed in the rule.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding the proposed definitions for ``legacy pipe'' and ``legacy
construction techniques.'' After considering these comments and as
recommended by the GPAC, PHMSA is withdrawing these definitions from
the final rule. Because the revised scope of MAOP confirmation
requirements, discussed in the previous sections, no longer includes
pipelines with previous reportable incidents due to crack defects,
these definitions are no longer necessary.

C. Seismicity and Other Integrity Management Clarifications--Sec.
192.917

1. Summary of PHMSA's Proposal
Subpart O of 49 CFR part 192 prescribes requirements for managing
pipeline integrity in HCAs. It requires operators of covered segments
to identify potential threats to pipeline integrity and use that threat
identification in their integrity programs. Included within this
process are requirements to identify threats to which the pipeline is
susceptible, collect data for analysis, and perform a risk assessment.
Special requirements are included to address particular threats such as
third-party damage and manufacturing and construction defects.
Following the PG&E incident, the NTSB recommended that PG&E
evaluate every aspect of its IM program, paying particular attention to
the areas identified in the incident investigation, and implement a
revised IM program. PHMSA held a workshop on July 21, 2011, to address
perceived shortcomings in the implementation of IM risk assessment
processes and the information and data analysis (including records)
upon which such risk assessments are based. PHMSA also sought input
from stakeholders on these issues in the ANPRM.
Section 29 of the 2011 Pipeline Safety Act requires that operators
consider the seismicity of the geographic area in identifying and
evaluating all potential threats to each pipeline segment, pursuant to
49 CFR part 192. Pipeline threat analysis is addressed as one program
element in the IM regulations in subpart O. Addressing seismicity is
already implicitly required by Sec. 192.917 as part of addressing
outside force threat through the incorporation by reference of ASME
B31.8S. Based on the direction of the mandate, PHMSA proposed to
explicitly require that operators analyze seismicity and related
geotechnical hazards, such as geology and soil stability, as part of
the threat identification IM program element and mitigate those threats
of outside force damage. PHMSA determined this would clarify
expectations for this requirement and explicitly implement section 29
of the 2011 Pipeline Safety Act.
PHMSA also proposed revisions to Sec. 192.917(e) to clarify that
certain pipe designs must be pressure tested to assume that seam flaws
are stable and that failures or changes to operating pressures that
could affect seam stability are evaluated using fracture mechanics
analysis.
2. Summary of Public Comment
There was broad support for explicitly requiring the consideration
of the seismicity of a geographic area when identifying and evaluating
all potential threats to a pipeline segment, and several stakeholders
suggested minor revisions to the proposal. California Public Utilities
Commission (CPUC) supported the proposed provisions and recommended
adding text that would require consideration of any significant
localized threat that could affect the integrity of the pipeline. CPUC
further commented that operating conditions on the pipeline must also
be a factor when operators identify local threats.
Some commenters, including PG&E and NGA, requested further
clarification regarding what would constitute a seismic event for the
purposes of identifying threats under the IM program for compliance
purposes. AGA requested clarification on the requirements regarding
whether operators are expected to conduct a one-time investigation on
the risk of seismicity and geology, or if there is an expectation of a
periodic requirement for re-investigation.
Multiple commenters disagreed with the proposed requirement in
Sec. 192.917(e) for operators to perform annual cyclic fatigue
analyses if an operator identifies cyclic fatigue as a threat. INGAA
and National Fuel

[[Page 52208]]

suggested that cyclic fatigue is an uncommon risk for natural gas
pipelines and asserted that PHMSA did not provided significant
technical justification for this analysis requirement. Some commenters
suggested that the proposal to address cyclic fatigue and require
pressure tests on seam threats is an overcompensation for the level of
risk the threats present. Trade associations and pipeline industries
proposed several alternative requirements for the conditions under
which cyclic fatigue analyses should be required. API stated that they
did not object to the measures listed, but the proposed provisions in
Sec. 192.935(b)(2) imply that an operator must take all the actions
listed. API asserted that PHMSA should modify this proposed provision
to state that operators must consider taking the actions listed but
would not be specifically required to take all of them. Other
commenters expressed concern that these proposed requirements conflict
with the proposed requirements for pipeline segments needing to
undertake MAOP reconfirmation because they experienced an incident due
to manufacturing and construction (M&C) defects. Specifically, the
requirements under Sec. 192.917(e)(3) only allow operators to consider
M&C defects stable if they have been subjected to a hydrostatic
pressure test of 1.25 times MAOP, which would seemingly disallow or
otherwise make fruitless the other methods of MAOP reconfirmation for
these types of pipeline segments.
At the GPAC meeting on January 12, 2017, the GPAC recommended that
no changes should be made to the proposed provisions on seismicity.
Regarding Sec. 192.917(e)(2), which was discussed during the
meeting on June 6-7, 2017, the GPAC noted that, under this provision,
operators should be monitoring for condition changes that would cause
the threat to potentially activate, and those condition changes should
be what triggers a reassessment. The GPAC also noted problems with a
suggested revision of performing a cyclic fatigue analysis within a 7-
calendar-year period to match certain IM requirements because it would
then impose a hard deadline on the continuous monitoring process and
would prompt operators to act and again study cyclic fatigue even if
the monitoring showed no evidence of cyclic fatigue being a threat. At
the meeting, PHMSA suggested that operators could ensure the data
involved in a cyclic fatigue analysis is periodically verified within a
period not exceeding 7 years to align with IM requirements, but
operators would only be required to perform a full evaluation if the
data has changed. Following that discussion, the GPAC recommended
revising the proposed requirements for cyclic fatigue at Sec. 192.917
based on the discussion of GPAC members and considering PHMSA's
proposed language that was presented at the meeting.
At the GPAC meeting on March 26-28, 2018, a public commenter
suggested PHMSA remove the word ``hydrostatic'' from the requirements
for considering M&C-related defects stable because any strength test
that is approved in subpart J should qualify. Further, that public
commenter suggested adding language where a pressure reduction or an
ILI assessment with an ECA could be allowed for M&C defects as well.
Another public commenter suggested removing references to cracks in
these sections if PHMSA was intending to create a new section dedicated
to addressing crack defects.
Ultimately, the GPAC recommended PHMSA revise the proposed
requirements for M&C defects by deleting a cross-reference with the
MAOP reconfirmation requirements, updating an applicability reference,
and considering removing the term ``hydrostatic'' while allowing other
authorized testing procedures. For the requirements related to electric
resistance welded (ERW) pipe, the GPAC recommended PHMSA delete the
phrase related to pipe body cracking and have those requirements be
addressed in a new section within the IM regulations related to crack
defects.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding the consideration of seismicity and manufacturing- and
construction-related defects under the IM regulations. After
considering these comments as well as recommendations by the GPAC,
PHMSA is revising Sec. 192.917(e)(2) to require operators monitor
operating pressure cycles and periodically determine if the cyclic
fatigue analysis is valid at least once every 7 calendar years, not to
exceed 90 months, as necessary. PHMSA is also deleting a reference to
the MAOP reconfirmation requirements in Sec. 192.624 and is
referencing the new Sec. 192.712 for fracture mechanics analysis.
PHMSA believes these changes are consistent with current IM
requirements and will increase regulatory flexibility while maintaining
pipeline safety.
In Sec. 192.917(e)(3), PHMSA deleted a cross-reference to the MAOP
reconfirmation requirements in Sec. 192.624 and replaced it with a
requirement to prioritize the pipeline segment if it has experienced an
in-service reportable incident since its most recent successful subpart
J pressure test due to an original manufacturing-related defect; or a
construction-, installation-, or fabrication-related defect. This
clarifies that the IM requirement in Sec. 192.917(e)(3) is not part of
the MAOP reconfirmation standards. Although the GPAC asked PHMSA to
consider removing the term ``hydrostatic'' and allow other testing
procedures, PHMSA is retaining the term ``hydrostatic'' in Sec.
192.917(e)(3), as the proposed revision, as written, addresses NTSB
recommendation P-11-15. The NTSB specifically recommended that PHMSA
amend part 192 so that manufacturing- and construction-related defects
can only be considered stable following a postconstruction hydrostatic
pressure test of at least 1.25 times the MAOP. Therefore, deleting the
word ``hydrostatic'' would be contrary to the letter and intent of this
NTSB recommendation.
For the requirements related to ERW pipe in Sec. 192.917(e)(4),
PHMSA has deleted the phrase related to pipe body cracking and deleted
a cross-reference to the MAOP reconfirmation requirements in Sec.
192.624, referencing the new Sec. 192.712 for fracture mechanics
analysis instead for cracking and crack-related issues. PHMSA made
these changes to streamline the regulations and increase readability.

D. 6-Month Grace Period for 7-Calendar-Year Reassessment Intervals--
Sec. 192.939

1. Summary of PHMSA's Proposal
Section 5 of the 2011 Pipeline Safety Act identifies a technical
correction amending 49 U.S.C. 60109(c)(3)(B) to allow the Secretary of
Transportation to extend the 7-calendar-year IM reassessment interval
for an additional 6 months if the operator submits written notice to
the Secretary with sufficient justification of the need for the
extension. The NPRM proposed to codify this technical correction as
required by the statute.
2. Summary of Public Comment
PHMSA received a comment regarding the 6-month grace period for the
7-calendar-year reassessment interval from a trade organization
expressing general support of the proposed provisions and requesting
that PHMSA clarify that the 6-month extension begins after the close of
the 7-calendar-year reassessment interval period, which would be
consistent with

[[Page 52209]]

the 2011 Pipeline Safety Act revision to the Federal Pipeline Safety
Statutes.
At the GPAC meeting on January 12, 2017, the GPAC voted that the
proposed changes on the 6-month grace period for the reassessment
intervals are technically feasible, reasonable, cost-effective, and
practicable, and did not recommend that PHMSA modify these proposed
provisions.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding the grace period for IM reassessment intervals. After
considering the comment and as recommended by the GPAC, PHMSA is
retaining the proposed revisions to Sec. 192.939 in this final rule.
The proposed rule clearly stated that the 6-month extension begins
after the close of the 7-calendar-year reassessment interval period.
This is mirrored in PHMSA's frequently asked questions (FAQ) for the IM
program,\72\ which clarifies that the maximum interval for reassessment
may be set using the specified number of calendar years in accordance
with the 2011 Pipeline Safety Act. The use of calendar years is
specific to gas pipeline reassessment interval years under IM and does
not alter the interval requirements that appear elsewhere in the code
for various inspection and maintenance requirements.
---------------------------------------------------------------------------

\72\ FAQ-41 at https://primis.phmsa.dot.gov/gasimp/faqs.htm.
---------------------------------------------------------------------------

E. ILI Launcher and Receiver Safety--Sec. 192.750

1. Summary of PHMSA's Proposal
PHMSA determined that more explicit safety requirements are needed
when performing maintenance activities that use launchers and receivers
for inserting and removing ILI maintenance tools and devices. The
current regulations for hazardous liquid pipelines under part 195 have,
since 1981, contained safety requirements for scraper and sphere
facilities. However, the current regulations for natural gas
transmission pipelines do not similarly require controls or
instrumentation to protect against an inadvertent breach of system
integrity due to the incorrect operation of launchers and receivers for
ILI tools, or scraper and sphere facilities. As a result, PHMSA
proposed to add a new section to the Federal Pipeline Safety
Regulations to require ILI launchers and receivers include a suitable
means to relieve pressure in the barrel and either a means to indicate
the pressure in the barrel or a means to prevent opening if pressure
has not been relieved. While most launchers and receivers are already
equipped with such devices, some older facilities may not be so
equipped. Under the proposed provisions, operators would be required to
have this safety equipment installed consistent with current industry
practice.
2. Summary of Public Comment
Stakeholders, including TPA, provided input on PHMSA's changes to
the requirements for safety when performing maintenance activities that
utilize launchers and receivers for inserting and removing inspection
and maintenance tools and devices. TPA supported the proposed safety
additions to the regulations but stated that Sec. 192.750 should be
included within the regulations for pipeline components rather than the
subpart for pipeline maintenance. In addition, TPA suggested PHMSA
revise the language to allow 18 months after the effective date of the
rule to comply with the provisions. This change would allow for more
time to plan, budget, and complete the work safely. Another commenter
recommended these provisions be effective prior to the next time an
operator would use an applicable launcher or receiver. Public interest
groups and others, such as PST and NAPSR, had broad support for the
proposed provisions regarding ILI launcher and receiver safety.
At the GPAC meeting on January 12, 2017, a public commenter
suggested clarification on PHMSA's use of the term ``relief device'' or
``relief valve'' within the proposed provisions. During discussion, the
committee noted that there are requirements for ``relief valves''
elsewhere in the code, and calling a needed safety device for ILI
launchers and receivers a ``relief valve'' would then make it subject
to those additional requirements. Based on that discussion, the
committee recommended that PHMSA modify the proposed rule to clarify
that the rule does not require ``relief valves'' or use ``relief
valve'' as an officially defined term within the provision, as those
terms have distinct meanings within the broader context of the Federal
Pipeline Safety Regulations.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding launcher and receiver safety. After considering these
comments and the GPAC input, PHMSA is finalizing the provisions as they
were proposed in the NPRM, with the exception of a compliance date 1
year after the effective date of the rule. This approach avoids
disruption of work planned within a year of the effective date of the
rule, and it allows operators that are not planning work until beyond
the 1-year grace period to implement the upgrade before the next
planned use. Therefore, special modification work would not be required
before the launcher or receiver is needed. Operators would not be
required to perform the upgrades until the launcher or receiver is to
be used.
Consistent with the originally proposed language, this final rule
does not use the term ``relief valve'' and instead uses the generic
phrase ``device capable of safely relieving pressure.'' The proposed
rule effectively avoided any potential for confusion with respect to
the defined term ``relief valve'' and the requirements associated with
those components, therefore no change to this wording was necessary for
this final rule.
PHMSA believes that this requirement is appropriately located in
subpart M, ``Maintenance,'' of part 192, and notes that the comparable
requirement in part 195 for hazardous liquid pipelines is located in
subpart F, ``Operations and Maintenance.''

F. MAOP Exceedance Reporting--Sec. Sec. 191.23, 191.25

1. Summary of PHMSA's Proposal
Section 23 of the 2011 Pipeline Safety Act requires that operators
report each exceedance of a pipeline's MAOP beyond the build-up allowed
for the operation of pressure-limiting or control devices. On December
21, 2012 (77 FR 75699), PHMSA published Advisory Bulletin ADB-2012-11
to advise operators of their responsibility under section 23 of the
2011 Pipeline Safety Act to report such exceedances. The advisory
bulletin further stated that the reporting requirement is applicable to
all gas transmission pipeline facility owners and operators. PHMSA
advised pipeline owners and operators to submit this information in the
same manner as safety-related condition reports. The information
pipeline owners and operators submit should comport with the
information listed at Sec. 191.25(b), and pipeline owners and
operators submitting such information should use the reporting methods
listed at Sec. 191.25(a).
Although this provision of the 2011 Pipeline Safety Act is self-
executing, PHMSA proposed to revise the safety-related condition
reporting requirements under part 191 to codify this requirement and
harmonize part 191 with the statutory requirement by eliminating the
reporting exemption and to provide a consistent procedure,

[[Page 52210]]

format, and structure for operators to submit such reports.
2. Summary of Public Comment
Trade associations, citizen groups, and pipeline industries
generally supported PHMSA's codification of the statutory reporting
requirements for MAOP exceedances for transmission lines.
API and GPA objected to MAOP exceedance reporting requirements for
unregulated gathering pipelines. GPA stated that PHMSA did not
sufficiently weigh the benefits of reporting MAOP exceedance against
the hurdles to compliance for unregulated gathering pipelines. GPA also
questioned whether PHMSA has the authority to require unregulated
gathering pipelines report MAOP exceedance, since complying with this
reporting requirement would necessitate that unregulated gathering
pipelines establish MAOP, which they are currently not required to do.
Citizen and other safety groups, including Earthworks, NAPSR, the
Pipeline Safety Coalition, and PST, supported the inclusion of
unregulated gathering pipelines in this section, stating that it would
improve pipeline safety.
Several commenters suggested editorial revisions to streamline and
improve these provisions. NGA expressed concern that the proposed
provisions could apply to distribution systems and suggested that PHMSA
clarify that reporting requirements for MAOP exceedance only apply to
transmission pipelines. Additionally, Spectra Energy Partners requested
that PHMSA require reporting of MAOP exceedances only when the operator
is unable to respond to MAOP exceedances within the timeframe required
elsewhere in part 192.
One operator expressed concern that the proposed change would
require operators to submit additional safety-related condition reports
anytime the operator had to implement a pressure reduction upon
discovering an immediate condition.
At the GPAC meeting on June 7, 2017, there was brief discussion on
whether the 5-day reporting requirement was too prescriptive, but the
committee agreed that PHMSA was properly implementing the statutory
requirement as written and intended by Congress. Following that
discussion, the committee recommended that PHMSA modify the proposed
rule to clarify that the MAOP exceedance reporting provisions do not
apply to gathering lines.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding MAOP exceedance reporting. The 2011 Pipeline Safety Act
mandates that an operator report MAOP exceedances on gas transmission
lines, regardless of whether the operator corrects the safety-related
condition through repair or replacement. After considering the comments
PHMSA received on the NPRM and as recommended by the GPAC, PHMSA is
inserting the word ``only'' in the additional MAOP exceedance reporting
provision in Sec. 191.23(a)(10) to make it clearer that the amended
requirement applies only to gas transmission lines and not to gathering
or distribution lines. Conforming changes were made to Sec.
191.23(a)(6). PHMSA notes that the prior safety-related condition
reporting requirements and exceptions related to pressure exceedances
for gathering and distribution lines have not been altered.

G. Strengthening Assessment Requirements--Sec. Sec. 192.150, 192.493,
192.921, 192.937, Appendix F

i. Industry Standards for ILI--Sec. Sec. 192.150, 192.493

1. Summary of PHMSA's Proposal
In the NPRM, PHMSA proposed to revise Sec. 192.150 to incorporate
by reference a NACE Standard Practice, NACE SP0102-2010, ``In-line
Inspection of Pipelines,'' to promote a higher level of safety by
establishing consistent standards for the design and construction of
pipelines to accommodate ILI devices.
In Sec. 192.493, PHMSA proposed requirements for operators to
comply with the requirements and recommendations of API STD 1163, In-
line Inspection Systems Qualification Standard; ANSI/ASNT ILI-PQ-2005,
In-line Inspection Personnel Qualification and Certification; and NACE
SP0102-2010, In-line Inspection of Pipelines. PHMSA also proposed to
allow operators to conduct assessments using tethered or remotely
controlled tools.
2. Summary of Public Comment
NAPSR supported the proposed provisions in Sec. 192.493,
commenting that the incorporation by reference of the three consensus
standards provides enhanced guidance for the determination of adequate
procedures and qualifications related to in-line inspections of
transmission pipelines.
Some industry representatives commented that it is unnecessary to
incorporate American Society for Nondestructive Testing (ASNT) ILI-PQ
by reference since API 1163 requires that providers of ILI services
ensure that their employees are qualified. Others commented that PHMSA
should exclude requirements contained in section 11 of API 1163, which
pertains to quality management systems. Lastly, industry
representatives asserted that ILI vendors may not be able to meet the
90 percent tool tolerance specified in the referenced standards, and
PHMSA should relocate these proposed requirements to a different
subpart.
Several commenters noted that if PHMSA required compliance with
``the requirements and recommendations of'' the recommended practices
and standards, it would create enforceable requirements out of actions
that the standards themselves did not necessarily mandate.
During the GPAC meeting of March 2, 2018, the committee recommended
PHMSA revise this provision by striking the phrase ``the requirements
and the recommendations of,'' so that recommendations within the
incorporated standard would not be made mandatory requirements.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding the incorporation by reference of industry standards for ILI.
After considering these comments and as recommended by the GPAC, PHMSA
is deleting the phrase ``the requirements and the recommendations of''
from Sec. Sec. 192.150 and 192.493 so that the recommendations within
the incorporated standard would not be made mandatory requirements.
PHMSA believes that the inclusion of the NACE standard at Sec.
192.150 will help to address the NTSB recommendation P-15-20, which
asked PHMSA to identify all operational complications that limit the
use of ILI tools in piggable pipelines, develop methods to eliminate
those complications, and require operators use such methods to increase
the use of ILI tools. PHMSA also believes that more pipelines will
become piggable in the future as the nation's pipeline infrastructure
ages and is eventually replaced. A current provision in the regulations
requires that all new and replaced pipeline be piggable, and as
operators address higher-risk infrastructure through this rulemaking,
there is a likelihood that some previously unpiggable pipe will be
replaced.
PHMSA disagrees that ASNT ILI-PQ is unnecessary. The foreword of
API 1163 states ``This standard serves as an umbrella document to be
used with and complement companion standards.

[[Page 52211]]

NACE SP0102, In-line Inspection of Pipelines and ASNT ILI-PQ, In-line
Inspection Personnel Qualification and Certification.'' These three
standards are complimentary and are intended to be used together. PHMSA
also disagrees that quality requirements should be excluded from the
rule. One of the fundamental objectives of this rule is to establish a
minimum standard for quality in conducting ILI. Also, the consensus
industry standard API 1163 only uses 90 percent tool tolerance as an
example to illustrate key points but does not specify or establish a
minimum standard tool tolerance of 90 percent.

G. Strengthening Assessment Requirements--Sec. Sec. 192.150, 192.493,
192.921, 192.937, Appendix F

ii. Expand Assessment Methods Allowed for IM--Sec. Sec. 192.921(a) and
192.937(c)

1. Summary of PHMSA's Proposal
In the current Federal Pipeline Safety Regulations, Sec. 192.921
requires that operators with pipelines subject to the IM rules must
perform integrity assessments. Currently, operators can assess their
pipelines using ILI, pressure test, direct assessment, and other
technology that the operator demonstrates provides an equivalent level
of understanding of the condition of the pipeline.
In the NPRM, PHMSA proposed to require that direct assessment only
be allowed when the pipeline cannot be assessed using ILI. As a
practical matter, direct assessment is typically not chosen as the
assessment method if the pipeline can be assessed using ILI. Further,
PHMSA proposed to add three additional assessment methods to the
regulations:
1. A spike hydrostatic pressure test, which is particularly well-
suited to address stress corrosion cracking and other cracking or
crack-like defects;
2. Guided Wave Ultrasonic Testing (GWUT), which is particularly
appropriate in cases where short segments such as road or railroad
crossings are difficult to assess; and
3. Excavation with direct in situ examination.
2. Summary of Public Comment
NAPSR expressed its support for the proposed provisions. Many
comments expressed concerns with the proposed provisions for the
assessment methods regarding uncertainties in reported results.
Multiple commenters stated that operators should be able to run the
appropriate assessment or ILI tools for the threats that are known or
likely to exist on the pipeline based on its condition. Atmos Energy
commented that ASME/ANSI B318.S requirements should be the standard to
which operators are required to follow. Enable Midstream Partners
proposed that PHMSA add ``significant'' to make a distinction between
significant and insignificant threats and offered specific language to
address its concerns. PG&E commented on the proposed provisions for ILI
assessments, requesting that PHMSA provide guidance as to how to
explicitly consider the numerous uncertainties associated with ILI
regarding anomaly location accuracy, detection thresholds, and sizing
accuracy, and suggested that PHMSA allow industry guidance and best
practices to be used where practical. Some commenters expressed concern
that PHMSA proposed to add requirements surrounding the detection of
anomalies that many ILI tools could not meet. These commenters stated
that there are no tools designed to find girth weld cracks and that
most incidents caused by girth weld cracks have third-party excavation
damage as a contributing factor. Commenters further stated that this is
a threat that is best handled by procedures that require caution around
girth welds during excavation and backfilling procedures.
Several entities commented on the proposed qualification
requirements under the ILI assessment method provisions, expressing
concern that they are redundant with existing operator qualification
regulations under the IM regulations at Sec. 192.915 and the proposed
revisions to Sec. 192.493 incorporating the industry ANSI standard on
ILI personnel qualification. Multiple entities proposed changes to
remove such redundancies and improve clarity.
Commenters requested clarification that the proposed text in the IM
assessment provisions ``apply one or more of the following methods for
each threat to which the covered segment is susceptible'' does not mean
that at least one assessment is required for each threat. Additionally,
commenters disagreed with adding an explicit requirement for a ``no
objection'' letter as notification of using ``other technology'' and
suggested that if this notification is required, operators should be
allowed to proceed with the technology if they do not receive a ``no
objection'' letter from PHMSA within a certain period.
The NTSB commented that PHMSA's proposal to revise the pipeline
inspection requirements to allow the direct assessment method to be
used only if a line is not capable of inspection by internal inspection
tools directly conflicts with the recommendations of their pipeline
safety study, Integrity Management of Gas Transmission Lines in High
Consequence Areas, which recommended that PHMSA develop and implement a
plan for eliminating the use of direct assessment as the sole integrity
assessment method for gas transmission pipelines. The CPUC asserted
that direct assessment must always be supplemented with other methods,
such as ILI or a pressure test.
Many industry entities argued that PHMSA's proposed changes to the
IM assessment provisions limiting direct assessment to unpiggable lines
are not technically justified. Several entities, including AGA and API,
believed it was unreasonable to limit operators' ability to use direct
assessment for pipeline assessments unless all other assessment methods
have been determined unfeasible or impractical. PG&E requested that
PHMSA recognize that although a pipeline may be considered piggable, it
does not mean that ILI technology is available, and they provided
specific suggestions for revision. Similarly, AGA stated that free-
swimming flow-driven ILI tools are often not compatible with intrastate
transmission lines for several reasons, stating that certain conditions
must exist to assess a pipeline by ILI and obtain valid data, including
adequate flow rate, lack of bends or valves that would impede diameter,
and ability to insert and remove the tool from the system. Therefore,
AGA provided a suggested definition for ``able to accommodate
inspection by means of an instrumented in-line inspection tool.''
Trade associations asserted that direct assessment is a proven
assessment technique that works in addressing the threat of corrosion.
INGAA stated that the criteria for when direct assessment can be used
should depend on whether direct assessment can provide the necessary
information about the pipe condition rather than whether other
assessment methods can be used. AGA commented that it is not aware of
any industry study that would suggest that direct assessment does not
work effectively to identify corrosion defects in certain
circumstances, which it describes in its comments. In addition, AGA
stated that direct assessment is a predictive tool that identifies
areas where corrosion could occur, including time-dependent threats,
while other methods can only detect where corrosion has resulted in a
measurable metal loss. Atmos Energy commented that limiting the use of
direct assessment only to those pipeline segments that are not capable
of

[[Page 52212]]

inspection by internal inspection tools is not consistent with other
requirements of subpart O.
At the GPAC meeting on December 15, 2017, the committee voted to
revise the ``no objection'' process to incorporate language stating
that, if an operator does not receive an objection letter from PHMSA
within 90 days of notifying PHMSA of an alternative sampling approach,
the operator can proceed with their method. Additionally, the GPAC,
during the meeting on March 2, 2018, recommended that PHMSA change
these provisions to clarify that operators should select the
appropriate assessment based on the threats to which the pipeline is
susceptible and remove certain language that is duplicative to another
existing section of the regulations. The GPAC also recommended that
PHMSA clarify that direct assessment is allowed where appropriate but
may not be used to assess threats for which the method is not suitable.
Further, the GPAC wanted PHMSA to incorporate the notification and
objection procedure and 90-day timeframe that the GPAC approved under
the material properties verification requirements.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding the inclusion of additional assessment methods for integrity
assessments. After considering these comments and as recommended by the
GPAC, PHMSA is clarifying in this final rule that operators should
select the appropriate assessment method based on the threats to which
the pipeline is susceptible and is removing language regarding the
qualification of persons reviewing ILI results that is duplicative with
existing Sec. 192.915. PHMSA is also clarifying in Sec. 192.921 that
direct assessment is allowed where appropriate but may not be used to
assess threats for which the method is not suitable, such as assessing
pipe seam threats. In addition, PHMSA incorporated the notification
procedure under Sec. 192.18 with the 90-day timeframe and objection
process.
PHMSA notes that other comments regarding the determination of
suitable assessment methods for applicable threats and ILI tool
capabilities relate to long-standing IM regulations that were not
proposed for revision. PHMSA did provide substantial additional
guidance and standards for implementing the integrity assessment
requirements for ILI by incorporating the industry standards in Sec.
192.493, as discussed in the previous sections.

G. Strengthening Assessment Requirements--Sec. Sec. 192.150, 192.493,
192.921, 192.937, Appendix F

iii. Guided Wave Ultrasonic Testing--Appendix F

1. Summary of PHMSA's Proposal
When expanding assessment methods for both HCA and non-HCA areas,
PHMSA proposed to add three additional assessment methods, one being
GWUT. Under the existing regulations, GWUT is considered ``other
technology,'' and operators must notify PHMSA prior to its use. PHMSA
developed guidelines for the use of GWUT, which have proven successful,
and proposed to add them under a new Appendix F to part 192--Criteria
for Conducting Integrity Assessments Using Guided Wave Ultrasonic
Testing. As such, future notifications to PHMSA would not be required,
representing a cost savings for operators.
2. Summary of Public Comment
Multiple entities commented in support of using GWUT and the
inclusion of proposed Appendix F. NAPSR expressed its agreement with
and support for the proposed Appendix. American Public Gas Association
(APGA) applauded PHMSA for including guidelines for GWUT; however, it
cautioned that the guidance only specifies Guided Ultrasonics LTD (GUL)
Wavemaker G3 and G4, which use piezoelectric transducer technology, as
acceptable technology. APGA recommended that Magnetostrictive Sensor
technology also be included as an acceptable guided wave technology,
stating that at least one of its members reported good results using
this technology for guided wave assessment of an unpiggable segment of
a transmission pipeline.
A commenter noted that the requirement of both torsional and
longitudinal wave modes in all situations introduces unnecessary
complexity into the GWUT data interpretation process. The commenter
further noted that PHMSA should specify that torsional wave mode is the
primary wave mode when utilizing GWUT, and that longitudinal wave mode
may be used as an optional, secondary mode. Other commenters
recommended additional changes to Appendix F, such as stating that
qualified GWUT equipment operators are trained to understand the
strengths, weaknesses, and proper applications of each wave mode and
should have the freedom to select the appropriate and most effective
wave mode(s) for the given situation. PG&E requested that PHMSA
recognize that this technology is used at locations other than casings
as implied in the introductory paragraph and commented that double-
ended inspections are not always required to meet the specification.
During the GPAC meeting on December 15, 2017, the GPAC agreed with
the provisions related to Appendix F and GWUT but recommended PHMSA
revise the ``no objection'' letter process.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding GWUT. After considering these comments and as recommended by
the GPAC, PHMSA is removing the reference to GUL equipment for clarity.
PHMSA is modifying the notification process to allow operators to
proceed with an alternative process for using GWUT if the operator does
not receive an objection letter from PHMSA within 90 days of notifying
PHMSA in accordance with Sec. 192.18. PHMSA believes this change
increases regulatory flexibility while maintaining pipeline safety.
In this final rule, PHMSA is retaining the requirement to use both
torsional and longitudinal wave modes since that is a long-standing
requirement in PHMSA's guidance for accepting GWUT as an allowed
technology under an ``other technology'' notification. Also, PHMSA
recognizes that GWUT is used at locations other than casings, although
it is most often deployed for the integrity assessment of cased
crossings. However, double-ended inspections would not always be
required to meet Appendix F, and Appendix F does not require double-
ended inspections. Double-ended inspections are not necessary as long
as the guided wave ultrasonic test covers the entire length of the
assessment as well as the ``dead zone'' where the equipment is set up.
The proposed rule already addresses validation of operator
training, but in this final rule, PHMSA is deleting the sentence
``[t]here is no industry standard for qualifying GWUT service
providers'' to provide clarity.

H. Assessing Areas Outside of HCAs--Sec. Sec. 192.3, 192.710

i. MCA Definition--Sec. 192.3

1. Summary of PHMSA's Proposal
In the NPRM, PHMSA introduced a new definition for a Moderate
Consequence Area (MCA). The proposed rule defined an MCA as an onshore
area, not meeting the definition of an HCA, that is within a potential
impact circle, as defined in Sec. 192.903, containing 5 or more
buildings intended

[[Page 52213]]

for human occupancy; an occupied site; or a right-of-way for a
designated interstate, freeway, expressway, or other principal four-
lane arterial roadway as defined in the Federal Highway
Administration's ``Highway Functional Classification Concepts, Criteria
and Procedures.'' PHMSA proposed that requirements for data analysis,
assessment methods, and immediate repair conditions within these MCAs
would be similar to requirements for HCA pipeline segments but with
longer timeframes so that operators could properly allocate resources
to higher-consequence areas. PHMSA proposed that the 1-year repair
conditions that currently exist for HCA pipeline segments would be 2-
year repair conditions when found on MCA pipeline segments. These
changes would ensure the prompt remediation of anomalous conditions
that could potentially affect people, property, or the environment,
commensurate with the severity of the defects, while still allowing
operators to allocate their resources to HCAs on a higher-priority
basis.
2. Summary of Public Comment
The NTSB stated that the proposed provisions to create an MCA
category and include a highway size threshold in the definition of an
MCA accomplishes part of what the NTSB intended in Safety
Recommendation P-14-1. However, the NTSB objected to the proposed
highway coverage as being limited to four lanes and stated its support
of expanding the highway size threshold as they had specifically
recommended in P-14-1. The NTSB asserted that the proposed language
would exclude the category of other principal arterial roadways wider
than four lanes when, in fact, the wider roadways should be included.
INGAA supported the addition of an MCA category to the Federal
Pipeline Safety Regulations but recommended several modifications to
the proposed definition. INGAA suggested PHMSA should limit the
definition of an MCA to only those pipeline segments that could be
assessed through an ILI inspection, amend the MCA definition to avoid
ambiguity regarding residential structures, remove ``outside areas and
open structures'' from the portion of the definition of MCA related to
``identified sites,'' include timeframes for incorporating changes to
existing MCAs, and permit operators to use the edge of the pavement
rather than the highway right-of-way to determine if a roadway
intersects with a Potential Impact Circle.
AGA, API, APGA, and several pipeline entities agreed with INGAA's
comments on the modification to PHMSA's proposed MCA definition.
Additionally, AGA, API, and APGA emphasized PHMSA should remove the
reference to ``a right-of-way'' for the designated roadways, commenting
that the MCA definition could be interpreted so that if a Potential
Impact Circle touches any portion of the roadway right-of-way, the
pipeline segment is an MCA. That interpretation would put undue burden
on operators in areas where its pipelines lay at or near the edge of
the public right-of-way that would not normally contain ``persons or
property'' that would sustain damage or loss in the event of a pipeline
failure. Further, API added that the reference to ``a right-of-way'' is
problematic because roadway right-of-ways are variable, cannot be seen
with the naked eye, and are often not included in publicly available
data sources.
Commenters also disagreed with the definition of ``occupied site''
within the MCA definition. GPA asserted that the criterion used in the
MCA definition should be limited to interstate highways, and the
definition of ``occupied site'' should be eliminated to more clearly
distinguish between MCAs and HCAs and to provide greater clarity in
identifying and managing MCAs. Similarly, Enlink Midstream commented
that PHMSA should eliminate the definition of occupied site and remove
this criterion from the proposed definition of MCA. Doing so would
permit the continued focus on HCAs that the IM process was intended to
accomplish. AGL Resources also expressed concern with the proposed
definition of occupied site, commenting that this definition could
require operators to effectively perform a census-like identification
of structures to verify the count of persons within that structure.
There were conflicting viewpoints on where the definition of MCA
should be placed in the regulations. API and other commenters stated
that they preferred a new category and a distinct definition for MCA as
opposed to expanding the definition of HCA or making a subcategory in
the HCA definition for MCAs, whereas SoCalGas encouraged expanding the
scope of HCAs rather than creating a new category.
Enterprise Products commented PHMSA should move the MCA definition
to subpart O and remove the ``occupied site'' criteria from the
proposed definition of MCA, which would provide more distinction
between MCAs and HCAs in the regulations and would also more
appropriately place them under the IM regulations.
AGA and several other organizations expressed concern over the
resource-intensive administrative task of identifying MCAs, especially
pertaining to recordkeeping requirements. API asserted that the
proposed provisions would limit operators' ability to prioritize
resources for pipelines that pose the highest risk. They further stated
that while they agree with the inclusion of all Class 3 and Class 4
locations, occupied sites, and major roadways in the definition of MCA,
they disagree with the proposed threshold of five buildings intended
for human occupancy within the potential impact radius. They suggested
that a more appropriate threshold would be more than 10 buildings
intended for human occupancy, as that number is consistent with
longstanding part 192 class location designations.
Multiple groups, such as AGI, INGAA, and Cheniere Energy, also
stated objections over various aspects of defining and identifying MCAs
and provided suggestions for revised language, including several broad
clarifications or deletions to the definition. In addition to
requesting modifications to the definition of MCA, INGAA objected to
the provided geographic information system (GIS) layer for right-of-way
determination, and suggested that PHMSA provide one database for
roadway classification. Numerous trade associations and pipeline
companies asked PHMSA to consider a qualifier that the definition of
MCA only applies to pipelines operating at greater than 30 percent
SMYS. EnLink Midstream suggested using a threshold level of 16-inch
pipe diameter to identify pipelines that pose a greater risk.
The GPAC had a comprehensive discussion on the MCA definition
during the meeting on March 2, 2018, and approved of the definition
with some changes. First, the GPAC recommended changing the highway
description within the definition to remove reference to the roadway
``rights-of-way'' and to add language so that the highway consists of
``any portion of the paved surface, including shoulders.'' Secondly,
the GPAC recommended clarifying that highways with 4 or more lanes are
included, and they also wanted PHMSA to work together with the Federal
Highway Administration to provide operators with clear information
relative to this aspect of the rulemaking and discuss it in the
preamble. The GPAC also recommended that PHMSA discuss in the preamble
what they expect the definition of ``piggable'' to be, as it is
critical for aspects of the MCA

[[Page 52214]]

definition as it relates to MAOP confirmation. Finally, the GPAC
recommended PHMSA modify the term ``occupied sites'' in the MCA
definition and in the definitions section of part 192 by removing the
language referring to ``5 or more persons'' and the timeframe of 50
days and tying the requirement into the HCA survey for ``identified
sites'' as discussed by GPAC members and PHMSA at the meeting. The
committee noted that such site identification could be made through
publicly available databases and class location surveys. The committee
suggested PHMSA consider the necessary sites and enforceability of the
definition per direction by the committee members.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding the definition of moderate consequence area. After
considering these comments and the GPAC input, PHMSA is modifying the
highway description within the definition to remove reference to the
roadway ``rights-of-way'' and to add language so that the highway
consists of ``any portion of the paved surface, including shoulders.''
Also, PHMSA is specifying that highways with 4 or more lanes are
included. PHMSA believes these changes provide additional clarity.
Per the GPAC's request that PHMSA provide additional guidance on
what roadways are included in the MCA definition as it pertains to
``other principal roadways with 4 or more lanes,'' PHMSA notes that the
Federal Highway Administration defines Other Principal Arterial
roadways \73\ as those roadways that serve major centers of
metropolitan areas, provide a high degree of mobility, and can also
provide mobility through rural areas. Unlike their access-controlled
counterparts (interstates, freeways, and expressways), abutting land
uses can be served directly. Forms of access for Other Principal
Arterial roadways include driveways to specific parcels and at-grade
intersections with other roadways. For the most part, roadways that
fall into the top three functional classification categories
(Interstate, Other Freeways & Expressways, and Other Principal
Arterials) provide similar service in both urban and rural areas. The
primary difference is that there are usually multiple arterial routes
serving a particular urban area, radiating out from the urban center to
serve the surrounding region. In contrast, an expanse of a rural area
of equal size would be served by a single arterial. The MCA definition
does not include all roadways that meet this definition but instead is
limited to those roadways meeting this definition that have four or
more lanes.
---------------------------------------------------------------------------

\73\ Federal Highway Administration, Office of Planning,
Environment, & Realty (HEP), Highway Functional Classification
Concepts, Criteria and Procedures (2013) https://www.fhwa.dot.gov/planning/processes/statewide/related/highway_functional_classifications/section03.cfm#Toc336872980.
---------------------------------------------------------------------------

With respect to ``occupied sites,'' PHMSA evaluated the comments
and the GPAC discussion and concluded that including occupied sites
within the MCA definition was not necessary. Industry representatives
on the GPAC asserted that most locations meeting the definition of
occupied site are, as a practical matter, already included as an
identified site and designated as an HCA. Commenters suggested most
operators find it expedient to declare sites similar to occupied areas
as HCAs instead of counting the specific occupancy of such locations to
see if they meet the occupancy standard over the course of a year.
Operators then monitor occupancy in subsequent years for changes that
might change the site's status as an occupied site. Such an approach
would require fewer resources and be more conservative from a public
safety standpoint. Based on these comments, PHMSA is persuaded that
including another category of locations, similar to identified sites in
HCAs but with a lower occupancy standard of 5 persons, is unnecessarily
burdensome without a comparable decrease in risk.
PHMSA disagrees that the MCA definition should be moved to subpart
O. The term is used in sections outside of subpart O. Including the MCA
definition in Sec. 192.3 is necessary for it to apply to the sections
in which it is used throughout part 192.

H. Assessing Areas Outside of HCAs--Sec. Sec. 192.3, 192.710

ii. Non-HCA Assessments--Sec. 192.710

1. Summary of PHMSA's Proposal
PHMSA proposed to add a new Sec. 192.710 to require that pipeline
segments in Class 3 or Class 4 locations, and piggable segments in
MCAs, be initially assessed within 15 years and no later than every 20
years thereafter on a recurring basis. PHMSA also proposed to require
assessments in these areas be conducted using the same methods that are
currently allowed for HCAs. PHMSA has found that operators have
assessed significant non-HCA pipeline mileage in conjunction with
performing HCA integrity assessments in the same pipeline. Therefore,
PHMSA proposed to allow the use of those prior assessments of non-HCA
pipeline segments to comply with the new Sec. 192.710.
In effect, to this limited population of pipeline segments outside
of HCAs, PHMSA proposed to expand the applicability of IM program
elements related to baseline integrity assessments, remediating
conditions found during integrity assessments, and periodic
reassessments. In addition, under the proposed provisions, MCAs would
be subject to other requirements related to the congressional mandates,
including material properties verification and MAOP reconfirmation. Any
assessments an operator would conduct to reconfirm MAOP under proposed
Sec. 192.624 would count as an initial assessment or re-assessment, as
applicable, under the proposed requirements for non-HCA assessments.
2. Summary of Public Comment
The NTSB and multiple citizen groups supported the expansion of IM
elements to gas transmission pipelines in areas outside those currently
defined as HCAs. However, several entities, including PST, stated that
applying a limited suite of IM tools to these areas was insufficient
and requested that the full suite of IM elements be applied to the
additional pipeline segments. Some citizen groups expressed concern
that the 15-year implementation period and 20-year re-inspection period
was too long.
While pipeline companies and trade associations generally supported
PHMSA's efforts to expand IM elements beyond HCAs, many of them stated
concerns over the time and cost required to identify MCAs, the efficacy
of the changes, and the language and requirements regarding both the
limitation of assessments to pipeline segments accommodating inline
inspection tools and (re)assessment periods. Many groups requested a
clear, concise set of codified requirements for IM outside of HCAs to
simplify identification, recordkeeping, and repairs.
Several commenters provided input on the allowable assessment
methods for non-HCAs. AGA suggested that PHMSA create a new subpart
consisting of a clear and concise set of codified requirements for the
non-HCA assessments, including new definitions regarding the limitation
of assessments to pipeline segments accommodating instrumented inline
inspection tools. Many trade associations and pipeline companies stated
that they thought the direct assessment method could achieve a
satisfactory level of inspection in place of costlier in-line
inspection,

[[Page 52215]]

especially given the additional detail added to the in-line inspection
assessment method in the proposal. API requested that PHMSA allow
operators to rely on any prior assessments performed under subpart O
requirements of part 192 in effect at the time of the assessment rather
than limit the allowance to ILI. Furthermore, other organizations
supported AGA's proposal that mirrors and extends to MCAs the two-
methodology approach used to determine HCAs in the existing Sec.
192.903, which allows for identification based on class location or by
the pipeline's potential impact radius.
Entities, including API and Atmos Energy, requested clarification
regarding assessment periods and reassessment intervals due to the
language regarding shorter reassessment intervals ``based on the type
[of] anomaly, operational, material and environmental conditions [. .
.], or as otherwise necessary.'' Those commenters said that language
was vague and subject to varying interpretations, so they suggested
revisions to the language for the reassessment intervals. Lastly, AGA
suggested that PHMSA define the term ``pipelines that can accommodate
inspection by means of an instrumented in-line inspection tool'' used
in proposed Sec. Sec. 192.710 and 192.624, stating that providing the
criteria that a pipeline must meet to be able to accommodate an in-line
inspection tool would remove uncertainty and inconsistency in
determining which pipelines meet PHMSA's proposed qualifier.
The GPAC discussed the provisions related to assessments outside of
HCAs during the meeting on March 2, 2018. The GPAC found the provisions
to be technically feasible, reasonable, cost-effective, and practicable
if PHMSA clarified that direct assessment could be used only if
appropriate for the threat being assessed and could not be used to
assess threats for which direct assessment is not suitable, and removed
the provisions related to low-stress assessments. The GPAC also
recommended revising the initial assessment and reassessment intervals
for applicable pipeline segments from an initial assessment within 15
years of the effective date of the rule and periodic assessments every
20 years thereafter to an initial assessment within 14 years of the
effective date of the rule and periodic assessments every 10 years
thereafter. The GPAC stated that the prioritization of initial
assessments and reassessments should be based on the risk profiles of
the pipelines. The GPAC also wanted PHMSA to apply the assessment and
reassessment requirements only to pipelines with MAOPs greater than or
equal to 30 percent SMYS.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding integrity assessments outside HCAs. After considering these
comments and as recommended by the GPAC, PHMSA is modifying the rule to
specify that direct assessment may be used only if appropriate for the
threat being assessed and cannot be used to assess threats for which
direct assessment is not suitable, such as assessing pipe seam threats.
PHMSA made these changes to provide clarity regarding the proper use of
direct assessments.
In addition, PHMSA is revising the applicability of Sec. 192.710
to apply only to pipelines with an MAOP of greater than or equal to 30
percent of SMYS. PHMSA made this change because the GPAC recommended it
was cost-effective for the provision to only apply to pipe operating
above 30% SMYS in Class 3 and 4 locations and because those pipelines
present the greatest risk to safety. Because of this modification,
PHMSA is withdrawing provisions related to low-stress assessments since
they will no longer be applicable.
Based on the comments and recommendations from the GPAC, PHMSA is
also modifying the initial assessment deadline and reassessment
intervals for applicable pipeline segments to 14 years after the
publication date of the rule and every 10 years thereafter, which was
reduced from 15 years and 20 years, respectively. PHMSA believes this
change increases regulatory flexibility while maintaining pipeline
safety. PHMSA is also adding a requirement that the initial assessments
must be scheduled using a risk-based prioritization.
PHMSA disagrees with the need to implement a dual approach to MCA
identification that would be similar to the ways that HCAs are
identified. Subpart O and the IM regulations were first promulgated
before pipeline operators had experience with potential impact radius
(PIR) techniques, and incorporating an alternative HCA identification
method into the original IM regulations using conventional class
locations was convenient and appropriate. Pipeline operators now have
over 15 years of experience working with the PIR concept; therefore,
PHMSA determined using the PIR method for determining MCAs in the
definition of MCAs is appropriate. PHMSA also disagrees that a separate
subpart would be preferable and is retaining the requirements for MCA
assessments in a new Sec. 192.710.
PHMSA believes the requirement to have a shorter reassessment
interval is clear and is not modifying that aspect of the rule. PHMSA
included a requirement for operators to not automatically default to
the maximum reassessment interval but to establish shorter reassessment
intervals ``based upon the type anomaly, operational, material, and
environmental conditions found on the pipeline segment, or as necessary
to ensure public safety'' when appropriate. Operators have been
required to perform similar analyses and adjustment of reassessment
intervals for HCAs since the inception of the IM regulations in 2003
and should be familiar with this process over 15 years later. PHMSA
believes that stating the overarching goal of assuring public safety by
evaluating each pipeline and its circumstances and establishing
appropriate assessment intervals based on those circumstances provides
clear intent and is an appropriate approach.
PHMSA believes that the term ``piggable segment'' is very widely
understood in the industry and is not including additional definitions
or regulatory language to expand upon this term. PHMSA understands that
a pipeline segment might be incapable of accommodating an in-line
inspection tool for a number of reasons, including but not limited to
short radius pipe bends or fittings, valves (reduced port) that would
not allow a tool to pass, telescoping line diameters, and a lack of
isolation valves for launchers and receivers. Some unpiggable pipelines
can be made piggable with modest modifications, but others cannot be
made piggable short of pipe replacement.
PHMSA understands that a pipeline segment is piggable if it can
accommodate an instrumented ILI tool without the need for major
physical or operational modification, other than the normal operational
work required by the process of performing the inline inspection. This
normal operational work includes segment pigging for internal cleaning,
operational pressure and flow adjustments to achieve proper tool
velocity, system setup such as valve positioning, installation of
temporary launchers and receivers, and usage of proper launcher and
receiver length and setup for ILI tools. In addition, a pipeline
segment that is not piggable for a particular threat because of
limitations in technology such that an ILI tool is not commercially
available, might be piggable for other threats. For example, a pipeline
that is unable to accommodate a crack tool might be able

[[Page 52216]]

to accommodate a conventional MFL or deformation tool, and thus be
piggable for those threats. Launcher and receiver lengths are not a
reason for a pipeline to be considered unpiggable, since through a
minor modification they can be modified to be piggable, and the removal
of launchers or receivers from the pipeline segment does not make a
pipeline unpiggable either.

I. Miscellaneous Issues

i. Legal Comments

The following section discusses industry comments related to legal
and administrative procedure issues with the proposed rule.
Summary of Public Comment
Several commenters asserted that the proposed provisions go beyond
PHMSA's statutory authority provided by the 2011 Pipeline Safety Act.
Many trade associations and pipeline industry entities stated that
PHMSA exceeded the congressional mandates in the proposed provisions by
imposing retroactive recordkeeping requirements and retroactive
material properties verification requirements. These comments are
discussed in more detail in their respective sections above.
Commenters asserted that, in the 2011 Pipeline Safety Act, Congress
identified specific factors that PHMSA is required to consider when
proposing regulations per the statutory mandates, including whether
certain proposed provisions would be economically, technically, and
operationally feasible, and that the proposed rule did not adequately
address these factors. For example, AGA expressed concerns that PHMSA
proposed to adopt NTSB recommendations without independently justifying
those provisions based on the specific factors required by Congress or
providing the reasoning behind adopting said recommendations.
AGA and INGAA also stated that PHMSA did not adequately consider
the impact that the Natural Gas Act of 1968 would have on
implementation of the proposed rule. Noting that operators are required
to obtain permission from FERC before removing pipelines from service
or replacing pipelines, these commenters stated that obtaining
permissions could hinder operators from quickly performing required
tests and repairs. INGAA and AGA also stated that PHMSA did not consult
with FERC and State regulators about implementation timelines for
certain provisions, which PHMSA is required to do in accordance with 49
U.S.C. 60139(d)(3) because gas service would be affected by the
proposed rule.
PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding the statutory authority for the proposed rule. With regard to
the comments about imposing retroactive recordkeeping requirements and
retroactive material properties verification requirements, PHMSA
explained in this document that the final provisions of this rule are
prospective and do not create retroactive requirements. This topic is
discussed in more detail in the respective sections about recordkeeping
and material properties verification.
Pertaining to PHMSA's broader authority, Congress has authorized
the Federal regulation of the transportation of gas by pipeline in the
Pipeline Safety Laws (49 U.S.C. 60101 et seq.) and established the
current framework for regulating pipelines transporting gas in the
Natural Gas Pipeline Safety Act of 1968, Public Law 90-481. Through
these laws, Congress has delegated the DOT the authority to develop,
prescribe, and enforce minimum Federal safety standards for the
transportation of gas, including natural gas, flammable gas, or toxic
or corrosive gas, by pipeline. As required by law, PHMSA has considered
whether the provisions of this rule are economically, technically, and
operationally feasible and has provided relevant analysis in the
Regulatory Impact Analysis and preamble of this rule.
In accordance with section 23 of the 2011 Pipeline Safety Act,
PHMSA consulted with the Federal Energy Regulatory Commission and State
regulators as appropriate to establish the timeframes for completing
MAOP reconfirmation. As a part of this consultation, PHMSA accounted
for potential consequences to public safety and the environment while
also accounting for minimal costs and service disruptions. Furthermore,
PHMSA will note that both a FERC member and a NAPSR member are on the
GPAC, providing both input and positive votes that the provisions were
technically feasible, reasonable, cost-effective, and practicable if
certain changes were made. As previously discussed, PHMSA has taken the
GPAC's input into consideration when drafting this final rule and made
the according changes to the provisions.

I. Miscellaneous Issues

ii.--Records

1. Summary of PHMSA's Proposal
Many pipeline records are necessary for the correct setting and
validation of MAOP, which is critically important for providing an
appropriate margin of safety to the public. Much of operator and PHMSA
data is obtained through testing and inspection under the existing IM
requirements. Section 192.917(b) requires operators to gather pipeline
attribute data as listed in ASME/ANSI B31.8S--2004 Edition, section 4,
table 1. ASME/ANSI B31.8S--2004 Edition, section 4.1 states:
``Pipeline operator procedures, operation and maintenance plans,
incident information, and other pipeline operator documents specify and
require collection of data that are suitable for integrity/risk
assessment. Integration of the data elements is essential in order to
obtain complete and accurate information needed for an integrity
management program. Implementation of the integrity management program
will drive the collection and prioritization of additional data
elements required to more fully understand and prevent/mitigate
pipeline threats.''
However, despite this requirement, there continue to be data gaps
that make it hard to fully understand the risks to and the integrity of
the nation's pipeline system. Therefore, PHMSA proposed amendments to
the records requirements for part 192, specifically under the general
recordkeeping requirements, class location determination records,
material mechanical property records, pipe design records, pipeline
component records, welder qualification records, and the MAOP
reconfirmation provisions.
2. Summary of Public Comment
Several commenters provided input on the proposed amendments to the
records requirements for part 192. Several public interest groups,
including Pipeline Safety Coalition and PST, supported the increased
emphasis on recordkeeping requirements, stating that the requirements
are a proactive response to NTSB recommendations and are common-sense
business best practices.
Several commenters opposed the proposed provisions providing
general recordkeeping requirements for part 192. Commenters asserted
that these proposed provisions apply significant new recordkeeping
requirements on operators by requiring that operators

[[Page 52217]]

document every aspect of part 192 to a higher and impractical standard
than before. Commenters also stated that the proposed recordkeeping
requirements appear to be retroactive and stated that it would be
inappropriate to require operators to document compliance in cases
where there have not been requirements to document or retain records in
the past. Commenters also asserted that the Pipeline Safety Laws at 49
U.S.C. 60104(b) prohibits PHMSA from applying new safety standards
pertaining to design, installation, construction, initial inspection,
and initial testing to pipeline facilities already existing when the
standard is adopted, and that PHMSA does not have the authority to
apply these requirements retroactively. These commenters suggested that
even the recordkeeping requirements in these non-retroactive subparts
could not be changed under PHMSA's current authority. Subsequently,
commenters requested that PHMSA confirm that the proposed general,
material, pipe design, and pipeline component recordkeeping
requirements would not apply to existing pipelines and that
recordkeeping requirements for the qualification of welders and
qualifying plastic pipe joint-makers would not apply to completed
pipeline projects.
Additionally, several commenters also requested that PHMSA clarify
that many of the proposed recordkeeping requirements apply only to gas
transmission lines. AGA also expressed concern regarding the proposed
reference to material properties verification requirements in the
proposed general recordkeeping requirements, which, as written, would
also require distribution pipelines without documentation to comply
with the proposed material properties verification requirements.
Many commenters opposed the proposed application of the term
``reliable, traceable, verifiable, and complete'' in part 192 beyond
the requirements for MAOP records, and AGA recommended the deletion of
``reliable, traceable, verifiable and complete'' from proposed
provisions under MAOP reconfirmation. Similarly, other commenters,
including INGAA, recommended omitting ``reliable'' from the phrase and
provided a suggested definition for ``traceable, verifiable, and
complete'' records. Additionally, commenters opposed the use of this
term in the general recordkeeping requirements at Sec. 192.13, stating
that it would apply a new standard of documentation to part 192. Citing
a 2012 PHMSA Advisory Bulletin in which PHMSA stated that verifiable
records are those ``in which information is confirmed by other
complementary, but separate, documentation,'' INGAA requested that
PHMSA acknowledge that a stand-alone record will suffice and a
complementary record is only necessary for cases in which the operator
is missing an element of a traceable or complete record.\74\ INGAA also
provided examples of records that they believed to be acceptable, and
requested that PHMSA includes these examples in the final preamble.
---------------------------------------------------------------------------

\74\ https://www.phmsa.dot.gov/regulations-fr/notices/2012-10866; 77 FR 26822; May 7, 2012, ``Pipeline Safety: Verification of
Records.''
---------------------------------------------------------------------------

Several commenters also opposed the proposed Appendix A to part 192
that summarizes the records requirements within part 192 and requested
that it be eliminated, stating that Appendix A goes beyond summarizing
the existing records requirements and introduces several new
recordkeeping requirements and retention times. Commenters also
asserted that Appendix A should not be retroactive. Some commenters
supported the inclusion of Appendix A, saying that it is a much-needed
clarification of record requirements and retention. Noting that the
title of Appendix A suggests that it is specific to gas transmission
lines but that it does include some record retention intervals for
distribution lines, NAPSR recommended that Appendix A be expanded to
include records and retention intervals for all types of pipelines.
Many commenters requested that PHMSA clarify that the proposed changes
to Appendix A apply only to gas transmission lines.
Some commenters also opposed the newly proposed recordkeeping
requirements for pipeline components at Sec. 192.205. Commenters,
including Dominion East Ohio, stated that PHMSA should exclude pipeline
components less than 2 inches in diameter, as these small components
are often purchased in bulk with pressure ratings and manufacturing
specifications only printed on the component or box. They further
stated that in doing this, PHMSA would be consistent with its proposed
material properties verification requirements. Another commenter stated
that these requirements should be eliminated because they are
duplicative of the current requirements for establishing and
documenting MAOP at Sec. 192.619(a)(1).
Some commenters also opposed the proposed recordkeeping
requirements regarding qualifications of welders and welding operators
and qualifying persons to make joints in Sec. Sec. 192.227 and
192.285, stating that keeping these records for the life of the
pipeline is not needed, nor are they necessary for the establishment of
MAOP.
Issues related to records were discussed during all of the GPAC
meetings in various capacities. At the meeting in January 2017, several
issues were discussed, including: broad records guidance in a general
duties clause might be a good idea in theory but might cause unintended
consequences, and they discussed the advisability of addressing
necessary record components individually in the context of specific
code sections.
The GPAC discussed the proposed addition of ``reliable'' to the
phrase ``traceable, verifiable, and complete'' (TVC) record in the
proposed rule. The ``TVC'' standard was recommended by the NTSB
following the PG&E incident. Changing that standard could potentially
derail work being done by operators to meet that traceable, verifiable,
and complete record standard.
The GPAC also discussed PHMSA's statutory authority to impose the
proposed recordkeeping requirements, even in subparts that are
retroactive, because PHMSA is not requiring particular types of design,
installation, construction, etc., but is requiring that operators keep
records relevant to current operation.
At the GPAC meeting on June 6, 2017, the GPAC discussed the
proposed recordkeeping requirements for the qualification of welders
and welding operators as well as the qualification of persons making
joints on plastic pipe systems. Specifically, the discussion revolved
around whether the recordkeeping requirements should be for the life of
the pipeline, as proposed in the NPRM, or whether it should be for 5
years. Certain members believed it should be a 5-year requirement to be
consistent with other operator qualification requirements, and other
members believed that a 5-year requirement would be adequate due to the
``bathtub curve'' phenomenon where pipelines are more likely to fail
early or late in their service history. Therefore, having the records
for welding qualification within that early period would be sufficient.
Following that discussion, the committee recommended that PHMSA
modify the proposed rule to delete the word ``reliable'' from the
records standard to now read ``traceable, verifiable, and complete''
wherever that standard is used; clarify that documentation be required
to substantiate the current class location under Sec. 192.5(d); and
modify the recordkeeping provisions related to the

[[Page 52218]]

qualification of welders and the qualification of persons joining
plastic pipe to include an effective date and change the retention
period of the necessary records to 5 years.
At the March 2, 2018, meeting, the GPAC recommended that PHMSA
withdraw the general duty recordkeeping requirement at Sec. 192.13(e)
and Appendix A; modify the recordkeeping requirements for pipeline
components to clarify they apply to components greater than 2 inches in
nominal diameter; and revise the requirements related to material, pipe
design, and pipeline component records to clarify the effective date of
the requirements.
At the meeting on March 27, 2018, the GPAC recommended that PHMSA
provide guidance in the preamble regarding what constitutes a
traceable, verifiable, and complete record. Further, the GPAC
recommended PHMSA clarify that the MAOP recordkeeping requirements in
the MAOP establishment section at Sec. 192.619(f) apply only to
onshore, steel, gas transmission pipelines, and that they only apply to
the records needed to demonstrate compliance with paragraphs (a)
through (d) of the section. The GPAC suggested PHMSA could remove
examples of acceptable MAOP documents from the rule and include that
listing in the preamble of the final rule and through guidance
materials.
The GPAC also recommended that PHMSA clarify that the MAOP
recordkeeping requirements are not retroactive, that existing records
on pipelines installed prior to the rule must be retained for the life
of the pipeline, that pipelines constructed after the effective date of
the rule must make and retain the appropriate records for the life of
the pipeline, and that MAOP records would be required for any pipeline
placed into service after the effective date of the rule. Further, the
GPAC recommended PHMSA revise the rule by changing other sections,
including Sec. Sec. 192.624 and 192.917, to require when and for which
pipeline segments missing MAOP records would need to be verified in
accordance with the MAOP reconfirmation and material properties
verification requirements of the rulemaking.
3. PHMSA Response
PHMSA appreciates the information provided by the commenters
regarding the proposed records requirements. After considering these
comments and as recommended by the GPAC, PHMSA is modifying the rule to
withdraw the proposed Sec. 192.13(e) and Appendix A to avoid possible
confusion regarding recordkeeping requirements. Also, whenever new
recordkeeping requirements are included, PHMSA modified the rule to
clarify that the new requirements are not retroactive. To the degree
that operators already have such records, they must retain them.
Operators must retain records created while performing future
activities required by the code.
In addition to these general modifications, with regard to specific
records requirements, PHMSA is modifying the rule as follows: (1) In
Sec. 192.5(d), operators must retain records documenting the current
class location (but not historical class locations that no longer apply
because PHMSA agrees they are not necessary). (2) In Sec. 192.67, the
rule is being modified to delete reference to ``original steel pipe
manufacturing records'' to avoid retroactivity concerns, add wall
thickness and seam type to clarify that this manufacturing information
must be recorded, and include an effective date to eliminate
retroactivity concerns. (3) In Sec. 192.205, records for components
are only required for components greater than 2 inches (instead of
greater than or equal to 2 inches) (see Section III(A)(i)(3)). (4) In
Sec. 192.227, records demonstrating each individual welder
qualification must be retained for a minimum of 5 years because PHMSA
believes 5 years of welder qualification records are sufficient to
evaluate whether systemic issues are present upon inspection and at the
start-up of the pipeline. (5) In Sec. 192.285, records demonstrating
plastic pipe joining qualifications at the time of pipeline
installation in accordance must be retained for a minimum of 5 years
because PHMSA believes 5 years of records are sufficient to evaluate
whether systemic issues are present upon inspection and at the start-up
of the pipeline. (6) In Sec. 192.619, PHMSA clarified that new
recordkeeping for MAOP only apply to onshore, steel, gas transmission
pipelines. In addition, PHMSA deleted the sentence with examples of
records that establish the pipeline MAOP, which include, but are not
limited to, design, construction, operation, maintenance, inspection,
testing, material strength, pipe wall thickness, seam type, and other
related data to prevent redundancies in the regulations as this list is
maintained in Sec. 192.607.
PHMSA notes that the recordkeeping requirements in this final rule
under Sec. Sec. 192.67, 192.127, 192.205, and 192.227(c) applicable to
gas transmission pipelines will apply to offshore gathering pipelines
and Type A gathering pipelines as well. In accordance with this final
rule's requirements, operators of such pipelines must keep any of the
pertinent records they have upon this rule's issuance, and they must
retain any records made when complying with these requirements
following the publication of this rule. PHMSA notes that the
requirements for creating records in Sec. Sec. 192.67, 192.127,
192.205, and 192.227(c) are forward-looking requirements. However, and
in accordance with this final rule, operators must retain any records
they currently have for their pipelines. Any records generated through
the course of operation, including, most notably, records generated by
the material properties verification process at Sec. 192.607, must
also be retained by operators for the life of the pipeline.
As requested by the GPAC, PHMSA considered moving Sec. 192.619(e)
to be a subsection of Sec. 192.619(a) and considered referencing Sec.
192.624 in Sec. 192.619(a). However, PHMSA is retaining the proposed
paragraph (e) in the final rule and the reference to Sec. 192.624
within Sec. 192.619(e) because it more clearly requires pipeline
segments that meet any of the applicability criteria in Sec.
192.624(a) must reconfirm MAOP in accordance with Sec. 192.624, even
if they comply with Sec. 192.619(a) through (d). This also avoids the
potential for conflict if this requirement were to be placed in a
paragraph that applies to gathering lines and distribution lines. It
also makes it clear that pipeline segments with MAOP reconfirmed under
Sec. 192.624 are not required to comply with Sec. 192.619(a) through
(d).
Lastly, throughout this final rule, PHMSA is deleting the word
``reliable'' from the records standard to now read ``traceable,
verifiable, and complete'' wherever that description is used. PHMSA
issued advisory bulletins ADB 12-06 on May 7, 2012 (77 FR 26822) and
ADB 11-01 on January 10, 2011 (76 FR 1504). In these advisory
bulletins, PHMSA provided clarification and guidance that all documents
are not records and provided additional information on the definition
and standard for records. For a document to be a record, it must be
traceable, verifiable, and complete. PHMSA provides further explanation
of these concepts below.
Traceable records are those which can be clearly linked to original
information about a pipeline segment or facility. Traceable records
might include pipe mill records, which include mechanical and chemical
properties; purchase requisition; or as-built documentation indicating
minimum pipe yield

[[Page 52219]]

strength, seam type, wall thickness and diameter. Careful attention
should be given to records transcribed from original documents as they
may contain errors. Information from a transcribed document, in many
cases, should be verified with complementary or supporting documents.
Verifiable records are those in which information is confirmed by
other complementary, but separate, documentation. Verifiable records
might include contract specifications for a pressure test of a pipeline
segment complemented by pressure charts or field logs. Another example
might include a purchase order to a pipe mill with pipe specifications
verified by a metallurgical test of a coupon pulled from the same
pipeline segment. In general, the only acceptable use of an affidavit
would be as a complementary document, prepared and signed at the time
of the test or inspection by a qualified individual who observed the
test or inspection being performed.
Complete records are those in which the record is finalized as
evidenced by a signature, date or other appropriate marking such as a
corporate stamp or seal. For example, a complete pressure testing
record should identify a specific segment of pipe, who conducted the
test, the duration of the test, the test medium, temperatures, accurate
pressure readings, and elevation information as applicable. An
incomplete record might reflect that the pressure test was initiated,
failed and restarted without conclusive indication of a successful
test. A record that cannot be specifically linked to an individual
pipeline segment is not a complete record for that segment. Incomplete
or partial records are not an adequate basis for establishing MAOP or
MOP. If records are unknown or unknowable, a more conservative approach
is indicated.
For example, a mill test report must be traceable, verifiable, and
complete, which is a typical record for pipelines. For the mill test
report to be traceable it would need to be dated in the same time frame
as construction or have some other link relating the mill record to the
material installed in the pipeline, such as a work order or project
identification. For the mill test report to be verified, it would need
to be confirmed by the purchase or project specification for the
pipeline or the alignment sheet with consistent information. Such an
example would be verified by independent records. For the mill test
report to be complete, it must be signed, stamped, or otherwise
authenticated as a genuine and true record of the material by the
source of the record or information, in this example it could be the
pipe mill, supplier, or testing lab.
Another common record is a pressure test record, which must be
traceable, verifiable, and complete. For the pressure test record to be
traceable, it would need to identify a specific and unique segment of
pipe that was tested (such as mileposts, survey stations, etc.) or have
some other link relating the pressure test to the physical location of
the test segment, such as a work order, project identification, or
alignment sheet. For the pressure test record to be verified, it would
need to be confirmed by the purchase or project specification for the
pipeline or the alignment sheet with consistent information. Such an
example would be verified by independent records. For the pressure test
record to be complete, it should identify a specific segment of pipe,
who conducted the test, the duration of the test, the test medium,
temperatures, accurate pressure readings, elevation information, and
any other information required by Sec. 192.517, as applicable. An
incomplete record might reflect that the pressure test was initiated,
failed and restarted without conclusive indication of a successful
test.

I. Miscellaneous Issues

iii.--Cost/Benefit Analysis, Information Collection, and Environmental
Impact Issues

NPRM Assumptions/Proposals
U.S. Code, title 49, chapter 601, section 60102 specifies that the
U.S. Department of Transportation (U.S. DOT), when prescribing any
pipeline safety standard, shall consider relevant available gas and
hazardous liquid pipeline safety information, environmental
information, the appropriateness of the standard, and the
reasonableness of the standard. In addition, the U.S. DOT must, based
on a risk assessment, evaluate the reasonably identifiable or estimated
benefits and costs expected to result from implementation or compliance
with the standard. PHMSA prepared a preliminary regulatory impact
analysis (PRIA) to fulfill this statutory requirement for the proposed
rule and a new regulatory impact analysis (RIA) for this final rule. In
addition, PHMSA's Environmental Assessment (EA) is prepared in
accordance with NEPA, as amended, and the Council on Environmental
Quality (CEQ) regulations for implementing NEPA (40 CFR parts 1500-
1508). When an agency anticipates that a proposed action will not have
significant environmental effects, the CEQ regulations provide for the
preparation of an EA to determine whether to prepare an environmental
impact statement or finding of no significant impact.
Summary of Public Comment
Cost Impacts
Several commenters provided input on the cost analysis conducted in
the PRIA, providing comments on the structure, assumptions, and unit
costs in the PRIA as well as on the lack of accounting for impacts such
as the abandonment of pipelines and the cost increase to electricity
ratepayers.
Some public interest groups provided input on the cost analysis in
the PRIA. EDF stated that the PRIA reasonably addressed uncertainty and
lack of information surrounding certain key data assumptions. EDF
further stated that the PRIA aligned with Office of Management and
Budget guidance on the development of regulatory analysis for
rulemakings. They stated that PHMSA used conservative values when
making best professional judgments. PST asserted that the costs
included in the PRIA for reconfirmation of MAOP, data gathering, record
maintenance, and data integration for lines subject to the IM
provisions result from the current IM regulations and practices and
should not be attributed to this rulemaking. They further stated that
the PRIA should be amended to remove these costs related to lines
within HCAs.
Several trade associations and industry pipeline entities provided
input on the assumptions, methodology, and unit costs used in the PRIA,
stating that PHMSA underestimated the cost of complying with the
proposed regulations. AGA stated that the organization of the PRIA by
``topic areas'' made it difficult to evaluate the cost estimates of the
various provisions of the rule and requested that PHMSA provide a RIA
with the final rule that addresses each regulatory section as organized
in the preamble. Many commenters, including INGAA, AGA, AGL Resources,
and Piedmont, stated that the PRIA underestimated the cost impacts of
increased material properties verification, recordkeeping, and MAOP
reconfirmation requirements. AGL Resources asserted that complying with
the proposed record requirements would involve increased labor and
investment costs that should be quantified in the final RIA. AGA stated
that it was unclear whether or how the PRIA incorporated material
properties verification costs related to material documentation, plan
creation, revisions, and testing. NYSEG asserted that the PRIA
underestimated the cost impact of the proposed rule on smaller local

[[Page 52220]]

distribution companies with combined transmission and distribution
systems and estimated that they would have to perform IM elements on 8
times the mileage currently in their IM program. Lastly, INGAA provided
a higher cost for MAOP confirmation than was estimated in the PRIA due
in large part to their assumption that industry would continue to rely
on pressure testing, as they asserted that the proposed methods for ILI
and ECA are not feasible.
INGAA, AGA, and API submitted detailed cost analyses to the
rulemaking docket, while many other commenters (approximately 40)
provided estimated unit costs for various provisions of the proposed
rule that were generally higher than the unit costs used in the PRIA.
For example, Southwest Gas stated that the costs included in the PRIA
for options such as ILI and pressure testing were not representative of
the costs to their system. With regard to the cost of integrity
assessments, BG&E stated that it would cost them over $1 million per
year to perform integrity assessments on the additional 100 miles of
MCA transmission pipelines, a total which equates to a higher cost per
mile estimate than was used in the PRIA. Additionally, New Mexico Gas
Co. stated that the proposed rule would cost their company $5.6 million
per year to perform integrity assessments on 528 miles of MCA
transmission pipe. Vectren estimated the impact to its transmission
system would cost $22 million annually. Lastly, PG&E stated that their
forecasted costs to implement the proposed rule are significantly
higher than the estimates in the PRIA. PG&E provided a comparison of
the PRIA costs with their expected expenditures to comply with many
provisions in the proposed rule. They projected the cost of compliance
would require an upfront investment of $578 million in addition to $222
million per year (as well as a reoccurring cost of $30 million every 7
years) and stated that, comparatively, the PRIA estimates a present
value annualized cost of $47 million per year.
Some stakeholders provided input on the estimated number of miles
that PHMSA used to determine the regulatory impact of the provisions in
the proposed rule. For example, INGAA stated that it assumed the
mileage estimated by PHMSA for estimation of MAOP confirmation,
material properties verification, and integrity assessments outside
HCAs to be accurate with the addition of reportable in-service
incidents since last pressure test data. INGAA also asserted that the
mileage estimated for MCA transmission pipes should be done on the per-
foot basis instead of on the per-mile basis because these pipes are
likely to be an aggregation of short pipeline segments that are 1 mile
or shorter in length. The North Dakota Petroleum Council asserted that
proposed changes in the definition of onshore gathering lines would
dramatically increase the number of miles of regulated gathering wells
beyond the mileage estimates in the PRIA.
Some commenters asserted that the financial impact of the proposed
rule would be immense and that, because operators would not be able to
bear these costs alone, they would likely pass the costs on to the
ratepayers. For example, APGA stated that all of their member utilities
purchase gas and pay transportation charges to transmission pipelines
to deliver gas from the producer to the utility. They asserted that
ratepayers would pay for the costs that would be incurred by their
transmission suppliers to comply with this rule. Similarly, Indiana
Utility Regulatory Commission requested that PHMSA consider the costs
to ratepayers in its cost analysis. Other commenters stated that this
rule could force operators to take significant portions of their
pipelines out of service while they are brought into compliance and
that the PRIA failed to recognize that FERC requires interstate natural
gas pipelines operators to provide demand charge credits to customers
when service is disrupted.
Some commenters stated that the proposed rule may cause pipeline
abandonment and that these impacts should be considered in the final
RIA. Boardwalk Pipeline stated that if a pipe is no longer economic to
operate, but FERC does not grant abandonment authority, a pipeline
company would be forced to either operate a pipeline that may not meet
PHMSA standards or undertake expensive replacement projects. Boardwalk
Pipeline further stated that while operators may seek to recover the
costs of replacement projects through rate increases, in a competitive
pipeline market where operators are forced to discount their pipeline
rates in order to retain customers, these costs might be too great to
recover. Similarly, the Independent Petroleum Association of America
stated that the PRIA failed to account for the costs that could be
incurred by operators if pipeline infrastructure is abandoned because
the cost that would be required to comply with the rule would
necessitate this abandonment. The Public Service Commission of West
Virginia suggested that, should operators abandon wells and pipelines
due to the requirements of this proposed rule, it could cause an
environmental and economic liability for State regulators if operators
abandon wells and pipelines without proper clean up.
Several commenters expressed concern that PHMSA's cost-benefit
analysis does not meet the requirements established by the 2011
Pipeline Safety Act and the Administrative Procedures Act (APA). Trade
associations stated that the PRIA does not fulfill PHMSA's statutory
obligations because it omits relevant costs, relies on incorrect
assumptions, and contains multiple inconsistencies. INGAA asserted that
the PRIA does not comply with the APA because the finding in the PRIA
that the proposed benefits outweigh the costs is contingent on an
underestimation of the costs of the proposed rule. INGAA also noted
that flawed cost-benefit analysis can be grounds for courts to reject
agency rulemakings. INGAA asserted that the proposed rulemaking does
not comply with the Paperwork Reduction Act (PRA), because PHMSA's
estimate of the information collection burden did not include the costs
of these additional recordkeeping requirements for transmission
pipeline operators.
Benefit Estimates
PHMSA also received comments on the benefits associated with the
proposed rule. Physicians for Social Responsibility expressed their
support of the proposed rule and the analysis of reduced accidents and
increased worker safety in the PRIA. Additionally, Physicians for
Social Responsibility stated that many harmful air pollutants, such as
nitrous oxide, sulfur dioxide, particulate matter, formaldehyde, and
lead, are all associated with gas pipelines and compressor stations.
They further stated that this rule would help reduce or mitigate this
pollution and that these public health benefits should be accounted for
in the benefits calculations.
Other commenters, including AGA and INGAA, stated that PHMSA
overestimated the damage caused by incidents in the quantification of
benefits in the PRIA. AGA stated that PHMSA allowed one major incident
to skew the data in their benefits analysis and proposed that PHMSA
adopt a new approach to quantify the benefits of reduced accidents.
INGAA stated that using data from the past 13 years skewed the results
and that the most recent 5 years of incident history would more
reasonably reflect positive developments in pipeline safety, given that
significant developments in pipeline safety have occurred within this
time period.

[[Page 52221]]

Several commenters provided input on the proposed use of the social
cost of carbon and the social cost of methane in the PRIA. EDF and
National Resource Defense Council supported the use of the social costs
of carbon and methane methodology in the PRIA. However, these
commenters stated that the estimates for social costs of carbon and
methane were likely too conservative and that the values should be
higher than those used in the PRIA. These commenters stated that PHMSA
should encourage the Interagency Working Group on Social Cost of Carbon
to update regularly the social cost of carbon and social cost of
methane as new economic and scientific information emerges. API stated
that the proposed use of the social cost of methane to calculate the
benefits of emissions reductions was flawed due to the discount rates
used by PHMSA. They asserted that PHMSA used low discount rates that
led to a liberal damage estimate. In addition, API and Industrial
Energy Consumers of America asserted that the social cost of carbon
values used by PHMSA inappropriately impose global carbon costs on
domestic manufacturers, which damages the industry's ability to compete
internationally. AGA stated that the process used to develop the social
cost of methane values in the PRIA did not undergo sufficient expert
and peer review. INGAA stated that PHMSA overestimated the amount of
greenhouse gas emissions that the rule would reduce.
Environmental Impacts
Several commenters noted that the 2011 Pipeline Safety Act mandates
that PHMSA consider the environmental impacts of proposed safety
standards. Citizen groups stated that the proposed regulation fulfills
this statutory obligation and is a step forward in reducing methane
emissions from natural gas pipelines. Multiple citizen groups
emphasized the consequences of climate change, the high global warming
potential of methane, and the responsibility of natural gas systems for
a significant portion of U.S. methane emissions. Citizen groups
underlined the importance of regulating methane leaks and considering
methane's climate implications in natural gas regulations. The Lebanon
Pipeline Awareness Group addressed local environmental impacts,
requesting that pipelines not be permitted to contaminate agricultural
soils.
Trade associations asserted that PHMSA did not fulfill its
statutory obligation to consider the full environmental impacts of the
proposed safety standards, suggesting that PHMSA failed to consider
several topics in the NPRM that would have direct environmental
impacts. These commenters claimed that certain topics and their
impacts, including IM clarifications, MAOP reconfirmation, and
hydrostatic pressure testing, were mischaracterized in the EA, and that
PHMSA further underestimated the number of excavations that would need
to be made per the proposal as well as the impacts of procuring and
disposing of water for hydrostatic tests.
Trade associations further expressed concerns that, while PHMSA had
addressed the emissions avoided under the proposed rule, PHMSA had not
addressed the extent to which the proposed rule would increase
emissions. AGA and INGAA noted that operators need to purge lines of
natural gas before conducting hydrostatic tests or removing pipelines
from service for replacement or repair. These commenters stated that
the proposed regulation would increase methane emissions by increasing
the number of hydrostatic tests, pipeline replacements, and pipeline
repairs required and asserted that the EA did not take the increased
emissions from these blowdowns into account. INGAA asserted that not
considering these methane emissions constituted a violation of the 2011
Pipeline Safety Act and failure to ``engage in reasoned decision
making.'' INGAA also suggested that the methane emissions resulting
from this rulemaking would run counter to President Obama's goals of
reducing methane emissions.
EDF and PST commissioned a study from M.J. Bradley & Associates
(MJB&A) that calculated the extent to which the proposed rule would
result in blowdown emissions. MJB&A found that potential methane
emissions resultant from the proposed rule would increase annual
methane emissions from natural gas transmission systems by less than
0.1 percent and increase annual methane emissions from transmission
system routine maintenance by less than one percent. MJB&A also noted
five mitigation methods that if implemented, could decrease blowdown
emissions by 50 to 90 percent.\75\ MBJ&A calculated that the societal
benefits of methane reduction outweighed the mitigation costs for all
mitigation options considered. Based on this study, EDF asserted that
while the marginal increase in emissions from the proposed rule would
be small, the total emissions from blowdowns would nonetheless be
significant. They stated that PHMSA should require operators to select
and implement one of the mitigation options and report to PHMSA
information about their blowdown events, such as the mitigation option
selected and the amount of product lost due to blowdowns required by
the proposed rule. EDF also stated that if operators do not mitigate
blowdown emissions, they should be required to provide an engineering
or economic analysis demonstrating why mitigation is deemed infeasible
or unsafe.
---------------------------------------------------------------------------

\75\ The methods are (1) gas flaring; (2) pressure reduction
prior to blowdown with inline compressors; (3) pressure reduction
prior to blowdown with mobile compressors; (4) transfer of gas to a
low-pressure system; and (5) reducing the length of pipe requiring
blowdown by using stopples.
---------------------------------------------------------------------------

AGA stated that the EA did not address other environmental impacts
resultant from hydrostatic pressure testing. AGA noted two anticipated
water-related impacts: (1) Hydrostatic pressure testing's water demand
could aggravate water scarcity in already water-scarce environments,
and (2), the water used in hydrostatic tests could introduce
contaminants if disposed on-site (or be very expensive to transport to
off-site disposal). AGA explained that wastewater from hydrostatic
tests could include hydrocarbon liquids and solids, chlorine, and
metals.
AGA also asserted that the EA did not adequately consider the land
disturbances that could result from the proposed hydrostatic testing
requirements, nor did it consider that performing inline inspections
and modifying pipelines to accommodate inline inspection tools would
generate waste and disturb natural lands. AGA explained that operators
must clean pipelines prior to conducting inline inspections or
modifying pipelines for inline inspection tools and that this cleaning
could produce large volumes of pipeline liquids, mill scale, oil, and
other debris. AGA expressed concerns that the proposed EA did not
discuss these environmental impacts associated with requiring MAOP
confirmation, given that PHMSA anticipates that most affected pipelines
would verify MAOP using ILI and pressure testing.
AGA also provided input on the local environmental impacts of the
proposed increased testing and inspection. AGA expressed concerns that
the EA had (1), underestimated the quantity of excavations that would
be required under the proposed rule, and (2), inadequately assessed the
environmental impacts of those excavations. AGA asserted that the EA
had insufficiently considered the extent to which more excavations
would generate water and soil waste. AGA also suggested that the
proposed rule may

[[Page 52222]]

induce operators to modify or replace pipelines and that these
modifications and replacements may affect land beyond existing rights
of way. AGA asserted that this additional land area should be
considered in the EA.
Trade associations raised other technical issues regarding the EA.
AGA expressed concerns that PHMSA provided insufficient information
about methods used to calculate values in the EA and that this
insufficient documentation interfered with stakeholders' ability to
provide comments on the values that PHMSA chose. INGAA asserted that
the proposed rule fell short of several legal obligations under NEPA,
stating that the EA does not provide the required ``hard look'' at
environmental impacts, that the EA does not adequately discuss the
indirect and cumulative effects of the proposed rule, and that the
purpose and need statement in the EA do not fulfill NEPA instructions.
INGAA also expressed concern that PHMSA did not consider sufficient
regulatory alternatives, stating that the EA considered solely the
proposed rule, one regulatory alternative, and the no action
alternative. INGAA stated that given the many provisions of the
proposed rule, this approach was too limited.
Other Impacts
Some trade associations and pipeline industry entities provided
input that the PRIA failed to account for the indirect effects of
operators shifting resources to comply with the proposed rule. For
example, AGA stated that the PRIA did not consider the potential
indirect impacts the rule might impose on distribution lines. They
asserted that the magnitude and prescriptiveness of the proposed rule
would require distribution companies with intrastate transmission and
distribution assets to reassign their limited resources to transmission
lines.
Some commenters stated that PHMSA did not consider that the
proposed rule would divert resources away from voluntary safety
programs their companies are initiating, stating that these voluntary
safety measures would be scaled back because of the proposed rule. For
example, AGA stated that accelerated pipe replacement programs that
replace aging cast iron, unprotected steel pipe, and vintage plastic
pipe, would lose resources as operators shift staff and capital to
comply with the proposed rule. They further asserted that failing to
replace these pipes would delay reductions in methane emissions from
old, leaky pipes.
PHMSA Response
Cost Impacts
PHMSA has reviewed the comments related to the RIA for the proposed
rule and has revised the final analysis consistent with the final rule
and in consideration of the comments. PHMSA addressed the comments
received on the RIA in two key ways. First, PHMSA revised many of the
requirements in the final rule, including (a) revising or clarifying
that the final provisions do not apply to gas distribution or gas
gathering pipelines; (b) revising MAOP reconfirmation requirements for
grandfathered pipelines to include only those lines with MAOP greater
than or equal to 30 percent SMYS; (c) streamlining the process for
operators to use an alternative technology for MAOP reconfirmation; (d)
removing the term ``occupied sites'' in the MCA definition; and (e)
revising the records provisions to remove certain proposed provisions
and clarifying that the new requirements are not retroactive. These
changes, as well as others made in the final rule, result in less
costly and more cost-effective requirements. Second, in response to
comments received, PHMSA made several revisions to the analysis
conducted in the RIA for the proposed rule, discussed below. Also, in
response to comments, PHMSA revised the final RIA to align more closely
to the preamble organization.
PHMSA acknowledges the baseline issues associated with establishing
MAOP, data collection, and other provisions noted in the comments. In
the final RIA, PHMSA is including estimated incremental costs to
reconfirm MAOP for lines within HCAs based on a current compliance
baseline. Attributing compliance to existing pipeline safety
regulations would reduce both the costs and benefits of the final rule.
Regarding the comments that the RIA for the proposed rule
underestimated the cost impacts of material properties verification,
recordkeeping, and MAOP confirmation, as discussed above, the changes
to the scope and applicability of the MAOP reconfirmation, data, and
recordkeeping provisions result in common-sense, cost-effective
requirements. For example, PHSMA designed the final requirements for
material properties verification to allow operators the option of a
sampling program that opportunistically takes advantage of repairs and
replacement projects to verify material properties simultaneously. The
final provisions allow, over time, operators to collect enough
information to gain significant confidence in the material properties
of pipe subject to this requirement.
Further, as discussed under the section regarding the material
properties verification process, the final rule removes the
applicability criteria of the material properties verification
requirements and makes a procedure for obtaining pipeline physical
properties and attributes that are not documented in traceable,
verifiable, and complete records or for otherwise verifying pipeline
attributes when required by MAOP reconfirmation requirements, IM
requirements, repair requirements, or other code sections. Therefore,
due to the changes made from the proposed rule, the material properties
verification requirements mandated by section 23 of the 2011 Pipeline
Safety Act represent a cost savings in comparison to existing
regulations, although PHMSA has not quantified those savings.
With regard to the operator-provided cost information or estimates
of the proposed rule, the commenters' estimates were not transparent
enough for PHMSA to discern the assumptions and inputs underlying the
estimates. As a result, PHMSA could not reliably confirm whether the
cost information accurately reflected the quantity and character of the
actions required by the proposed rule. To improve the transparency of
the analysis and address commenters' concerns about PHMSA's reliance on
best professional judgment in the RIA for the proposed rule, PHMSA
contacted five vendors of pipeline inspection and testing services to
obtain updated cost estimates for several unit costs that were based on
best professional judgement in the RIA for the proposed rule. These
vendors provided representative incremental costs associated with the
final rule requirements. In the final RIA, PHMSA used prices provided
by vendors to estimate unit costs for all MAOP reconfirmation and
integrity assessment methods, as well as for upgrades to launchers and
receivers.
Regarding MAOP reconfirmation specifically, in the RIA for the
proposed rule PHMSA assumed operators would conduct MAOP reconfirmation
using either pressure testing or ILI. In the final RIA, based on
feedback received during a GPAC meeting,\76\ PHMSA assumed that
operators would reconfirm MAOP using a mix of all six available
compliance methods.
---------------------------------------------------------------------------

\76\ GPAC Meeting, March 26-28, 2018. For a transcript of the
meeting, see https://primis.phmsa.dot.gov/meetings/FilGet.mtg?fil=970.
---------------------------------------------------------------------------

Additionally, in the final RIA, PHMSA analyzed the requirements for
MAOP reconfirmation and integrity

[[Page 52223]]

assessments outside HCAs for each operator individually based on the
information they submitted in their Annual Reports. Based on the
information in operator Annual Reports and the final rule requirements
for MAOP reconfirmation, some operators will incur less of an impact
than indicated by their public comments.
Regarding the comment that the proposed changes to the definition
of onshore gathering lines would dramatically increase the number of
miles of regulated gathering wells beyond the mileage estimates in the
RIA for the proposed rule, this final rule does not change the
definition of gathering pipelines.
With respect to pipelines located within MCAs, PHMSA confirmed the
analysis of the length of gas transmission pipelines located within
MCAs in the RIA for the proposed rule by integrating additional spatial
data from the U.S. Census Bureau, U.S. Geological Survey, Environmental
Systems Research Institute, and Tele-Atlas North America, Inc. For
additional details on the MCA GIS analysis, see section 5.7 of the RIA
for the final rule. This allowed PHMSA to confirm the number of
impacted miles. Additionally, due to existing state MAOP reconfirmation
requirements, PHMSA updated the RIA to reflect that impacts in
California are not attributable to the rule. Lastly, PHMSA presented
all impacted mileage on a dollar-per-foot basis instead of dollars per
mile, based on comments received that these pipeline segments are
likely to be an aggregation of short pipeline segments that are a mile
or shorter in length.
Regarding the comment that PHMSA underestimated the cost impact of
the proposed rule on smaller local distribution companies with combined
gas transmission and gas distribution systems, PHMSA conducted an
analysis of the rule's impact on small entities by comparing entity-
level cost estimates to annual entity revenues and identifying entities
for which annualized costs may exceed 1 percent and 3 percent of
revenue. As documented in the final Regulatory Flexibility Act (FRFA)
analysis, PHMSA relied on conservative assumptions in performing this
sales test, which may overstate, rather than understate, compliance
costs for small entities. PHMSA found that the final rule will not have
a significant economic impact on small entities.
PHMSA does not agree that the final rule requirements constitute a
significant energy action. PHMSA agrees with the comment that the costs
would be passed on to ratepayers; however, PHMSA disagrees that these
costs would be immense. E.O. 13211 requires agencies to prepare a
Statement of Energy Effects when undertaking certain agency actions if,
among other criteria, the regulation is expected to see an increase in
the cost of energy production or distribution in excess of one percent.
The annualized cost of these requirements represents less than 0.1
percent of pipeline transportation of natural gas (North American
Industry Classification System code 486210) industry revenues ($25
billion), adjusting the 2012 Economic Census value into 2017 dollars
using the Gross Domestic Product Implicit Price Deflator Index.
Therefore, in the aggregate it is extremely unlikely that these
requirements would cause a significant increase in costs that utilities
would pass on to the ratepayer.
Available information supports that, in the baseline, operators are
replacing or abandoning certain pipelines regardless of the
implementation of this rule as well as taking other actions such as
making lines piggable.\77\ As discussed above, in the final RIA, PHMSA
assumed some use of pipe replacement and abandonment as a means of
operators reconfirming MAOP. However, the costs of replacing
infrastructure operating beyond the design useful life are not
attributable to safety regulations and investment in plant, including a
return on investment, are already recovered through rates.
---------------------------------------------------------------------------

\77\ PG&E. 2011. ``Pacific Gas And Electric Company's Natural
Gas Transmission Pipeline Replacement Or Testing Implementation
Plan.'' California Public Utilities Commission; Consolidated Edison
Company Of New York. 2016. ``Consolidated Edison Company Of New
York, Inc. 2017-2019 Gas Operations Capital Programs/Projects.'' New
York State Department of Public Service. https://documents.dps.ny.gov/public/MatterManagement/CaseMaster.aspx?MatterCaseNo=16-G-0061&submit=Search.
---------------------------------------------------------------------------

The RIA for the final rule meets all PHMSA's requirements under
applicable acts and executive orders. The analysis involves estimating
a baseline scenario and changes under the regulation. PHMSA has used
its judgement, available data, information, and analytical methods to
develop an analysis of the baseline and incremental costs and benefits
under the rule. As discussed above, some costs and benefits may be
attributable to existing requirements and some may occur in the absence
of the rule.
Benefits Estimates
PHMSA agrees that recent data is more reflective of recent
improvements in pipeline safety and performance relative to current
standards. For the final RIA, PHMSA used more recent data on pipeline
incidents from 2010 to 2017 versus the 2003 to 2015 data used in the
RIA for the proposed rule. PHMSA used the data from 2010 on because
PHMSA updated its incident reporting methodology in 2010, and this
period therefore provides the largest available sample of consistently
reported incident data. Regarding the benefits analysis for the
preliminary RIA developed for the NPRM potentially being skewed by one
major incident (the PG&E incident at San Bruno), there is no evidence
that more serious incidents are not possible in the future in the
absence of the regulation, and therefore, PHMSA does not exclude this
incident when qualitatively assessing benefits. At the same time, and
although PHMSA developed this rule to prevent future, similar
incidents, PHMSA cannot know with certainty whether a similar incident
would occur again absent this rulemaking. According to the historical
record, serious incidents, like the one occurring at San Bruno, occur
approximately once per decade. For example, on August 19, 2000, a 30-
inch-diameter natural gas transmission pipeline operated by the El Paso
Natural Gas Company ruptured adjacent to the Pecos River near Carlsbad,
NM. The released gas ignited and burned for 55 minutes. Twelve persons
camping near the incident location were killed, and their three
vehicles were destroyed.\78\ Similarly, on March 23, 1994, a 36-inch-
diameter natural gas transmission pipeline owned and operated by Texas
Eastern Transmission Corporation ruptured in Ellison Township, NJ. The
incident caused at least $25 million in damages, dozens of injuries,
and the evacuation of hundreds.\79\ More detailed data on current
pipeline integrity in relation to populations and the environment would
enable more detailed predictions of the benefits of regulations.
---------------------------------------------------------------------------

\78\ Natural Gas Pipeline Rupture and Fire Near Carlsbad, New
Mexico, August 19, 2000, Pipeline Accident Report, NTSB/PAR-03/01,
Washington, DC.
\79\ Texas Eastern Transmission Corporation Natural Gas Pipeline
Explosion and Fire, Pipeline Accident Report, NTSB/PAR-95-01,
Washington, DC.
---------------------------------------------------------------------------

Due to the speculative nature of predicting the occurrence,
avoidance, and character of specific future pipeline incidents, in the
final RIA, PHMSA elected not to quantify the rule's benefits. PHMSA
uses this approach rather than make highly uncertain predictions about
both a specific number of future incidents avoided due to the final
rule, and the character of avoided incidents with respect to effects on
benefit-analysis endpoints (e.g., fatalities, injuries, evacuation).
The

[[Page 52224]]

quantified benefits for each provision therefore represent the quantity
of a given benefit category required to achieve a dollar value equal to
the provision's compliance cost.
PHMSA does not have data on harmful air pollutants such as nitrous
oxide, sulfur dioxide, particulate matter, formaldehyde, and lead
associated with gas pipelines and compressor stations, or the
reductions in these pollutants under the rule. Therefore, the analysis
did not address the environmental costs associated with these
pollutants. PHMSA did not include estimates of benefits based on the
social cost of methane for the final rule.
Environmental Impacts
Regarding the comments stating that the preliminary EA did not
adequately consider the air emissions that would result from
hydrostatic pressure testing, inline inspections, excavations, and MAOP
reconfirmation, PHMSA revised the EA to address this issue. Commenters
asserted that by increasing the number of hydrostatic tests, pipeline
replacements, and pipeline repairs required, the proposed provisions
would increase methane ``blowdown'' emissions that result from the
required purging of natural gas pipelines before conducting these
actions. PHMSA revised the EA to include a discussion of the study
conducted by M.J. Bradley & Associates (MJB&A) \80\ that calculated the
extent to which the proposed rule would result in blowdown emissions.
---------------------------------------------------------------------------

\80\ The study was commissioned by EDF and PST and is available
at https://blogs.edf.org/energyexchange/files/2016/07/PHMSA-Blowdown-Analysis-FINAL.pdf.
---------------------------------------------------------------------------

MJB&A found that unmitigated blowdown from the miles of
transmission pipeline that would be required to conduct a MAOP
determination would release an average of 1,353 metric tons per year of
methane to the atmosphere for the 15-year compliance period \81\
proposed by PHMSA. By comparison, historical unintentional releases
from natural gas transmission pipelines outside of HCAs with piggable
lines greater than 30 percent SMYS (a universe of facilities that could
be subject to MAOP reconfirmation in MCAs) averaged 13,500 metric tons
per year from 2010 to 2017. These releases were caused by 163 incidents
that released an average of 663.4 metric tons per incident.\82\
---------------------------------------------------------------------------

\81\ See Sec. 192.624(b).
\82\ ``Distribution, Transmission & Gathering, LNG, and Liquid
Accident and Incident Data.'' Phmsa.Dot.Gov. 2017. https://www.phmsa.dot.gov/data-and-statistics/pipeline/distribution-transmission-gathering-lng-and-liquid-accident-and-incident-data.
---------------------------------------------------------------------------

Therefore, if the final rule requirements avoided two average
incidents per year, the rule would not result in any net methane
releases. MJB&A further stated that the potential methane emissions
resultant from the NPRM would increase annual methane emissions from
natural gas transmission systems by less than 0.1 percent and increase
annual methane emissions from transmission system routine maintenance/
upsets by less than one percent. Given these factors, PHMSA does not
believe that the final rule will result in a significant, if any,
increase in methane releases.
In response to comments, PHMSA revised the EA to also include a
discussion of water-related impacts resulting from hydrostatic pressure
testing as well as waste generation land disturbances from hydrostatic
pressure testing and inline inspections. Operators must conduct all
waste and wastewater disposal activities in accordance with federal,
state, and local regulations and permit requirements, and the final
rule requires processes and procedures in which pipeline operators are
already familiar with respect to pipeline IM. Regarding the comments on
the environmental impacts of pipe replacement, as discussed above, the
impacts of replacing infrastructure that is operating beyond the design
useful life are not attributable to the final rule requirements. While
the final RIA assumes that operators will comply with MAOP
reconfirmation using pipe replacement for approximately 300 miles of
pipe, PHMSA did not consider these replacements to be incremental
costs. Similarly, the environmental impacts are not attributable to the
final rule requirements.
Other Impacts
PHMSA disagrees with the analysis of operators shifting resources
away from safety programs to comply with the proposed rule. PHMSA has
revised and clarified the pipeline safety and integrity applicability
of the final rule such that many operators will incur lower costs than
previously anticipated. The final rule also provides long compliance
schedules to enable planning for efficient compliance actions.

IV. GPAC Recommendations

This section briefly summarizes the NPRM proposals, the GPAC's
major comments on the proposals discussed, and the recommendations of
the committee regarding how those provisions should be finalized. More
detail, the presentations, and the transcripts from all of the meetings
are available in the docket for this rulemaking.\83\ The provisions,
which are presented in the order they were discussed at the GPAC
meetings, the changes the committee agreed upon, and the corresponding
vote counts are as follows:
---------------------------------------------------------------------------

\83\ https://www.regulations.gov/docket?D=PHMSA-2011-0023.
---------------------------------------------------------------------------

6-Month Grace Period for 7-Calendar-Year Reassessment Intervals (Sec.
192.939(b))
In the NPRM, PHMSA proposed to allow operators to request a 6-month
extension of the 7-calendar-year reassessment interval if the operator
submits written notice to the Secretary with sufficient justification
of the need for the extension in accordance with the technical
correction at section 5 of the 2011 Pipeline Safety Act. The committee
had no objections or substantial comments on this provision and voted
12-0 that it was, as published, technically feasible, reasonable, cost-
effective, and practicable.
Safety Features on ILI Launchers and Receivers (Sec. 192.750)
In the NPRM, PHMSA proposed to require operators equip ILI tool
launchers and receivers with a device capable of safely relieving
pressure in the barrel before the insertion or removal of ILI tools,
scrapers, or spheres. Further, PHMSA proposed requiring operators to
use a suitable device to indicate that pressure has been relieved in
the barrel or otherwise provide a means to prevent the opening of the
barrel if pressure has not been relieved. The committee voted 12-0 that
this provision was, as published, technically feasible, reasonable,
cost-effective, and practicable, as long as PHMSA clarified that the
rule language does not require ``relief valves'' or use ``relief
valve'' as a term. Some committee members were concerned that using
language related to ``relief valves'' would bring in other code
requirements, which was not PHMSA's intent.
Seismicity (Sec. Sec. 192.917, 192.935(b)(2))
In the NPRM, PHMSA proposed to include seismicity in the list of
factors operators must evaluate for the threat of outside force damage
when considering preventative and mitigative measures, as well as
include the seismicity of an area as a pipeline attribute in an
operator's data gathering and integration when performing risk
analyses. The committee had no substantial comments or recommendations
on this topic, and

[[Page 52225]]

they voted 12-0 that this provision was, as published, technically
feasible, reasonable, cost-effective, and practicable.
Records (Sec. Sec. 192.5(d), 192.13(e), 192.67, 192.127, 192.205,
192.227(c), 192.285(e), 192.619(f), 192.624(f), Appendix A)
In the NPRM, PHMSA proposed to clarify that the records required by
part 192 must be documented in a reliable, traceable, verifiable, and
complete manner. PHMSA summarized the recordkeeping requirements of
part 192 in a new Appendix A, and required that operators must re-
establish pipeline documentation whenever records were not available
and make and retain records demonstrating compliance with part 192.
Issues related to records were discussed through the final 4 GPAC
meetings over the course of 2017 and 2018. The committee found the
assorted provisions related to records as being technically feasible,
reasonable, cost-effective, and practicable, if certain changes were
made. Specifically, the committee recommended the word ``reliable'' be
deleted from the records standard so that it reads ``traceable,
verifiable, and complete'' records wherever the standard is used.
Members noted that the NTSB never used the term ``reliable,'' and a
PHMSA advisory bulletin reflects the language without referring to
``reliable'' records. In the class location requirements at Sec.
192.5, the committee recommended PHMSA clarify that documentation be
required to substantiate the current class location and not previous
historical ones. The committee also recommended that PHMSA modify the
requirements for the qualification of welders and persons joining
plastic pipe to include an effective date and change the records
retention provision to a period of 5 years.
During the June 2017 GPAC meeting, the committee recommended PHMSA
amend provisions related to the general duty clause for records and
edit the corresponding reference to retention periods in Appendix A.
After further discussion, during the meeting on March 2, 2018, the
committee recommended PHMSA withdraw the proposed addition of Sec.
192.13. Similarly, in the June 2017 meeting, the committee recommended
PHMSA modify the proposed Appendix A to clarify that it does not apply
to distribution or gathering pipelines. After considering the issue at
the meeting on March 2, 2018, the committee recommended PHMSA withdraw
proposed Appendix A from the rulemaking.
Other changes the committee suggested regarding the proposed
recordkeeping requirements included revising the record provisions for
materials, pipe design, and components to clarify the effective date of
those provisions and recommended PHMSA clarify that the recordkeeping
provisions for components only applies to components greater than 2
inches in nominal diameter. The recordkeeping provisions proposed under
the MAOP determination and MAOP reconfirmation sections were discussed
by the GPAC separately and are expanded upon under the discussions for
those specific topics below.
Following those discussions over the course of multiple meetings,
the committee voted unanimously that the provisions related to
recordkeeping requirements in part 192 were technically feasible,
reasonable, cost-effective, and practicable, if PHMSA made the changes
outlined above.
IM Clarifications (Sec. Sec. 192.917(e)(2), (e)(3) & (e)(4))
In the NPRM, PHMSA proposed several changes to provisions related
to how operators use data in their IM programs and manage certain types
of defects. PHMSA proposed changes regarding an operator's analysis of
cyclic fatigue and clarifying that certain pipe, such as low-frequency
electric resistance welded pipe, must have been pressure tested for an
operator to assume that any seam flaws are stable. PHMSA also proposed
that any failures or changes to operation that could affect seam
stability must be evaluated using a fracture mechanics analysis.
Regarding cyclic fatigue, some GPAC members expressed concern that
PHMSA proposed to require an annual analysis of cyclic fatigue even if
the underpinning conditions affecting cyclic fatigue had not changed.
Certain GPAC members wanted to ensure that it would be a change in
conditions that would trigger an evaluation and that operators would
not necessarily need to do an evaluation within a certain period
otherwise. During the meeting, PHMSA suggested it would consider
changing cyclic fatigue analysis from annually to periodically based on
any changes to cyclic fatigue data and other changes to loading
conditions since the previous analysis was completed, not to exceed 7
calendar years. Further, PHMSA would consider whether there was
conflict with this section and the MAOP reconfirmation requirements,
which was a concern brought up during the public comment period of the
meeting. Following the discussion, the committee voted 11-0, that the
provisions related to cyclic fatigue were technically feasible,
reasonable, cost-effective, and practicable if PHMSA revised the
paragraph based on the GPAC member discussion and PHMSA's proposed
language at the meeting.
For the provisions related to the stability of manufacturing- and
construction-related defects, PHMSA proposed during the GPAC meeting to
provide that an operator could consider manufacturing- and
construction-related defects as stable only if the covered segment has
been subjected to a subpart J pressure test of at least 1.25 times MAOP
and the covered segment has not experienced a reportable incident
attributed to a manufacturing or construction defect since the date of
the most recent subpart J pressure test. Pipeline segments that have
experienced a reportable incident since its most recent subpart J
pressure test due to an original manufacturing-related defect, a
construction-related defect, an installation-related defect, or a
fabrication-related defect would be required to be prioritized as a
high-risk segment for the purposes of a baseline assessment or a
reassessment. PHMSA proposed to explicitly lay out these requirements
in the regulations rather than cross-reference these requirements to
the MAOP reconfirmation provisions. Additionally, PHMSA indicated it
would create a stand-alone section to deal with pipeline cracking
issues within the IM regulations and would delete a specific reference
to ``pipe body cracking'' in the provisions related to electric
resistance welded pipe.
Following the discussion, the committee voted 12-0 that the
provisions related to IM clarifications regarding manufacturing and
construction defects were technically feasible, reasonable, cost-
effective, and practicable if PHMSA made the changes it proposed during
the meeting, created a new, stand-alone section for addressing pipeline
cracking within the IM regulations, deleted the phrase related to
``pipe body cracking,'' and considered allowing other test procedures
for determining whether manufacturing- and construction-related defects
were stable.
MAOP Exceedances (Sec. Sec. 191.23, 191.25)
In the NPRM, PHMSA proposed requiring operators to report each
exceedance of the MAOP that exceeds the build-up allowed for the
operation of pressure-limiting or control devices per the congressional
mandate provided in the 2011 Pipeline Safety Act, which requires
operators to report such exceedances on or before the 5th day

[[Page 52226]]

following the date on which the exceedance occurs.
During the public comment period of the June 7, 2017, meeting, a
commenter expressed concern that being required to report an exceedance
within 5 days might be problematic where an ongoing investigation might
preclude an operator from being able to complete a full safety-related
condition report. The GPAC considered this viewpoint but noted that the
5-day reporting requirement was prescribed by statute, and PHMSA does
not have discretion when implementing that deadline. The GPAC, echoing
another comment from the public, discussed whether the provision would
be applicable to gathering lines. PHMSA, in response, noted that the
requirement would be limited to gas transmission lines only. Following
the discussion, the GPAC voted 11-0 that the provision was technically
feasible, reasonable, cost-effective, and practicable if PHMSA
clarified that this provision does not apply to gathering lines.
Verification of Pipeline Material Properties and Attributes (Sec.
192.607)
In the NPRM, PHMSA proposed a process for operators to re-establish
material properties on pipelines where those attributes may be unknown.
The process was an opportunistic sampling approach that did not require
any mandatory excavations and allowed operators to verify material
properties of pipelines as opportunities presented themselves during
normal operations and maintenance, such as excavations for the repair
of anomalies.
The GPAC had a robust discussion on the proposed material
properties verification requirements and wanted to clarify that two
separate activities--MAOP reconfirmation and the application of IM
principles--drive the need for material properties verification and
should be addressed separately. Overall, the GPAC was supportive of
PHMSA's opportunistic approach for verifying material properties.
During the public comment period, members representing the pipeline
industry suggested PHMSA allow a statistical sampling plan developed by
operators instead of prescribing a specific number of samples needed.
PHMSA clarified that it expected a 1 pipe-per-mile sampling standard in
most cases.
At the December 2017 GPAC meeting, some GPAC members expressed
concern with the specific attributes PHMSA was proposing operators
collect and verify. There was also some discussion regarding how the
notification procedure PHMSA proposed might be cumbersome if operators
would be required to wait on a response or action from PHMSA every time
an operator wanted to submit an alternative plan. The GPAC suggested
adding language where, if PHMSA was to object to an operator
notification, they would have to object within 90 days. If PHMSA did
not object within 90 days, the operator would be free to go forward
with the intended action.
Following the discussion, the GPAC voted 12-0 that the provisions
related to material properties verification were technically feasible,
reasonable, cost-effective, and practicable if the following changes
were made:
Clarify that material properties verification applies to
onshore steel transmission lines only, and not distribution or
gathering lines.
Remove the applicability criteria of the section and make
the material properties verification provisions a procedure that
operators can use for obtaining missing or inadequate records or
verifying pipeline attributes if required by the MAOP reconfirmation
provisions or other code sections. The committee agreed to address the
applicability of the material properties verification requirements
under each of the MAOP reconfirmation methods and other sections as
appropriate.
Delete the requirements for creating a material properties
verification program plan.
Drop the list of mandatory attributes operators would be
required to verify but require that operators keep any records
developed through this material properties verification method.
Retain the opportunistic approach of obtaining unknown or
undocumented material properties when excavations are performed for
repairs or other reasons, using a one-per-mile standard proposed by
PHMSA, but allow operators to use their own statistical approach and
submit a notification to PHMSA with their method. Establish a minimum
standard of a 95% confidence level for operator statistical methods
submitted to PHMSA.
Retain flexibility to allow either destructive or non-
destructive tests when verification is needed.
Incorporate language stating that, if an operator does not
receive an objection letter from PHMSA within 90 days of notifying
PHMSA of an alternative sampling approach, the operator can proceed
with their method. PHMSA will notify the operator if additional review
time is needed.
Revise the paragraph to accommodate situations where a
single material properties verification test is needed (e.g.,
additional information is needed for an anomaly evaluation/repair).
Drop accuracy specifications (retain requirement that test
methods must be validated and that calibrated equipment be used).
Drop mandatory requirements for multiple test locations
for large excavations (multiple joints within the same excavation).
Reduce number of quadrants at which NDE tests must be made
from 4 to 2.
Delete specified program requirements for how to address
sampling failures and replace with a requirement for operators to
determine how to deal with sample failures through an expanded sample
program that is specific to their system and circumstances. Require
notification to provide expanded sample program to PHMSA, and require
operators establish a minimum standard that sampling programs must be
based on a minimum 95% confidence level.
Clarify the applicability of Sec. 192.607 (d)(3)(i).
Strengthened Assessment Requirements (Appendix F, Sec. Sec. 192.493,
192.506, 192.921(a))
In the NPRM, PHMSA proposed to clarify the selection and conduct of
ILI tools per updated industry standards that would be incorporated by
reference, clarify the consideration of uncertainties in ILI reported
results, add additional assessment methods to allow greater flexibility
to operators, and allow direct assessment as a method only if the
pipeline was not piggable. PHMSA also proposed to explicitly allow
guided wave ultrasonic testing (GWUT) in the list of integrity
assessment methods by codifying in a new Appendix F the current
guidelines operators use for submitting GWUT inspection procedures.
For the updated ILI standards, some GPAC members requested PHMSA
delete the ``requirements and recommendations'' language in Sec.
192.493 and other places where standards are incorporated by reference
to avoid the consequence that non-mandatory recommendations in the
standards would become regulatory requirements. Following the
discussion, the GPAC voted 10-0 that the provisions related to
strengthened assessment requirements pertaining to in-line assessment
standards were technically feasible, reasonable, cost-effective, and
practicable if PHMSA struck the phrase ``the requirements and
recommendations of'' from the appropriate paragraph in Sec. 192.493.

[[Page 52227]]

Regarding the usage of assessment methods, certain committee
members recommended PHMSA allow the direct assessment method whenever
appropriate (i.e., do not restrict the use of direct assessments to
unpiggable pipeline segments or when other methods are impractical) and
incorporate better language to clarify when it is appropriate for
operators to use direct assessments. Similarly, the GPAC suggested
PHMSA clarify the regulatory language so that it was clear operators
must select the appropriate assessment method based on the applicable
threats. The clarification would avoid the implication that operators
need to run certain tools against certain threats when there is no
evidence or susceptibility of that threat for that particular pipeline
segment.
The GPAC also recommended that PHMSA delete the proposed
requirement in the baseline assessment method that required a review of
ILI results by knowledgeable individuals, since it is duplicative with
other existing requirements elsewhere in the regulations. Further, some
GPAC members expressed concern that all tools cannot meet the 90
percent tool tolerance that is specified in the referenced industry
standard. PHMSA representatives noted that the rule would not require
that every tool perform within a 90 percent specification rate, but
that actual tool performance should be verified and applied when ILI
data is interpreted. As in other sections of the proposed regulations,
the committee also requested PHMSA adopt the same objection procedure
that the GPAC discussed and approved under the material properties
verification provisions for any notification under this section.
Following the discussion, the GPAC voted 10-0 that the provisions
related to strengthening the conduct of a baseline integrity assessment
were technically feasible, reasonable, cost-effective, and practicable
if PHMSA revised the requirements to clarify that operators must select
assessment methods based on the threats to which the pipeline is
susceptible and removed language in the provision that is duplicative
with requirements elsewhere in the regulations; clarified that direct
assessment is allowed where appropriate but may not be used to assess
threats for which the method is not suitable; and incorporated the same
objection procedure the committee approved for the material properties
verification provisions and with a PHMSA review timeframe of 90 days.
In discussing the provisions related to the ``spike'' hydrostatic
pressure test method, the committee had several comments and
recommendations. Specifically, some GPAC members recommended that the
spike test should be performed at a pressure level of 100 percent SMYS,
and not 105 percent, to account for varying elevations and test segment
lengths. They also suggested that the 30-minute hold time was too long
and requested PHMSA consider minimizing the duration of the spike
pressure to avoid growing subcritical cracks. Further, the GPAC
recommended PHMSA clarify that spike testing should be performed
against the threat of ``time-dependent cracking'' and remove instances
in other sections of the regulations where PHMSA listed the threats for
which a spike pressure test is appropriate. Following the discussion,
the committee voted 10-0 that the provisions related to the ``spike''
hydrostatic pressure test method were technically feasible, reasonable,
cost-effective, and practicable if PHMSA changed the minimum spike
pressure to whichever is lesser: 100 percent SMYS or 1.5 times MAOP,
reduced the spike hold time to a minimum of 15 minutes after the spike
pressure stabilizes, referred to ``time-dependent cracking'' in the
section, incorporated the same objection procedure the committee
approved for the material properties verification provisions and with a
PHMSA review timeframe of 90 days, and incorporated the term
``qualified technical subject matter expert'' (SME) at the SME
requirements.
The GPAC did not have major concerns with incorporating the GWUT
procedures into the regulations and voted 13-0 that the provisions
related to the GWUT process were technically feasible, reasonable,
cost-effective, and practicable if PHMSA revised the objection
procedure as recommended by GPAC members during the discussion on the
proposed material properties verification requirements and considering
certain minor technical recommendations made by the GPAC members.
Moderate Consequence Area Definition (Sec. 192.3)
In the NPRM, PHMSA proposed a new definition for ``Moderate
Consequence Areas'' (MCA) which would be areas operators would have to
assess per the proposed requirements for performing integrity
assessments outside of HCAs. PHMSA proposed to define an MCA as an area
in a ``potential impact circle'' \84\ with 5 or more buildings intended
for human occupancy; an ``occupied site;'' or the right-of-way of an
interstate, freeway, expressway, and other principal 4-lane arterial
roadway. PHMSA proposed the definition of an ``occupied site'' to be
areas or buildings occupied by 5 or more persons, which was the same as
an ``identified site'' under the HCA definitions at Sec. 192.903,
except that the occupancy threshold was lowered from 20 persons to 5
persons.
---------------------------------------------------------------------------

\84\ A ``potential impact circle'' is defined under Sec.
192.903 as ``a circle of radius equal to the potential impact
radius,'' where the ``potential impact radius'' is the radius of a
circle within which the potential failure of a pipeline could have
significant impact on people or property.
---------------------------------------------------------------------------

The GPAC, based on a comment made by a member of the public, asked
if PHMSA could provide more guidance on what a ``piggable'' line is,
for the purposes of this definition. The GPAC asked whether PHMSA
believed that qualifier applies to pipelines that can be fully assessed
by a traditional, free-swimming ILI tool without further modification
to the pipeline, and PHMSA noted during the meeting that a ``piggable''
line would be one without physical or operational modifications. The
GPAC then suggested PHMSA clarify that definition in the preamble of
this final rule.
GPAC members representing the public were concerned about PHMSA's
proposal during the meeting to eliminate the concept of an ``occupied
site'' from the MCA definition. Industry members argued that, from a
practicability standpoint, determining whether five people were in a
location at any given time could be difficult, and there was
significant overlap between ``occupied sites'' and the class locations
that would need to be assessed per the proposal. The GPAC discussed
whether some of these sites would be included within an operator's HCA
identification program already and, if not, whether operators would be
able to otherwise incorporate ``occupied sites'' into their
identification and assessment programs.
Several GPAC members discussed whether PHMSA should create a
database or provide other guidance on which highways should be included
in the MCA definition for consistency between PHMSA, State regulators,
and operators. Those comments regarding highways were made following a
public comment asking whether certain elevated highways needed to be
included.
Following the discussion, the GPAC voted 10-0 that the MCA
definition was technically feasible, reasonable, cost-effective, and
practicable if PHMSA

[[Page 52228]]

changed the highway description to remove the reference to ``rights-of-
way'' and added language so that the highway description includes ``any
portion of the paved surface, including shoulders;'' clarified that
highways with 4 or more lanes are included within the definition;
discussed in the preamble what the definition of ``piggable'' is; and
worked with the Federal Highway Administration to provide operators
with clear information and discuss it in the preamble of this final
rule. Additionally, the GPAC recommended PHMSA modify the term
``occupied sites'' in the definition by removing ``5 or more persons''
and the occupancy timeframe of 50 days, and tie the requirement into
the HCA survey for ``identified sites'' as discussed by members and
PHMSA at the meeting. Such identification could be made through
publicly available databases and class location surveys, and PHMSA was
to consider the sites and enforceability per direction by the committee
members.
Assessments Outside of HCAs (Sec. 192.710)
In the NPRM, PHMSA proposed to require operators perform integrity
assessments of certain pipelines outside of HCAs. Specifically,
operators would perform an initial assessment within 15 years and
periodic assessments 20 years thereafter of pipelines in Class 3 and
Class 4 locations as well as piggable pipelines in newly-defined
``moderate consequence areas'' as discussed above.
The GPAC, based on a public comment during the meeting, questioned
whether the timeframes for the initial assessment and periodic
assessments were appropriate. Members debated shortening the time
frames and suggested a few timeframes that could be based on a risk-
based prioritization and taking into account timeframes for HCA
assessments.
Following the discussion, the GPAC voted 10-0 that the provisions
related to assessments outside of HCAs were technically feasible,
reasonable, cost-effective, and practicable if PHMSA clarified that
direct assessment can be used as an assessment method only if
appropriate for the threat being assessed but cannot be used to assess
threats for which direct assessment is not suitable; revised the
initial assessment and reassessment intervals from 15 years and 20
years, respectively, to 14 years and 10 years, respectively, and with a
risk-based prioritization; revised the applicability requirements to
apply to lines with MAOPs of 30 percent SMYS or greater; and removed
the provisions related to low-stress assessments.
MAOP Reconfirmation (Sec. 192.624)
In the NPRM, PHMSA proposed a testing regime for (1) pipelines in
HCAs, Class 3 or Class 4 locations, or ``piggable'' MCAs that
experienced a reportable in-service incident due to certain types of
defects since its most recent successful subpart J pressure test, (2)
pipelines in HCAs or Class 3 or Class 4 locations that lacked the
traceable, verifiable, and complete pressure test records necessary to
substantiate the current MAOP, and (3) pipelines in HCAs, Class 3 or
Class 4 locations, or piggable MCAs where the operator established the
MAOP using the ``grandfather'' clause pursuant to Sec. 192.619(c).
PHMSA proposed operators of these pipelines re-confirm the MAOP of
those pipelines by choosing and executing one of a variety of methods.
Those methods are discussed in more detail in individual sections
below.

MAOP Reconfirmation Scope and Completion Date

During the discussion on MAOP reconfirmation, some GPAC members
suggested PHMSA revise the applicability of the provisions to remove
pipeline segments with prior crack or seam incidents, as those issues
would be dealt with in an operator's IM program. Certain committee
members recommended PHMSA restrict the scope of the MAOP reconfirmation
provisions to pipeline segments with MAOPs of 30 percent SMYS or
greater. These members argued that threshold was explicit in the
congressional mandate as it pertained to previously untested pipe, and
that it was based on the concept that lower-stress lines leak rather
than rupture. Members further suggested that the benefit in addressing
low-stress lines was not commensurate with the cost of doing so. Other
committee members supported retaining the scope of PHMSA's proposals in
the NPRM in order to address specific NTSB recommendations.
Following the discussion, the committee voted 13-0 that the
provisions related to the scope for MAOP reconfirmation were
technically feasible, reasonable, cost-effective, and practicable if
PHMSA removed pipelines with previous reportable incidents due to crack
defects from the applicability paragraph; addressed pipeline segments
with crack incident history in a new paragraph under the IM
requirements; withdrew the definitions for ``modern pipe,'' ``legacy
pipe,'' and ``legacy construction techniques;'' revised a reference to
necessary records within the applicability paragraph to refer to
records needed for MAOP determination and not subpart J pressure test
records; and revised the applicability of the requirements for
grandfathered lines to apply only to those lines with MAOPs of 30
percent or greater of SMYS. The committee also recommended PHMSA review
the costs and benefits of making the requirements applicable to Class 3
and Class 4 non-HCA pipe operating below 30 percent SMYS.
As for the completion date for the MAOP reconfirmation
requirements, the GPAC voted 13-0 that the related provisions were
technically feasible, reasonable, cost-effective, and practicable if
PHMSA addressed how the completion plan and completion dates required
by the section would apply to pipelines that currently do not meet the
applicability conditions but may in the future. The committee suggested
PHMSA could add a phrase stating that operators must complete all
actions required by the section on 100 percent of the applicable
pipeline mileage 15 years after the effective date of the rule or, as
soon as practicable but not to exceed 4 years after the pipeline
segment first meets the applicability conditions, whichever date is
later. The GPAC also recommended that PHMSA consider a waiver or no-
objection procedure for extending that timeline past 4 years, if
necessary.

MAOP Reconfirmation: Methods 1 and 2 (Pressure Test and Pressure
Reduction)

In the NPRM, PHMSA proposed six methods an operator could use if
needing to reconfirm MAOP. Method 1, a hydrostatic pressure test, would
be conducted at 1.25 times MAOP or the MAOP times the class location
test factor, whichever is greater. PHMSA proposed operators use a
``spike'' test method on pipeline segments with reportable in-service
incidents due to known manufacturing or construction issues, and PHMSA
also proposed operators estimate the remaining life of pipeline
segments with crack defects. Method 2, a pressure reduction, would
allow operators to reduce the pipeline segment's MAOP to the highest
operating pressure divided by 1.25 times MAOP or the class location
test factor times MAOP, whichever is greater. Similar to Method 1,
PHMSA proposed operators taking a pressure reduction to reconfirm MAOP
be required to estimate the remaining life of pipeline segments with
crack defects.
The GPAC members representing the industry argued that a ``spike''
test is more appropriate to include under IM requirements and that it
is not

[[Page 52229]]

appropriate for MAOP reconfirmation. During the meeting, PHMSA noted
that if the scope of the MAOP reconfirmation provisions was to be
revised to delete lines with crack-like defects, the spike test
requirement would not be needed. However, PHMSA would expect the spike
test provisions to be utilized when otherwise required by the
regulations. GPAC members also suggested adding language to address
material properties verification requirements with respect to the
information that is needed to conduct a pressure test. At the meeting,
PHMSA suggested that the GPAC consider explicitly requiring that any
information an operator does not have to perform a successful pressure
test in accordance with subpart J (or that is not documented in
traceable, verifiable, and complete records) be verified in accordance
with the material properties verification provisions.
Following the discussion, the GPAC voted 12-0 that the provisions
related to the pressure test method for MAOP reconfirmation were
technically feasible, reasonable, cost-effective, and practicable if
PHMSA deleted the spike hydrostatic testing component for pipelines
with suspected crack defects and referred to subpart J more broadly
instead of certain sections within subpart J. The GPAC also recommended
that if the pressure test segment does not have traceable, verifiable,
and complete MAOP records, operators should use the best available
information upon which the MAOP is currently based to perform the
pressure test. The committee recommended PHMSA require operators of
such pipeline segments add those segments to its plan for
opportunistically verifying material properties in accordance with the
material properties verification requirements, noting that most
pressure tests will present at least two opportunities for material
properties verification at the test manifolds.
As for the pressure reduction method of MAOP reconfirmation, the
GPAC voted 12-0 that the related provisions were technically feasible,
reasonable, cost-effective, and practicable if PHMSA increased the
look-back period from 18 months to 5 years and removed the requirement
for operators to perform fracture mechanics analysis on those pipeline
segments where the pressure is being reduced to reconfirm the MAOP.

MAOP Reconfirmation: Method 3 (Engineering Critical Assessment and
Fracture Mechanics)

In the NPRM, PHMSA proposed allowing operators to use an
engineering critical assessment (ECA) analysis in conjunction with an
ILI assessment to reconfirm a pipeline segment's MAOP where the
segment's MAOP would be based upon the lowest predicted failure
pressure (PFP) of the segment. This method would require specific
technical documentation and material properties verification, and it
would require operators analyze crack, metal loss, and interacting
defects remaining in the pipe, or that could remain in the pipe, to
determine the PFP. The pipeline segment's MAOP would then be
established at the lowest PFP divided by 1.25 or by the applicable
class location factor listed under the MAOP determination provisions,
whichever of those derating factors is greater.
Most of the GPAC discussion on this portion of MAOP reconfirmation
related to the specific values used in the fracture mechanics analysis
portion of the ECA and whether those requirements would best be located
in a section independent from the MAOP reconfirmation requirements.
During the meetings, PHMSA noted it would consider creating a stand-
alone fracture mechanics section that could be referenced when the
procedure is needed or required by other sections of the regulations.
PHMSA clarified that fracture mechanics would be needed in the context
of MAOP reconfirmation only for the ECA method and ``other technology''
usage under Method 6 where the applicable pipeline segments have cracks
or crack-like defects.
Following the discussion, the GPAC voted 12-0 that the provisions
related to the ECA method of MAOP reconfirmation and fracture mechanics
were technically feasible, reasonable, cost-effective, and practicable
if PHMSA moved the fracture mechanics requirements to a stand-alone
section in the regulations. The GPAC recommended the section not
specify when, or for which pipeline segments, fracture mechanics
analysis would be required, but instead provide a procedure by which
operators needing to perform fracture mechanics analysis could do so.
The GPAC recommended several changes to the fracture mechanics
requirements, including striking cross-references to the MAOP
reconfirmation requirements and spike hydrostatic testing requirements,
as well as striking the sensitivity analysis requirements and replacing
them with a requirement that operators account for model inaccuracies
and tolerances. Additionally, the GPAC recommended PHMSA add a
paragraph specifying that any records created through the performance
of a fracture mechanics analysis must be retained.
There were several technical GPAC recommendations related to the
use of Charpy V-notch toughness values in the fracture mechanics
analysis. Specifically, the GPAC recommended operators have the ability
to use a conservative Charpy V-notch toughness value based on the
sampling requirements of the material properties verification
provisions, and that operators could use Charpy V-notch toughness
values from similar or the same vintage pipe until the properties are
obtained through an opportunistic testing program. Further, the GPAC
recommended that the default Charpy V-notch toughness values (full-size
specimen, based on the lowest operational temperature) of 13-ft.-lbs.
(body) and 4-ft.-lbs. (seam) only apply to pipe with suspected low-
toughness properties or unknown toughness properties. Additionally, the
GPAC recommended PHMSA include a requirement for operators of pipeline
segments with a history of leaks or failures due to cracks to work
diligently to obtain toughness data if unknown and use Charpy V-notch
toughness values (full-size specimen, based on the lowest operational
temperature) of 5-ft.-lbs. (body) and 1-ft.-lbs. (seam) in the interim.
Further, the GPAC suggested PHMSA allow operators to request the use of
different default Charpy V-notch toughness values via a 90-day
notification to PHMSA.
For the ECA method itself, the committee recommended PHMSA add a
requirement to verify material properties in accordance with the
material properties verification requirements if the information needed
to conduct an ECA is not documented in traceable, verifiable, and
complete records. Further, the GPAC recommended that PHMSA not include
default Charpy V-notch toughness values or other technical fracture
mechanics requirements in the ECA method, as those items would be
specified in the new stand-alone fracture mechanics section. Similarly,
the GPAC recommended removing ILI tool performance specifications and
replacing them with a requirement to verify tool performance using
unity plots or equivalent technologies.

MAOP Reconfirmation: Methods 4, 5, and 6 (Pipe Replacement, Small-
Diameter & Potential Impact Radius Pressure Reduction, and Other
Technology)

In the NPRM, PHMSA proposed three additional methods operators
could use to reconfirm a pipeline's MAOP. Method 4, pipe replacement,
would require operators to replace pipe for

[[Page 52230]]

which they have inadequate records or pipe that was not previously
tested due to the grandfather clause in Sec. 192.619(c). Method 5, as
proposed, was applicable to low-stress, small diameter, and small
potential impact radius (PIR) lines,\85\ and would require operators to
take a 10 percent pressure cut as well as perform more frequent patrols
and leak surveys. Method 6, ``other technology,'' would allow operators
to use an alternative method, with notification to PHMSA, to reconfirm
the MAOP of their applicable pipeline segments.
---------------------------------------------------------------------------

\85\ These lines would be lines operating below 30 percent SMYS
with diameters of 8 inches or less and PIRs of 150 feet or less.
---------------------------------------------------------------------------

The GPAC had no major comments regarding Method 4, pipe
replacement. For Method 5, GPAC members representing the industry
questioned the need for the compensatory safety measures, such as the
additional patrols and leak surveys, in conjunction with the 10 percent
pressure reduction. They also supported public comments that promoted
expanding the applicability of Method 5 beyond the prescribed pipe
diameter of less than or equal to 8 inches and the operating pressure
of below 30 percent SMYS. During the meeting, PHMSA noted it could drop
the diameter and operating pressure requirements from the applicability
and use the prescribed PIR of 150 feet or less as a proxy for those
risk factors. Additionally, PHMSA noted it would expand the look-back
period to 5 years to be consistent with committee and public comments
regarding the pressure reduction method (Method 2) of MAOP
reconfirmation discussed earlier. With regard to the ``other
technology'' method, committee members suggested using the notification
procedure developed for the material properties verification
requirements, and PHMSA acknowledged it could be included here as well.
Following the discussion, the committee voted 11-0 that the
provisions related to the pipe replacement, pressure reduction for
small PIR and diameter lines, and ``other technology'' methods of MAOP
reconfirmation were technically feasible, reasonable, cost-effective,
and practicable if PHMSA made certain changes. For Method 4, pipe
replacement, the committee had no significant comments or changes. For
Method 5, the small PIR and diameter pressure reduction method, the
GPAC recommended PHMSA delete the size and pressure criteria, limiting
the requirement to those lines with a PIR of 150 feet or less; remove
the external corrosion direct assessment, crack analysis program,
odorization, and fracture mechanics analysis requirements; and change
the frequency of patrols and surveys to 4 times per year in Class 1 and
Class 2 locations and 6 times per year in Class 3 and Class 4
locations. For Method 6, the ``other technology'' method, the GPAC
recommended PHMSA incorporate the same 90-day notification and
objection procedure the GPAC approved for the material properties
verification requirements.

MAOP Reconfirmation: Recordkeeping and Notification

The GPAC also voted on the notification procedure and recordkeeping
requirements of the MAOP reconfirmation requirements. As there were no
substantial GPAC comments on these issues, the GPAC voted 11-0 that the
provisions are technically feasible, reasonable, cost-effective, and
practicable if PHMSA provided guidance regarding what ``traceable,
verifiable, and complete'' records are in the preamble, and if the
notification procedure is retained as it was proposed in the NPRM, but
incorporating the same 90-day notification and objection procedure the
committee approved for the material properties verification
requirements into any notification required under the MAOP
reconfirmation requirements.
Other MAOP Amendments (Sec. Sec. 192.503, 192.605(b)(5),
192.619(a)(2), 192.619(a)(4), 192.619(e), 192.619(f))
PHMSA presented to the committee issues related to other portions
of MAOP determination \86\ that had cross-references to MAOP
reconfirmation methods or other areas of the proposed regulations. More
specifically, the GPAC was to consider recommending PHMSA eliminate
duplications in scope between the MAOP determination provisions and the
MAOP reconfirmation provisions, and eliminate a duplicative revision to
the subpart J pressure test general requirements that was referenced
adequately elsewhere in the proposal. PHMSA also proposed that the
establishment of MAOP under Sec. 192.619 should rely on traceable,
verifiable, and complete records, and therefore cross-referenced the
material properties verification provisions with the MAOP determination
provisions. Similarly, PHMSA added a paragraph to the existing MAOP
determination provisions to more clearly specify that operators must
have records to substantiate the MAOP of their pipeline segments. To
address an NTSB recommendation from the PG&E incident, PHMSA also
proposed requiring that the MAOP pressure limitation factor specified
in the MAOP determination section of the regulations for Class 1
pipeline segments be based on the subpart J test pressure divided by
1.25, whereas the existing requirement was the test pressure divided by
1.1. Finally, PHMSA proposed adding a clarification that the
requirement for overpressure protection applied to pipeline segments
where the MAOP was established using one of the six methods under MAOP
reconfirmation. However, PHMSA noted in response to public comment that
the clarification seemed to be overly confusing and should be
withdrawn.
---------------------------------------------------------------------------

\86\ See Sec. 192.619.
---------------------------------------------------------------------------

The GPAC reviewed and discussed PHMSA's proposed changes to the
other MAOP-related provisions, voting 12-0 that the provisions are
technically feasible, reasonable, cost-effective, and practicable if
PHMSA considered editorially restructuring the applicability of the
MAOP determination provisions; clarifying that the recordkeeping
requirements specified under MAOP determination only apply to onshore,
steel, gas transmission pipelines; and clarifying that the MAOP
recordkeeping requirements are not retroactive. The GPAC suggested this
be clarified by stating existing records for pipelines installed on or
before the effective date of the rule must be kept for the life of the
pipeline, that pipelines installed after the effective date of the rule
must make and retain records as required for the life of the pipeline,
and that MAOP records are required for any pipeline placed in service
after the effective date of the rule. The GPAC noted that other
sections, including the MAOP reconfirmation and material properties
verification requirements, would require when and for which pipeline
segments where MAOP records are not documented in a traceable,
verifiable, and complete manner would need to be verified.
Changes From the GPAC Recommendations
In this final rule, PHMSA considered the recommendations of the
GPAC and adopted them as PHMSA deemed appropriate. However, there were
recommendations from the GPAC that PHMSA considered but did not adopt.
To summarize, the major changes PHMSA made in this rule that deviate
from the GPAC recommendations are as follows:
(1) When discussing the other proposed issues related to the MAOP
requirements, the GPAC recommended

[[Page 52231]]

PHMSA consider moving Sec. 192.619(e) to be a subsection of Sec.
192.619(a) and consider referencing section Sec. 192.624 in Sec.
192.619(a). PHMSA did not implement this recommendation because MAOP
reconfirmation for grandfathered segments is not applicable for new
pipeline segments.
(2) When considering the IM clarifications at Sec. 192.917, the
GPAC recommended PHMSA consider removing the term ``hydrostatic'' from
the testing requirements at Sec. 192.917(e)(3), which deals with
manufacturing and construction defects, and allow other authorized
testing procedures. PHMSA is not implementing this recommendation
because allowing pneumatic tests would be a safety concern to the
public and operating personnel.
(3) When discussing the assessment requirements for non-HCAs under
proposed Sec. 192.710, the GPAC recommended PHMSA change the
``discovery of condition'' period allotted from 180 to 240 days. PHMSA
is not implementing this suggestion from the GPAC and is retaining the
180-day timeframe for operators to determine whether a condition
presents a potential threat to the integrity of the pipeline.
(4) PHMSA added a notification requirement for the use of other
technology under the non-HCA assessment requirements at Sec. 192.710.
While the GPAC did not specifically request PHMSA make this change, the
GPAC was generally supportive of incorporating the notification
procedure the committee agreed to under the proposed material
properties verification requirements for other applications.
(5) Regarding the requirements for the scope of MAOP
reconfirmation, the GPAC recommended PHMSA review the costs and
benefits of including Class 3 and Class 4 pipelines not located in HCAs
and that operate at less than 30 percent SMYS. PHMSA did consider this
as an alternative in the RIA but chose not to move forward with the
proposal as suggested as it is outside the scope of the mandate.
(6) Regarding the MCA definition, the GPAC recommended PHMSA
consider modifying the term ``occupied sites'' within the definition by
removing reference to ``5 or more persons'' and the timeframe of 50
days and tying the requirement for identifying occupied sites to the
HCA ``identified sites'' survey requirement as discussed by members and
PHMSA at the meeting. In this final rule, PHMSA chose to delete the
term ``occupied sites'' from the MCA definition and from the general
definitions section of part 192.
(7) PHMSA moved the specific ECA requirements outside of the MAOP
reconfirmation section into a new stand-alone Sec. 192.632. The MAOP
reconfirmation requirements regarding the ECA method at Sec.
192.624(c)(3) and the ECA requirements in Sec. 192.632 will cross-
reference each other. PHMSA made this change to streamline the MAOP
reconfirmation provisions and improve the readability of the
requirements. No substantive changes were made to the procedure in
connection with this reorganization; this was a stylistic change only.

V. Section-by-Section Analysis

Sec. 191.23 Reporting Safety-Related Conditions

Section 23 of the 2011 Pipeline Safety Act requires operators to
report each exceedance of MAOP that exceeds the margin (build-up)
allowed for operation of pressure-limiting or control devices. On
December 21, 2012, PHMSA published advisory bulletin ADB-2012-11, which
advised operators of their responsibility under section 23 of the 2011
Pipeline Safety Act to report such exceedances. PHMSA is revising Sec.
191.23 to codify this statutory requirement.

Sec. 191.25 Filing Safety-Related Condition Reports

Section 23 of the 2011 Pipeline Safety Act requires operators to
report each exceedance of the MAOP that exceeds the margin (build-up)
allowed for operation of pressure-limiting or control devices. As
described above, PHMSA is revising Sec. 191.23 to codify this
requirement. Section 191.25 is also revised to make conforming edits
and comply with the mandatory 5-day reporting deadline specified in
section 23 of the 2011 Pipeline Safety Act.

Sec. 192.3 Definitions

Section 192.3 provides definitions for various terms used
throughout part 192. In support of other regulations adopted in this
final rule, PHMSA is amending the proposed definition of ``Moderate
consequence area.'' This change will define this term as it is used
throughout part 192.
The definition of a ``moderate consequence area,'' or MCA, is based
on similar methodology used to define ``high consequence area,'' or HCA
in Sec. 192.903. Moderate consequence areas will define the subset of
non-HCA locations where integrity assessments are required (Sec.
192.710) and where MAOP reconfirmation is required (Sec. 192.624). The
criteria for determining MCA locations differs from the criteria
currently used to identify HCAs in that the threshold for buildings
intended for human occupancy located within the potential impact radius
is lowered from 20 to 5, and identified sites are excluded. In response
to NTSB recommendation P-14-01, which was issued as a result of the
incident near Sissonville, WV, the MCA definition also includes
locations where interstate highways, freeways, expressways, and other
principal 4-or-more-lane arterial roadways are located within the
potential impact radius.
PHMSA is also adopting a definition of an ``engineering critical
assessment,'' as that term will be used in Sec. Sec. 192.624 and
192.632. More specifically, the ECA is a documented analytical
procedure that operators can use to determine the maximum tolerable
size for pipeline imperfections based on the MAOP of the particular
pipeline segment. Operators can use an ECA in conjunction with an ILI
inspection as one of the methods to reconfirm MAOP, if required.

Sec. 192.5 Class Locations

Section 23 of the 2011 Pipeline Safety Act requires the Secretary
of Transportation to require verification of records used to establish
MAOP to ensure they accurately reflect the physical and operational
characteristics of certain pipelines and to confirm the established
MAOP of the pipelines. PHMSA has determined that an important aspect of
compliance with this requirement is to assure that pipeline class
location records are complete and accurate. This final rule adds a new
paragraph, Sec. 192.5(d), to require each operator of transmission
pipelines to maintain records documenting the current class location of
each pipeline segment and demonstrating how an operator determined each
current class location in accordance with this section.

Sec. 192.7 What documents are incorporated by reference partly or
wholly in this part?

Section 192.7 lists documents that are incorporated by reference in
part 192. PHMSA is making conforming amendments to Sec. 192.7 in the
rule text to reflect other changes adopted in this final rule.

Sec. 192.9 What requirements apply to gathering lines?

This final rule codifies new standards for gas transmission
pipelines, most of which are not intended to be applied to gas
gathering pipelines. PHMSA is making conforming amendments to Sec.
192.9 to clarify which provisions

[[Page 52232]]

apply only to gas transmission pipelines and not to gas gathering
pipelines.

Sec. 192.18 How To Notify PHMSA

This final rule allows operators to notify PHMSA of proposed
alternative approaches to achieving the objective of the minimum safety
standards in several different regulatory sections. These notification
procedures for alternative actions are comparable to the existing
notification requirements in subpart O for the integrity management
regulations. Because PHMSA is expanding the use of notifications to
pipeline segments for which subpart O does not apply (i.e., to non-HCA
pipeline segments), PHMSA is adding a new Sec. 192.18 in subpart A
that contains the procedure for submitting such notifications for any
pipeline segment.

Sec. 192.67 Records: Material Properties

Section 23 of the 2011 Pipeline Safety Act requires the Secretary
of Transportation to require the verification of records to ensure they
accurately reflect the physical and operational characteristics of
certain pipelines and to confirm the established MAOP of the pipelines.
PHMSA has determined that compliance requires that pipeline material
properties records are complete and accurate. This final rule moves the
original Sec. 192.67 to Sec. 192.69 and adds in its place a new Sec.
192.67 that requires each operator of gas transmission pipelines
installed after the effective date of this final rule to collect or
make, and retain for the life of the pipeline, records that document
the physical characteristics of the pipeline, including tests,
inspections, and attributes required by the manufacturing specification
in effect at the time the pipe was manufactured. The physical
characteristics an operator must keep documented include diameter,
yield strength, ultimate tensile strength, wall thickness, seam type,
and chemical composition. These requirements also apply to any new
materials or components that are put on existing pipelines. For
pipelines installed prior to the effective date of this final rule,
operators are required to retain for the life of the pipeline all such
records in their possession as of the effective date of this final
rule. These recordkeeping requirements apply to offshore gathering
lines and Type A gathering lines in accordance with Sec. 192.9.
Pipelines that lack the traceable, verifiable, and complete records
needed to substantiate MAOP may be subject to the MAOP reconfirmation
requirements at Sec. 192.624, as specified in that section.

Sec. 192.69 Storage and Handling of Plastic Pipe and Associated
Components

Previous Sec. 192.67, titled ``Storage and handling of plastic
pipe and associated components,'' was created as a part of the Plastic
Pipe rule, which was published on November 20, 2018 (83 FR 58716).
PHMSA is redesignating that section in this final rule to a new Sec.
192.69. No other changes have been made to the section.

Sec. 192.127 Records: Pipe Design

Sec. 192.150 Passage of Internal Inspection Devices

The current pipeline safety regulations in Sec. 192.150 require
that pipelines be designed and constructed to accommodate in-line
inspection devices. Prior to this rulemaking, part 192 was silent on
technical standards or guidelines for implementing requirements to
assure pipelines are designed and constructed for in-line inspection
assessments. Previously, there was no consensus industry standard that
addressed design and construction requirements for in-line inspection
assessments. NACE Standard Practice, NACE SP0102-2010, ``In-line
Inspection of Pipelines,'' has since been published and provides
guidance on this issue in section 7. The incorporation of this standard
into the Federal Pipeline Safety Regulations at Sec. 192.150 will
promote a higher level of safety by establishing consistent standards
for the design and construction of pipelines to accommodate in-line
inspection devices.

Sec. 192.205 Records: Pipeline Components

Sec. 192.227 Qualification of Welders

Sec. 192.285 Plastic Pipe: Qualifying Persons To Make Joints

Section 23 of the 2011 Pipeline Safety Act requires the Secretary
of Transportation to require the verification of records to ensure they
accurately reflect the physical and

[[Page 52233]]

operational characteristics of certain pipelines and to confirm the
established MAOP of the pipelines. PHMSA has determined that compliance
requires that plastic pipeline qualification records are complete and
accurate. This final rule adds a new paragraph, Sec. 192.285(e), to
require each operator of gas transmission pipelines to make and retain
records demonstrating a person's plastic pipe joining qualifications in
accordance with this section for a minimum of 5 years following
construction. This requirement will apply to pipelines installed after
one year from the effective date of the rule.

Sec. 192.493 In-Line Inspection of Pipelines

The current pipeline safety regulations at Sec. Sec. 192.921 and
192.937 require that operators assess the material condition of
pipelines in certain circumstances (e.g., IM assessments for pipelines
in HCAs) and allow the use of ILI tools for these assessments.
Operators of gas transmission pipelines are required to follow the
requirements of ASME/ANSI B31.8S, ``Managing System Integrity of Gas
Pipelines,'' in conducting their IM activities. ASME B31.8S provides
limited guidance for conducting ILI assessments. Presently, part 192 is
silent on the technical standards or guidelines for performing ILI
assessments or implementing these requirements. When the IM regulations
were initially promulgated, there were no uniform industry standards
for ILI assessments. Three related standards have since been published:
API STD 1163-2013, ``In-Line Inspection Systems
Qualification Standard.'' This Standard serves as an umbrella document
to be used with and as a complement to the NACE and ASNT standards
below, which are incorporated by reference in API STD 1163.
NACE Standard Practice, NACE SP0102-2010, ``In-line
Inspection of Pipelines.''
ANSI/ASNT ILI-PQ-2005 (2010), ``In-line Inspection
Personnel Qualification and Certification.''
API 1163-2013 is more comprehensive and rigorous than the current
requirements in 49 CFR part 192. The incorporation of this standard
into the Federal Pipeline Safety Regulations will promote a higher
level of safety by establishing consistent standards to qualify the
equipment, people, processes, and software utilized by the ILI
industry. The API standard addresses in detail each of the following
aspects of ILI inspections, most of which are not currently addressed
in the regulations:
Systems qualification process.
Personnel qualification.
ILI system selection.
Qualification of performance specifications.
System operational validation.
System results qualification.
Reporting requirements.
Quality management system.
The NACE standard covers in detail each of the following aspects of
ILI assessments, most of which are not currently addressed in part 192
or in ASME B31.8S:
Tool selection.
Evaluation of pipeline compatibility with ILI.
Logistical guidelines, which includes survey acceptance
criteria and reporting.
Scheduling.
New construction (planning for future ILI in new lines).
Data analysis.
Data management.
The NACE standard provides a standardized questionnaire and
specifies that the completed questionnaire should be provided to the
ILI vendor. The questionnaire lists relevant parameters and
characteristics of the pipeline section to be inspected. PHMSA
determined that the consistency, accuracy, and quality of pipeline in-
line inspections would be improved by incorporating the consensus NACE
standard into the regulations.
The NACE standard applies to ``free swimming'' inspection tools
that are carried down the pipeline by the transported product. It does
not apply to tethered or remotely controlled ILI tools, which can also
be used in special circumstances (e.g., examination of laterals). While
their use is less prevalent than free-swimming tools, some pipeline IM
assessments have been conducted using tethered or remotely controlled
ILI tools. PHMSA determined that many of the provisions in the NACE
standard can be applied to tethered or remotely controlled ILI tools.
Therefore, PHMSA is amending the Federal Pipeline Safety Regulations to
allow the use of these tools, provided they comply with the applicable
sections of the NACE standard.
The ANSI/ASNT standard provides for qualification and certification
requirements that are not addressed by 49 CFR part 192. The
incorporation of this standard into the regulations will promote a
higher level of safety by establishing consistent standards to qualify
the equipment, people, processes and software utilized by the ILI
industry. The ANSI/ASNT standard addresses in detail each of the
following aspects, which are not currently addressed in the
regulations:
Requirements for written procedures.
Personnel qualification levels.
Education, training and experience requirements.
Training programs.
Examinations (testing of personnel).
Personnel certification and recertification.
Personnel technical performance evaluations.
The final rule adds a new Sec. 192.493 to require compliance with
the three consensus standards discussed above when conducting ILI of
pipelines.

Sec. 192.506 Transmission Lines: Spike Hydrostatic Pressure Test

A pressure test that incorporates a short duration ``spike''
pressure is a proven means to confirm the strength of pipe with known
or suspected threats of cracks or crack-like defects (e.g., stress
corrosion cracking, longitudinal seam defects, etc.). Currently, part
192 does not include minimum standards for such a spike hydrostatic
pressure test. This final rule adds a new Sec. 192.506 to codify the
minimum standards for performing spike hydrostatic pressure tests when
operators are required to, or elect to, use this assessment method.
Under the spike hydrostatic pressure test requirements, an operator may
use other technologies or processes equivalent to a spike hydrostatic
pressure test with justification and notification in accordance with
Sec. 192.18.

Sec. 192.517 Records: Tests

Section 192.517 prescribes the recordkeeping requirements for each
test performed under Sec. Sec. 192.505 and 192.507. PHMSA is making
conforming amendments to Sec. 192.517 to add the recordkeeping
requirements for the new Sec. 192.506.

Sec. 192.607 Verification of Pipeline Material Properties and
Attributes: Onshore Steel Transmission Pipelines

Section 23 of the 2011 Pipeline Safety Act mandates the Secretary
of Transportation to require operators of gas transmission pipelines in
Class 3 and Class 4 locations and Class 1 and Class 2 locations in HCAs
to verify records to ensure the records accurately reflect the physical
and operational characteristics of the pipelines and confirm the MAOP
of the pipelines established by the operator (49 U.S.C. 60139). PHMSA
issued Advisory Bulletin 11-01 on January 10, 2011 (76

[[Page 52234]]

FR 1504), and Advisory Bulletin 12-06 on May 7, 2012 (77 FR 26822), to
inform operators of this requirement. Operators have submitted
information in their Annual Reports (starting for calendar year 2012)
indicating that a portion of transmission pipeline segments do not have
adequate records to establish MAOP and that some operators do not have
traceable, verifiable, and complete records that accurately reflect the
physical and operational characteristics of the pipeline. Therefore,
PHMSA has determined that additional regulations are needed to
implement the 2011 Pipeline Safety Act. This final rule promulgates
specific criteria for determining which pipeline segments must undergo
examinations and tests to understand and document physical and material
properties and reconfirm a proper MAOP. For operators that do not have
traceable, verifiable, and complete documentation for the physical
pipeline characteristics and attributes of a pipeline segment, PHMSA is
adding a new Sec. 192.607 that contains the procedure for verifying
and documenting pipeline physical properties and attributes that are
not documented in traceable, verifiable, and complete records and to
establish standards for performing these actions. For operators of
certain pipelines lacking the necessary records to substantiate MAOP,
PHMSA is also adding Sec. 192.624, which provides operators several
methods for reconfirming a pipeline segment's MAOP.
The new material properties verification requirements at Sec.
192.607 include the scope of information needed and the methodology for
verifying material properties and attributes of pipelines. The most
difficult information to obtain, from a technical perspective, is the
strength of the pipeline's steel. Conventional techniques to obtain
that data would include cutting out a piece of pipe and destructively
testing it to determine the yield and ultimate tensile strength. In
this final rule, PHMSA is providing operators with flexibility by
allowing the use of non-destructive techniques that have been validated
to produce accurate results for the grade and type of pipe being
evaluated (see Sec. 192.624).
Another issue regarding material properties verification is the
cost associated with excavating the pipeline to verify material
properties and determining how much pipeline needs to be exposed and
tested to have assurance of the accuracy of the verification. PHMSA
addresses these issues within this final rule by specifying that
operators can take advantage of opportunities when the pipeline is
already being exposed, such as when maintenance activity is occurring
and when anomaly repairs are being made, to verify material properties
that are not documented in traceable, verifiable, and complete records.
For example, PHMSA considers excavations associated with the direct
examination of anomalies, pipeline relocations at road crossings and
river or stream crossings, pipe upgrades for class location changes,
pipe cut-outs for hydrostatic pressure tests, and excavations where
pipe is replaced due to anomalies to be opportunities to perform
material properties verification. Over time, pipeline operators will
develop a substantial set of traceable, verifiable, and complete
material properties data, which will provide assurance that material
properties are reliably known for the population of segments that did
not have pipeline physical properties and attributes documented in
traceable, verifiable, and complete records previously. Through this
final rule, PHMSA is requiring that operators continue this
opportunistic material properties verification process until the
operator has completed enough verifications to obtain a high level of
confidence that only a small percentage of pipeline segments have
physical pipeline characteristics and attributes that are not verified
or are otherwise inconsistent with all available information or
operators' past assumptions. This final rule specifies the number of
excavations required for operators to achieve this level of confidence.
Operators may use an alternative sampling approach that differs
from the sampling approach specified in the requirements if they notify
PHMSA in advance of using an alternative sampling approach in
accordance with Sec. 192.18.
Requirements are also included in the material properties
verification section to ensure that operators document the results of
the material properties verification process in records that must be
retained for the life of the pipeline.

Sec. 192.619 Maximum Allowable Operating Pressure: Steel or Plastic
Pipelines

The NTSB report on the PG&E incident included a recommendation (P-
11-15) that PHMSA amend its regulations so that manufacturing-and
construction-related defects can only be considered ``stable'' if a gas
pipeline has been subjected to a post-construction hydrostatic pressure
test of at least 1.25 times the MAOP. This final rule revises the test
pressure factors in Sec. 192.619(a)(2)(ii) to correspond to at least
1.25 times MAOP for pipelines installed after the effective date of
this rule.
The NTSB also recommended repealing Sec. 192.619(c), commonly
referred to as the ``grandfather clause,'' and requiring that all gas
transmission pipelines constructed before 1970 be subjected to a
hydrostatic pressure test that incorporates a spike test
(recommendation P-11-14). Similarly, section 23 of the 2011 Pipeline
Safety Act requires that selected pipeline segments in certain
locations with previously untested pipe (i.e., the MAOP is established
under Sec. 192.619(c)) or without MAOP records be tested with a
pressure test or equivalent means to reconfirm the pipeline's MAOP.
These requirements are addressed in the new Sec. 192.624 and are
described in more detail in the following section. This final rule also
makes conforming changes to Sec. 192.619 to require that operators of
pipeline segments to which Sec. 192.624 applies establish and document
the segment's MAOP in accordance with Sec. 192.624.

Sec. 192.624 Maximum Allowable Operating Pressure Reconfirmation:
Onshore Steel Transmission Pipelines

Section 23 of the 2011 Pipeline Safety Act requires the
verification of records for pipe in Class 3 and Class 4 locations, and
high-consequence areas in Class 1 and Class 2 locations, to ensure they
accurately reflect the physical and operational characteristics of the
pipelines and confirm the established MAOP of the pipelines. Operators
have submitted information in annual reports (beginning in calendar
year 2012) indicating that some gas transmission pipeline segments do
not have adequate material properties records or testing records to
confirm physical and operational characteristics and to establish MAOP.
For these pipelines, the 2011 Pipeline Safety Act requires that PHMSA
promulgate regulations to require operators to reconfirm MAOP as
expeditiously as economically feasible. The statute also requires PHMSA
to issue regulations that require previously untested pipeline segments
located in HCAs and operating at greater than 30 percent SMYS be tested
to confirm the material strength of the pipelines. Such tests must be
performed by pressure testing or other methods determined by the
Secretary to be of equal or greater effectiveness.
As a result of its investigation of the PG&E incident, the NTSB
issued two related recommendations. NTSB recommended that PHMSA repeal
Sec. 192.619(c), commonly referred to as

[[Page 52235]]

the ``grandfather clause,'' and require that all gas transmission
pipelines constructed before 1970 be subjected to a hydrostatic
pressure test that incorporates a spike test (P-11-14). The NTSB also
recommended that PHMSA amend the Federal Pipeline Safety Regulations so
that manufacturing- and construction-related defects can only be
considered stable if a pipeline has been subjected to a post-
construction hydrostatic pressure test of at least 1.25 times the MAOP
(P-11-15).
Through this final rule, PHMSA is finalizing a new Sec. 192.624 to
address these mandates and recommendations. This final rule requires
that operators reconfirm and document MAOP for certain onshore steel
gas transmission pipelines located in HCAs or MCAs that meet one or
more of the criteria specified in Sec. 192.624(a). More specifically,
this section applies to (1) pipelines in HCAs or Class 3 or Class 4
locations lacking traceable, verifiable, and complete records necessary
to establish the MAOP (per Sec. 192.619(a)) for the pipeline segment,
including, but not limited to, hydrostatic pressure test records
required by Sec. 192.517(a); and (2) pipelines where the MAOP was
established in accordance with Sec. 192.619(c), the pipeline segment's
MAOP is greater than or equal to 30 percent of SMYS, and the pipeline
is located in an HCA, a Class 3 or Class 4 location, or an MCA that can
accommodate inspection by means of instrumented inline inspection tools
(i.e., ``smart pigs''). This approach implements the mandate in the
2011 Pipeline Safety Act for pipeline segments in HCAs and Class 3 and
Class 4 locations (49 U.S.C. 60139). In addition, the scope includes
pipeline segments in the newly defined MCAs. This approach is intended
to address the NTSB recommendations and to provide increased safety in
areas where a pipeline rupture would have a significant impact on the
public or the environment. Though PHMSA is subjecting certain
grandfathered pipeline segments to the MAOP reconfirmation requirements
of Sec. 192.624, PHMSA is not repealing Sec. 192.619(c) for pipeline
segments located outside of HCAs, Class 3 or Class 4 locations, or MCAs
that can accommodate inspection by means of instrumented ILI tools.
Previously grandfathered pipelines that reconfirm MAOP using one of the
methods of Sec. 192.624 that operate above 72 percent SMYS may
continue to operate at the reconfirmed pressure.
The methods to reconfirm MAOP are specified in Sec. 192.624 and
are as follows:
Method 1--Pressure test. The pressure test method as specified in
section 23 of the 2011 Pipeline Safety Act. Operators choosing to
pressure test must also verify material property records in accordance
with Sec. 192.607. PHMSA notes that a pressure test requires the
cutout of pipe at test manifold sites and those pipe cutouts would be a
prime example of pipe that could and should be tested through the
material properties verification procedure, if necessary. In accordance
with the statute, PHMSA determined that the following methods (2)
through (6) are equally effective as a pressure test for the purposes
of reconfirming MAOP.
Method 2--Pressure reduction. De-rating the pipeline segment so
that the new MAOP is less than the historical actual sustained
operating pressure by using a pressure test safety factor of 0.80 (for
Class 1 and Class 2 locations) or 0.67 (for Class 3 and Class 4
locations) times the sustained operating pressure (equivalent to a
pressure test using gas or water as the test medium with a test
pressure of 1.25 times MAOP for Class 1 and Class 2 locations and 1.5
times MAOP for Class 3 and Class 4 locations).
Method 3--Engineering critical assessment. An in-line inspection,
previously performed pressure test, or alternative technology and
engineering critical assessment process using technical analysis with
acceptance criteria to establish a safety margin equivalent to that
provided by a new pressure test. PHMSA organized the ECA process
requirements under a new Sec. 192.632 and established the technical
requirements for analyzing the predicted failure pressure as a part of
the ECA analysis in a new Sec. 192.712. If an operator chooses the ECA
method for MAOP reconfirmation but does not have any of the material
properties necessary to perform an ECA analysis (diameter, wall
thickness, seam type, grade, and Charpy V-notch toughness values, if
applicable), the operator must include the pipeline segment in its
program to verify the undocumented information in accordance with the
material properties verification requirements at Sec. 192.607.
Method 4--Pipe replacement. Replacement of the pipe, which would
require a new pressure test that conforms with subpart J before the
pipe is placed into service.
Method 5--Pressure reduction for pipeline segments with small
potential impact radii. For pipeline segments with a potential impact
radius of less than or equal to 150 feet, a pressure reduction using a
safety factor of 0.90 times the sustained operating pressure is allowed
(equivalent to a pressure test of 1.11 times MAOP), supplemented with
additional preventive and mitigative measures specified in this final
rule.
Method 6--Alternative technology. Other technology that the
operator demonstrates provides an equivalent or greater level of
safety, provided PHMSA is notified in advance in accordance with Sec.
192.18.
Lastly, this final rule includes a new paragraph, Sec. 192.624(f),
to clearly specify that records created while reconfirming MAOP must be
retained for the life of the pipeline.

Sec. 192.632 Engineering Critical Assessment for Maximum Allowable
Operating Pressure Reconfirmation: Onshore Steel Transmission Pipelines

The requirements for reconfirming MAOP in the new Sec. 192.624
include an option for operators to perform an engineering critical
assessment, or ECA, to reconfirm MAOP in lieu of pressure testing and
the other methods provided. The requirements for conducting such an ECA
were proposed under the MAOP reconfirmation requirements at Sec.
192.624(c)(3); however, PHMSA has moved the ECA requirements to a new,
stand-alone section and cross-referenced those requirements in order to
improve the readability of the MAOP reconfirmation requirements.
Operators choosing the ECA method for MAOP reconfirmation may
perform an in-line inspection and a technical analysis with acceptance
criteria to establish a safety margin equivalent to that provided by a
pressure test. PHMSA established the technical requirements for
analyzing the predicted failure pressure as a part of the ECA analysis
in a new Sec. 192.712, and those requirements are cross-referenced
within this ECA process.
Although PHMSA expects that most operators will use an ECA in
conjunction with in-line inspection, PHMSA would also allow operators
with past, valid pressure tests to calculate the largest defects that
could have survived the pressure test and analyze the postulated
defects to calculate a predicted failure pressure with which to
establish MAOP. This approach might be desirable for operators in
certain circumstances, such as for line segments that have valid
pressure test records, but that lack other records (such as material
strength or pipe wall thickness) necessary to determine design pressure
and establish MAOP under the existing Sec. 192.619(a). Another
situation for which operators could use this approach would be if the
operator has a valid pressure test, but it was not conducted at a test
pressure that

[[Page 52236]]

was high enough to establish the current MAOP.
Operators with pressure test records meeting the subpart J test
requirements may use an ECA by calculating the largest defect that
could have survived the pressure test and estimating the flaw growth
between the date of the test and the date of the ECA. The ECA is then
performed using these postulated defect sizes. In addition, operators
must calculate the remaining life of the most severe defects that could
have survived the pressure test and establish an appropriate re-
assessment interval in accordance with new Sec. 192.712.
If an operator chooses to use ILI to characterize the defects
remaining in the pipe segment and the ECA method for MAOP
reconfirmation but does not have one or more of the material properties
necessary to perform an ECA analysis (diameter, wall thickness, seam
type, grade, and Charpy V-notch toughness values, if applicable), the
operator must use conservative assumptions and include the pipeline
segment in its program to verify the undocumented information in
accordance with the material properties verification requirements at
Sec. 192.607.

Sec. 192.710 Transmission Lines: Assessments Outside of High
Consequence Areas

Section 5 of the 2011 Pipeline Safety Act requires, if appropriate,
the Secretary of Transportation to issue regulations expanding IM
system requirements, or elements thereof, beyond HCAs. Currently, part
192 does not contain any requirement for operators to conduct integrity
assessments of onshore transmission pipelines that are not HCA
segments, as defined in Sec. 192.903, and are therefore not subject to
subpart O. However, only approximately 7 percent of onshore gas
transmission pipelines are located in HCAs. Through this final rule,
operators are required to periodically assess Class 3 locations, Class
4 locations, and MCAs that can accommodate inspection by means of an
instrumented inline inspection tool. The periodic assessment
requirements under this section apply to pipelines in these locations
with MAOPs greater than or equal to 30 percent of SMYS.
Industry has, as a practical matter, assessed portions of pipelines
in non-HCA segments coincident with integrity assessments of HCA
pipeline segments. For example, INGAA has noted in comment submissions
that approximately 90 percent of Class 3 and Class 4 mileage not in
HCAs are presently assessed during IM assessments. This is because, in
large part, ILI or pressure testing, by their nature, assess large
continuous pipeline segments that may contain some HCA segments but
that could also contain significant amounts of non-HCA segments.
While INGAA does not represent all pipeline operators subject to
part 192, it does represent the majority of gas transmission operators.
PHMSA has determined that, given this level of assessment, it is
appropriate and consistent with industry direction to codify
requirements for operators to periodically assess certain gas
transmission pipelines outside of HCAs to monitor for, detect, and
remediate pipeline defects and anomalies. Additionally, to achieve the
desired outcome of performing assessments in areas where people live,
work, or congregate, while minimizing the cost of identifying such
locations, PHMSA is basing the requirements for identifying those
locations on processes already being implemented by pipeline operators.
More specifically, the MCA definition assumes a similar process used
for identifying HCAs, with the exception that the threshold for
buildings intended for human occupancy located within the potential
impact circle is reduced from 20 to 5.
Because significant non-HCA pipeline mileage has been previously
assessed in conjunction with the regular assessment of HCA pipeline
segments, PHMSA is allowing operators to count those prior assessments
as compliant with the new Sec. 192.710 for the purposes of assessing
non-HCAs if those assessments were conducted, and threats remediated,
in conjunction with an integrity assessment required by subpart O.
This final rule also requires that the assessment required by the
new Sec. 192.710 be conducted using the same methods as adopted for
HCAs (see Sec. 192.921, below). Operators may use ``other technology''
as an assessment method, provided the operator notifies PHMSA in
accordance with Sec. 192.18.

Sec. 192.712 Analysis of Predicted Failure Pressure

The new requirements for reconfirming MAOP in the new Sec. 192.624
include an option for operators to perform an engineering critical
assessment, or ECA, to reconfirm MAOP in lieu of pressure testing and
the other methods provided. A key aspect of the ECA analysis is the
detailed analysis of the remaining strength of pipe with known or
assumed defects. The current Federal Pipeline Safety Regulations in
subparts I and O refer to methods for predicting the failure pressure
for pipe with corrosion metal loss defects. However, the regulations
are silent on performing such analysis for pipe with cracks (including
crack-like defects such as selective seam weld corrosion). Therefore,
in this final rule, PHMSA is inserting a new section to address the
techniques and procedures for analyzing the predicted failure pressures
for pipe with corrosion metal loss and cracks or crack-like defects.
Examples of technically proven models for calculating predicted failure
pressures include: For the brittle failure mode, the Newman-Raju Model
\87\ and PipeAssess PI^TM software; \88\ and for the ductile
failure mode, Modified Log-Secant Model,\89\ API RP 579-1 \90\--Level
II or Level III, CorLas^TM software,\91\ PAFFC Model,\92\ and
PipeAssess PI^TM software. All failure models used for the
ECA analysis must be used within its technical parameters for the
defect type and the pipe or weld material properties. Conforming
changes are being made to applicable sections in subparts I and O to
refer to this new section, for consistency, but the basic techniques
are unchanged.
---------------------------------------------------------------------------

\87\ Newman, J.C., and Raju; ``Stress Intensity Factors for
Cracks in Three Dimensional Finite Bodies Subjected to Tension and
Bending Loads;'' Computational Methods in the Mechanics of Fracture;
Elsevier; 1986; pp. 311-334.
\88\ Interim Report for Phase II--Task 5 of the Comprehensive
Study to Understand Longitudinal ERW Seam Failures, ``Summary Report
for an Integrity Management Software Tool,'' May 2017. https://primis.phmsa.dot.gov/matrix/FilGet.rdm?fil=11469.
\89\ ASTM International, ASTM STP 536, ``Failure Stress Levels
of Flaws in Pressurized Cylinders,'' 1973.
\90\ American Petroleum Institute and American Society of
Mechanical Engineers, API 579-1/ASME FFS-1, ``Fitness-For-Service,''
Second Edition, June 2007.
\91\ NACE International, NACE Corrosion 96 Paper 255, ``Effect
of Stress Corrosion Cracking on Integrity and Remaining Life of
Natural Gas Pipelines,'' March 1996.
\92\ Pipeline Research Council International, Inc., Topical
Report NG-18 No. 193, ``Development and Validation of a Ductile Flaw
Growth Analysis for Gas Transmission Line Pipe,'' June 1991.
---------------------------------------------------------------------------

As a part of this section, PHMSA is including a new paragraph to
address cracks and crack-like defects, which as stated above is a
critical function of the ECA analysis. The ECA analysis requires the
conservative analysis of any in-service cracks, crack-like defects
remaining in the pipe, or the largest possible crack that could remain
in the pipe, including crack dimensions (length and depth) to determine
the predicted failure pressure (PFP) of each defect; the failure mode
(ductile, brittle, or both) for the microstructure; the defect's
location and type; the pipeline's operating conditions (including
pressure cycling); and failure stress and

[[Page 52237]]

crack growth analysis to determine the remaining life of the pipeline.
An ECA must use the techniques and procedures developed and confirmed
through the research findings provided by PHMSA and other reputable
technical sources for longitudinal seam and crack growth, such as the
Comprehensive Study to Understand Longitudinal ERW Seam Research &
Development study task reports: Battelle Final Reports (``Battelle's
Experience with ERW and Flash Weld Seam Failures: Causes and
Implications''--Task 1.4), Report No. 13-002 (``Models for Predicting
Failure Stress Levels for Defects Affecting ERW and Flash-Welded
Seams''--Subtask 2.4), Report No. 13-021 (``Predicting Times to Failure
for ERW Seam Defects that Grow by Pressure-Cycle-Induced Fatigue''--
Subtask 2.5), and ``Final Summary Report and Recommendations for the
Comprehensive Study to Understand Longitudinal ERW Seam Failures--Phase
1''--Task 4.5), which can be found online at: https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390. Operators wanting to
use assumed Charpy V-notch toughness values differing from the
prescribed values as a part of fracture mechanics analysis must notify
PHMSA in accordance with Sec. 192.18.

Sec. 192.750 Launcher and Receiver Safety

PHMSA has determined that more explicit requirements are needed for
safety when performing maintenance activities that use launchers and
receivers to insert and remove maintenance tools and devices, as such
facilities are subject to pipeline system pressures. The current
regulations for hazardous liquid pipelines at 49 CFR part 195 have,
since 1981, contained such safety requirements for scraper and sphere
facilities (Sec. 195.426). However, the regulations for natural gas
pipelines do not similarly require controls or instrumentation to
protect against inadvertent breaches of system integrity due to the
incorrect operation of launchers and receivers for ILI tools, scraper,
and sphere facilities. Accordingly, this final rule is adding a new
Sec. 192.750 to require a suitable means to relieve pressure in the
barrel and either a means to indicate the pressure in the barrel or a
means to prevent opening if pressure has not been relieved.

Sec. 192.805 Qualification Program

PHMSA is revising the Federal Pipeline Safety Regulations to
include a new Sec. 192.18 that provides instructions for submitting
notifications to PHMSA whenever required by part 192. PHMSA is making
conforming changes to Sec. 192.805 to refer to the new Sec. 192.18.

Sec. 192.909 How can an operator change its integrity management
program?

Sec. 192.917 How does an operator identify potential threats to
pipeline integrity and use the threat identification in its integrity
program?

Section 29 of the 2011 Pipeline Safety Act requires operators to
consider seismicity when evaluating threats. Accordingly, PHMSA is
revising Sec. 192.917(a)(3) to include seismicity of the area in
evaluating the threat of outside force damage. To address NTSB
recommendation P-11-15, PHMSA is also revising the criteria in Sec.
192.917(e)(3) for addressing the threat of manufacturing and
construction defects by requiring that a pipeline segment must have
been pressure tested to a minimum of 1.25 times MAOP to conclude latent
defects are stable. Section 192.917(e)(4) has additional requirements
for the assessment of low-frequency ERW pipe with seam failures. It now
requires usage of the appropriate technology to assess low-frequency
ERW pipe, including seam cracking and selective seam weld corrosion.
Pipe with seam cracks must be evaluated using fracture mechanics
modeling for failure stress pressures and cyclic fatigue crack growth
analysis to estimate the remaining life of the pipe in accordance with
Sec. 192.712.
Lastly, the integrity management requirements to address specific
threats in Sec. 192.917(e) include requirements for the major causes
of pipeline incidents, such as corrosion, third-party damage, cyclic
fatigue, manufacturing and construction defects, and electric
resistance welded pipe. However, Sec. 192.917(e) does not address
cracks and crack-like defects. Therefore, PHMSA is adding a new
paragraph, Sec. 192.917(e)(6), to include specific IM requirements for
addressing the threat of cracks and crack-like defects (including, but
not limited to, stress corrosion cracking or other environmentally
assisted cracking, seam defects, selective seam weld corrosion, girth
weld cracks, hook cracks, and fatigue cracks) comparable to the other
types of threats addressed in Sec. 192.917(e).

Sec. 192.921 How is the baseline assessment to be conducted?

Section 192.921 requires that pipelines subject to the IM
regulations have an integrity assessment. The current regulations allow
operators to use ILI tools; pressure testing in accordance with subpart
J; direct assessment for the threats of external corrosion, internal
corrosion, and stress corrosion cracking; and other technology that the
operator demonstrates provides an equivalent level of understanding of
the condition of the pipeline. Following the PG&E incident, PHMSA
determined that the baseline assessment methods should be clarified and
strengthened to emphasize ILI use and pressure testing over direct
assessment. At San Bruno, PG&E relied heavily on direct assessment
under circumstances for which direct assessment was not effective nor
appropriate for the pipeline seam type and the threats to the pipeline.
Therefore, this final rule requires that direct assessment only be
allowed to assess the threats for which the specific direct assessment
process is appropriate.
This final rule also adds three additional assessment methods for
operators to use: (1) A ``spike'' hydrostatic pressure test, which is
particularly well-suited to address time-dependent threats, such as
stress corrosion cracking and other cracking or crack-like defects that
can include manufacturing- and construction-related defects; (2) guided
wave ultrasonic testing (GWUT), which is particularly appropriate in
cases where short pipeline segments, such as road or railroad
crossings, are difficult to assess; and (3) excavation with direct in
situ examination. Based upon the threat assessed, examples of
appropriate non-destructive examination methods for in situ examination
can include ultrasonic testing, phased array ultrasonic testing,
inverse wave field extrapolation, radiography, or magnetic particle
inspection.
The current regulations indicate that ILI tools are an acceptable
assessment method for the threats that the particular ILI tool type can
assess. PHMSA is clarifying in this final rule that the use of ILI
tools is appropriate for threats such as corrosion, deformation and
mechanical damage (including dents, gouges, and grooves), material
cracking and crack-like defects (e.g., stress corrosion cracking,
selective seam weld corrosion, environmentally assisted cracking, and
girth weld cracks), and hard spots with cracking. As discussed above,
this final rule

[[Page 52238]]

strengthens guidance in this area by adding a new Sec. 192.493 to
require compliance with the requirements and recommendations of API STD
1163-2005, NACE SP0102-2010, and ANSI/ASNT ILI-PQ-2005 when conducting
in-line inspection of pipelines. Accordingly, PHMSA revises Sec.
192.921(a)(1) in this final rule to require compliance with Sec.
192.493 instead of ASME B31.8S for baseline ILI assessments for covered
segments.
GWUT has been used by pipeline operators for several years.
Previously, operators were required by Sec. 192.921(a)(4) to submit a
notification to PHMSA as an ``other technology'' assessment method to
use GWUT. In 2007, PHMSA developed guidelines for how it would evaluate
notifications for the use of GWUT. These guidelines have been
effectively used for over 9 years, and PHMSA has confidence that
operators can use GWUT to assess the integrity of short segments of
pipe against corrosion threats. In this final rule, PHMSA is
incorporating these guidelines into a new Appendix F, which is
referenced in Sec. 192.921. Therefore, operators would no longer be
required to notify PHMSA to use GWUT.
ASME B31.8S, section 6.1, describes both excavation and direct in
situ examination as specialized integrity assessment methods applicable
to particular circumstances:

It is important to note that some of the integrity assessment
methods discussed in para. 6 only provide indications of defects.
Examination using visual inspection and a variety of nondestructive
examination (NDE) techniques are required, followed by evaluation of
these inspection results in order to characterize the defect. The
operator may choose to go directly to examination and evaluation for
the entire length of the pipeline segment being assessed, in lieu of
conducting inspections. For example, the operator may wish to
conduct visual examination of aboveground piping for the external
corrosion threat. Since the pipe is accessible for this technique
and external corrosion can be readily evaluated, performing in-line
inspection is not necessary.

PHMSA is clarifying its requirements to explicitly add excavation
and direct in situ examination as an acceptable assessment method. As
previously discussed under Sec. 192.710, PHMSA intends for operators
to assess non-HCA pipe with the same methods as HCA pipe. Therefore,
PHMSA has standardized the assessment methods between both the IM and
non-IM sections. Operators wishing to use ``other technology''
differing from the prescribed acceptable assessment methods must notify
PHMSA in accordance with Sec. 192.18.

Sec. 192.933 What actions must be taken to address integrity issues?

Sec. 192.935 What additional preventive and mitigative measures must
an operator take?

Section 29 of the 2011 Pipeline Safety Act requires operators to
consider seismicity when evaluating threats. Accordingly, PHMSA is
revising Sec. 192.935(b)(2) to include seismicity of the area when
evaluating preventive and mitigative measures with respect to the
threat of outside force damage.

Sec. 192.937 What is a continual process of evaluation and assessment
to maintain a pipeline's integrity?

Section 192.937 requires that operators continue to periodically
assess HCA pipeline segments and periodically evaluate the integrity of
each covered pipeline segment. PHMSA determined that conforming
amendments would be needed to implement, and be consistent with, the
changes discussed above for Sec. 192.921. Accordingly, this final rule
requires that reassessments use the same assessment methods specified
in Sec. 192.921. Operators wishing to use ``other technology''
differing from the prescribed acceptable assessment methods must notify
PHMSA in accordance with Sec. 192.18.

Sec. 192.939 What are the required reassessment intervals?

Section 192.939 specifies reassessment intervals for pipelines
subject to IM requirements. Section 5 of the 2011 Pipeline Safety Act
includes a technical correction that clarified that periodic
reassessments must occur at a minimum of once every 7 calendar years,
but that the Secretary may extend such deadline for an additional 6
months if the operator submits written notice to the Secretary with
sufficient justification of the need for the extension. PHMSA expects
that any justification, at a minimum, must demonstrate that the
extension does not pose a safety risk. In this final rule, PHMSA is
codifying this technical correction.
As explained in PHMSA IM FAQ-41, the maximum interval for
reassessment may be set using the specified number of calendar years.
The use of calendar years is specific to gas pipeline reassessment
interval years and does not alter the actual year interval requirements
which appear elsewhere in the code for various inspection and
maintenance requirements.
Additionally, PHMSA is revising Sec. 192.939 to include a new
Sec. 192.18 that provides instructions for submitting notifications to
PHMSA whenever required by part 192. PHMSA is making conforming changes
to Sec. 192.939 to refer to the new Sec. 192.18.

Sec. 192.949 How does an operator notify PHMSA? (Removed and Reserved)

This rulemaking includes several requirements that allow operators
to notify PHMSA of proposed alternative approaches to achieving the
objective of the minimum safety standards. This is comparable to
existing notification requirements in subpart O for pipelines subject
to the IM regulations. Because PHMSA is expanding the use of
notifications to pipeline segments for which subpart O does not apply
(i.e., to non-HCA pipeline segments), PHMSA is adding a new Sec.
192.18 that contains the procedure for submitting such notifications.
As such, Sec. 192.949 is no longer needed and is being removed and
reserved.

Appendix F to Part 192--Criteria for Conducting Integrity Assessments
Using Guided Wave Ultrasonic Testing (GWUT)

As discussed under Sec. 192.921 above, a new Appendix F to part
192 is needed to provide specific requirements and acceptance criteria
for the use of GWUT as an integrity assessment method. Operators must
apply all 18 criteria defined in Appendix F to use GWUT as an integrity
assessment method. If an operator applies GWUT technology in a manner
that does not conform with the guidelines in Appendix F, it would be
considered ``other technology'' for the purposes of Sec. Sec. 192.710,
192.921, and 192.937.

VI. Standards Incorporated by Reference

A. Summary of New and Revised Standards

Consistent with the amendments in this document, PHMSA is
incorporating by reference several standards as described below. Some
of these standards are already incorporated by reference into the
Federal Pipeline Safety Regulations and are being extended to other
sections of the regulations. Other standards provide a technical basis
for corresponding regulatory changes in this final rule.

[[Page 52239]]

API STD 1163, ``In-Line Inspection Systems
Qualification,'' Second edition, April 2013, Reaffirmed August 2018.
This standard covers the use of ILI systems for onshore and
offshore gas and hazardous liquid pipelines. This includes, but is not
limited to, tethered, self-propelled, or free-flowing systems for
detecting metal loss, cracks, mechanical damage, pipeline geometries,
and pipeline location or mapping. The standard applies to both existing
and developing technologies. This standard is an umbrella document that
provides performance-based requirements for ILI systems, including
procedures, personnel, equipment, and associated software. The
incorporation of this standard into the Federal Pipeline Safety
Regulations will provide rigorous processes for qualifying the
equipment, people, processes, and software used in in-line inspections.
ANSI/ASNT ILI-PQ-2005(2010), ``In-line Inspection
Personnel Qualification and Certification,'' Reapproved October 11,
2010.
This standard establishes minimum requirements for the
qualification and certification of in-line inspection personnel whose
jobs demand specific knowledge of the technical principles of in-line
inspection technologies, operations, regulatory requirements, and
industry standards as those are applicable to pipeline systems. The
employer-based standard includes qualification and certification for
Levels I, II, and III. The incorporation of this standard into the
Federal Pipeline Safety Regulations provides for certification and
qualification requirements that are not otherwise addressed in part 192
and will promote a higher level of safety by establishing consistent
standards to qualify the equipment, people, processes, and software
used in in-line inspections.
NACE Standard Practice 0102-2010, ``In-Line Inspection of
Pipelines,'' Revised 2010-03-13.
This standard outlines a process of related activities that a
pipeline operator can use to plan, organize, and execute an ILI
project, and it includes guidelines pertaining to ILI data management
and data analysis. This standard is intended for individuals and teams,
including engineers, O&M personnel, technicians, specialists,
construction personnel, and inspectors, involved in planning,
implementing, and managing ILI projects and programs. The incorporation
of this standard into the Federal Pipeline Safety Regulations would
promote a higher level of safety by establishing consistent standards
to qualify the equipment, people, processes, and software used in in-
line inspections.
PHMSA is also extending the applicability of the following three
currently incorporated-by-reference standards to new sections of the
Federal Pipeline Safety Regulations:
ASME/ANSI B16.5-2003, ``Pipe Flanges and Flanged
Fittings,'' October 2004, IBR approved for Sec. 192.607(f).
This standard covers pressure-temperature ratings, materials,
dimensions, tolerances, marking, testing, and methods of designating
openings for pipe flanges and flanged fittings. The standard includes
requirements and recommendations regarding flange bolting, flange
gaskets, and flange joints. This standard is intended for
manufacturers, owners, employers, users, and others concerned with the
specification, buying, maintenance, training, and safe use of valves
with pressure equipment. The incorporation of this standard promotes
industry best practices and operational, cost, and safety benefits.
ASME/ANSI B31G-1991 (Reaffirmed 2004), ``Manual for
Determining the Remaining Strength of Corroded Pipelines,'' 2004, IBR
approved for Sec. Sec. 192.632(a) and 192.712(b).
This document provides guidance for the evaluation of metal loss in
pressurized pipelines and piping systems. It is applicable to all
pipelines and piping systems that are part of the scope of the
transportation pipeline codes that are part of ASME B31 Code for
Pressure Piping, namely: ASME B31.4, Pipeline Transportation Systems
for Liquid Hydrocarbons and Other Liquids; ASME B31.8, Gas Transmission
and Distribution Piping Systems; ASME B31.11, Slurry Transportation
Piping Systems; and ASME B31.12, Hydrogen Piping and Pipelines, Part
PL.
AGA, Pipeline Research Committee Project, PR-3-805, ``A
Modified Criterion for Evaluating the Remaining Strength of Corroded
Pipe,'' (December 22, 1989), IBR approved for Sec. Sec. 192.632(a) and
192.712(b).
This document was developed from the Modified B31G method to allow
assessment of a river bottom profile of a corroded area on a pipeline
to provide more accurate predictions of the pipeline's remaining
strength, and it was adapted into a software program known as RSTRENG.
Pipeline operators can use RSTRENG to calculate a pipeline's predicted
failure pressure and safe pressure when determining operating pressures
and anomaly response times.
The incorporation by reference of ASME/ANSI B31.8S was approved for
Sec. Sec. 192.921 and 192.937 as of January 14, 2004. That approval is
unaffected by the section revisions in this final rule.

B. Availability of Standards Incorporated by Reference

PHMSA currently incorporates by reference into 49 CFR parts 192,
193, and 195 all or parts of more than 60 standards and specifications
developed and published by standard developing organizations (SDO). In
general, SDOs update and revise their published standards every 2 to 5
years to reflect modern technology and best technical practices. ASTM
often updates some of its more widely used standards every year, and
sometimes multiple editions of standards are published in a given year.
In accordance with the National Technology Transfer and Advancement
Act of 1995 (Pub. L. 104-113), PHMSA has the responsibility for
determining which currently referenced standards should be updated,
revised, or removed, and which standards should be added to 49 CFR
parts 192, 193, and 195. Revisions to incorporated by reference
materials in parts 192, 193, and 195 are handled via the rulemaking
process, which allows for the public and regulated entities to provide
input. During the rulemaking process, PHMSA must also obtain approval
from the Office of the Federal Register to incorporate by reference any
new materials.
On January 3, 2012, President Obama signed the Pipeline Safety,
Regulatory Certainty, and Job Creation Act of 2011, Public Law 112-90.
Section 24 of that law states: ``Beginning 1 year after the date of
enactment of this subsection, the Secretary may not issue guidance or a
regulation pursuant to this chapter that incorporates by reference any
documents or portions thereof unless the documents or portions thereof
are made available to the public, free of charge, on an internet
website.'' 49 U.S.C. 60102(p).
On August 9, 2013, Public Law 113-30 revised 49 U.S.C. 60102(p) to
replace ``1 year'' with ``3 years'' and remove the phrases ``guidance
or'' and, ``on an internet website.'' This resulted in the current
language in 49 U.S.C. 60102(p), which now reads as follows:
Beginning 3 years after the date of enactment of this subsection,
the Secretary may not issue a regulation pursuant to this chapter that
incorporates by reference any documents or portions thereof unless the
documents or portions thereof are made available to the public, free of
charge.

[[Page 52240]]

On November 7, 2014, the Office of the Federal Register issued a
final rule that revised 1 CFR 51.5 to require that Federal agencies
include a discussion in the preamble of the final rule ``the ways the
materials it incorporates by reference are reasonably available to
interested parties and how interested parties can obtain the
materials.'' 79 FR 66278. In relation to this rulemaking, PHMSA has
contacted each SDO and has requested free public access of each
standard that has been incorporated by reference. The SDOs agreed to
make viewable copies of the incorporated standards available to the
public at no cost. Pipeline operators interested in purchasing these
standards can contact the individual and applicable standards
organizations. The contact information is provided in this rulemaking
action, see Sec. 192.7.
In addition, PHMSA will provide individual members of the public
temporary access to any standard that is incorporated by reference that
is not otherwise available for free. Requests for access can be sent to
the following email address: [email protected].

VII. Regulatory Analysis and Notices

A. Statutory/Legal Authority for This Rulemaking

This final rule is published under the authority of the Federal
Pipeline Safety Statutes (49 U.S.C. 60101 et seq.). Section 60102
authorizes the Secretary of Transportation to issue regulations
governing design, installation, inspection, emergency plans and
procedures, testing, construction, extension, operation, replacement,
and maintenance of pipeline facilities, as delegated to the PHMSA
Administrator under 49 CFR 1.97.
PHMSA is revising the ``Authority'' entry for parts 191 and 192 to
include a citation to a provision of the Mineral Leasing Act (MLA),
specifically, 30 U.S.C. 185(w)(3). Section 185(w)(3) provides that
``[p]eriodically, but at least once a year, the Secretary of the
Department of Transportation shall cause the examination of all
pipelines and associated facilities on Federal lands and shall cause
the prompt reporting of any potential leaks or safety problems.'' The
Secretary has delegated this responsibility to PHMSA (49 CFR 1.97).
PHMSA has traditionally complied with Sec. 185(w)(3) through the
issuance of its pipeline safety regulations, which require annual
examinations and prompt reporting for all or most of the pipelines they
cover. PHMSA is making this change to be consistent with and make clear
its long-standing position that the agency complies with the MLA
through the issuance of pipeline safety regulations.

B. Executive Orders 12866 and 13771, and DOT Regulatory Policies and
Procedures

Executive Order 12866 requires agencies to regulate in the ``most
cost-effective manner,'' to make a ``reasoned determination that the
benefits of the intended regulation justify its costs,'' and to develop
regulations that ``impose the least burden on society.'' This action
has been determined to be significant under Executive Order 12866. It
is also considered significant under the Regulatory Policies and
Procedures of the Department of Transportation because of substantial
congressional, State, industry, and public interest in pipeline safety.
The final rule has been reviewed by the Office of Management and Budget
in accordance with Executive Order 12866 (Regulatory Planning and
Review) and is consistent with the Executive Order 12866 requirements
and 49 U.S.C. 60102(b)(5)-(6). Pursuant to the Congressional Review Act
(5 U.S.C. 801 et seq., the Office of Information and Regulatory Affairs
designated this rule as not a ``major rule,'' as defined by 5 U.S.C.
804(2). This final rule is considered an Executive Order 13771
regulatory action. Details on the estimated costs of this final rule
can be found in the rule's RIA.
The table below summarizes the annualized costs for the provisions
in the final rule. These estimates reflect the timing of the compliance
actions taken by operators and are annualized, where applicable, over
21 years and discounted to 2017 using rates of 3 percent and 7 percent.
PHMSA estimates incremental costs for the final requirements in Section
5 of the RIA. PHMSA finds that the other final rule requirements will
not result in an incremental cost. Additionally, PHMSA did not quantify
the cost savings from the material properties verification provisions
under this final rule compared to the existing regulations. The costs
of this final rule reflect incremental integrity assessments, MAOP
reconfirmation actions, and ILI launcher and receiver upgrades; PHMSA
estimates the annualized cost of this rule is $32.7 million at a 7
percent discount rate.

Summary of Annualized Costs, 2019-2039
[$2017 thousands]
------------------------------------------------------------------------
Annualized cost
-------------------------------
Provision 3% Discount 7% Discount
rate rate
------------------------------------------------------------------------
1. MAOP Reconfirmation & Material $25.9 $27.9
Properties Verification................
2. Seismicity........................... 0 0
3. Six-Month Grace Period for Seven 0 0
Calendar-Year Reassessment Intervals...
4. In-Line Inspection Launcher/Receiver 0.03 0.04
Safety.................................
5. MAOP Exceedance Reports.............. 0 0
6. Strengthening Requirements for 0 0
Assessment Methods.....................
7. Assessments Outside HCAs............. 5.48 4.71
8. Related Records Provisions........... 0 0
-------------------------------
Total............................... 31.4 32.7
------------------------------------------------------------------------

The benefits of the final rule will depend on the degree to which
compliance actions result in additional safety measures, relative to
the current baseline, and the effectiveness of these measures in
preventing or mitigating future pipeline releases or other incidents.
For the final rule RIA, PHMSA did not monetize benefits. The rule's
benefits are discussed qualitatively instead.
For more information, please see the RIA in the docket for this
rulemaking.

[[Page 52241]]

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA), as amended by the Small
Business Regulatory Flexibility Fairness Act of 1996, requires Federal
regulatory agencies to prepare a Final Regulatory Flexibility Analysis
(FRFA) for any final rule subject to notice-and-comment rulemaking
under the Administrative Procedure Act unless the agency head certifies
that the rule will not have a significant economic impact on a
substantial number of small entities. PHMSA prepared a FRFA which is
available in the docket for the rulemaking.

D. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments

PHMSA analyzed this final rule per the principles and criteria in
Executive Order 13175, ``Consultation and Coordination with Indian
Tribal Governments.'' Because this final rule would not significantly
or uniquely affect the communities of the Indian tribal governments or
impose substantial direct compliance costs, the funding and
consultation requirements of Executive Order 13175 do not apply.

E. Paperwork Reduction Act

Pursuant to 5 CFR 1320.8(d), PHMSA is required to provide
interested members of the public and affected agencies with an
opportunity to comment on information collection and recordkeeping
requests. On April 18, 2016, PHMSA published an NPRM seeking public
comments on the revision of the Federal Pipeline Safety Regulations
applicable to the safety of gas transmission pipelines and gas
gathering pipelines. During that time, PHMSA proposed changes to
information collections that are no longer included in this final rule.
PHMSA determined it would be more effective to advance a rulemaking
that focuses on the mandates from the 2011 Pipeline Safety Act and
split out the other provisions contained in the NPRM into two other
separate rules. As such, PHMSA has removed all references to those
collections previously contained in the NPRM and will submit
information collection revision requests to OMB based on the
requirements solely contained within this final rule.
PHMSA estimates that the proposals in this final rule will impact
the information collections described below. These information
collections are contained in the PSR, 49 CFR parts 190-199. The
following information is provided for each information collection: (1)
Title of the information collection, (2) OMB control number, (3)
Current expiration date, (4) Type of request, (5) Abstract of the
information collection activity, (6) Description of affected public,
(7) Estimate of total annual reporting and recordkeeping burden, and
(8) Frequency of collection. The information collection burden for the
following information collections are estimated to be revised as
follows:

1. Title: Recordkeeping Requirements for Gas Pipeline Operators.
OMB Control Number: 2137-0049.
Current Expiration Date: 09/30/2021.
Abstract: A person owning or operating a natural gas pipeline
facility is required to maintain records, make reports, and provide
information to the Secretary of Transportation at the Secretary's
request. Based on the proposed revisions in this rule, 25 new
recordkeeping requirements are being added to the pipeline safety
regulations for owners and operators of natural gas pipelines.
Therefore, PHMSA expects to add 24,609 responses and 3,740 hours to
this information collection because of the provisions in this final
rule.
Affected Public: Natural Gas Pipeline Operators.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 3,861,470.
Total Annual Burden Hours: 1,674,810.
Frequency of Collection: On occasion.

2. Title: Notification Requirements for Gas Transmission Pipeline
Operators.
OMB Control Number: New Collection. Will Request from OMB.
Current Expiration Date: TBD.
Abstract: A person owning or operating a natural gas pipeline
facility is required to provide information to the Secretary of
Transportation at the Secretary's request. Based on the proposed
revisions in this rule, 10 new notification requirements are being
added to the pipeline safety regulations for owners and operators of
natural gas pipelines. Therefore, PHMSA expects to add 721 responses
and 1,070 hours because of the notification requirements in this final
rule.
Affected Public: Gas Transmission operators.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 721.
Total Annual Burden Hours: 1,070.
Frequency of Collection: On occasion.

3. Title: Annual Reports for Gas Pipeline Operators.
OMB Control Number: 2137-0522.
Current Expiration Date: 8/31/2020.
Abstract: This information collection covers the collection of
annual report data from natural gas pipeline operators. PHMSA is
revising the Gas Transmission and Gas Gathering Annual Report (form
PHMSA F7 100.2-1) to collect additional information including mileage
of pipe subject to the MAOP reconfirmation and MCA criteria. Based on
the proposed revisions, PHMSA estimates that the Annual Report will
take an additional 5 hours per report to complete to include the newly
required data, increasing the burden for each report to 47 burden hours
for an overall burden increase of 7,200 burden hours across all
operators.
Affected Public: Natural Gas Pipeline Operators.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 10,852.
Total Annual Burden Hours: 83,151.
Frequency of Collection: On occasion.

4. Title: Incident for Natural Gas Pipeline Operators.
OMB Control Number: 2137-0635.
Current Expiration Date: 4/30/2022.
Abstract: This information collection covers the collection of
incident report data from natural gas pipeline operators. PHMSA is
revising the Gas Transmission Incident Report to have operators
indicate whether incidents occur inside Moderate Consequence Areas.
PHMSA does not expect there to be an increase in burden for the
reporting of Gas Transmission incident data.
Affected Public: Natural Gas Pipeline Operators.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 301.
Total Annual Burden Hours: 3,612.
Frequency of Collection: On occasion.
Requests for copies of these information collections should be
directed to Angela Hill or Cameron Satterthwaite, Office of Pipeline
Safety (PHP-30), Pipeline Hazardous Materials Safety Administration
(PHMSA), 2nd Floor, 1200 New Jersey Avenue SE, Washington, DC 20590-
0001, Telephone (202) 366-4595.

Comments are invited on:
(a) The need for the proposed collection of information for the
proper performance of the functions of the agency, including whether
the information will have practical utility;
(b) The accuracy of the agency's estimate of the burden of the
revised collection of information, including the validity of the
methodology and assumptions used;
(c) Ways to enhance the quality, utility, and clarity of the
information to be collected; and
(d) Ways to minimize the burden of the collection of information on
those

[[Page 52242]]

who are to respond, including the use of appropriate automated,
electronic, mechanical, or other technological collection techniques.
Those desiring to comment on these information collections should
send comments directly to the Office of Management and Budget, Office
of Information and Regulatory Affairs, Attn: Desk Officer for the
Department of Transportation, 725 17th Street NW, Washington, DC 20503.
Comments should be submitted on or prior to October 31, 2019. Comments
may also be sent via email to the Office of Management and Budget at
the following address: [email protected]. OMB is required to
make a decision concerning the collection of information requirements
contained in this final rule between 30 and 60 days after publication
of this document in the Federal Register. Therefore, a comment to OMB
is best assured of having its full effect if received within 30 days of
publication.

F. Unfunded Mandates Reform Act of 1995

An evaluation of Unfunded Mandates Reform Act (UMRA) considerations
is performed as part of the Final Regulatory Impact Assessment. PHMSA
determined that this final rule does not impose enforceable duties on
State, local, or tribal governments or on the private sector of $100
million or more, adjusted for inflation, in any one year and therefore
does not have implications under Section 202 of the UMRA of 1995. A
copy of the RIA is available for review in the docket.

G. National Environmental Policy Act

PHMSA analyzed this final rule in accordance with the National
Environmental Policy Act (42 U.S.C. 4332) and determined this action
will not significantly affect the quality of the human environment. The
Environmental Assessment for this final rule is in the docket.

H. Executive Order 13132: Federalism

PHMSA analyzed this final rule in accordance with Executive Order
13132 (``Federalism''). The final rule does not have a substantial
direct effect on the States, the relationship between the national
government and the States, or the distribution of power and
responsibilities among the various levels of government. This
rulemaking action does not impose substantial direct compliance costs
on State and local governments. The pipeline safety laws, specifically
49 U.S.C. 60104(c), prohibits State safety regulation of interstate
pipelines. Under the pipeline safety law, States have the ability to
augment pipeline safety requirements for intrastate pipelines regulated
by PHMSA, but may not approve safety requirements less stringent than
those required by Federal law. A State may also regulate an intrastate
pipeline facility PHMSA does not regulate. It is these statutory
provisions, not the rule, that govern preemption of State law.
Therefore, the consultation and funding requirements of Executive Order
13132 do not apply.

I. Executive Order 13211

This final rule is not a ``significant energy action'' under
Executive Order 13211 (Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use). It is not
likely to have a significant adverse effect on supply, distribution, or
energy use. Further, the Office of Information and Regulatory Affairs
has not designated this final rule as a significant energy action.

J. Privacy Act Statement

Anyone may search the electronic form of all comments received for
any of our dockets. You may review DOT's complete Privacy Act
Statement, published on April 11, 2000 (65 FR 19476), in the Federal
Register at: https://www.govinfo.gov/content/FR-2000-04-11/pdf/00-8505.pdf.

K. Regulation Identifier Number (RIN)

A regulation identifier number (RIN) is assigned to each regulatory
action listed in the Unified Agenda of Federal Regulations. The
Regulatory Information Service Center publishes the Unified Agenda in
April and October of each year. The RIN number contained in the heading
of this document can be used to cross-reference this action with the
Unified Agenda.

List of Subjects

49 CFR Part 191

MAOP exceedance, Pipeline reporting requirements.

49 CFR Part 192

Incorporation by reference, Integrity assessments, Material
properties verification, MAOP reconfirmation, Pipeline safety,
Predicted failure pressure, Recordkeeping, Risk assessment, Safety
devices.

In consideration of the foregoing, PHMSA is amending 49 CFR parts
191 and 192 as follows:

PART 191--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE;
ANNUAL, INCIDENT, AND OTHER REPORTING

0
1. The authority citation for part 191 is revised to read as follows:

Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5121, 60101 et. seq.,
and 49 CFR 1.97.

0
2. In Sec. 191.23, paragraph (a)(6) is revised, paragraph (a)(10) is
added, and paragraph (b)(4) is revised to read as follows:

Sec. 191.23 Reporting safety-related conditions.

(a) * * *
(6) Any malfunction or operating error that causes the pressure--
plus the margin (build-up) allowed for operation of pressure limiting
or control devices--to exceed either the maximum allowable operating
pressure of a distribution or gathering line, the maximum well
allowable operating pressure of an underground natural gas storage
facility, or the maximum allowable working pressure of an LNG facility
that contains or processes gas or LNG.
* * * * *
(10) For transmission pipelines only, each exceedance of the
maximum allowable operating pressure that exceeds the margin (build-up)
allowed for operation of pressure-limiting or control devices as
specified in the applicable requirements of Sec. Sec. 192.201,
192.620(e), and 192.739. The reporting requirement of this paragraph
(a)(10) is not applicable to gathering lines, distribution lines, LNG
facilities, or underground natural gas storage facilities (See
paragraph (a)(6) of this section).
(b) * * *
(4) Is corrected by repair or replacement in accordance with
applicable safety standards before the deadline for filing the safety-
related condition report. Notwithstanding this exception, a report must
be filed for:
(i) Conditions under paragraph (a)(1) of this section, unless the
condition is localized corrosion pitting on an effectively coated and
cathodically protected pipeline; and
(ii) Any condition under paragraph (a)(10) of this section.
* * * * *

0
3. Section 191.25 is revised to read as follows:

Sec. 191.25 Filing safety-related condition reports.

(a) Each report of a safety-related condition under Sec.
191.23(a)(1) through (9) must be filed (received by the Associate
Administrator) in writing

[[Page 52243]]

within 5 working days (not including Saturday, Sunday, or Federal
holidays) after the day a representative of an operator first
determines that the condition exists, but not later than 10 working
days after the day a representative of an operator discovers the
condition. Separate conditions may be described in a single report if
they are closely related. Reporting methods and report requirements are
described in paragraph (c) of this section.
(b) Each report of a maximum allowable operating pressure
exceedance meeting the requirements of criteria in Sec. 191.23(a)(10)
for a gas transmission pipeline must be filed (received by the
Associate Administrator) in writing within 5 calendar days of the
exceedance using the reporting methods and report requirements
described in paragraph (c) of this section.
(c) Reports must be filed by email to
[email protected] or by facsimile to (202) 366-7128.
For a report made pursuant to Sec. 191.23(a)(1) through (9), the
report must be headed ``Safety-Related Condition Report.'' For a report
made pursuant to Sec. 191.23(a)(10), the report must be headed
``Maximum Allowable Operating Pressure Exceedances.'' All reports must
provide the following information:
(1) Name, principal address, and operator identification number
(OPID) of the operator.
(2) Date of report.
(3) Name, job title, and business telephone number of person
submitting the report.
(4) Name, job title, and business telephone number of person who
determined that the condition exists.
(5) Date condition was discovered and date condition was first
determined to exist.
(6) Location of condition, with reference to the State (and town,
city, or county) or offshore site, and as appropriate, nearest street
address, offshore platform, survey station number, milepost, landmark,
or name of pipeline.
(7) Description of the condition, including circumstances leading
to its discovery, any significant effects of the condition on safety,
and the name of the commodity transported or stored.
(8) The corrective action taken (including reduction of pressure or
shutdown) before the report is submitted and the planned follow-up or
future corrective action, including the anticipated schedule for
starting and concluding such action.

PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE:
MINIMUM FEDERAL SAFETY STANDARDS

0
4. The authority citation for part 192 is revised to read as follows:

Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et. seq.,
and 49 CFR 1.97.

0
5. In Sec. 192.3, the definitions for ``Engineering critical
assessment (ECA)'' and ``Moderate consequence area'' are added in
alphabetical order to read as follows:

Sec. 192.3 Definitions.

* * * * *
Engineering critical assessment (ECA) means a documented analytical
procedure based on fracture mechanics principles, relevant material
properties (mechanical and fracture resistance properties), operating
history, operational environment, in-service degradation, possible
failure mechanisms, initial and final defect sizes, and usage of future
operating and maintenance procedures to determine the maximum tolerable
sizes for imperfections based upon the pipeline segment maximum
allowable operating pressure.
* * * * *
Moderate consequence area means:
(1) An onshore area that is within a potential impact circle, as
defined in Sec. 192.903, containing either:
(i) Five or more buildings intended for human occupancy; or
(ii) Any portion of the paved surface, including shoulders, of a
designated interstate, other freeway, or expressway, as well as any
other principal arterial roadway with 4 or more lanes, as defined in
the Federal Highway Administration's Highway Functional Classification
Concepts, Criteria and Procedures, Section 3.1 (see: https://www.fhwa.dot.gov/planning/processes/statewide/related/highway_functional_classifications/fcauab.pdf), and that does not meet
the definition of high consequence area, as defined in Sec. 192.903.
(2) The length of the moderate consequence area extends axially
along the length of the pipeline from the outermost edge of the first
potential impact circle containing either 5 or more buildings intended
for human occupancy; or any portion of the paved surface, including
shoulders, of any designated interstate, freeway, or expressway, as
well as any other principal arterial roadway with 4 or more lanes, to
the outermost edge of the last contiguous potential impact circle that
contains either 5 or more buildings intended for human occupancy, or
any portion of the paved surface, including shoulders, of any
designated interstate, freeway, or expressway, as well as any other
principal arterial roadway with 4 or more lanes.
* * * * *

0
6. In Sec. 192.5, paragraph (d) is added to read as follows:

Sec. 192.5 Class locations.

* * * * *
(d) An operator must have records that document the current class
location of each pipeline segment and that demonstrate how the operator
determined each current class location in accordance with this section.

0
7. Amend Sec. 192.7 as follows:
0
a. Revise paragraph (a)(1)(ii);
0
b. Add paragraph (b)(12);
0
c. Revise paragraphs (c)(2) and (4);
0
d. Re-designate paragraphs (d) through (j) as paragraphs (e) through
(k), respectively;
0
e. Add new paragraphs (d) and (h)(2); and
0
f. Revise newly redesignated paragraph (j)(1).
The revisions and additions read as follows:

Sec. 192.7 What documents are incorporated by reference partly or
wholly in this part?

(a) * * *
(1) * * *
(ii) The National Archives and Records Administration (NARA). For
information on the availability of this material at NARA, email
[email protected] or go to www.archives.gov/federal-register/cfr/ibr-locations.html.
(b) * * *
(12) API STANDARD 1163, ``In-Line Inspection Systems
Qualification,'' Second edition, April 2013, Reaffirmed August 2018,
(API STD 1163), IBR approved for Sec. 192.493.
(c) * * *
(2) ASME/ANSI B16.5-2003, ``Pipe Flanges and Flanged Fittings,''
October 2004, (ASME/ANSI B16.5), IBR approved for Sec. Sec.
192.147(a), 192.279, and 192.607(f).
* * * * *
(4) ASME/ANSI B31G-1991 (Reaffirmed 2004), ``Manual for Determining
the Remaining Strength of Corroded Pipelines,'' 2004, (ASME/ANSI B31G),
IBR approved for Sec. Sec. 192.485(c), 192.632(a), 192.712(b), and
192.933(a).
* * * * *
(d) American Society for Nondestructive Testing (ASNT), P.O. Box
28518, 1711 Arlingate Lane, Columbus, OH 43228, phone: 800-222-2768,
website: https://www.asnt.org/.

[[Page 52244]]

(1) ANSI/ASNT ILI-PQ-2005(2010), ``In-line Inspection Personnel
Qualification and Certification,'' Reapproved October 11, 2010, (ANSI/
ASNT ILI-PQ), IBR approved for Sec. 192.493.
(2) [Reserved]
* * * * *
(h) * * *
(2) NACE Standard Practice 0102-2010, ``In-Line Inspection of
Pipelines,'' Revised 2010-03-13, (NACE SP0102), IBR approved for
Sec. Sec. 192.150(a) and 192.493.
* * * * *
(j) * * *
(1) AGA, Pipeline Research Committee Project, PR-3-805, ``A
Modified Criterion for Evaluating the Remaining Strength of Corroded
Pipe,'' (December 22, 1989), (PRCI PR-3-805 (R-STRENG)), IBR approved
for Sec. Sec. 192.485(c); 192.632(a); 192.712(b); 192.933(a) and (d).
* * * * *

0
8. In Sec. 192.9, paragraphs (b), (c), and (d)(1), (2), and (6) are
revised to read as follows:

Sec. 192.9 What requirements apply to gathering lines?

* * * * *
(b) Offshore lines. An operator of an offshore gathering line must
comply with requirements of this part applicable to transmission lines,
except the requirements in Sec. Sec. 192.150, 192.285(e), 192.493,
192.506, 192.607, 192.619(e), 192.624, 192.710, 192.712, and in subpart
O of this part.
(c) Type A lines. An operator of a Type A regulated onshore
gathering line must comply with the requirements of this part
applicable to transmission lines, except the requirements in Sec. Sec.
192.150, 192.285(e), 192.493, 192.506, 192.607, 192.619(e), 192.624,
192.710, 192.712, and in subpart O of this part. However, operators of
Type A regulated onshore gathering lines in a Class 2 location may
demonstrate compliance with subpart N by describing the processes it
uses to determine the qualification of persons performing operations
and maintenance tasks.
(d) * * *
(1) If a line is new, replaced, relocated, or otherwise changed,
the design, installation, construction, initial inspection, and initial
testing must be in accordance with requirements of this part applicable
to transmission lines except the requirements in Sec. Sec. 192.67,
192.127, 192.205, 192.227(c), 192.285(e), and 192.506;
(2) If the pipeline is metallic, control corrosion according to
requirements of subpart I of this part applicable to transmission lines
except the requirements in Sec. 192.493;
* * * * *
(6) Establish the MAOP of the line under Sec. 192.619(a), (b), and
(c);
* * * * *

0
9. Section 192.18 is added to read as follows:

Sec. 192.18 How to notify PHMSA.

(a) An operator must provide any notification required by this part
by--
(1) Sending the notification by electronic mail to
[email protected]; or
(2) Sending the notification by mail to ATTN: Information Resources
Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New
Jersey Ave. SE, Washington, DC 20590.
(b) An operator must also notify the appropriate State or local
pipeline safety authority when an applicable pipeline segment is
located in a State where OPS has an interstate agent agreement, or an
intrastate applicable pipeline segment is regulated by that State.
(c) Unless otherwise specified, if the notification is made
pursuant to Sec. 192.506(b), Sec. 192.607(e)(4), Sec. 192.607(e)(5),
Sec. 192.624(c)(2)(iii), Sec. 192.624(c)(6), Sec. 192.632(b)(3),
Sec. 192.710(c)(7), Sec. 192.712(d)(3)(iv), Sec.
192.712(e)(2)(i)(E), Sec. 192.921(a)(7), or Sec. 192.937(c)(7) to use
a different integrity assessment method, analytical method, sampling
approach, or technique (i.e., ``other technology'') that differs from
that prescribed in those sections, the operator must notify PHMSA at
least 90 days in advance of using the other technology. An operator may
proceed to use the other technology 91 days after submittal of the
notification unless it receives a letter from the Associate
Administrator for Pipeline Safety informing the operator that PHMSA
objects to the proposed use of other technology or that PHMSA requires
additional time to conduct its review.

Sec. 192.67 [Redesignated as Sec. 192.69]

0
10. Redesignate Sec. 192.67 as Sec. 192.69.
0
11. Section 192.67 is added to read as follows:

Sec. 192.67 Records: Material properties.

(a) For steel transmission pipelines installed after [July 1, 2020,
an operator must collect or make, and retain for the life of the
pipeline, records that document the physical characteristics of the
pipeline, including diameter, yield strength, ultimate tensile
strength, wall thickness, seam type, and chemical composition of
materials for pipe in accordance with Sec. Sec. 192.53 and 192.55.
Records must include tests, inspections, and attributes required by the
manufacturing specifications applicable at the time the pipe was
manufactured or installed.
(b) For steel transmission pipelines installed on or before July 1,
2020], if operators have records that document tests, inspections, and
attributes required by the manufacturing specifications applicable at
the time the pipe was manufactured or installed, including diameter,
yield strength, ultimate tensile strength, wall thickness, seam type,
and chemical composition in accordance with Sec. Sec. 192.53 and
192.55, operators must retain such records for the life of the
pipeline.
(c) For steel transmission pipeline segments installed on or before
July 1, 2020], if an operator does not have records necessary to
establish the MAOP of a pipeline segment, the operator may be subject
to the requirements of Sec. 192.624 according to the terms of that
section.

0
12. Section 192.127 is added to read as follows:

Sec. 192.127 Records: Pipe design.

(a) For steel transmission pipelines installed after July 1, 2020],
an operator must collect or make, and retain for the life of the
pipeline, records documenting that the pipe is designed to withstand
anticipated external pressures and loads in accordance with Sec.
192.103 and documenting that the determination of design pressure for
the pipe is made in accordance with Sec. 192.105.
(b) For steel transmission pipelines installed on or before July 1,
2020, if operators have records documenting pipe design and the
determination of design pressure in accordance with Sec. Sec. 192.103
and 192.105, operators must retain such records for the life of the
pipeline.
(c) For steel transmission pipeline segments installed on or before
July 1, 2020, if an operator does not have records necessary to
establish the MAOP of a pipeline segment, the operator may be subject
to the requirements of Sec. 192.624 according to the terms of that
section.

0
13. In Sec. 192.150, paragraph (a) is revised to read as follows:

Sec. 192.150 Passage of internal inspection devices.

(a) Except as provided in paragraphs (b) and (c) of this section,
each new transmission line and each replacement of line pipe, valve,
fitting, or other line component in a transmission line, must

[[Page 52245]]

be designed and constructed to accommodate the passage of instrumented
internal inspection devices in accordance with NACE SP0102, section 7
(incorporated by reference, see Sec. 192.7).
* * * * *

0
14. Section 192.205 is added to read as follows:

Sec. 192.205 Records: Pipeline components.

(a) For steel transmission pipelines installed after July 1, 2020,
an operator must collect or make, and retain for the life of the
pipeline, records documenting the manufacturing standard and pressure
rating to which each valve was manufactured and tested in accordance
with this subpart. Flanges, fittings, branch connections, extruded
outlets, anchor forgings, and other components with material yield
strength grades of 42,000 psi (X42) or greater and with nominal
diameters of greater than 2 inches must have records documenting the
manufacturing specification in effect at the time of manufacture,
including yield strength, ultimate tensile strength, and chemical
composition of materials.
(b) For steel transmission pipelines installed on or before July 1,
2020, if operators have records documenting the manufacturing standard
and pressure rating for valves, flanges, fittings, branch connections,
extruded outlets, anchor forgings, and other components with material
yield strength grades of 42,000 psi (X42) or greater and with nominal
diameters of greater than 2 inches, operators must retain such records
for the life of the pipeline.
(c) For steel transmission pipeline segments installed on or before
July 1, 2020, if an operator does not have records necessary to
establish the MAOP of a pipeline segment, the operator may be subject
to the requirements of Sec. 192.624 according to the terms of that
section.

0
15. In Sec. 192.227, paragraph (c) is added to read as follows:

Sec. 192.227 Qualification of welders.

* * * * *
(c) For steel transmission pipe installed after July 1, 2021,
records demonstrating each individual welder qualification at the time
of construction in accordance with this section must be retained for a
minimum of 5 years following construction.

0
16. In Sec. 192.285, paragraph (e) is added to read as follows:

Sec. 192.285 Plastic pipe: Qualifying persons to make joints.

* * * * *
(e) For transmission pipe installed after July 1, 2021, records
demonstrating each person's plastic pipe joining qualifications at the
time of construction in accordance with this section must be retained
for a minimum of 5 years following construction.

0
17. Section 192.493 is added to read as follows:

Sec. 192.493 In-line inspection of pipelines.

When conducting in-line inspections of pipelines required by this
part, an operator must comply with API STD 1163, ANSI/ASNT ILI-PQ, and
NACE SP0102, (incorporated by reference, see Sec. 192.7). Assessments
may be conducted using tethered or remotely controlled tools, not
explicitly discussed in NACE SP0102, provided they comply with those
sections of NACE SP0102 that are applicable.

0
18. Section 192.506 is added to read as follows:

Sec. 192.506 Transmission lines: Spike hydrostatic pressure test.

(a) Spike test requirements. Whenever a segment of steel
transmission pipeline that is operated at a hoop stress level of 30
percent or more of SMYS is spike tested under this part, the spike
hydrostatic pressure test must be conducted in accordance with this
section.
(1) The test must use water as the test medium.
(2) The baseline test pressure must be as specified in the
applicable paragraphs of Sec. 192.619(a)(2) or Sec. 192.620(a)(2),
whichever applies.
(3) The test must be conducted by maintaining a pressure at or
above the baseline test pressure for at least 8 hours as specified in
Sec. 192.505.
(4) After the test pressure stabilizes at the baseline pressure and
within the first 2 hours of the 8-hour test interval, the hydrostatic
pressure must be raised (spiked) to a minimum of the lesser of 1.5
times MAOP or 100% SMYS. This spike hydrostatic pressure test must be
held for at least 15 minutes after the spike test pressure stabilizes.
(b) Other technology or other technical evaluation process.
Operators may use other technology or another process supported by a
documented engineering analysis for establishing a spike hydrostatic
pressure test or equivalent. Operators must notify PHMSA 90 days in
advance of the assessment or reassessment requirements of this
subchapter. The notification must be made in accordance with Sec.
192.18 and must include the following information:
(1) Descriptions of the technology or technologies to be used for
all tests, examinations, and assessments;
(2) Procedures and processes to conduct tests, examinations,
assessments, perform evaluations, analyze defects, and remediate
defects discovered;
(3) Data requirements, including original design, maintenance and
operating history, anomaly or flaw characterization;
(4) Assessment techniques and acceptance criteria;
(5) Remediation methods for assessment findings;
(6) Spike hydrostatic pressure test monitoring and acceptance
procedures, if used;
(7) Procedures for remaining crack growth analysis and pipeline
segment life analysis for the time interval for additional assessments,
as required; and
(8) Evidence of a review of all procedures and assessments by a
qualified technical subject matter expert.

0
19. In Sec. 192.517, paragraph (a) introductory text is revised to
read as follows:

Sec. 192.517 Records: Tests.

(a) An operator must make, and retain for the useful life of the
pipeline, a record of each test performed under Sec. Sec. 192.505,
192.506, and 192.507. The record must contain at least the following
information:
* * * * *

0
20. Section 192.607 is added to read as follows:

Sec. 192.607 Verification of Pipeline Material Properties and
Attributes: Onshore steel transmission pipelines.

(a) Applicability. Wherever required by this part, operators of
onshore steel transmission pipelines must document and verify material
properties and attributes in accordance with this section.
(b) Documentation of material properties and attributes. Records
established under this section documenting physical pipeline
characteristics and attributes, including diameter, wall thickness,
seam type, and grade (e.g., yield strength, ultimate tensile strength,
or pressure rating for valves and flanges, etc.), must be maintained
for the life of the pipeline and be traceable, verifiable, and
complete. Charpy v-notch toughness values established under this
section needed to meet the requirements of the ECA method at Sec.
192.624(c)(3) or the fracture mechanics requirements at Sec. 192.712
must be maintained for the life of the pipeline.

[[Page 52246]]

(c) Verification of material properties and attributes. If an
operator does not have traceable, verifiable, and complete records
required by paragraph (b) of this section, the operator must develop
and implement procedures for conducting nondestructive or destructive
tests, examinations, and assessments in order to verify the material
properties of aboveground line pipe and components, and of buried line
pipe and components when excavations occur at the following
opportunities: Anomaly direct examinations, in situ evaluations,
repairs, remediations, maintenance, and excavations that are associated
with replacements or relocations of pipeline segments that are removed
from service. The procedures must also provide for the following:
(1) For nondestructive tests, at each test location, material
properties for minimum yield strength and ultimate tensile strength
must be determined at a minimum of 5 places in at least 2
circumferential quadrants of the pipe for a minimum total of 10 test
readings at each pipe cylinder location.
(2) For destructive tests, at each test location, a set of material
properties tests for minimum yield strength and ultimate tensile
strength must be conducted on each test pipe cylinder removed from each
location, in accordance with API Specification 5L.
(3) Tests, examinations, and assessments must be appropriate for
verifying the necessary material properties and attributes.
(4) If toughness properties are not documented, the procedures must
include accepted industry methods for verifying pipe material
toughness.
(5) Verification of material properties and attributes for non-line
pipe components must comply with paragraph (f) of this section.
(d) Special requirements for nondestructive Methods. Procedures
developed in accordance with paragraph (c) of this section for
verification of material properties and attributes using nondestructive
methods must:
(1) Use methods, tools, procedures, and techniques that have been
validated by a subject matter expert based on comparison with
destructive test results on material of comparable grade and vintage;
(2) Conservatively account for measurement inaccuracy and
uncertainty using reliable engineering tests and analyses; and
(3) Use test equipment that has been properly calibrated for
comparable test materials prior to usage.
(e) Sampling multiple segments of pipe. To verify material
properties and attributes for a population of multiple, comparable
segments of pipe without traceable, verifiable, and complete records,
an operator may use a sampling program in accordance with the following
requirements:
(1) The operator must define separate populations of similar
segments of pipe for each combination of the following material
properties and attributes: Nominal wall thicknesses, grade,
manufacturing process, pipe manufacturing dates, and construction
dates. If the dates between the manufacture or construction of the
pipeline segments exceeds 2 years, those segments cannot be considered
as the same vintage for the purpose of defining a population under this
section. The total population mileage is the cumulative mileage of
pipeline segments in the population. The pipeline segments need not be
continuous.
(2) For each population defined according to paragraph (e)(1) of
this section, the operator must determine material properties at all
excavations that expose the pipe associated with anomaly direct
examinations, in situ evaluations, repairs, remediations, or
maintenance, except for pipeline segments exposed during excavation
activities pursuant to Sec. 192.614, until completion of the lesser of
the following:
(i) One excavation per mile rounded up to the nearest whole number;
or
(ii) 150 excavations if the population is more than 150 miles.
(3) Prior tests conducted for a single excavation according to the
requirements of paragraph (c) of this section may be counted as one
sample under the sampling requirements of this paragraph (e).
(4) If the test results identify line pipe with properties that are
not consistent with available information or existing expectations or
assumed properties used for operations and maintenance in the past, the
operator must establish an expanded sampling program. The expanded
sampling program must use valid statistical bases designed to achieve
at least a 95% confidence level that material properties used in the
operation and maintenance of the pipeline are valid. The approach must
address how the sampling plan will be expanded to address findings that
reveal material properties that are not consistent with all available
information or existing expectations or assumed material properties
used for pipeline operations and maintenance in the past. Operators
must notify PHMSA in advance of using an expanded sampling approach in
accordance with Sec. 192.18.
(5) An operator may use an alternative statistical sampling
approach that differs from the requirements specified in paragraph
(e)(2) of this section. The alternative sampling program must use valid
statistical bases designed to achieve at least a 95% confidence level
that material properties used in the operation and maintenance of the
pipeline are valid. The approach must address how the sampling plan
will be expanded to address findings that reveal material properties
that are not consistent with all available information or existing
expectations or assumed material properties used for pipeline
operations and maintenance in the past. Operators must notify PHMSA in
advance of using an alternative sampling approach in accordance with
Sec. 192.18.
(f) Components. For mainline pipeline components other than line
pipe, an operator must develop and implement procedures in accordance
with paragraph (c) of this section for establishing and documenting the
ANSI rating or pressure rating (in accordance with ASME/ANSI B16.5
(incorporated by reference, see Sec. 192.7)),
(1) Operators are not required to test for the chemical and
mechanical properties of components in compressor stations, meter
stations, regulator stations, separators, river crossing headers,
mainline valve assemblies, valve operator piping, or cross-connections
with isolation valves from the mainline pipeline.
(2) Verification of material properties is required for non-line
pipe components, including valves, flanges, fittings, fabricated
assemblies, and other pressure retaining components and appurtenances
that are:
(i) Larger than 2 inches in nominal outside diameter,
(ii) Material grades of 42,000 psi (Grade X-42) or greater, or
(iii) Appurtenances of any size that are directly installed on the
pipeline and cannot be isolated from mainline pipeline pressures.
(3) Procedures for establishing material properties of non-line
pipe components must be based on the documented manufacturing
specification for the components. If specifications are not known,
usage of manufacturer's stamped, marked, or tagged material pressure
ratings and material type may be used to establish pressure rating.
Operators must document the method used to determine the pressure
rating and the findings of that determination.
(g) Uprating. The material properties determined from the
destructive or nondestructive tests required by this

[[Page 52247]]

section cannot be used to raise the grade or specification of the
material, unless the original grade or specification is unknown and
MAOP is based on an assumed yield strength of 24,000 psi in accordance
with Sec. 192.107(b)(2).

0
21. In Sec. 192.619, the introductory text of paragraphs (a)
introductory text and (a)(2) and (4) are revised and paragraphs (e) and
(f) are added to read as follows:

Sec. 192.619 Maximum allowable operating pressure: Steel or plastic
pipelines.

(a) No person may operate a segment of steel or plastic pipeline at
a pressure that exceeds a maximum allowable operating pressure (MAOP)
determined under paragraph (c), (d), or (e) of this section, or the
lowest of the following:
* * * * *
(2) The pressure obtained by dividing the pressure to which the
pipeline segment was tested after construction as follows:
(i) For plastic pipe in all locations, the test pressure is divided
by a factor of 1.5.
(ii) For steel pipe operated at 100 psi (689 kPa) gage or more, the
test pressure is divided by a factor determined in accordance with the
Table 1 to paragraph (a)(2)(ii):

Table 1 to Paragraph (a)(2)(ii)
----------------------------------------------------------------------------------------------------------------
Factors,\1\ segment--
--------------------------------------------------------
Installed before Installed after
Class location (Nov. 12, 1970) (Nov. 11, 1970) Installed on or Converted under
and before July after July 1, Sec. 192.14
1, 2020 2020
----------------------------------------------------------------------------------------------------------------
1................................... 1.1 1.1 1.25 1.25
2................................... 1.25 1.25 1.25 1.25
3................................... 1.4 1.5 1.5 1.5
4................................... 1.4 1.5 1.5 1.5
----------------------------------------------------------------------------------------------------------------
\1\ For offshore pipeline segments installed, uprated or converted after July 31, 1977, that are not located on
an offshore platform, the factor is 1.25. For pipeline segments installed, uprated or converted after July 31,
1977, that are located on an offshore platform or on a platform in inland navigable waters, including a pipe
riser, the factor is 1.5.

* * * * *
(4) The pressure determined by the operator to be the maximum safe
pressure after considering and accounting for records of material
properties, including material properties verified in accordance with
Sec. 192.607, if applicable, and the history of the pipeline segment,
including known corrosion and actual operating pressure.
* * * * *
(e) Notwithstanding the requirements in paragraphs (a) through (d)
of this section, operators of onshore steel transmission pipelines that
meet the criteria specified in Sec. 192.624(a) must establish and
document the maximum allowable operating pressure in accordance with
Sec. 192.624.
(f) Operators of onshore steel transmission pipelines must make and
retain records necessary to establish and document the MAOP of each
pipeline segment in accordance with paragraphs (a) through (e) of this
section as follows:
(1) Operators of pipelines in operation as of [July 1, 2020 must
retain any existing records establishing MAOP for the life of the
pipeline;
(2) Operators of pipelines in operation as of July 1, 2020 that do
not have records establishing MAOP and are required to reconfirm MAOP
in accordance with Sec. 192.624, must retain the records reconfirming
MAOP for the life of the pipeline; and
(3) Operators of pipelines placed in operation after July 1, 2020
must make and retain records establishing MAOP for the life of the
pipeline.

0
22. Section 192.624 is added to read as follows:

Sec. 192.624 Maximum allowable operating pressure reconfirmation:
Onshore steel transmission pipelines.

(a) Applicability. Operators of onshore steel transmission pipeline
segments must reconfirm the maximum allowable operating pressure (MAOP)
of all pipeline segments in accordance with the requirements of this
section if either of the following conditions are met:
(1) Records necessary to establish the MAOP in accordance with
Sec. 192.619(a), including records required by Sec. 192.517(a), are
not traceable, verifiable, and complete and the pipeline is located in
one of the following locations:
(i) A high consequence area as defined in Sec. 192.903; or
(ii) A Class 3 or Class 4 location.
(2) The pipeline segment's MAOP was established in accordance with
Sec. 192.619(c), the pipeline segment's MAOP is greater than or equal
to 30 percent of the specified minimum yield strength, and the pipeline
segment is located in one of the following areas:
(i) A high consequence area as defined in Sec. 192.903;
(ii) A Class 3 or Class 4 location; or
(iii) A moderate consequence area as defined in Sec. 192.3, if the
pipeline segment can accommodate inspection by means of instrumented
inline inspection tools.
(b) Procedures and completion dates. Operators of a pipeline
subject to this section must develop and document procedures for
completing all actions required by this section by July 1, 2021. These
procedures must include a process for reconfirming MAOP for any
pipelines that meet a condition of Sec. 192.624(a), and for performing
a spike test or material verification in accordance with Sec. Sec.
192.506 and 192.607, if applicable. All actions required by this
section must be completed according to the following schedule:
(1) Operators must complete all actions required by this section on
at least 50% of the pipeline mileage by July 3, 2028.
(2) Operators must complete all actions required by this section on
100% of the pipeline mileage by July 2, 2035 or as soon as practicable,
but not to exceed 4 years after the pipeline segment first meets a
condition of Sec. 192.624(a) (e.g., due to a location becoming a high
consequence area), whichever is later.
(3) If operational and environmental constraints limit an operator
from meeting the deadlines in Sec. 192.624, the operator may petition
for an extension of the completion deadlines by up to 1 year, upon
submittal of a notification in accordance with Sec. 192.18. The
notification must include an up-to-date plan for completing all actions
in accordance with this section, the reason for the requested
extension, current status, proposed completion date, outstanding
remediation activities, and

[[Page 52248]]

any needed temporary measures needed to mitigate the impact on safety.
(c) Maximum allowable operating pressure determination. Operators
of a pipeline segment meeting a condition in paragraph (a) of this
section must reconfirm its MAOP using one of the following methods:
(1) Method 1: Pressure test. Perform a pressure test and verify
material properties records in accordance with Sec. 192.607 and the
following requirements:
(i) Pressure test. Perform a pressure test in accordance with
subpart J of this part. The MAOP must be equal to the test pressure
divided by the greater of either 1.25 or the applicable class location
factor in Sec. 192.619(a)(2)(ii).
(ii) Material properties records. Determine if the following
material properties records are documented in traceable, verifiable,
and complete records: Diameter, wall thickness, seam type, and grade
(minimum yield strength, ultimate tensile strength).
(iii) Material properties verification. If any of the records
required by paragraph (c)(1)(ii) of this section are not documented in
traceable, verifiable, and complete records, the operator must obtain
the missing records in accordance with Sec. 192.607. An operator must
test the pipe materials cut out from the test manifold sites at the
time the pressure test is conducted. If there is a failure during the
pressure test, the operator must test any removed pipe from the
pressure test failure in accordance with Sec. 192.607.
(2) Method 2: Pressure Reduction. Reduce pressure, as necessary,
and limit MAOP to no greater than the highest actual operating pressure
sustained by the pipeline during the 5 years preceding October 1, 2019,
divided by the greater of 1.25 or the applicable class location factor
in Sec. 192.619(a)(2)(ii). The highest actual sustained pressure must
have been reached for a minimum cumulative duration of 8 hours during a
continuous 30-day period. The value used as the highest actual
sustained operating pressure must account for differences between
upstream and downstream pressure on the pipeline by use of either the
lowest maximum pressure value for the entire pipeline segment or using
the operating pressure gradient along the entire pipeline segment
(i.e., the location-specific operating pressure at each location).
(i) Where the pipeline segment has had a class location change in
accordance with Sec. 192.611, and records documenting diameter, wall
thickness, seam type, grade (minimum yield strength and ultimate
tensile strength), and pressure tests are not documented in traceable,
verifiable, and complete records, the operator must reduce the pipeline
segment MAOP as follows:
(A) For pipeline segments where a class location changed from Class
1 to Class 2, from Class 2 to Class 3, or from Class 3 to Class 4,
reduce the pipeline MAOP to no greater than the highest actual
operating pressure sustained by the pipeline during the 5 years
preceding October 1, 2019, divided by 1.39 for Class 1 to Class 2, 1.67
for Class 2 to Class 3, and 2.00 for Class 3 to Class 4.
(B) For pipeline segments where a class location changed from Class
1 to Class 3, reduce the pipeline MAOP to no greater than the highest
actual operating pressure sustained by the pipeline during the 5 years
preceding October 1, 2019, divided by 2.00.
(ii) Future uprating of the pipeline segment in accordance with
subpart K is allowed if the MAOP is established using Method 2.
(iii) If an operator elects to use Method 2, but desires to use a
less conservative pressure reduction factor or longer look-back period,
the operator must notify PHMSA in accordance with Sec. 192.18 no later
than 7 calendar days after establishing the reduced MAOP. The
notification must include the following details:
(A) Descriptions of the operational constraints, special
circumstances, or other factors that preclude, or make it impractical,
to use the pressure reduction factor specified in Sec. 192.624(c)(2);
(B) The fracture mechanics modeling for failure stress pressures
and cyclic fatigue crack growth analysis that complies with Sec.
192.712;
(C) Justification that establishing MAOP by another method allowed
by this section is impractical;
(D) Justification that the reduced MAOP determined by the operator
is safe based on analysis of the condition of the pipeline segment,
including material properties records, material properties verified in
accordance Sec. 192.607, and the history of the pipeline segment,
particularly known corrosion and leakage, and the actual operating
pressure, and additional compensatory preventive and mitigative
measures taken or planned; and
(E) Planned duration for operating at the requested MAOP, long-term
remediation measures and justification of this operating time interval,
including fracture mechanics modeling for failure stress pressures and
cyclic fatigue growth analysis and other validated forms of engineering
analysis that have been reviewed and confirmed by subject matter
experts.
(3) Method 3: Engineering Critical Assessment (ECA). Conduct an ECA
in accordance with Sec. 192.632.
(4) Method 4: Pipe Replacement. Replace the pipeline segment in
accordance with this part.
(5) Method 5: Pressure Reduction for Pipeline Segments with Small
Potential Impact Radius. Pipelines with a potential impact radius (PIR)
less than or equal to 150 feet may establish the MAOP as follows:
(i) Reduce the MAOP to no greater than the highest actual operating
pressure sustained by the pipeline during 5 years preceding October 1,
2019, divided by 1.1. The highest actual sustained pressure must have
been reached for a minimum cumulative duration of 8 hours during one
continuous 30-day period. The reduced MAOP must account for differences
between discharge and upstream pressure on the pipeline by use of
either the lowest value for the entire pipeline segment or the
operating pressure gradient (i.e., the location specific operating
pressure at each location);
(ii) Conduct patrols in accordance with Sec. 192.705 paragraphs
(a) and (c) and conduct instrumented leakage surveys in accordance with
Sec. 192.706 at intervals not to exceed those in the following table 1
to Sec. 192.624(c)(5)(ii):

Table 1 to Sec. 192.624(c)(5)(ii)
------------------------------------------------------------------------
Class locations Patrols Leakage surveys
------------------------------------------------------------------------
(A) Class 1 and Class 2..... 3 \1/2\ months, but 3 \1/2\ months, but
at least four times at least four times
each calendar year. each calendar year.
(B) Class 3 and Class 4..... 3 months, but at 3 months, but at
least six times least six times
each calendar year. each calendar year.
------------------------------------------------------------------------

[[Page 52249]]

(iii) Under Method 5, future uprating of the pipeline segment in
accordance with subpart K is allowed.
(6) Method 6: Alternative Technology. Operators may use an
alternative technical evaluation process that provides a documented
engineering analysis for establishing MAOP. If an operator elects to
use alternative technology, the operator must notify PHMSA in advance
in accordance with Sec. 192.18. The notification must include
descriptions of the following details:
(i) The technology or technologies to be used for tests,
examinations, and assessments; the method for establishing material
properties; and analytical techniques with similar analysis from prior
tool runs done to ensure the results are consistent with the required
corresponding hydrostatic test pressure for the pipeline segment being
evaluated;
(ii) Procedures and processes to conduct tests, examinations,
assessments and evaluations, analyze defects and flaws, and remediate
defects discovered;
(iii) Pipeline segment data, including original design, maintenance
and operating history, anomaly or flaw characterization;
(iv) Assessment techniques and acceptance criteria, including
anomaly detection confidence level, probability of detection, and
uncertainty of the predicted failure pressure quantified as a fraction
of specified minimum yield strength;
(v) If any pipeline segment contains cracking or may be susceptible
to cracking or crack-like defects found through or identified by
assessments, leaks, failures, manufacturing vintage histories, or any
other available information about the pipeline, the operator must
estimate the remaining life of the pipeline in accordance with
paragraph Sec. 192.712;
(vi) Operational monitoring procedures;
(vii) Methodology and criteria used to justify and establish the
MAOP; and
(vii) Documentation of the operator's process and procedures used
to implement the use of the alternative technology, including any
records generated through its use.
(d) Records. An operator must retain records of investigations,
tests, analyses, assessments, repairs, replacements, alterations, and
other actions taken in accordance with the requirements of this section
for the life of the pipeline.

0
23. Section 192.632 is added to read as follows:

Sec. 192.632 Engineering Critical Assessment for Maximum Allowable
Operating Pressure Reconfirmation: Onshore steel transmission
pipelines.

When an operator conducts an MAOP reconfirmation in accordance with
Sec. 192.624(c)(3) ``Method 3'' using an ECA to establish the material
strength and MAOP of the pipeline segment, the ECA must comply with the
requirements of this section. The ECA must assess: Threats; loadings
and operational circumstances relevant to those threats, including
along the pipeline right-of way; outcomes of the threat assessment;
relevant mechanical and fracture properties; in-service degradation or
failure processes; and initial and final defect size relevance. The ECA
must quantify the interacting effects of threats on any defect in the
pipeline.
(a) ECA Analysis. (1) The material properties required to perform
an ECA analysis in accordance with this paragraph are as follows:
Diameter, wall thickness, seam type, grade (minimum yield strength and
ultimate tensile strength), and Charpy v-notch toughness values based
upon the lowest operational temperatures, if applicable. If any
material properties required to perform an ECA for any pipeline segment
in accordance with this paragraph are not documented in traceable,
verifiable and complete records, an operator must use conservative
assumptions and include the pipeline segment in its program to verify
the undocumented information in accordance with Sec. 192.607. The ECA
must integrate, analyze, and account for the material properties, the
results of all tests, direct examinations, destructive tests, and
assessments performed in accordance with this section, along with other
pertinent information related to pipeline integrity, including close
interval surveys, coating surveys, interference surveys required by
subpart I of this part, cause analyses of prior incidents, prior
pressure test leaks and failures, other leaks, pipe inspections, and
prior integrity assessments, including those required by Sec. Sec.
192.617, 192.710, and subpart O of this part.
(2) The ECA must analyze and determine the predicted failure
pressure for the defect being assessed using procedures that implement
the appropriate failure criteria and justification as follows:
(i) The ECA must analyze any cracks or crack-like defects remaining
in the pipe, or that could remain in the pipe, to determine the
predicted failure pressure of each defect in accordance with Sec.
192.712.
(ii) The ECA must analyze any metal loss defects not associated
with a dent, including corrosion, gouges, scrapes or other metal loss
defects that could remain in the pipe, to determine the predicted
failure pressure. ASME/ANSI B31G (incorporated by reference, see Sec.
192.7) or R-STRENG (incorporated by reference, see Sec. 192.7) must be
used for corrosion defects. Both procedures and their analysis apply to
corroded regions that do not penetrate the pipe wall over 80 percent of
the wall thickness and are subject to the limitations prescribed in the
equations' procedures. The ECA must use conservative assumptions for
metal loss dimensions (length, width, and depth).
(iii) When determining the predicted failure pressure for gouges,
scrapes, selective seam weld corrosion, crack-related defects, or any
defect within a dent, appropriate failure criteria and justification of
the criteria must be used and documented.
(iv) If SMYS or actual material yield and ultimate tensile strength
is not known or not documented by traceable, verifiable, and complete
records, then the operator must assume 30,000 p.s.i. or determine the
material properties using Sec. 192.607.
(3) The ECA must analyze the interaction of defects to
conservatively determine the most limiting predicted failure pressure.
Examples include, but are not limited to, cracks in or near locations
with corrosion metal loss, dents with gouges or other metal loss, or
cracks in or near dents or other deformation damage. The ECA must
document all evaluations and any assumptions used in the ECA process.
(4) The MAOP must be established at the lowest predicted failure
pressure for any known or postulated defect, or interacting defects,
remaining in the pipe divided by the greater of 1.25 or the applicable
factor listed in Sec. 192.619(a)(2)(ii).
(b) Assessment to determine defects remaining in the pipe. An
operator must utilize previous pressure tests or develop and implement
an assessment program to determine the size of defects remaining in the
pipe to be analyzed in accordance with paragraph (a) of this section.
(1) An operator may use a previous pressure test that complied with
subpart J to determine the defects remaining in the pipe if records for
a pressure test meeting the requirements of subpart J of this part
exist for the pipeline segment. The operator must calculate the largest
defect that could have survived the pressure test. The operator must
predict how much the defects have grown since the date of the pressure
test in

[[Page 52250]]

accordance with Sec. 192.712. The ECA must analyze the predicted size
of the largest defect that could have survived the pressure test that
could remain in the pipe at the time the ECA is performed. The operator
must calculate the remaining life of the most severe defects that could
have survived the pressure test and establish a re-assessment interval
in accordance with the methodology in Sec. 192.712.
(2) Operators may use an inline inspection program in accordance
with paragraph (c) of this section.
(3) Operators may use ``other technology'' if it is validated by a
subject matter expert to produce an equivalent understanding of the
condition of the pipe equal to or greater than pressure testing or an
inline inspection program. If an operator elects to use ``other
technology'' in the ECA, it must notify PHMSA in advance of using the
other technology in accordance with Sec. 192.18. The ``other
technology'' notification must have:
(i) Descriptions of the technology or technologies to be used for
all tests, examinations, and assessments, including characterization of
defect size used in the crack assessments (length, depth, and
volumetric); and
(ii) Procedures and processes to conduct tests, examinations,
assessments and evaluations, analyze defects, and remediate defects
discovered.
(c) In-line inspection. An inline inspection (ILI) program to
determine the defects remaining the pipe for the ECA analysis must be
performed using tools that can detect wall loss, deformation from
dents, wrinkle bends, ovalities, expansion, seam defects, including
cracking and selective seam weld corrosion, longitudinal,
circumferential and girth weld cracks, hard spot cracking, and stress
corrosion cracking.
(1) If a pipeline has segments that might be susceptible to hard
spots based on assessment, leak, failure, manufacturing vintage
history, or other information, then the ILI program must include a tool
that can detect hard spots.
(2) If the pipeline has had a reportable incident, as defined in
Sec. 191.3, attributed to a girth weld failure since its most recent
pressure test, then the ILI program must include a tool that can detect
girth weld defects unless the ECA analysis performed in accordance with
this section includes an engineering evaluation program to analyze and
account for the susceptibility of girth weld failure due to lateral
stresses.
(3) Inline inspection must be performed in accordance with Sec.
192.493.
(4) An operator must use unity plots or equivalent methodologies to
validate the performance of the ILI tools in identifying and sizing
actionable manufacturing and construction related anomalies. Enough
data points must be used to validate tool performance at the same or
better statistical confidence level provided in the tool
specifications. The operator must have a process for identifying
defects outside the tool performance specifications and following up
with the ILI vendor to conduct additional in-field examinations,
reanalyze ILI data, or both.
(5) Interpretation and evaluation of assessment results must meet
the requirements of Sec. Sec. 192.710, 192.713, and subpart O of this
part, and must conservatively account for the accuracy and reliability
of ILI, in-the-ditch examination methods and tools, and any other
assessment and examination results used to determine the actual sizes
of cracks, metal loss, deformation and other defect dimensions by
applying the most conservative limit of the tool tolerance
specification. ILI and in-the-ditch examination tools and procedures
for crack assessments (length and depth) must have performance and
evaluation standards confirmed for accuracy through confirmation tests
for the defect types and pipe material vintage being evaluated.
Inaccuracies must be accounted for in the procedures for evaluations
and fracture mechanics models for predicted failure pressure
determinations.
(6) Anomalies detected by ILI assessments must be remediated in
accordance with applicable criteria in Sec. Sec. 192.713 and 192.933.
(d) Defect remaining life. If any pipeline segment contains
cracking or may be susceptible to cracking or crack-like defects found
through or identified by assessments, leaks, failures, manufacturing
vintage histories, or any other available information about the
pipeline, the operator must estimate the remaining life of the pipeline
in accordance with Sec. 192.712.
(e) Records. An operator must retain records of investigations,
tests, analyses, assessments, repairs, replacements, alterations, and
other actions taken in accordance with the requirements of this section
for the life of the pipeline.

0
24. Section 192.710 is added to read as follows:

Sec. 192.710 Transmission lines: Assessments outside of high
consequence areas.

(a) Applicability: This section applies to onshore steel
transmission pipeline segments with a maximum allowable operating
pressure of greater than or equal to 30% of the specified minimum yield
strength and are located in:
(1) A Class 3 or Class 4 location; or
(2) A moderate consequence area as defined in Sec. 192.3, if the
pipeline segment can accommodate inspection by means of an instrumented
inline inspection tool (i.e., ``smart pig'').
(3) This section does not apply to a pipeline segment located in a
high consequence area as defined in Sec. 192.903.
(b) General--(1) Initial assessment. An operator must perform
initial assessments in accordance with this section based on a risk-
based prioritization schedule and complete initial assessment for all
applicable pipeline segments no later than July 3, 2034, or as soon as
practicable but not to exceed 10 years after the pipeline segment first
meets the conditions of Sec. 192.710(a) (e.g., due to a change in
class location or the area becomes a moderate consequence area),
whichever is later.
(2) Periodic reassessment. An operator must perform periodic
reassessments at least once every 10 years, with intervals not to
exceed 126 months, or a shorter reassessment interval based upon the
type of anomaly, operational, material, and environmental conditions
found on the pipeline segment, or as necessary to ensure public safety.
(3) Prior assessment. An operator may use a prior assessment
conducted before July 1, 2020 as an initial assessment for the pipeline
segment, if the assessment met the subpart O requirements of part 192
for in-line inspection at the time of the assessment. If an operator
uses this prior assessment as its initial assessment, the operator must
reassess the pipeline segment according to the reassessment interval
specified in paragraph (b)(2) of this section calculated from the date
of the prior assessment.
(4) MAOP verification. An integrity assessment conducted in
accordance with the requirements of Sec. 192.624(c) for establishing
MAOP may be used as an initial assessment or reassessment under this
section.
(c) Assessment method. The initial assessments and the
reassessments required by paragraph (b) of this section must be capable
of identifying anomalies and defects associated with each of the
threats to which the pipeline segment is susceptible and must be
performed using one or more of the following methods:
(1) Internal inspection. Internal inspection tool or tools capable
of detecting those threats to which the

[[Page 52251]]

pipeline is susceptible, such as corrosion, deformation and mechanical
damage (e.g., dents, gouges and grooves), material cracking and crack-
like defects (e.g., stress corrosion cracking, selective seam weld
corrosion, environmentally assisted cracking, and girth weld cracks),
hard spots with cracking, and any other threats to which the covered
segment is susceptible. When performing an assessment using an in-line
inspection tool, an operator must comply with Sec. 192.493;
(2) Pressure test. Pressure test conducted in accordance with
subpart J of this part. The use of subpart J pressure testing is
appropriate for threats such as internal corrosion, external corrosion,
and other environmentally assisted corrosion mechanisms; manufacturing
and related defect threats, including defective pipe and pipe seams;
and stress corrosion cracking, selective seam weld corrosion, dents and
other forms of mechanical damage;
(3) Spike hydrostatic pressure test. A spike hydrostatic pressure
test conducted in accordance with Sec. 192.506. A spike hydrostatic
pressure test is appropriate for time-dependent threats such as stress
corrosion cracking; selective seam weld corrosion; manufacturing and
related defects, including defective pipe and pipe seams; and other
forms of defect or damage involving cracks or crack-like defects;
(4) Direct examination. Excavation and in situ direct examination
by means of visual examination, direct measurement, and recorded non-
destructive examination results and data needed to assess all
applicable threats. Based upon the threat assessed, examples of
appropriate non-destructive examination methods include ultrasonic
testing (UT), phased array ultrasonic testing (PAUT), Inverse Wave
Field Extrapolation (IWEX), radiography, and magnetic particle
inspection (MPI);
(5) Guided Wave Ultrasonic Testing. Guided Wave Ultrasonic Testing
(GWUT) as described in Appendix F;
(6) Direct assessment. Direct assessment to address threats of
external corrosion, internal corrosion, and stress corrosion cracking.
The use of use of direct assessment to address threats of external
corrosion, internal corrosion, and stress corrosion cracking is allowed
only if appropriate for the threat and pipeline segment being assessed.
Use of direct assessment for threats other than the threat for which
the direct assessment method is suitable is not allowed. An operator
must conduct the direct assessment in accordance with the requirements
listed in Sec. 192.923 and with the applicable requirements specified
in Sec. Sec. 192.925, 192.927 and 192.929; or
(7) Other technology. Other technology that an operator
demonstrates can provide an equivalent understanding of the condition
of the line pipe for each of the threats to which the pipeline is
susceptible. An operator must notify PHMSA in advance of using the
other technology in accordance with Sec. 192.18.
(d) Data analysis. An operator must analyze and account for the
data obtained from an assessment performed under paragraph (c) of this
section to determine if a condition could adversely affect the safe
operation of the pipeline using personnel qualified by knowledge,
training, and experience. In addition, when analyzing inline inspection
data, an operator must account for uncertainties in reported results
(e.g., tool tolerance, detection threshold, probability of detection,
probability of identification, sizing accuracy, conservative anomaly
interaction criteria, location accuracy, anomaly findings, and unity
chart plots or equivalent for determining uncertainties and verifying
actual tool performance) in identifying and characterizing anomalies.
(e) Discovery of condition. Discovery of a condition occurs when an
operator has adequate information about a condition to determine that
the condition presents a potential threat to the integrity of the
pipeline. An operator must promptly, but no later than 180 days after
conducting an integrity assessment, obtain sufficient information about
a condition to make that determination, unless the operator
demonstrates that 180 days is impracticable.
(f) Remediation. An operator must comply with the requirements in
Sec. Sec. 192.485, 192.711, and 192.713, where applicable, if a
condition that could adversely affect the safe operation of a pipeline
is discovered.
(g) Analysis of information. An operator must analyze and account
for all available relevant information about a pipeline in complying
with the requirements in paragraphs (a) through (f) of this section.

0
25. Section 192.712 is added to read as follows:

Sec. 192.712 Analysis of predicted failure pressure.

(a) Applicability. Whenever required by this part, operators of
onshore steel transmission pipelines must analyze anomalies or defects
to determine the predicted failure pressure at the location of the
anomaly or defect, and the remaining life of the pipeline segment at
the location of the anomaly or defect, in accordance with this section.
(b) Corrosion metal loss. When analyzing corrosion metal loss under
this section, an operator must use a suitable remaining strength
calculation method including, ASME/ANSI B31G (incorporated by
reference, see Sec. 192.7); R-STRENG (incorporated by reference, see
Sec. 192.7); or an alternative equivalent method of remaining strength
calculation that will provide an equally conservative result.
(c) [Reserved]
(d) Cracks and crack-like defects--(1) Crack analysis models. When
analyzing cracks and crack-like defects under this section, an operator
must determine predicted failure pressure, failure stress pressure, and
crack growth using a technically proven fracture mechanics model
appropriate to the failure mode (ductile, brittle or both), material
properties (pipe and weld properties), and boundary condition used
(pressure test, ILI, or other).
(2) Analysis for crack growth and remaining life. If the pipeline
segment is susceptible to cyclic fatigue or other loading conditions
that could lead to fatigue crack growth, fatigue analysis must be
performed using an applicable fatigue crack growth law (for example,
Paris Law) or other technically appropriate engineering methodology.
For other degradation processes that can cause crack growth,
appropriate engineering analysis must be used. The above methodologies
must be validated by a subject matter expert to determine conservative
predictions of flaw growth and remaining life at the maximum allowable
operating pressure. The operator must calculate the remaining life of
the pipeline by determining the amount of time required for the crack
to grow to a size that would fail at maximum allowable operating
pressure.
(i) When calculating crack size that would fail at MAOP, and the
material toughness is not documented in traceable, verifiable, and
complete records, the same Charpy v-notch toughness value established
in paragraph (e)(2) of this section must be used.
(ii) Initial and final flaw size must be determined using a
fracture mechanics model appropriate to the failure mode (ductile,
brittle or both) and boundary condition used (pressure test, ILI, or
other).
(iii) An operator must re-evaluate the remaining life of the
pipeline before 50% of the remaining life calculated by this analysis
has expired. The operator must determine and document if further
pressure tests or use of other assessment

[[Page 52252]]

methods are required at that time. The operator must continue to re-
evaluate the remaining life of the pipeline before 50% of the remaining
life calculated in the most recent evaluation has expired.
(3) Cracks that survive pressure testing. For cases in which the
operator does not have in-line inspection crack anomaly data and is
analyzing potential crack defects that could have survived a pressure
test, the operator must calculate the largest potential crack defect
sizes using the methods in paragraph (d)(1) of this section. If pipe
material toughness is not documented in traceable, verifiable, and
complete records, the operator must use one of the following for Charpy
v-notch toughness values based upon minimum operational temperature and
equivalent to a full-size specimen value:
(i) Charpy v-notch toughness values from comparable pipe with known
properties of the same vintage and from the same steel and pipe
manufacturer;
(ii) A conservative Charpy v-notch toughness value to determine the
toughness based upon the material properties verification process
specified in Sec. 192.607;
(iii) A full size equivalent Charpy v-notch upper-shelf toughness
level of 120 ft.-lbs.; or
(iv) Other appropriate values that an operator demonstrates can
provide conservative Charpy v-notch toughness values of the crack-
related conditions of the pipeline segment. Operators using an assumed
Charpy v-notch toughness value must notify PHMSA in accordance with
Sec. 192.18.
(e) Data. In performing the analyses of predicted or assumed
anomalies or defects in accordance with this section, an operator must
use data as follows.
(1) An operator must explicitly analyze and account for
uncertainties in reported assessment results (including tool tolerance,
detection threshold, probability of detection, probability of
identification, sizing accuracy, conservative anomaly interaction
criteria, location accuracy, anomaly findings, and unity chart plots or
equivalent for determining uncertainties and verifying tool
performance) in identifying and characterizing the type and dimensions
of anomalies or defects used in the analyses, unless the defect
dimensions have been verified using in situ direct measurements.
(2) The analyses performed in accordance with this section must
utilize pipe and material properties that are documented in traceable,
verifiable, and complete records. If documented data required for any
analysis is not available, an operator must obtain the undocumented
data through Sec. 192.607. Until documented material properties are
available, the operator shall use conservative assumptions as follows:
(i) Material toughness. An operator must use one of the following
for material toughness:
(A) Charpy v-notch toughness values from comparable pipe with known
properties of the same vintage and from the same steel and pipe
manufacturer;
(B) A conservative Charpy v-notch toughness value to determine the
toughness based upon the ongoing material properties verification
process specified in Sec. 192.607;
(C) If the pipeline segment does not have a history of reportable
incidents caused by cracking or crack-like defects, maximum Charpy v-
notch toughness values of 13.0 ft.-lbs. for body cracks and 4.0 ft.-
lbs. for cold weld, lack of fusion, and selective seam weld corrosion
defects;
(D) If the pipeline segment has a history of reportable incidents
caused by cracking or crack-like defects, maximum Charpy v-notch
toughness values of 5.0 ft.-lbs. for body cracks and 1.0 ft.-lbs. for
cold weld, lack of fusion, and selective seam weld corrosion; or
(E) Other appropriate values that an operator demonstrates can
provide conservative Charpy v-notch toughness values of crack-related
conditions of the pipeline segment. Operators using an assumed Charpy
v-notch toughness value must notify PHMSA in advance in accordance with
Sec. 192.18 and include in the notification the bases for
demonstrating that the Charpy v-notch toughness values proposed are
appropriate and conservative for use in analysis of crack-related
conditions.
(ii) Material strength. An operator must assume one of the
following for material strength:
(A) Grade A pipe (30,000 psi), or
(B) The specified minimum yield strength that is the basis for the
current maximum allowable operating pressure.
(iii) Pipe dimensions and other data. Until pipe wall thickness,
diameter, or other data are determined and documented in accordance
with Sec. 192.607, the operator must use values upon which the current
MAOP is based.
(f) Review. Analyses conducted in accordance with this section must
be reviewed and confirmed by a subject matter expert.
(g) Records. An operator must keep for the life of the pipeline
records of the investigations, analyses, and other actions taken in
accordance with the requirements of this section. Records must document
justifications, deviations, and determinations made for the following,
as applicable:
(1) The technical approach used for the analysis;
(2) All data used and analyzed;
(3) Pipe and weld properties;
(4) Procedures used;
(5) Evaluation methodology used;
(6) Models used;
(7) Direct in situ examination data;
(8) In-line inspection tool run information evaluated, including
any multiple in-line inspection tool runs;
(9) Pressure test data and results;
(10) In-the-ditch assessments;
(11) All measurement tool, assessment, and evaluation accuracy
specifications and tolerances used in technical and operational
results;
(12) All finite element analysis results;
(13) The number of pressure cycles to failure, the equivalent
number of annual pressure cycles, and the pressure cycle counting
method;
(14) The predicted fatigue life and predicted failure pressure from
the required fatigue life models and fracture mechanics evaluation
methods;
(15) Safety factors used for fatigue life and/or predicted failure
pressure calculations;
(16) Reassessment time interval and safety factors;
(17) The date of the review;
(18) Confirmation of the results by qualified technical subject
matter experts; and
(19) Approval by responsible operator management personnel.

0
26. Section 192.750 is added to read as follows:

Sec. 192.750 Launcher and receiver safety.

Any launcher or receiver used after July 1, 2021, must be equipped
with a device capable of safely relieving pressure in the barrel before
removal or opening of the launcher or receiver barrel closure or flange
and insertion or removal of in-line inspection tools, scrapers, or
spheres. An operator must use a device to either: Indicate that
pressure has been relieved in the barrel; or alternatively prevent
opening of the barrel closure or flange when pressurized, or insertion
or removal of in-line devices (e.g. inspection tools, scrapers, or
spheres), if pressure has not been relieved.

0
27. In Sec. 192.805, paragraph (i) is revised to read as follows:

Sec. 192.805 Qualification Program.

* * * * *
(i) After December 16, 2004, notify the Administrator or a state
agency participating under 49 U.S.C. Chapter 601 if an operator
significantly modifies the program after the administrator or state
agency has verified that it complies

[[Page 52253]]

with this section. Notifications to PHMSA must be submitted in
accordance with Sec. 192.18.

0
28. In Sec. 192.909, paragraph (b) is revised to read as follows:

Sec. 192.909 How can an operator change its integrity management
program?

* * * * *
(b) Notification. An operator must notify OPS, in accordance with
Sec. 192.18, of any change to the program that may substantially
affect the program's implementation or may significantly modify the
program or schedule for carrying out the program elements. An operator
must provide notification within 30 days after adopting this type of
change into its program.

0
29. In Sec. 192.917, paragraphs (a)(3) and (e)(2) through (4) are
revised, and paragraph (e)(6) is added to read as follows:

Sec. 192.917 How does an operator identify potential threats to
pipeline integrity and use the threat identification in its integrity
program?

(a) * * *
(3) Time independent threats such as third party damage, mechanical
damage, incorrect operational procedure, weather related and outside
force damage to include consideration of seismicity, geology, and soil
stability of the area; and
* * * * *
(e) * * *
(2) Cyclic fatigue. An operator must analyze and account for
whether cyclic fatigue or other loading conditions (including ground
movement, and suspension bridge condition) could lead to a failure of a
deformation, including a dent or gouge, crack, or other defect in the
covered segment. The analysis must assume the presence of threats in
the covered segment that could be exacerbated by cyclic fatigue. An
operator must use the results from the analysis together with the
criteria used to determine the significance of the threat(s) to the
covered segment to prioritize the integrity baseline assessment or
reassessment. Failure stress pressure and crack growth analysis of
cracks and crack-like defects must be conducted in accordance with
Sec. 192.712. An operator must monitor operating pressure cycles and
periodically, but at least every 7 calendar years, with intervals not
to exceed 90 months, determine if the cyclic fatigue analysis remains
valid or if the cyclic fatigue analysis must be revised based on
changes to operating pressure cycles or other loading conditions.
(3) Manufacturing and construction defects. An operator must
analyze the covered segment to determine and account for the risk of
failure from manufacturing and construction defects (including seam
defects) in the covered segment. The analysis must account for the
results of prior assessments on the covered segment. An operator may
consider manufacturing and construction related defects to be stable
defects only if the covered segment has been subjected to hydrostatic
pressure testing satisfying the criteria of subpart J of at least 1.25
times MAOP, and the covered segment has not experienced a reportable
incident attributed to a manufacturing or construction defect since the
date of the most recent subpart J pressure test. If any of the
following changes occur in the covered segment, an operator must
prioritize the covered segment as a high-risk segment for the baseline
assessment or a subsequent reassessment.
(i) The pipeline segment has experienced a reportable incident, as
defined in Sec. 191.3, since its most recent successful subpart J
pressure test, due to an original manufacturing-related defect, or a
construction-, installation-, or fabrication-related defect;
(ii) MAOP increases; or
(iii) The stresses leading to cyclic fatigue increase.
(4) Electric Resistance Welded (ERW) pipe. If a covered pipeline
segment contains low frequency ERW pipe, lap welded pipe, pipe with
longitudinal joint factor less than 1.0 as defined in Sec. 192.113, or
other pipe that satisfies the conditions specified in ASME/ANSI B31.8S,
Appendices A4.3 and A4.4, and any covered or non-covered segment in the
pipeline system with such pipe has experienced seam failure (including
seam cracking and selective seam weld corrosion), or operating pressure
on the covered segment has increased over the maximum operating
pressure experienced during the preceding 5 years (including abnormal
operation as defined in Sec. 192.605(c)), or MAOP has been increased,
an operator must select an assessment technology or technologies with a
proven application capable of assessing seam integrity and seam
corrosion anomalies. The operator must prioritize the covered segment
as a high-risk segment for the baseline assessment or a subsequent
reassessment. Pipe with seam cracks must be evaluated using fracture
mechanics modeling for failure stress pressures and cyclic fatigue
crack growth analysis to estimate the remaining life of the pipe in
accordance with Sec. 192.712.
* * * * *
(6) Cracks. If an operator identifies any crack or crack-like
defect (e.g., stress corrosion cracking or other environmentally
assisted cracking, seam defects, selective seam weld corrosion, girth
weld cracks, hook cracks, and fatigue cracks) on a covered pipeline
segment that could adversely affect the integrity of the pipeline, the
operator must evaluate, and remediate, as necessary, all pipeline
segments (both covered and non-covered) with similar characteristics
associated with the crack or crack-like defect. Similar characteristics
may include operating and maintenance histories, material properties,
and environmental characteristics. An operator must establish a
schedule for evaluating, and remediating, as necessary, the similar
pipeline segments that is consistent with the operator's established
operating and maintenance procedures under this part for testing and
repair.

0
30. In Sec. 192.921, revise paragraph (a) and add paragraph (i) to
read as follows:

Sec. 192.921 How is the baseline assessment to be conducted?

(a) Assessment methods. An operator must assess the integrity of
the line pipe in each covered segment by applying one or more of the
following methods for each threat to which the covered segment is
susceptible. An operator must select the method or methods best suited
to address the threats identified to the covered segment (See Sec.
192.917).
(1) Internal inspection tool or tools capable of detecting those
threats to which the pipeline is susceptible. The use of internal
inspection tools is appropriate for threats such as corrosion,
deformation and mechanical damage (including dents, gouges and
grooves), material cracking and crack-like defects (e.g., stress
corrosion cracking, selective seam weld corrosion, environmentally
assisted cracking, and girth weld cracks), hard spots with cracking,
and any other threats to which the covered segment is susceptible. When
performing an assessment using an in-line inspection tool, an operator
must comply with Sec. 192.493. In addition, an operator must analyze
and account for uncertainties in reported results (e.g., tool
tolerance, detection threshold, probability of detection, probability
of identification, sizing accuracy, conservative anomaly interaction
criteria, location accuracy, anomaly findings, and unity chart plots or
equivalent for determining uncertainties and verifying actual tool

[[Page 52254]]

performance) in identifying and characterizing anomalies;
(2) Pressure test conducted in accordance with subpart J of this
part. The use of subpart J pressure testing is appropriate for threats
such as internal corrosion; external corrosion and other
environmentally assisted corrosion mechanisms; manufacturing and
related defects threats, including defective pipe and pipe seams;
stress corrosion cracking; selective seam weld corrosion; dents; and
other forms of mechanical damage. An operator must use the test
pressures specified in Table 3 of section 5 of ASME/ANSI B31.8S
(incorporated by reference, see Sec. 192.7) to justify an extended
reassessment interval in accordance with Sec. 192.939.
(3) Spike hydrostatic pressure test conducted in accordance with
Sec. 192.506. The use of spike hydrostatic pressure testing is
appropriate for time-dependent threats such as stress corrosion
cracking; selective seam weld corrosion; manufacturing and related
defects, including defective pipe and pipe seams; and other forms of
defect or damage involving cracks or crack-like defects;
(4) Excavation and in situ direct examination by means of visual
examination, direct measurement, and recorded non-destructive
examination results and data needed to assess all threats. Based upon
the threat assessed, examples of appropriate non-destructive
examination methods include ultrasonic testing (UT), phased array
ultrasonic testing (PAUT), inverse wave field extrapolation (IWEX),
radiography, and magnetic particle inspection (MPI);
(5) Guided wave ultrasonic testing (GWUT) as described in Appendix
F. The use of GWUT is appropriate for internal and external pipe wall
loss;
(6) Direct assessment to address threats of external corrosion,
internal corrosion, and stress corrosion cracking. The use of direct
assessment to address threats of external corrosion, internal
corrosion, and stress corrosion cracking is allowed only if appropriate
for the threat and the pipeline segment being assessed. Use of direct
assessment for threats other than the threat for which the direct
assessment method is suitable is not allowed. An operator must conduct
the direct assessment in accordance with the requirements listed in
Sec. 192.923 and with the applicable requirements specified in
Sec. Sec. 192.925, 192.927 and 192.929; or
(7) Other technology that an operator demonstrates can provide an
equivalent understanding of the condition of the line pipe for each of
the threats to which the pipeline is susceptible. An operator must
notify PHMSA in advance of using the other technology in accordance
with Sec. 192.18.
* * * * *
(i) Baseline assessments for pipeline segments with a reconfirmed
MAOP. An integrity assessment conducted in accordance with the
requirements of Sec. 192.624(c) may be used as a baseline assessment
under this section.

0
31. In Sec. 192.933, paragraphs (a)(1) and (2) are revised to read as
follows:

Sec. 192.933 What actions must be taken to address integrity issues?

(a) * * *
(1) Temporary pressure reduction. If an operator is unable to
respond within the time limits for certain conditions specified in this
section, the operator must temporarily reduce the operating pressure of
the pipeline or take other action that ensures the safety of the
covered segment. An operator must determine any temporary reduction in
operating pressure required by this section using ASME/ANSI B31G
(incorporated by reference, see Sec. 192.7); R-STRENG (incorporated by
reference, see Sec. 192.7); or by reducing the operating pressure to a
level not exceeding 80 percent of the level at the time the condition
was discovered. An operator must notify PHMSA in accordance with Sec.
192.18 if it cannot meet the schedule for evaluation and remediation
required under paragraph (c) of this section and cannot provide safety
through a temporary reduction in operating pressure or through another
action.
(2) Long-term pressure reduction. When a pressure reduction exceeds
365 days, an operator must notify PHMSA under Sec. 192.18 and explain
the reasons for the remediation delay. This notice must include a
technical justification that the continued pressure reduction will not
jeopardize the integrity of the pipeline.
* * * * *

0
32. In Sec. 192.935, paragraph (b)(2) is revised to read as follows:

Sec. 192.935 What additional preventive and mitigative measures must
an operator take?

* * * * *
(b) * * *
(2) Outside force damage. If an operator determines that outside
force (e.g., earth movement, loading, longitudinal, or lateral forces,
seismicity of the area, floods, unstable suspension bridge) is a threat
to the integrity of a covered segment, the operator must take measures
to minimize the consequences to the covered segment from outside force
damage. These measures include increasing the frequency of aerial, foot
or other methods of patrols; adding external protection; reducing
external stress; relocating the line; or inline inspections with
geospatial and deformation tools.
* * * * *

0
33. In Sec. 192.937, revise paragraph (c) and add paragraph (d) to
read as follows:

Sec. 192.937 What is a continual process of evaluation and assessment
to maintain a pipeline's integrity?

* * * * *
(c) Assessment methods. In conducting the integrity reassessment,
an operator must assess the integrity of the line pipe in each covered
segment by applying one or more of the following methods for each
threat to which the covered segment is susceptible. An operator must
select the method or methods best suited to address the threats
identified on the covered segment (see Sec. 192.917).
(1) Internal inspection tools. When performing an assessment using
an in-line inspection tool, an operator must comply with the following
requirements:
(i) Perform the in-line inspection in accordance with Sec.
192.493;
(ii) Select a tool or combination of tools capable of detecting the
threats to which the pipeline segment is susceptible such as corrosion,
deformation and mechanical damage (e.g. dents, gouges and grooves),
material cracking and crack-like defects (e.g. stress corrosion
cracking, selective seam weld corrosion, environmentally assisted
cracking, and girth weld cracks), hard spots with cracking, and any
other threats to which the covered segment is susceptible; and
(iii) Analyze and account for uncertainties in reported results
(e.g., tool tolerance, detection threshold, probability of detection,
probability of identification, sizing accuracy, conservative anomaly
interaction criteria, location accuracy, anomaly findings, and unity
chart plots or equivalent for determining uncertainties and verifying
actual tool performance) in identifying and characterizing anomalies.
(2) Pressure test conducted in accordance with subpart J of this
part. The use of pressure testing is appropriate for threats such as:
Internal corrosion; external corrosion and other environmentally
assisted corrosion mechanisms; manufacturing and related defects
threats, including defective pipe and pipe seams; stress corrosion
cracking; selective seam weld corrosion; dents; and other forms of
mechanical damage. An operator must use the test

[[Page 52255]]

pressures specified in table 3 of section 5 of ASME/ANSI B31.8S
(incorporated by reference, see Sec. 192.7) to justify an extended
reassessment interval in accordance with Sec. 192.939.
(3) Spike hydrostatic pressure test in accordance with Sec.
192.506. The use of spike hydrostatic pressure testing is appropriate
for time-dependent threats such as: Stress corrosion cracking;
selective seam weld corrosion; manufacturing and related defects,
including defective pipe and pipe seams; and other forms of defect or
damage involving cracks or crack-like defects;
(4) Excavation and in situ direct examination by means of visual
examination, direct measurement, and recorded non-destructive
examination results and data needed to assess all threats. Based upon
the threat assessed, examples of appropriate non-destructive
examination methods include ultrasonic testing (UT), phased array
ultrasonic testing (PAUT), inverse wave field extrapolation (IWEX),
radiography, or magnetic particle inspection (MPI);
(5) Guided wave ultrasonic testing (GWUT) as described in Appendix
F. The use of GWUT is appropriate for internal and external pipe wall
loss;
(6) Direct assessment to address threats of external corrosion,
internal corrosion, and stress corrosion cracking. The use of direct
assessment to address threats of external corrosion, internal
corrosion, and stress corrosion cracking is allowed only if appropriate
for the threat and pipeline segment being assessed. Use of direct
assessment for threats other than the threat for which the direct
assessment method is suitable is not allowed. An operator must conduct
the direct assessment in accordance with the requirements listed in
Sec. 192.923 and with the applicable requirements specified in
Sec. Sec. 192.925, 192.927, and 192.929;
(7) Other technology that an operator demonstrates can provide an
equivalent understanding of the condition of the line pipe for each of
the threats to which the pipeline is susceptible. An operator must
notify PHMSA in advance of using the other technology in accordance
with Sec. 192.18; or
(8) Confirmatory direct assessment when used on a covered segment
that is scheduled for reassessment at a period longer than 7 calendar
years. An operator using this reassessment method must comply with
Sec. 192.931.
(d) MAOP reconfirmation assessments. An integrity assessment
conducted in accordance with the requirements of Sec. 192.624(c) may
be used as a reassessment under this section.

0
34. In Sec. 192.939, paragraphs (a) introductory text, (b)
introductory text, and (b)(1) are revised to read as follows:

Sec. 192.939 What are the required reassessment intervals?

* * * * *
(a) Pipelines operating at or above 30% SMYS. An operator must
establish a reassessment interval for each covered segment operating at
or above 30% SMYS in accordance with the requirements of this section.
The maximum reassessment interval by an allowable reassessment method
is 7 calendar years. Operators may request a 6-month extension of the
7-calendar-year reassessment interval if the operator submits written
notice to OPS, in accordance with Sec. 192.18, with sufficient
justification of the need for the extension. If an operator establishes
a reassessment interval that is greater than 7 calendar years, the
operator must, within the 7-calendar-year period, conduct a
confirmatory direct assessment on the covered segment, and then conduct
the follow-up reassessment at the interval the operator has
established. A reassessment carried out using confirmatory direct
assessment must be done in accordance with Sec. 192.931. The table
that follows this section sets forth the maximum allowed reassessment
intervals.
* * * * *
(b) Pipelines Operating below 30% SMYS. An operator must establish
a reassessment interval for each covered segment operating below 30%
SMYS in accordance with the requirements of this section. The maximum
reassessment interval by an allowable reassessment method is 7 calendar
years. Operators may request a 6-month extension of the 7-calendar-year
reassessment interval if the operator submits written notice to OPS in
accordance with Sec. 192.18. The notice must include sufficient
justification of the need for the extension. An operator must establish
reassessment by at least one of the following--
(1) Reassessment by pressure test, internal inspection or other
equivalent technology following the requirements in paragraph (a)(1) of
this section except that the stress level referenced in paragraph
(a)(1)(ii) of this section would be adjusted to reflect the lower
operating stress level. If an established interval is more than 7
calendar years, an operator must conduct by the seventh calendar year
of the interval either a confirmatory direct assessment in accordance
with Sec. 192.931, or a low stress reassessment in accordance with
Sec. 192.941.
* * * * *

Sec. 192.949 [Removed and Reserved]

0
35. Remove and reserve Sec. 192.949.

0
36. Appendix F is added to read as follows:

Appendix F to Part 192-Criteria for Conducting Integrity Assessments
Using Guided Wave Ultrasonic Testing (GWUT)

This appendix defines criteria which must be properly implemented
for use of guided wave ultrasonic testing (GWUT) as an integrity
assessment method. Any application of GWUT that does not conform to
these criteria is considered ``other technology'' as described by
Sec. Sec. 192.710(c)(7), 192.921(a)(7), and 192.937(c)(7), for which
OPS must be notified 90 days prior to use in accordance with Sec. Sec.
192.921(a)(7) or 192.937(c)(7). GWUT in the ``Go-No Go'' mode means
that all indications (wall loss anomalies) above the testing threshold
(a maximum of 5% of cross sectional area (CSA) sensitivity) be directly
examined, in-line tool inspected, pressure tested, or replaced prior to
completing the integrity assessment on the carrier pipe.
I. Equipment and Software: Generation. The equipment and the
computer software used are critical to the success of the inspection.
Computer software for the inspection equipment must be reviewed and
updated, as required, on an annual basis, with intervals not to exceed
15 months, to support sensors, enhance functionality, and resolve any
technical or operational issues identified.
II. Inspection Range. The inspection range and sensitivity are set
by the signal to noise (S/N) ratio but must still keep the maximum
threshold sensitivity at 5% cross sectional area (CSA). A signal that
has an amplitude that is at least twice the noise level can be reliably
interpreted. The greater the S/N ratio the easier it is to identify and
interpret signals from small changes. The signal to noise ratio is
dependent on several variables such as surface roughness, coating,
coating condition, associated pipe fittings (T's, elbows, flanges),
soil compaction, and environment. Each of these affects the propagation
of sound waves and influences the range of the test. It may be
necessary to inspect from both ends of the pipeline segment to achieve
a full inspection. In general, the inspection range can approach 60 to
100 feet for a 5% CSA, depending on field conditions.
III. Complete Pipe Inspection. To ensure that the entire pipeline
segment is assessed there should be at least a 2 to 1 signal to noise
ratio across the entire pipeline segment that is

[[Page 52256]]

inspected. This may require multiple GWUT shots. Double-ended
inspections are expected. These two inspections are to be overlaid to
show the minimum 2 to 1 S/N ratio is met in the middle. If possible,
show the same near or midpoint feature from both sides and show an
approximate 5% distance overlap.
IV. Sensitivity. The detection sensitivity threshold determines the
ability to identify a cross sectional change. The maximum threshold
sensitivity cannot be greater than 5% of the cross sectional area
(CSA).
The locations and estimated CSA of all metal loss features in
excess of the detection threshold must be determined and documented.
All defect indications in the ``Go-No Go'' mode above the 5%
testing threshold must be directly examined, in-line inspected,
pressure tested, or replaced prior to completing the integrity
assessment.
V. Wave Frequency. Because a single wave frequency may not detect
certain defects, a minimum of three frequencies must be run for each
inspection to determine the best frequency for characterizing
indications. The frequencies used for the inspections must be
documented and must be in the range specified by the manufacturer of
the equipment.
VI. Signal or Wave Type: Torsional and Longitudinal. Both torsional
and longitudinal waves must be used and use must be documented.
VII. Distance Amplitude Correction (DAC) Curve and Weld
Calibration. The distance amplitude correction curve accounts for
coating, pipe diameter, pipe wall and environmental conditions at the
assessment location. The DAC curve must be set for each inspection as
part of establishing the effective range of a GWUT inspection. DAC
curves provide a means for evaluating the cross-sectional area change
of reflections at various distances in the test range by assessing
signal to noise ratio. A DAC curve is a means of taking apparent
attenuation into account along the time base of a test signal. It is a
line of equal sensitivity along the trace which allows the amplitudes
of signals at different axial distances from the collar to be compared.
VIII. Dead Zone. The dead zone is the area adjacent to the collar
in which the transmitted signal blinds the received signal, making it
impossible to obtain reliable results. Because the entire line must be
inspected, inspection procedures must account for the dead zone by
requiring the movement of the collar for additional inspections. An
alternate method of obtaining valid readings in the dead zone is to use
B-scan ultrasonic equipment and visual examination of the external
surface. The length of the dead zone and the near field for each
inspection must be documented.
IX. Near Field Effects. The near field is the region beyond the
dead zone where the receiving amplifiers are increasing in power,
before the wave is properly established. Because the entire line must
be inspected, inspection procedures must account for the near field by
requiring the movement of the collar for additional inspections. An
alternate method of obtaining valid readings in the near field is to
use B-scan ultrasonic equipment and visual examination of the external
surface. The length of the dead zone and the near field for each
inspection must be documented.
X. Coating Type. Coatings can have the effect of attenuating the
signal. Their thickness and condition are the primary factors that
affect the rate of signal attenuation. Due to their variability,
coatings make it difficult to predict the effective inspection
distance. Several coating types may affect the GWUT results to the
point that they may reduce the expected inspection distance. For
example, concrete coated pipe may be problematic when well bonded due
to the attenuation effects. If an inspection is done and the required
sensitivity is not achieved for the entire length of the pipe, then
another type of assessment method must be utilized.
XI. End Seal. When assessing cased carrier pipe with GWUT,
operators must remove the end seal from the casing at each GWUT test
location to facilitate visual inspection. Operators must remove debris
and water from the casing at the end seals. Any corrosion material
observed must be removed, collected and reviewed by the operator's
corrosion technician. The end seal does not interfere with the accuracy
of the GWUT inspection but may have a dampening effect on the range.
XII. Weld Calibration to set DAC Curve. Accessible welds, along or
outside the pipeline segment to be inspected, must be used to set the
DAC curve. A weld or welds in the access hole (secondary area) may be
used if welds along the pipeline segment are not accessible. In order
to use these welds in the secondary area, sufficient distance must be
allowed to account for the dead zone and near field. There must not be
a weld between the transducer collar and the calibration weld. A
conservative estimate of the predicted amplitude for the weld is 25%
CSA (cross sectional area) and can be used if welds are not accessible.
Calibrations (setting of the DAC curve) should be on pipe with similar
properties such as wall thickness and coating. If the actual weld cap
height is different from the assumed weld cap height, the estimated CSA
may be inaccurate and adjustments to the DAC curve may be required.
Alternative means of calibration can be used if justified by a
documented engineering analysis and evaluation.
XIII. Validation of Operator Training. Pipeline operators must
require all guided wave service providers to have equipment-specific
training and experience for all GWUT Equipment Operators which includes
training for:
A. Equipment operation,
B. field data collection, and
C. data interpretation on cased and buried pipe.
Only individuals who have been qualified by the manufacturer or an
independently assessed evaluation procedure similar to ISO 9712
(Sections: 5 Responsibilities; 6 Levels of Qualification; 7
Eligibility; and 10 Certification), as specified above, may operate the
equipment. A senior-level GWUT equipment operator with pipeline
specific experience must provide onsite oversight of the inspection and
approve the final reports. A senior-level GWUT equipment operator must
have additional training and experience, including training specific to
cased and buried pipe, with a quality control program which that
conforms to Section 12 of ASME B31.8S (for availability, see Sec.
192.7).
XIV. Training and Experience Minimums for Senior Level GWUT
Equipment Operators:
Equipment Manufacturer's minimum qualification for
equipment operation and data collection with specific endorsements for
casings and buried pipe
Training, qualification and experience in testing
procedures and frequency determination
Training, qualification and experience in conversion of
guided wave data into pipe features and estimated metal loss (estimated
cross-sectional area loss and circumferential extent)
Equipment Manufacturer's minimum qualification with
specific endorsements for data interpretation of anomaly features for
pipe within casings and buried pipe.
XV. Equipment: Traceable from vendor to inspection company. An
operator must maintain documentation of the version of the GWUT
software used and the serial number of the other

[[Page 52257]]

equipment such as collars, cables, etc., in the report.
XVI. Calibration Onsite. The GWUT equipment must be calibrated for
performance in accordance with the manufacturer's requirements and
specifications, including the frequency of calibrations. A diagnostic
check and system check must be performed on-site each time the
equipment is relocated to a different casing or pipeline segment. If
on-site diagnostics show a discrepancy with the manufacturer's
requirements and specifications, testing must cease until the equipment
can be restored to manufacturer's specifications.
XVII. Use on Shorted Casings (direct or electrolytic). GWUT may not
be used to assess shorted casings. GWUT operators must have operations
and maintenance procedures (see Sec. 192.605) to address the effect of
shorted casings on the GWUT signal. The equipment operator must clear
any evidence of interference, other than some slight dampening of the
GWUT signal from the shorted casing, according to their operating and
maintenance procedures. All shorted casings found while conducting GWUT
inspections must be addressed by the operator's standard operating
procedures.
XVIII. Direct examination of all indications above the detection
sensitivity threshold. The use of GWUT in the ``Go-No Go'' mode
requires that all indications (wall loss anomalies) above the testing
threshold (5% of CSA sensitivity) be directly examined (or replaced)
prior to completing the integrity assessment on the cased carrier pipe
or other GWUT application. If this cannot be accomplished, then
alternative methods of assessment (such as hydrostatic pressure tests
or ILI) must be utilized.
XIV. Timing of direct examination of all indications above the
detection sensitivity threshold. Operators must either replace or
conduct direct examinations of all indications identified above the
detection sensitivity threshold according to the table below. Operators
must conduct leak surveys and reduce operating pressure as specified
until the pipe is replaced or direct examinations are completed.

Required Response to GWUT Indications
----------------------------------------------------------------------------------------------------------------
Operating pressure Operating pressure over 30
GWUT criterion less than or equal to and less than or equal to Operating pressure over
30% SMYS 50% SMYS 50% SMYS
----------------------------------------------------------------------------------------------------------------
Over the detection sensitivity Replace or direct Replace or direct Replace or direct
threshold (maximum of 5% CSA). examination within examination within 6 examination within 6
12 months, and months, instrumented leak months, instrumented
instrumented leak survey once every 30 leak survey once every
survey once every 30 calendar days, and 30 calendar days, and
calendar days. maintain MAOP below the reduce MAOP to 80% of
operating pressure at operating pressure at
time of discovery. time of discovery.
----------------------------------------------------------------------------------------------------------------

Issued in Washington, DC, on September 16, 2019, under authority
delegated in 49 CFR part 1.97.
Howard R. Elliott,
Administrator.
[FR Doc. 2019-20306 Filed 9-30-19; 8:45 am]
BILLING CODE 4910-60-P

This site is protected by reCAPTCHA and the Google Privacy Policy and Terms of Service apply.