{"operation":"document","citation":"PHMSA Gas Transmission Final Rule FAQs, Batch 2 (2023)","title":"Gas Transmission Final Rule FAQs, Batch 2","source_type":"guidance","agency":"Pipeline and Hazardous Materials Safety Administration","status":"guidance","official":true,"published_on":"2023-04-19","effective_on":"2023-04-19","summary":"Title: Second Batch of Frequently Asked Questions (FAQs) for the Final Rule titled “Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments,” Published October 1, 2019 Date: Wednesday, April 19, 2023 Summary: The Pipeline and Hazardous Materials Safety Administration (PHMSA) is issuing supplementary regulatory guidance documents in","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-gas-transmission-final-rule-faqs-batch-2.json","markdown":"https://regulus.evalyn.ai/document/phmsa-gas-transmission-final-rule-faqs-batch-2.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-gas-transmission-final-rule-faqs-batch-2","source_url":"https://www.phmsa.dot.gov/regulatory-compliance/phmsa-guidance/frequently-asked-questions-faqs-gas-transmission-final-rule","body":"<<<PAGE 1>>>\n\nTitle: Second Batch of Frequently Asked Questions (FAQs) for the Final Rule titled\n“Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion\nof Assessment Requirements, and Other Related Amendments,” Published October 1, 2019\nDate: Wednesday, April 19, 2023\nSummary:\nThe Pipeline and Hazardous Materials Safety Administration (PHMSA) is issuing supplementary\nregulatory guidance documents in the form of additional frequently asked questions (FAQs).\nThe first set of FAQs related to this rule were posted to the docket on September 16, 2020. This\nsecond batch of FAQs (Batch-2 FAQs) is intended to further help owners and operators of gas\npipelines comply with revisions to the pipeline safety standards in 49 CFR Part 192. These\nstandards were amended on October 1, 2019, by the final rule entitled “Pipeline Safety: Safety of\nGas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements,\nand Other Related Amendments” (84 FR 52180) (Final Rule). Using a similar review process as\nthe first batch of FAQs (Batch-1 FAQs), the draft Batch-2 FAQs were posted to a PHMSA\ndocket for public comment on December 21, 2020. PHMSA considered the comments received\nby March 16, 2021 along with the results of recent “pilot” inspections of pipeline operators to\nfinalize the Batch-2 FAQs. Both Batch-1 and Batch-2 FAQs are published on the PHMSA\nwebsite at https://www.phmsa.dot.gov/guidance. These draft Batch-2 FAQs are intended to\nsupplement the Batch-1 FAQs and are not intended to replace or revise any previously issued\nguidance.\nPHMSA provides FAQs to help the public understand how to comply with the existing\nrequirements under the regulations. FAQs are not substantive rules, are not meant to bind the\npublic in any way, and do not assign duties, create legally enforceable rights, or impose new\nobligations not otherwise contained in the existing regulations. However, an operator who can\ndemonstrate compliance with the FAQs is likely to be able to demonstrate compliance with the\nrelevant regulations.\nGeneral FAQs\nFAQ-45. Do the changes made to § 191.23 Reporting safety-related conditions impact the\nconditions under which operators must file Safety-Related Condition Reports (SRCRs)?\nNo. Revisions made to § 191.23(a)(6) clarify which events should be considered safety-related\nconditions by operators of distribution or gathering lines, underground natural gas storage\nfacilities, or LNG facilities that contain or process gas or LNG. The Final Rule did not change\nthe types of events described. Section 191.23(a)(10) was added to clarify which Maximum\nAllowable Operating Pressure (MAOP) exceedance reporting events are safety-related\nconditions for transmission pipelines. PHMSA revised § 191.23 to incorporate the statutory\nrequirement, mandated in Section 23 of the 2011 Pipeline Safety Act, into its regulations.\n1\n\n<<<PAGE 2>>>\n\nOperators are reminded that § 191.7(c) requires that they concurrently report safety-related\nconditions, including MAOP exceedances, to the appropriate State agency for intrastate pipeline\ntransportation or when the State agency acts as an agent of the Secretary with respect to interstate\ntransmission facilities.\nFAQ-46. Is the addition of a “covered task” considered a significant modification of an\noperator’s Operator Qualification (OQ) program requiring notification pursuant to §\n192.18?\nIt depends. Section 192.805(i) applies to notification by the operator of significant changes to\ntheir OQ program. Operators who add new covered task(s) or alter existing covered tasks may be\nsignificantly modifying their OQ programs and, if so, must notify PHMSA of these changes, per\n§ 192.805(i) and in accordance with § 192.18. Operators should define in their OQ program\ncriteria for evaluating whether new or modified “covered tasks” are considered to be a significant\nmodification of their OQ plans which in turn would warrant notification to PHMSA per §\n192.18.\nPHMSA expects operators to add more “covered tasks,” or modify existing “covered tasks” to\ntake advantage of the permitted methods to safely implement the new requirements of the Final\nRule. For example, an operator may determine that its OQ program needs to incorporate new\n“covered tasks” in the form of activities (e.g., use of new assessment technologies, testing and\nverifying material properties, and determining the predicted failure pressure of anomalies)\nneeded to comply with the amended regulations. Insofar as the identification of covered tasks is a\nkey component of any OQ program, the addition of an entirely new “covered task” may be a\nsignificant modification of that program requiring notice pursuant to § 192.18.\nFurthermore, an operator’s efforts to comply with new regulations may require modification of\nan existing “covered task” within its OQ program to revise or elaborate on sub-processes (e.g.,\nsupporting activities such as excavation, coating removal, recoating, backfilling, removing\nprevious repairs, removing casings to determine the properties of the carrier pipe, etc.) integral to\nthat existing “covered task.”\nFAQ-47. What does PHMSA mean when using the term “piggable segment” in the\npreamble to the rule?\nPHMSA discusses what it considers to be “unpiggable” and “piggable” in the Preamble to the\nFinal Rule (see excerpt below). A pipeline segment constructed after April 1994 was required to\nbe designed to accommodate an ILI tool (and therefore would be considered piggable) per\n§ 192.150. A pre-1994 pipeline is considered unpiggable if it requires major physical\nmodification to accommodate an instrumented ILI tool or if operational limits—including\noperating pressure, low flow, pipeline length, or availability of in-line inspection (ILI) tool\ntechnology for the pipe diameter—prevent the tool from safely or accurately performing the\nassessment. If a segment is not able to accommodate any commercially-available tool for a\nparticular threat to which the segment is susceptible, the segment must still be inspected per §\n192.710 for the threats for which the segment can accommodate an appropriate in-line inspection\ntool or use other assessment methods.\n2\n\n<<<PAGE 3>>>\n\nOn rare occasions, there may be segments that cannot be inspected with an ILI because the line\ncannot be taken out of service without jeopardizing critical service, as would be the case with\npower plants; however, those pipelines are still considered piggable and must still be assessed\nusing one of the other methods allowed under § 192.710.\nThe Preamble to the Final Rule states the following:\nPHMSA believes that the term “piggable segment” is very widely understood in the industry and\nis not including additional definitions or regulatory language to expand upon this term. PHMSA\nunderstands that a pipeline segment might be incapable of accommodating an in-line inspection\ntool for a number of reasons, including but not limited to short radius pipe bends or fittings,\nvalves (reduced port) that would not allow a tool to pass, telescoping line diameters, and a lack\nof isolation valves for launchers and receivers. Some unpiggable pipelines can be made piggable\nwith modest modifications, but others cannot be made piggable short of pipe replacement.\nPHMSA understands that a pipeline segment is piggable if it can accommodate an instrumented\nILI tool without the need for major physical or operational modification, other than the normal\noperational work required by the process of performing the inline inspection. This normal\noperational work includes segment pigging for internal cleaning, operational pressure and flow\nadjustments to achieve proper tool velocity, system setup such as valve positioning, installation\nof temporary launchers and receivers, and usage of proper launcher and receiver length and\nsetup for ILI tools.\nIn addition, a pipeline segment that is not piggable for a particular threat because of limitations\nin technology such that an ILI tool is not commercially available, might be piggable for other\nthreats. For example, a pipeline that is unable to accommodate a crack tool might be able to\naccommodate a conventional MFL or deformation tool, and thus be piggable for those threats.\nLauncher and receiver lengths are not a reason for a pipeline to be considered unpiggable, since\nthrough a minor modification they can be modified to be piggable, and the removal of launchers\nor receivers from the pipeline segment does not make a pipeline unpiggable either. 84 FR 52180,\n52215 (October 1, 2019).\nFAQ-48. When establishing the MAOP of Type A, Type B, and certain Type C gathering\npipelines, does the operator need to comply with §§ 192.619?\nYes. Operators of Type A, Type B, and certain Type C gathering lines must comply with the\nrequirements of § 192.619 in accordance with § 192.9. Type A gathering lines are subject to all\nrequirements of § 192.619 except for § 192.619(e). For Type B gathering lines, § 192.619(a), §\n192.619(b), and § 192.619(c) apply. Type C gathering lines with outside diameter greater than\n12.75 inches are subject to § 192.619(a) or § 192.619(c), and the remaining Type C gathering\nlines are not necessarily required to establish MAOP pursuant to § 192.619.\n3\n\n<<<PAGE 4>>>\n\nFAQ-49. Do any of the new rules apply to distribution lines?\nYes. While the new rules focus primarily on the safety of onshore gas transmission lines, a few\nnew requirements apply to distribution lines as well. Distribution line operators should review\nthe following code sections, which were revised in the rulemaking to determine if these sections\napply to their distribution pipeline systems: §§ 191.23; 191.25; 192.3; 192.5; 192.7; 192.18;\n192.517; 192.619; 192.750; and 192.805.\nFAQ-50. Is material verification required for mainline pipeline components other than line\npipe?\nYes, but only for some mainline pipeline components. Pursuant to § 192.607(f)(2), material\nverification for components other than line pipe is required if they are larger than 2 inches in\nnominal outside diameter or have material yield strength grades of 42,000 psi or greater. Section\n192.607(f) also requires that any appurtenance regardless of size that is directly installed on the\npipeline and cannot be isolated from the mainline pipeline pressure must have its material\nverified. Note that § 192.607(a) provides that the material verification requirement only applies\nwhere required by another section of part 192 (e.g., §§ 192.619(a)(4), 192.624(c), 192.632(a), or\n192.712) and does not apply inboard of station emergency shutdown or isolation valves (see\nFAQ-37).\nSection 192.205 outlines the material verification record keeping requirements for pipeline\ncomponents. For pipeline components installed on or before July 1, 2020, if operators have\nrecords documenting the manufacturing standard and pressure rating for components that are\nlarger than 2 inches in nominal outside diameter having material yield strength grades of 42,000\npsi or greater, these records must be retained per § 192.205(a). Section 192.205(b) also requires\noperators to collect or make, and retain for the operational life of the component, records\ndocumenting the manufacturing standard and pressure rating for any such components installed\nafter July 1, 2020.\nFAQ-51. Is the operator required to follow § 192.712 when evaluating an anomaly on a\nsteel transmission pipeline with a legacy MAOP (i.e., established according to § 192.619(c))\nif the operator does not have material properties records and the pipeline is operating at\nless than 30% SMYS?\nIt depends. Section 192.712 only applies when required by other provisions of part 192. Because\nlegacy pipelines operating under 30% of SMYS are not subject to MAOP reconfirmation\nrequirements (see § 192.624(a)(2) and FAQ-64), the following situations could invoke § 192.712\nfor this scenario:\n4\n\n<<<PAGE 5>>>\n\n• Calculating remaining wall thickness for each segment of transmission line with general\ncorrosion and with a remaining wall thickness less than that required for the MAOP as\nrequired by § 192.485(c) (Effective May 24, 2023);\n• Remediating conditions discovered during assessments conducted under § 192.710 that\ncould adversely affect the safe operation of a pipeline, as required by § 192.710(f);\n• Evaluating cracking on an HCA segment susceptible to the cyclic fatigue threat as\nrequired by § 192.917(e)(2); and\n• Evaluating seam cracking on an HCA segment that has pipe meeting the requirements of\n§ 192.917(e)(4).\nFAQ-52. While documenting or verifying material properties and attributes under\n§192.607, if an operator determines that the material properties of the pipeline segment are\ninconsistent with the methods used to establish the current MAOP, would that operator be\nrequired to revise the MAOP and report it to PHMSA under §§ 191.23 and 191.25?\nIt depends. If the MAOP was established using § 192.619(a), the operator would need to apply §\n192.619(a)(1 - 4) to see if an MAOP revision is required. If the current MAOP was established\nusing § 192.619(c) and lower strength materials were found and confirmed to be inconsistent\nwith the method used to establish that MAOP, the operator would then need to apply §§ 192.607,\n192.624 (if applicable), and 192.703 for the pipeline segment.\nRegardless of how the MAOP is reconfirmed or revised, the operator must also re-evaluate\npreviously assessed anomalies using the newly confirmed material properties. Per §§\n192.619(a)(4), 192.710(g) and 192.712, the operator must determine if the defect’s predicted\nfailure pressure times the appropriate safety factor is still commensurate with the MAOP.\nAfter re-evaluating the MAOP, if necessary, the operator would need to determine whether the\nreconfirmed MAOP (regardless of location) would trigger a reportable event per §§\n191.23(a)(10) and 191.25(b) as a result of identifying lower material strength than expected,\nunless the safety-related condition report is not required per § 191.23(b). The operator may\ncontact its PHMSA regional office or State program to discuss a proper course of action.\nFAQ-53. If the record retention requirement for welder qualification for steel transmission\npipe installed after July 1, 2021 is a minimum of 5 years following construction under §\n192.227(c), can an operator use a welder qualification that predates July 1, 2021 to meet the\nrecord retention requirement?\nYes. For pipelines installed after July 1, 2021, operators are required by § 192.227 to retain\nwelder qualification records for welders who performed or are in the process of performing\nwelds on a regulated pipeline pursuant to a qualified welding procedure. The operator can use a\nwelder qualification record created before July 1, 2021, to demonstrate qualification after that\n5\n\n<<<PAGE 6>>>\n\ndate. If the basis of a welder’s qualification is a requalification to a welding procedure for which\nthe welder has been continuously qualified (see §§ 192.229(c) and 192.229(d)), the operator\nmust retain appropriate records demonstrating the individual welder’s qualification in accordance\nwith § 192.227. At a minimum, these records would include the operator’s qualification form\nand all weld test reports (destructive and nondestructive) to demonstrate continuity of\nqualification for that welder.\nPer § 192.227, records required to demonstrate welder qualification are described in Section 6 of\nAPI Standard 1104 (incorporated by reference, see § 192.7), or Section IX of the ASME Boiler\nand Pressure Vessel Code (ASME BPVC) (incorporated by reference, see § 192.7).\nModerate Consequence Area FAQs\nFAQ-54. In lieu of performing an MCA study, can an operator designate all non-HCA\nClass 1 and 2 locations as MCAs?\nYes. Operators may choose to designate all Class 1, 2, 3, and 4 locations outside high\nconsequence areas (HCAs) as moderate consequence areas (MCAs) for determining the\napplicability of § 192.624(a), but if they do, per § 192.624(a)(2)(iii) they must reconfirm MAOP\nunder § 192.624 for any piggable pipeline segments in locations designated as MCAs where the\nsegment’s MAOP was established in accordance with § 192.619(c), and per § 192.710 they must\nalso conduct integrity assessments in locations designated as MCAs. The operators must update\ntheir procedures and records to reflect the designation accordingly per § 192.624(b).\nFAQ-55. Which is the appropriate designation for a pipeline segment identified as being\nlocated in an HCA per § 192.903 as well as in an MCA per § 192.3?\nA pipeline cannot meet the definition of both an HCA and an MCA, since an MCA is an area\n“that does not meet the definition of high consequence area, as defined in §192.903” (per §\n192.3). An operator may elect to categorize MCAs or other non-HCA locations as HCAs and\nupdate its procedures and records accordingly.\nSpike Hydrostatic Testing FAQs\nFAQ-56. When is a spike test required? What code sections require a spike test?\nSpike hydrostatic pressure testing described in § 192.506 may be applied based on multiple part\n192 sections to properly assess threats applicable to the pipeline. There are multiple acceptable\nassessment methods for any specific threat, as described in those code sections. (See §§\n192.710(c)(3), 192.921(a)(3) and 192.937(c)(3).)\n6\n\n<<<PAGE 7>>>\n\nMaterial Verification FAQs\nFAQ-57. If an operator conducts an anomaly direct examination on a steel transmission\npipeline and no pipe is required to be removed from service, must the operator perform a\ncutout for material properties testing under § 192.607(c)?\nNo. In this case, the operator is not required to perform a cutout for material property testing\nunless required by the operator’s procedures. Section 192.607(c) requires operators to develop\nand implement procedures for conducting nondestructive or destructive tests, examinations, and\nassessments during each listed activity. Per § 192.607, and clarified in FAQ-24, operators must\naddress each activity listed in § 192.607(c) in their procedures for safely conducting\nnondestructive or destructive tests, examinations, and assessments to verify the material\nproperties. Operators must ensure that in situ nondestructive testing equipment is calibrated with\na known strength of material and in accordance with the manufacturer’s recommendations prior\nto performing the test per § 192.607(d)(3).\nPer § 192.712(e), operators must use pipe and material properties documented in traceable,\nverifiable, and complete (TVC) records in their analysis of predicted failure pressure and\nremaining life of anomalies. If documentation required for the analyses is not available, the\noperator must obtain the undocumented data through § 192.607. Until documented material\nproperties are available, operators must use the conservative values included in § 192.712(e)(2).\nFAQ-58. A) How many sample locations are required to verify material properties and\nattributes per § 192.607(e) if an operator has a 10-mile long pipeline segment with similar\nbut unknown material attributes, and two miles – either continuous or in discrete sections -\nof the segment contain HCAs or Class 3 or 4 locations?\nA minimum of two sampling locations are required for this scenario because § 192.607(e)(2)\nrequires one excavation per mile (rounded up to the nearest whole number) for each population\nof similar pipe segments defined according to § 192.607(e)(1). However, per § 192.607(e)(1), the\noperator would still need to provide evidence that the pipe material properties and attributes were\nsimilar in each of the HCA, Class 3, and Class 4 areas (i.e., they were of the same population\ngroup and same pipe vintage as defined in § 192.607(e)). The HCAs, Class 3, or Class 4 pipe\npopulations within this two-mile segment need not be contiguous.\nPHMSA expects operators to opportunistically perform sampling to obtain representative\nsamples of the pipe population group at excavations that expose the pipe as required by §\n192.607(e)(2). The “one excavation per mile” requirement of §192.607(e)(2) applies to the\nquantity and spacing of samples along the pipeline. Per § 192.607(e), samples must be taken at\nexcavations within a similar population of material properties and attributes until the required\nsample quantity prescribed by regulation to verify material properties and attributes of that\npopulation group is reached. PHMSA will not consider attribute sampling from the same joint of\npipe to be representative of the entire pipe population group. Sampling must also occur within\neach cumulative 1-mile segment of the pipeline with a similar population of material properties\n7\n\n<<<PAGE 8>>>\n\nand attributes as required by §192.607(e)(2). If the length of the applicable segments is greater\nthan one mile but less than two miles, such as 1.2 miles, the required number of excavations\nwould still be two because the regulation requires rounding up to the nearest whole number (per\n§192.607(e)(2)(i)) to determine the minimum number of excavations.\nB) May samples from non-HCA or Class 1 or 2 locations be used in assessing the material\nproperties of HCA or Class 3 or Class 4 locations?\nFor the purposes of material property verification for an HCA, MCA, Class 3, or Class 4 pipeline\nsegment (covered segment), operators may rely on material sampling from a pipeline segment\nnot requiring material property verification. However, to utilize this option, per § 192.607(e),\noperators must prove that materials from a “non-covered” segment are from the same population\ngroup as the covered segment. To demonstrate that the segments are from the same population\ngroup, per § 192.607(e), operators must have records showing that the non-covered segment has\nsimilar material attributes (e.g., collected from previous excavations or ILI surveys) as the\ncovered segment. The pipe attribute samples from the non-covered pipeline segments should be\ntaken as close as logistically practicable to the pipe segments needing MAOP reconfirmation.\nFAQ-59. What is the sampling frequency for components requiring verification of\nmaterial properties described under § 192.607(f)?\nSection 192.607(f) does not specify a sampling frequency for components. However, operators\nare required by § 192.607(c) and (f), to verify material properties opportunistically. The\npreferred way to meet this requirement would be by sampling components at the same frequency\nas line pipe per § 192.607(e).\nAs outlined in § 192.607(f), operators must verify material properties of components per §\n192.607(c). To do so, operators must establish and document the ANSI rating or pressure rating\n(per ASME/ANSI B16.5 (incorporated by reference, see § 192.7)). However, operators are not\nrequired to verify pressure ratings or otherwise test for the chemical and mechanical properties of\ncomponents in compressor stations, meter stations, regulator stations, separators, river crossing\nheaders, mainline valve assemblies, valve operator piping, or cross-connections with isolation\nvalves from the mainline pipeline. Consistent with FAQ-37, compressor, meter, and pressure-\nlimiting station emergency shutdown and isolation valves are subject to MAOP reconfirmation\nand material verification requirements. Operators may also exercise the alternative sampling\nprogram allowance described in § 192.607(e)(5) to verify the material properties of components.\n8\n\n<<<PAGE 9>>>\n\nFAQ-60. If an operator of a pipeline segment does not have documented traceable,\nverifiable, and complete (TVC) material properties records for yield strength, and used\n24,000 psig (pursuant to §§ 192.619(a) and 192.107(b)(2)) to determine its MAOP, must the\noperator still perform material properties testing for yield strength in accordance with §\n192.607(f)?\nNo. PHMSA considers pipeline segments that have an established and documented MAOP\nusing 24,000 psig for the yield strength (per § 192.107(b)(2)) to have a TVC material property\nrecord for yield strength. This approach of using a 24,000 psig yield strength will result in a\nconservative value for MAOP determination.\nIf that same pipeline segment requires MAOP reconfirmation and a pressure test is to be\nperformed, PHMSA would not expect the operator to perform material properties testing for\nyield strength at the pressure test manifold sites when 24,000 psig yield strength values are being\nused for MAOP determination. For that segment, the yield strength record is considered to be\nTVC based on the conservative assumption that the operator applied in establishing the MAOP.\nAn operator is encouraged, but not required, to test for yield strength, pipe wall thickness, and\nseam type at these locations per § 192.607 requirements. Additionally, if the same pipeline\nsegment has an anomaly that requires evaluation per § 192.712 requirements, the operator must\nuse the conservative assumptions described in § 192.712(e)(2) for determining predicted failure\npressure and remaining life.\nFAQ-61. If an operator does not have records of the tests, inspections, and attributes\nrequired by the manufacturing specifications for chemical composition for a steel\ntransmission pipeline segment installed on or before July 1, 2020, must an operator\nperform testing to determine the chemical composition per §§ 192.67 and 192.205?\nNo. Per §§ 192.67 and 192.205, operators must make and retain chemical composition records\nfor pipelines installed after July 1, 2020, and retain chemical composition records, if the operator\nalready has them, for pipelines installed on or before July 1, 2020.\nFurthermore, an operator is required to verify the material properties, per § 192.607, for those\nmaterial properties needed to comply with the requirements of Part 192 where such records are\nnot TVC.\nChemical composition records are not required to establish the MAOP of a pipeline, but pursuant\nto § 192.225, information regarding chemical composition may be needed to qualify a welding\nprocedure.\n9\n\n<<<PAGE 10>>>\n\nMaximum Allowable Operating Pressure Establishment and Reconfirmation FAQs\nFAQ-62. Does an operator need to collect ultimate tensile strength records under either §§\n192.607 or 192.712 when the operator already has TVC records demonstrating the grade or\nminimum yield strength of the pipeline segment?\nIf the operator already has TVC records demonstrating the grade of the pipe per §§ 192.607(b)\nand (c), 192.67 or 192.205, an operator does not need to collect ultimate tensile strength records\nof materials for determining or reconfirming the MAOP. If an operator does not have TVC\nrecords demonstrating the grade, the operator must conduct future testing for both minimum\nyield strength and ultimate tensile strength per § 192.607(c)(1) and (2).\nAn operator may, however, need ultimate tensile strength values to accurately predict a failure\npressure for some types of anomalies depending on the analysis method used. The analyses\nperformed per § 192.712 must use pipe and material properties that are documented in TVC\nrecords. If documented data required for any analysis is not available, an operator must follow §\n192.607 to obtain the undocumented data and use conservative values as prescribed in §\n192.712(e)(2) until documented material properties are available. In the case of ultimate tensile\nstrength, an operator must follow § 192.712(e)(2)(iii) which could include an assumed yield\nstrength (see §§ 192.107(b)(2), 192.607 (g) and 192.712(e)) for the pipe grade and using API 5L\nto determine the ultimate tensile strength for the pipe grade.\nFAQ-63. Does an operator need more than one record of a material property or attribute\nto demonstrate the documentation is TVC per § 192.607?\nIt depends. Records vary greatly in the amount and types of information documented. Some\noperators may need to include multiple corroborating documents to constitute a TVC record,\nwhile others may have that TVC record in a single consolidated document. In any event, the\nmaterial property records must contain the attributes in § 192.607(b), 192.67, or 192.205. A\nsingle document such as a pipe manufacturer’s “mill test report” with the required pipe\nmechanical and chemical properties would still need some identifying number or description\nlinking the material attributes to the pipeline that was placed into service (e.g., work order, line\ndesignation).\nFAQ-64. Is a pipeline segment with an MAOP established under § 192.619(c) (i.e. “legacy”\nMAOP) also required to comply with § 192.624(a)(1)?\nNo. A pipeline segment with an MAOP established under § 192.619(c) falls under §\n192.624(a)(2), and therefore it is not subject to § 192.624(a)(1). Section 192.624(a)(2) still\nrequires the implementation of the additional paragraphs in § 192.624(b) through (d).\nPipeline segments with an MAOP established under § 192.619(c) must comply with §\n192.624(a)(2) if the MAOP is greater than or equal to 30% SMYS and is located in an HCA,\nClass 3 or 4 location, or a moderate consequence area if the segment can accommodate inline\n10\n\n<<<PAGE 11>>>\n\ninspection tools. Non-legacy pipelines where the MAOP was established per § 192.619(a) are\nsubject to the applicability of § 192.624(a)(1) if they do not have TVC records necessary to\nestablish the MAOP, including hydrotest records required by § 192.517, and they are located in\nan HCA or a Class 3 or 4 area.\nFAQ-65. RESERVED\nAssessments Outside of High Consequence Areas FAQs\nFAQ-66. Can an operator’s “risk-based prioritization” of initial assessments required by §\n192.710(b)(1) allow a pipeline segment containing a lower-risk MCA to be assessed prior to\na higher-risk MCA in another pipeline segment?\nYes. PHMSA requires operators to perform their initial assessments per § 192.710 based on a\n“risk-based prioritization” schedule. This requirement does not prevent an operator from\nconsidering other non-risk factors that may influence the schedule of assessments (e.g., ILI\navailability, segment continuity). Operators must have and follow written procedures per §\n192.605(a) and retain records per § 192.603(b) to document the rationale for their assessment\nschedule and any deviations to that schedule that may be necessary in the future.\nFAQ-67. Can an operator use External Corrosion Direct Assessment (ECDA) as a direct\nassessment method to assess threat of third-party damage per § 192.710(c)?\nYes. While third-party damage is not explicitly listed in § 192.710(c)(6), ECDA may be used as\na direct assessment method to address the threat of third-party damage for assessments outside of\nhigh consequence areas, similar to HCA assessments conducted per Subpart O. As stated in §\n192.710(c)(6), the ECDA assessment must be conducted in accordance with §§ 192.923;\n192.925; 192.927; and 192.929.\nFAQ-68. Does the statement in § 192.712(b) “or an alternative equivalent method of\nremaining strength calculation that will provide an equally conservative result” allow\noperators to use corrosion evaluation methods for anomaly evaluations that give predicted\nfailure pressures less than either R-STRENG or ASME/ANSI B31G?\nSection 192.712(b) allows the use of alternative evaluation methods that result in a level of\nsafety for the anomaly’s predicted failure pressure (PFP) that is equivalent to either R-STRENG\nor ASME/ANSI B31G. In determining whether an alternative method will result in an\nequivalent level of safety, the operator should evaluate both the accuracy and precision of the\nalternative model relative to R-STRENG or ASME/ANSI B31G. The alternative equivalent\nmethod of a remaining strength calculation must provide an equally conservative result. The\noperator can demonstrate the alternative method is equivalent through a comparison of its\npredicted failure pressures to R-STRENG or ASME/ANSI B31G, burst pressure tests used to\nsupport the comparison, and any other technical reviews used to qualify the alternative method\nfor varying corrosion profiles.\n11\n\n<<<PAGE 12>>>\n\nThe level of safety achieved from an alternate evaluation method must be based on how\neffectively the model predicts the actual safety performance of the anomaly being evaluated in\naccordance with § 192.712(b). This is achieved by considering the accuracy and precision of the\nmodel, and is supported by empirical data using similar pipe materials, anomaly characteristics,\nand operating pressures and through destructive tests to validate the model.\nFAQ – 69. RESERVED\n12","truncated":false,"body_characters":32287}