{"operation":"document","citation":"PHMSA Gas Transmission Final Rule FAQs, Batch 1 (2020)","title":"Gas Transmission Final Rule FAQs, Batch 1","source_type":"guidance","agency":"Pipeline and Hazardous Materials Safety Administration","status":"guidance","official":true,"published_on":"2020-09-15","effective_on":"2020-09-15","summary":"Frequently Asked Questions (FAQs) on Gas Transmission Final Rule Title: Frequently Asked Questions (FAQ) for the Final Rule titled “Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments,” published on October 1, 2019 Date: September 15, 2020 Summary: PHMSA is issuing these Frequently Asked Questions (FAQs) to assist gas pipeline ","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-gas-transmission-final-rule-faqs-batch-1.json","markdown":"https://regulus.evalyn.ai/document/phmsa-gas-transmission-final-rule-faqs-batch-1.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-gas-transmission-final-rule-faqs-batch-1","source_url":"https://www.phmsa.dot.gov/regulatory-compliance/phmsa-guidance/frequently-asked-questions-faqs-gas-transmission-final-rule","body":"<<<PAGE 1>>>\n\nFrequently Asked Questions (FAQs) on Gas Transmission Final Rule\nTitle: Frequently Asked Questions (FAQ) for the Final Rule titled “Pipeline\nSafety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation,\nExpansion of Assessment Requirements, and Other Related Amendments,”\npublished on October 1, 2019\nDate: September 15, 2020\nSummary:\nPHMSA is issuing these Frequently Asked Questions (FAQs) to assist gas pipeline owners and\noperators in complying with the pipeline safety regulations in 49 CFR Parts 191 and 192. These\nregulations were amended on October 1, 2019, by the Final Rule entitled “Pipeline Safety: Safety\nof Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements,\nand Other Related Amendments” (84 FR 52180). This guidance document was not deemed\n“significant” or “otherwise of importance to the Department’s interests,” as defined by 49 CFR\n5.37. However, PHMSA voluntarily posted the FAQs to the Federal Register on January 29,\n2020, for public comment, under Docket Number PHMSA-2019-0225. A public meeting was\nthen held on February 27, 2020. In finalizing this guidance document, PHMSA considered\ncomments made at the public meeting along with the 18 comments submitted to the docket as of\nMarch 30, 2020. This guidance document is not intended to replace or revise any previously\nissued guidance.\nThis guidance does not have the force and effect of law and is not meant to bind the public in any\nway, although pipeline operators must still comply with the underlying safety standards. These\nFAQs are only intended to clarify existing requirements under the pipeline safety laws, PHMSA\nregulations, and agency policies.\nGeneral FAQs\nFAQ-1. What are key implementation dates associated with this Final Rule?\nJuly 1, 2020\n• Operators must prepare and follow procedures (per §§ 192.13(c) and 192.605) addressing\napplicable regulations without timeframes explicitly defined in the Final Rule (§§ 191.23,\n191.25, 192.3, 192.5, 192.7, 192.9, 192.18, 192.67, 192.127, 192.150, 192.205, 192.493,\n192.506, 192.517, 192.607 (if material verification is being used per § 192.712), 192.619,\n192.632, 192.710, 192.712, 192.805, 192.909, 192.917, 192.921, 192.933, 192.935,\n192.937, 192.939, 192.949 (removed and replaced with 192.18), and Appendix F to Part\n192.\n• Operators must begin to identify, schedule (according to a risk-based prioritization), and\nperform assessments required by § 192.710 (see FAQ-12 regarding MCA identification).\nPage 1 of 16\n\n<<<PAGE 2>>>\n\nFrequently Asked Questions (FAQs) on Gas Transmission Final Rule\nJuly 1, 2021\n• Operators must begin retaining records for each individual welder qualification at the\ntime of construction for a minimum of 5 years following construction, per § 192.227.\n• For transmission pipe installed after July 1, 2021, operators must begin retaining records\nfor each person’s plastic pipe joining qualifications at the time of construction for a\nminimum of 5 years following construction, per § 192.285.\n• If subject to § 192.624, operators must develop and document procedures for completing\nall actions required by this section (see FAQ-12 regarding MCA identification). These\nprocedures must include:\no A process for reconfirming MAOP for any pipelines that meet a condition of\n§ 192.624(a)\no A process for performing a spike test or material verification per §§ 192.506 and\n192.607, if applicable\no A process for performing an engineering critical assessment (ECA) for MAOP\nreconfirmation per § 192.632, if implemented\n• Operators must modify their launchers and receivers that will be used after this date to\nmeet the conditions of §192.750.\nMarch 15, 2022\n• Operators must submit a revised Annual Report (PHMSA F 7100.2-1) that reflect this\nrulemaking.\nJuly 3, 2028\nJuly 3, 2034\nJuly 2, 2035\n• Operators must complete all actions required by § 192.624 on 100% of the pipeline\nmileage subject to MAOP reconfirmation.\nFAQ-2. Do any of the new rules apply to regulated gas gathering lines?\nYes. While the new rule focuses on the safety of onshore gas transmission lines, new\nrequirements apply to regulated gas gathering lines. Section § 192.9 identifies the safety\nrequirements applicable to regulated gas gathering lines. Sections §§ 192.9(b), 192.9(c), and\n192.9(d) identify code sections that do not apply to gas gathering lines. Operators of regulated\ngas gathering lines should review the following code sections, revised in this rulemaking, to see\n• Operators must complete all actions required by § 192.624 on at least 50% of the pipeline\nmileage subject to MAOP reconfirmation.\n• Operators must complete all originally identified assessments required by § 192.710.\nPage 2 of 16\n\n<<<PAGE 3>>>\n\nFrequently Asked Questions (FAQs) on Gas Transmission Final Rule\nhow they apply to their systems: §§ 191.23, 191.25, 192.3, 192.5, 192.7, 192.18, 192.67,\n192.127, 192.205, 192.227, 192.517, 192.619(a), 192.619(f), 192.750, and 192.805.\nFAQ-3. Who qualifies as a “subject matter expert” for purposes of reviewing and\nvalidating failure pressure analyses under § 192.712?\nPHMSA described the qualifications of a “subject matter expert” in the Preamble of the Final\nRule at 84 FR 52206: PHMSA expects a qualified subject matter expert to be an individual with\nformal or on-the-job technical training in the technical or operational area being analyzed,\nevaluated, or assessed. The operator must be able to document that the individual is\nappropriately knowledgeable and experienced in the subject being assessed.\nThe intent of § 192.712 is to require operators to conduct rigorous failure pressure analyses that\nare properly documented, for review and evaluation by qualified experts. Subject matter experts\ndon’t necessarily need to perform the analyses, but they must review and confirm the analyses.\nFAQ-4. What date or what activities should an operator use to compute the beginning of\nthe five-year period from which it needs to retain individual joining or welding\nqualification records pursuant to § 192.227(c)?\nRecords required by 192.227(c) must be retained for a minimum of five years after the end of\nconstruction. PHMSA considers the end of construction to be prior to an operator placing a gas,\nas defined by §§ 192.1(a) and 192.3, into the pipeline, making it an in-service pipeline, and\noperating that pipeline. Per § 192.227(c), “construction” activities include the installation of\npipe—be it for new construction, replacement, relocation, or repair. These construction activities\nwould also include the installation or replacement of components with pipe attached.\nFAQ-5. Removed.\nReporting FAQs\nFAQ-6. When is the effective date of the revised incident report form? (The revised form\nrequires collecting data on the MAOP reconfirmation method and moderate consequence\narea location for the pipe segment involved in an incident.)\nOperators can report new data requirements on the revised incident form (Form PHMSA F\n7100.2) starting July 1, 2021. However, operators can view this revised form currently on the\ndocket (PHMSA-2019-0225). Section 191.15 requires each operator of a transmission or a\ngathering pipeline system to submit DOT Form PHMSA F 7100.2 as soon as practicable, but not\nmore than 30 days after detecting an incident required to be reported under § 191.5 of Part 191.\nThe form has been modified to collect information and data the pipeline operator must obtain as\npart of the Final Rule, including a record(s) of the maximum allowable operating pressure\n(MAOP) reconfirmation method used for the pipeline segment that experienced the incident, and\nwhether the incident occurred in a moderate consequence area (MCA). Operators must identify\nMCAs to determine if the new requirements under §§ 192.624(a) and 192.710(a) apply to them.\nPage 3 of 16\n\n<<<PAGE 4>>>\n\nFrequently Asked Questions (FAQs) on Gas Transmission Final Rule\nFAQ-7. When will Form PHMSA F 7100.2-1 (annual report) be revised to reflect the\nadditional information that PHMSA expects to collect for miles of pipe in MCAs and\nMAOP reconfirmation?\nThe revised annual report form (Form PHMSA F 7100.2-1) for gas transmission pipelines has\nbeen modified to collect MCA and MAOP reconfirmation information. Operators will be able to\nstart using the annual report form on July 1, 2021. Operators, however, can view this revised\nform currently on the docket (PHMSA-2019-0225). PHMSA will require operators to use the\nrevised annual report form beginning Calendar Year 2021, due no later than March 15, 2022.\nThe Final Rule does not require modifications of the annual report for gas distribution; therefore,\nthat report remains unchanged.\nOther Technology Notification FAQs\nFAQ-8. Does the notification process set forth in § 192.18 apply to all of Part 192?\nNo. The notification guidance in § 192.18(a) and (b) applies to all sections of Part 192. The\nsections specifically identified in § 192.18(c) require that the operator provide notification to\nPHMSA at least 90 days prior to using other technologies or methodologies. These sections\ninclude as follows: §§ 192.506(b), 192.607(e)(4), 192.607(e)(5), 192.624(c)(2)(iii),\n192.624(c)(6), 192.632(b)(3), 192.710(c)(7), 192.712(d)(3)(iv), 192.712(e)(2)(i)(E),\n192.921(a)(7), or 192.937(c)(7). Operators are also required to notify PHMSA of changes to\ntheir Operator Qualification and Integrity Management plans per § 192.805(i) and § 192.909 (b),\nrespectively.\nFAQ-9. Removed.\nFAQ-10. Must operators wait for written approval from PHMSA prior to implementing\nother technology for purposes of complying with the sections identified in § 192.18(c)?\nNo, operators may proceed with using other technologies if they submitted a notification per §\n192.18 and PHMSA did not respond within 90 days. After 90 days following notification\nsubmission, an operator does not have to wait for a written approval or a “no objection letter”\nfrom PHMSA to proceed with using “other technology.” An operator seeking a written “no\nobjection letter” from PHMSA prior to implementing the alternative technology per § 192.18(c)\nshould include a specific request for the written response in its § 192.18 notification.\nPage 4 of 16\n\n<<<PAGE 5>>>\n\nFrequently Asked Questions (FAQs) on Gas Transmission Final Rule\nModerate Consequence Area (MCA) FAQs\nFAQ-11. In identifying MCAs affecting their pipelines, where can operators obtain\ninformation as to the location of a designated interstate, other freeway or expressway, and\nother principal arterial roadway with 4 or more lanes?\nTo identify applicable roadways, PHMSA expects operators to use all information available\nincluding but not limited to the following: www.thenationalmap.gov, www.fhwa.dot.gov, and\nother federal and state highway mapping data; aerial imagery; pipeline patrols and surveys\n(ground and aerial); and, pipeline route maps. When identifying an MCA, PHMSA expects\noperators to capture the area between the outermost edge of the paved surfaces, including all\nmedians. Entrance and exit ramps to access-controlled roadways should be included in the MCA\nanalysis. There is no comprehensive GIS-based source of roadways as defined in the Federal\nHighway Administration’s (FHWA) Highway Functional Classification Concepts, Criteria and\nProcedures, Section 3.1 (see:\nhttps://www.fhwa.dot.gov/planning/processes/statewide/related/highway_functional_classificatio\nns/fcauab.pdf). However, Section 4 of the FHWA document includes recommendations and\nguidance on how to obtain GIS-based roadway inventory data at a state level. PHMSA does not\nintend to develop a single source of data for operators to use to determine if an MCA exists on\ntheir pipeline system.\nFAQ-12. When must operators complete the initial determination of MCAs on their\npipeline system?\nThe new rule, which went into effect July 1, 2020, requires operators to develop procedures per §\n192.605(b)(1) to determine the location of MCAs on their pipeline system and to incorporate\nthese procedures into their manual for maintenance and normal operations. Operators must then\nimplement those procedures to complete the initial identification of MCAs by July 1, 2021 and\nrecord those MCAs in the revised incident and annual reports after this date. (See FAQ-6 and\nFAQ-7.)\nPHMSA anticipates that some operators will incorporate an MCA identification process into\nexisting HCA and class identification procedures, while other operators might prepare a separate\nprocedure for identifying MCAs. MCAs are used to determine a pipeline segment’s applicability\nunder §§ 192.624 and 192.710.\nOperators must begin performing assessments according to a risk-based prioritization schedule\nstarting July 1, 2020, the effective date of the rule, and complete all assessments no later than\nJuly 3, 2034, per § 192.710(b). Operators must also begin performing MAOP reconfirmations\non July 1, 2021, to complete all actions required by the schedules in § 192.624(b)(1) and (2).\nAn assessment performed prior to July 1, 2020, the effective date of the rule, that meets the\nconditions outlined in § 192.710(b)(3) may be used as an assessment. Operators who use a prior\nassessment for a pipeline segment located in an MCA must conduct ongoing reassessments of\nthat segment within 10 years as per § 192.710(b)(2)—not 14 years as would be the case for an\ninitial assessment under § 192.710(b)(1).\nPage 5 of 16\n\n<<<PAGE 6>>>\n\nFrequently Asked Questions (FAQs) on Gas Transmission Final Rule\nFAQ-13. Do operators need to identify, document, and track “unpiggable” MCAs\noperating less than 30% Specified Minimum Yield Strength (SMYS)?\nYes. Operators must identify, document and track all MCAs—regardless of piggability and\noperating stress—for annual and incident report data collection.\nFAQ-14. How frequently must a re-evaluation of MCAs be performed and when must new\nMCAs be incorporated into an operator’s plans and procedures?\nPHMSA expects that operators will re-evaluate their MCAs once per calendar year, not to\nexceed a period of 15 months, consistent with current HCA and class location change studies\n(per §§ 192.905 and 192.609). PHMSA also expects that operators will add any newly identified\nMCAs to their § 192.710 assessment schedule within one year of the discovery date. This\nexpectation is consistent with current Gas IMP FAQ-19, FAQ-20, and FAQ-179, posted on the\nPHMSA’s Technical Resources site at https://www.phmsa.dot.gov/pipeline/gas-transmission-\nintegrity-management/gas-transmission-integrity-management-faqs.\nSpike Hydrostatic Testing FAQs\nFAQ-15. Under § 192.506 Transmission lines: Spike hydrostatic pressure test, is a spike test\nrequired for all pipelines that are hydrotested (or re-hydrotested) and are operating at\n30% or more of SMYS? For what threats is a spike hydrostatic pressure test appropriate?\nNo. A spike test is not required for all pipelines that are hydrotested or re-hydrotested and are\noperating at 30% or more of SMYS. The hydrostatic spike pressure testing requirements in\n§ 192.506 applies only when conducted as required by §§ 192.710 and 192.921.\nA spike test is appropriate and should be considered for time-dependent threats, such as the\nfollowing: stress corrosion cracking; selective seam weld corrosion; manufacturing and related\ndefects, including defective pipe and pipe seams; and, other forms of defect or damage involving\ncracks or crack-like defects, such as those listed in §§ 192.710(c)(3), 192.917(e)(6) and\n192.937(c)(3).\nIf an operator decides to spike test a transmission pipeline operated at a hoop stress greater than\n30% SMYS, the test must be conducted according to the spike-test procedures listed in §\n192.506.\nMaterial Verification FAQs\nFAQ-16. Is the use of § 192.607 Verification of Pipeline Material Properties and Attributes\nallowed outside of HCAs, MCAs, and Class 3 and Class 4 locations?\nYes. While pipeline operators must verify material properties per § 192.607 where explicitly\nreferenced in Part 192, PHMSA also allows the voluntary use of § 192.607 (per § 192.619(a)(4))\nPage 6 of 16\n\n<<<PAGE 7>>>\n\nFrequently Asked Questions (FAQs) on Gas Transmission Final Rule\nfor material property verification outside of HCAs, MCAs, and Class 3 and Class 4 locations in\norder to determine key Subpart C – Pipe Design attributes. Operators of pipeline segments that\ndo not meet the applicability of § 192.624 may, and in fact are encouraged to, conduct and use\nthe results of a properly conducted testing program such as those outlined in §192.607 to ensure\nthe safe operation of the pipeline regardless of location. That said, operators must consider the\nnewly determined material property results regardless of pipeline location when they analyze\npredicted failure pressures for anomalies, develop appropriate repair procedures, conduct\nengineering critical assessments, or fulfill other requirements under Part 192.\nFAQ-17. PHMSA allows the data collection process to be accomplished\n“opportunistically” per § 192.607(c). Is there a deadline by which operators are expected\nto complete this process?\nNo. The opportunistic gathering of data on unknown material properties does not need to meet\nthe MAOP reconfirmation schedule outlined in § 192.624(b), except when the selected MAOP\nreconfirmation method requires material properties testing to reconfirm the MAOP. The\ntimeframe for opportunistic data collection may vary, based on the length of the pipeline, amount\nof pipe with missing material properties, number of opportunities, and testing results. (See\n§ 192.607 for a complete description.) Also, § 192.712 requires the operator to know the pipe\nmaterial properties when conducting the analysis of predicted failure pressure for anomalies or\ndefect evaluations.\nFAQ-18. When determining separate pipe “populations” for conducting a verifiable\nmaterial properties and attributes sampling program that satisfies § 192.607(e)(1), must an\noperator compare the dates of manufacture and construction together, or must the\nmanufacture and construction dates be compared separately? For example, would two\nsegments of pipe that were manufactured in the same year but were installed together, 3\nyears after manufacture, be in the same population? As a second example, would two\nsegments of pipe that were manufactured in the same year but installed 3 years apart be in\nthe same population?\nWhen determining the vintage of two potentially similar pipeline segments (e.g., same diameter,\nwall thickness, grade, and seam type), operators must consider the following: If the difference\nbetween either the manufacturing date of the two segments or the construction date of the two\nsegments is greater than 2 years, the two segments cannot be considered similar and must be\nplaced in separate populations per the mandate in § 192.607(e)(1). In the first example, the two\npipe segments would be in the same population. In the second example, the operator would not\nbe able to place the two pipe segments in the same population unless additional records\ndemonstrate traceability to another population of pipe.\nPage 7 of 16\n\n<<<PAGE 8>>>\n\nFrequently Asked Questions (FAQs) on Gas Transmission Final Rule\nFAQ-19. It appears to be a requirement to separate pipe segments into different\npopulations based on the material properties and attributes listed in § 192.607(e)(1), but\nhow do you handle the situation where you are missing documentation for an attribute like\npipe manufacturing dates?\nOperators should only split populations based on known attributes and they should have separate\npopulations of pipe segments where attributes are unknown. Operators that can document pipe\nmaterial properties but are missing the manufacturing or construction date attributes would not\nneed to conduct an expanded sampling program to determine material properties. When material\nattributes are unknown, operators must use manufacturing and construction dates noted in\n§ 192.607(e)(1) and FAQ-18 to delineate the boundaries of the material properties sampling\nprogram.\nFAQ-20. How should operators define populations where necessary documentation is\nmissing? Can an operator group all pipe sections with unknown attributes into one\npopulation?\nPer § 192.607, operators must implement a sampling program for each unique pipe population\ngroup with unknown pipe attributes. Operators can initially group pipe segments with no known\nmaterial properties information into a single population. When performing material properties\ntesting on pipe from the unknown population group, operators must add newly verified samples\ninto matching pipe populations or create new pipe population groups, as applicable.\nFAQ-21. Can the data from in-line inspection tools be used to help determine population\ngroups under § 192.607(e)?\nYes. In-line inspection data may be used to delineate various pipe population groups for\nsubsequent sampling of multiple segments for material property verification. Operators must\ndefine processes they plan to implement the requirements of MAOP reconfirmation and material\nverification, and report whether they are using an alternative sampling approach under §\n192.607(e)(5). This alternate sampling method must also be reported per § 192.18.\nFAQ-22. Can an operator use SMYS, wall thickness and seam type derived from in-line\ninspection tools for material verification under § 192.607(c)?\nYes. Depending on the in-line inspection tool capabilities, operators can determine certain\nmaterial properties and attributes with the required confidence levels. Any verification of\nmaterial properties and attributes using nondestructive methods or inspection tools must meet the\nrequirements in § 192.607(d).\nFAQ-23. Is there a process to compile comparable pipe material properties across the\nindustry?\nNo process currently exists to compile pipe material property information. Material properties\ncan vary greatly during the manufacturing process. PHMSA expects operators to verify pipe\nmaterial used within their system.\nPage 8 of 16\n\n<<<PAGE 9>>>\n\nFrequently Asked Questions (FAQs) on Gas Transmission Final Rule\nFAQ-24. During which type of pipeline exposures does an operator need to perform\nmaterial properties and attributes verification?\nOperators must address each activity listed in § 192.607(c) in their procedures for safely\nconducting nondestructive or destructive tests, examinations, and assessments to verify the\nmaterial properties. The listed activities include: anomaly direct examinations, in situ\nevaluations, repairs, remediations, maintenance, and excavations associated with replacements or\nrelocations of pipeline segments that are removed from service. Operators’ procedures should\nestablish specific criteria for identifying when these pipeline exposures are safe “opportunities”\nfor material verification and identify any criteria that would render an exposure inappropriate for\nmaterial verification, such as confined space concerns or unstable excavations. In most cases, an\noperator should be able to conduct material properties tests after completing an immediate repair.\nPHMSA does not expect operators to perform material properties verification for unknown pipe\nproperties on pipeline segments exposed during excavation activities per § 192.614 Damage\nPrevention Program. However, material verification performed during a one-call excavation\nmust be performed per §192.607.\nFAQ-25. If an operator has unknown material properties and during normal operations\nexcavates a leak on a transmission line operating at less than 30% SMYS, must it perform\na destructive or nondestructive test to verify material properties?\nAfter making the area safe, an operator must perform testing to verify pipeline material\nproperties and attributes per § 192.607 if the pipeline segment experiencing the leak meets\napplicability per §§ 192.624 Maximum allowable operating pressure reconfirmation: Onshore\nsteel transmission pipelines, or per 192.712 Analysis of Predicted Failure Pressure.\nFAQ-26. In accordance with § 192.607, what pipe material properties or attributes must\nbe verified through in situ (non-destructive) testing during an excavation and exposure of\nthe pipeline?\nOperators must verify diameter, wall thickness, seam type, and grade (e.g., yield strength,\nultimate tensile strength, or pressure rating for valves and flanges, etc.), and Charpy v-notch\ntoughness values (if needed), if these items are unknown and are necessary for MAOP\nreconfirmation (per § 192.624), an engineering critical assessment (per § 192.632), or failure\npressure analysis (per § 192.712), as specified by those regulations.\nOther material properties and attributes might be required to be documented (e.g. Subpart I,\nSubpart O).\nFAQ-27. What are operators expected to do if they find material properties records that\ndo not substantiate MAOP in Class 1 or 2 locations or in non-MCA/HCA segment while\ncomplying with § 192.607?\nOperators must reduce the operating pressure and MAOP per § 192.619 and may need to\nperform MAOP Exceedance reporting per §§ 191.23(a)(10) and 191.25(b).\nPage 9 of 16\n\n<<<PAGE 10>>>\n\nFrequently Asked Questions (FAQs) on Gas Transmission Final Rule\nFAQ-28. What does PHMSA mean in § 192.607(e)(4) when it states that an operator must\nestablish an expanded sampling program when it finds line pipe with properties “that are\nnot consistent with available information or existing expectations or assumed properties\nused for operations and maintenance in the past?”\nPHMSA expects operators to define the term “not consistent” in their material verification\nprocedures as it relates to pipe properties, and to detail how they will establish an expanded\nsampling program in response to such information. The regulation requires operators to maintain\nmaterial records for line pipe, such as pipe wall thicknesses, grades, and manufacturing process\n(seam types). Pipeline material records and class location information are used to determine and\nsupport the pipeline MAOP. Any operator who discovers pipe properties that differ from those\nused to determine the pipeline’s MAOP should consider such properties to be “not consistent”\nwith available information or assumptions for operations and maintenance. The operator\nmaterial sampling programs must be modified to comply with the requirements of §\n192.607(e)(4).\nFAQ-29. Can I collect material information from Class 1 and 2 and non-MCA/non-HCA\nlocations and apply it to segments that require material properties and attributes\nverification under § 192.607, assuming the pipe is similar? For example, can pipe material\nproperties that are collected and validated for pipe examined outside of HCA, MCA, Class\n3 and 4 locations be used if similar pipe is found in an HCA, MCA, Class 3 and 4?\nYes. Operators may take advantage of all pipeline excavations and exposures to collect material\nproperties regardless of pipeline location. If operators plan to use material and attribute\ninformation collected from pipe segments outside of HCA, MCA, and Class 3 and 4 areas to\nfulfill the requirements of §§ 192.624 and 192.712, they must adopt and follow procedures for\nimplementing § 192.607(e) in those areas as well. Any acquired material properties and attribute\ndata will aid the operators’ efforts to safely conduct MAOP reconfirmation, pipeline\nassessments, anomaly evaluations, analysis of failure pressure, and repairs for all pipeline\nsegment irrespective of Class Location or HCA/MCA designation.\nIf the sampling procedures mandated by § 192.607(e) are used outside of HCA, MCA, or Class 3\nor 4 areas, the operator must also include procedures to delineate the geographic limits of the\nsampled segments and how that pipe material and attribute information will be applied to meet\nthe additional regulatory requirements for HCA, MCA, and Class 3 and 4 areas.\nMaximum Allowable Operating Pressure Establishment and Reconfirmation FAQs\nFAQ-30. What is meant by “traceable, verifiable, and complete in relation to MAOP\nrecords?\nThe Preamble of the rule at 84 FR 52218, excerpted below, states PHMSA’s expectations\nrelative to “TVC” records.\nPage 10 of 16\n\n<<<PAGE 11>>>\n\nFrequently Asked Questions (FAQs) on Gas Transmission Final Rule\nTraceable records are those which can be clearly linked to original information about a pipeline\nsegment or facility. Traceable records might include pipe mill records, which include\nmechanical and chemical properties; purchase requisition; or as-built documentation indicating\nminimum pipe yield strength, seam type, wall thickness and diameter. Careful attention should\nbe given to records transcribed from original documents as they may contain errors. Information\nfrom a transcribed document, in many cases, should be verified with complementary or\nsupporting documents.\nVerifiable records are those in which information is confirmed by other complementary, but\nseparate, documentation. Verifiable records might include contract specifications for a pressure\ntest of a pipeline segment complemented by pressure charts or field logs. Another example might\ninclude a purchase order to a pipe mill with pipe specifications verified by a metallurgical test of\na coupon pulled from the same pipeline segment. In general, the only acceptable use of an\naffidavit would be as a complementary document, prepared and signed at the time of the test or\ninspection by a qualified individual who observed the test or inspection being performed.\nComplete records are those in which the record is finalized as evidenced by a signature, date or\nother appropriate marking such as a corporate stamp or seal. For example, a complete pressure\ntesting record should identify a specific segment of pipe, who conducted the test, the duration of\nthe test, the test medium, temperatures, accurate pressure readings, and elevation information as\napplicable. An incomplete record might reflect that the pressure test was initiated, failed and\nrestarted without conclusive indication of a successful test. A record that cannot be specifically\nlinked to an individual pipeline segment is not a complete record for that segment. Incomplete or\npartial records are not an adequate basis for establishing MAOP or MOP. If records are\nunknown or unknowable, a more conservative approach is indicated.\nFor example, a mill test report must be traceable, verifiable, and complete, which is a typical\nrecord for pipelines. For the mill test report to be traceable it would need to be dated in the\nsame time frame as construction or have some other link relating the mill record to the material\ninstalled in the pipeline, such as a work order or project identification. For the mill test report\nto be verified, it would need to be confirmed by the purchase or project specification for the\npipeline or the alignment sheet with consistent information. Such an example would be verified\nby independent records. For the mill test report to be complete, it must be signed, stamped, or\notherwise authenticated as a genuine and true record of the material by the source of the record\nor information, in this example it could be the pipe mill, supplier, or testing lab.\nAnother common record is a pressure test record, which must be traceable, verifiable, and\ncomplete. For the pressure test record to be traceable, it would need to identify a specific and\nunique segment of pipe that was tested (such as mileposts, survey stations, etc.) or have some\nother link relating the pressure test to the physical location of the test segment, such as a work\norder, project identification, or alignment sheet. For the pressure test record to be verified, it\nwould need to be confirmed by the purchase or project specification for the pipeline or the\nalignment sheet with consistent information. Such an example would be verified by independent\nrecords. For the pressure test record to be complete, it should identify a specific segment of\npipe, who conducted the test, the duration of the test, the test medium, temperatures, accurate\npressure readings, elevation information, and any other information required by § 192.517, as\nPage 11 of 16\n\n<<<PAGE 12>>>\n\nFrequently Asked Questions (FAQs) on Gas Transmission Final Rule\napplicable. An incomplete record might reflect that the pressure test was initiated, failed and\nrestarted without conclusive indication of a successful test.\nFAQ-31. What sources of information should operators use to discover segments that\nrequire MAOP reconfirmation under § 192.624 (i.e., segments that do not have traceable,\nverifiable, and complete MAOP records)?\nIf operators do not have traceable, verifiable and complete records to establish MAOP for\nsegments listed in § 192.624(a), they must reconfirm the segments’ MAOP. Therefore, operators\nshould review all existing records, particularly those reflecting pipe replacements, relocations,\nrepairs, or other changes to verify that those modifications have been integrated into their MAOP\nrecords. Operators, for example, should compare records of historical repairs, leaks, ruptures,\nincidents, and in-line inspection data (wall thickness, coating, seam type, joint length, fittings,\netc.) against their MAOP records. If the records are incomplete or otherwise inadequate, the\noperator must reconfirm MAOP for those segments.\nFAQ-32. If an operator does not have to reconfirm MAOP under § 192.624, what must it\ndo if it does not have records necessary to establish the MAOP of a pipeline segment?\nExamples of pipelines that would not be covered under § 192.624 include Class 1 and 2\n(non-HCA/non-MCA) onshore transmission lines.\nPHMSA requires operators of onshore gas transmission pipelines that do not meet the\napplicability criteria of § 192.624(a) to comply with the other MAOP and design requirements of\nPart 192, such as § § 192.603(b), 192.605,192.609, 192.611, 192.619, 192.620, 192.195,\n192.201, and 192.739. These code sections all require knowledge of a documented MAOP and\nthe materials of which the pipeline is constructed. Operators who do not have proper records\nshould follow the sections of Part 192 that address pressure testing and/or materials confirmation\nbased on the type of documents that are not available.\nFAQ-33. Can an operator take a pressure reduction per § 192.624(c)(2) and not have to\nreconfirm MAOP?\nYes. An operator performing a pressure reduction based on “Method 2” of § 192.624(c)(2) is\nreconfirming the pipeline’s MAOP by creating a safety margin by which the pipeline is\noperating. The pressure reduction creates and establishes a new MAOP. The recordkeeping\nrequirements of § 192.619(f) will apply to the MAOP reconfirmation records that document the\npressure reduction (i.e., 5-year operating pressures, application of reduction factors, etc.). Note,\nhowever, that operators who need traceable, verifiable, and complete records of material\nproperties and attributes to comply with elements of §§ 192.624, 192.632, or 192.712 (for\nanomaly repairs, an Engineering Critical Assessment, use of another MAOP reconfirmation\nmethod, or the calculation of predicted failure pressures, for example) would still need to obtain\nthose records per the opportunistic method described in § 192.607.\nPage 12 of 16\n\n<<<PAGE 13>>>\n\nFrequently Asked Questions (FAQs) on Gas Transmission Final Rule\nFAQ-34. Methods 2 and 5 under § 192.624(c) permit reconfirming MAOP based upon the\nhighest actual operating pressure during the 5 years preceding October 1, 2019. What does\n“the highest actual sustained pressure must have been reached for a minimum cumulative\nduration of 8 hours during one continuous 30-day period” mean?\nThis statement means the 8-hour period does not need to be continuous; it can be made up of\nshorter periods that over the course of 30-days amount to at least 8 hours above a certain\npressure. Per §§ 192.624(c)(2) and (c)(5)(i), the value used as the highest actual sustained\noperating pressure must account for differences between upstream and downstream pressure on\nthe pipeline by use of either the lowest maximum pressure value for the entire pipeline segment\nor using the operating pressure gradient along the entire pipeline segment (i.e., the location-\nspecific operating pressure at each location) that is protected from over-pressuring (see\n§§ 192.199 and 192.201).\nFAQ-35. After July 1, 2021, if an operator discovers a pipeline segment that meets the\napplicability criteria under § 192.624 due to a change in class location, when must the\noperator confirm or revise the MAOP for that segment?\nWhen a change in class location occurs on a pipeline segment, operators must confirm or revise\nthe MAOP for that segment within 24 months from the date the classification changed, per §§\n192.609 and 192.611, not in accordance with MAOP reconfirmation requirements established in\n§ 192.624(b)(2). When an HCA or MCA on a pipeline segment is added or changed, that area\nwill need to comply with § 192.624(a). If this occurs, the operator must reconfirm the MAOP\nper § 192.624(b)(2). Operators must ensure that the MAOP records for these new segments are\ntraceable, verifiable, and complete.\nFAQ-36. If a pipeline is operating at greater than 72% SMYS with a “legacy” MAOP (i.e.,\nestablished according to § 192.619(c)) and experiences a change in class location from Class\n1 to Class 2 or from Class 1 to Class 3, can an operator use § 192.624 to confirm the\nMAOP?\nNo. The MAOP of the legacy pipeline segment (+72% SMYS) must still be revised per\n§§ 192.611(a)(1)(i), 192.611(a)(2), 192.611(a)(3), and 192.619(a), as applicable for the Class\nlocation change and the in-service pipeline. To meet these requirements, the operator must use\nmaterial properties per § 192.105 (or acquire them per § 192.607), and have a hydrotest\nperformed per § 192.619(a)(2). A legacy pipeline with an MAOP above 72% SMYS cannot\nhave a class location change, such as from a Class 1 to a Class 2 location, without either\nlowering the MAOP to at or below 72% SMYS or replacing the pipe with materials suitable for a\nClass 2 or Class 3 location design factor and pressure test. However, if the pipeline is operating\nat a corresponding hoop stress (at or below 72% SMYS) that is commensurate with the present\nclass location, the existing legacy MAOP can be maintained, assuming the legacy MAOP is\ndocumented (per §§ 192.603(b) and 192.605(b)(3)) and material properties, pipe design and pipe\ncomponent records are traceable, verifiable, and complete.\nPage 13 of 16\n\n<<<PAGE 14>>>\n\nFrequently Asked Questions (FAQs) on Gas Transmission Final Rule\nFAQ-39. Must water be used for pressure tests to address manufacturing and construction\nFAQ-37. Is MAOP reconfirmation required for non-line pipe and components within\nappurtenant facilities, including compressor, meter, and pressure-limiting stations?\nYes. Line pipe and non-line pipe within compressor, meter, and pressure-limiting stations,\nincluding bypasses (up to the station emergency shutdown or isolation valves), are subject to §\n192.624 and must be incorporated into the operator’s MAOP reconfirmation program. PHMSA\nexpects the operator to examine or assess the pressure rating for all above-ground components.\nFor buried components, PHMSA expects operators to implement a sampling program similar to\nthat required for line pipe per § 192.607(e). Under § 192.607(f), testing of components for\nchemical and mechanical properties is not required.\nFAQ-38. Must material property and MAOP reconfirmation records be retained after a\npipeline has been abandoned?\nNo. However, the destruction or loss of such records would prevent the pipeline from operating\nin the future under Parts 192 or 195 (see conversion of service requirements under §§ 192.14 and\n195.5).\ndefects?\nIt depends on the circumstances:\nFor Non-HCAs Pipeline Segments: Operators must follow § 192.503 general requirements,\nincluding test medium, when conducting future pressure tests in non-HCA segments. If the non-\nHCA segment requires a spike hydrostatic pressure test the threat, the operator must follow\n192.710(c)(3) and 192.506.\nFor HCAs Pipeline segments subject to Subpart O: Operators must follow §","truncated":true,"body_characters":90253}