{"operation":"document","citation":"PHMSA Guidance, Gas Transmission Integrity Management FAQs","title":"Gas Transmission Integrity Management FAQs","source_type":"guidance","agency":"Pipeline and Hazardous Materials Safety Administration","status":"guidance","official":true,"published_on":"2021-01-15","effective_on":"2021-01-15","summary":"Gas Transmission Integrity Management FAQs Document Final GAS IM FAQs 8-26-21.pdf (653.41 KB) This site provides information about PHMSA's implementation of Control Room Management oversight, and links to other educational information on human factors and human operational performance. Issued Date: Friday, January 15, 2021","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-guidance-gas-transmission-integrity-management-faqs-a3046830.json","markdown":"https://regulus.evalyn.ai/document/phmsa-guidance-gas-transmission-integrity-management-faqs-a3046830.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-guidance-gas-transmission-integrity-management-faqs-a3046830","source_url":"https://www.phmsa.dot.gov/pipeline/gas-transmission-integrity-management/gas-transmission-integrity-management-faqs","body":"Gas Transmission Integrity Management FAQs\n\nDocument\n\n Final GAS IM FAQs 8-26-21.pdf (653.41 KB)\n\n        This site provides information about PHMSA's implementation of Control Room Management oversight, and links to other educational information on human factors and human operational performance.\n\n          Issued Date: Friday, January 15, 2021\n\n<<<PAGE 1>>>\n\nGas Transmission Integrity Management: FAQs\nThe Pipeline and Hazardous Materials Safety Administration (PHMSA) provides written clarification of the\npipeline safety regulations (49 CFR Parts 190-199) in the form of frequently asked questions (FAQs) and\nother guidance materials. The FAQs contained on this page are intended to clarify, explain, and promote\nbetter understanding of the gas transmission pipeline integrity management (IM) regulations. These FAQs\nreflect PHMSA’s current application of the regulations to the specific implementation scenarios presented.\nFAQs are not substantive rules, themselves, and do not create legally enforceable rights, assign duties, or\nimpose new obligations not otherwise contained in the existing regulations and standards, but are provided to\nhelp the regulated community understand how to comply with the regulations. However, an operator who is\nable to demonstrate compliance with the FAQs is likely to be able to demonstrate compliance with the\nrelevant regulations. If a different course of action is taken by a pipeline operator, the operator must be able\nto demonstrate that their conduct is in accordance with the regulations. Written regulatory interpretations\nregarding specific situations may also be obtained from PHMSA in accordance with 49 CFR Part 190, §\n190.11.\nThe rule does not apply to gathering lines. Section 192.9 has been changed to make this clear. The rule\ndoes apply to low-stress pipeline that meets the definition in 192.3 as a transmission line, but some\nrequirements are slightly different for low-pressure transmission pipelines (i.e. <30% SMYS).\nFAQ Topical Categories\n• General (6)\n• Rule Basics (2)\n• Rule Applicability (6)\n• Time Periods (6)\n• Integrity Management Programs (9)\n• HCA Identification (38)\n• Threat/Risk Analysis (7)\n• Identification of Threats (1)\n• Data Integration (4)\n• Risk Analysis and Prioritization (6)\n• Specific Threats (2)\n• Assessment (15)\n• Baseline Assessment Plan (BAP) (3)\n• Assessment Methods (28)\n• Continual Assessment and Evaluation (11)\n• Remediation (16)\n• Preventive and Mitigative Measures (5)\n• Performance Measures (5)\n• Record Keeping (3)\n• Management of Change (MOC) (1)\n• Regulatory and External Interaction (2)\n• Communication Plan (1)\n• Notification (7)\n• Inspection (3)\n• Enforcement (3)\n• State Agencies and Intrastate Pipelines (2)\n• Exceptional Performance Deviations (2)\n• ECDA for Cased Pipe (30)\n\n<<<PAGE 2>>>\n\nGeneral FAQ\nFAQ-10. If a pipeline subject to 192 Subpart O is sold, does the new operator \"inherit\" integrity\nmanagement plans and deadlines from the original operator? [05/18/2004]\nThe regulatory deadlines for assessments (e.g., that re-assessments be conducted within specified intervals,\nbased on operating stress levels) continue to apply, as well as the schedule requirements for any remediation\nrequired by 192.933 that may be pending at the time ownership of the pipeline is transferred. Compliance\ndeadlines established in 192 Subpart O for identifying segments in HCAs and for completing 50% or 100% of\nBaseline Assessments continue to apply. For purposes of integrity management, an operator acquiring a\npipeline would be expected to integrate that pipeline into its integrity management program. OPS would\nexpect this integration to occur within one year. Integration of new assets into existing Baseline Assessment\nPlans may result in realigning schedules for future assessments based on the relative risk of the acquired\npipeline and the operator’s existing pipeline(s).\nIntegration of acquired pipe into an operator's IM plan could constitute the kind of substantial change in the\nIM program for which notification is required under 192.909(b), if the integration caused significant changes\nto existing schedules and programs.\nFAQ-11. Who will be held accountable for implementing Integrity Management requirements in a\ncase where an operator transfers pipeline assets to another company but retains responsibility,\nby contract, for maintenance and integrity management activities until some later\ndate? [06/29/2004]\nTypically, OPS inspects the operator for compliance with the pipeline safety regulations, however,\ncompliance responsibility would have to be determined on a case by case basis and is contingent on the\nterms of contracts, operating agreements, and any other relevant correspondence between the involved\nparties. Depending on the terms of the agreement, either or both could be held responsible.\nFAQ-12. If a pipeline transports both gas and liquids (e.g., some off shore lines), does the\nhazardous liquid integrity management rule or the gas integrity management rule\napply? [02/20/2004]\nLines that transport both liquids and gas must meet requirements applicable to both. In practice, this means\nthat the more stringent requirements must be met.\nFAQ-155. In several places, the rule requires that operators follow Appendices in ASME/ANSI\nB31.8S. The title of both Appendices A and B in the standard indicate they are non-mandatory.\nMust the requirements in these Appendices be followed verbatim? [05/05/2004]\nWhere sections of consensus standards are incorporated by reference into a rule, those sections become\nbinding requirements the same as if the language were repeated in the rule. Operators must follow the\nrequirements in the Appendices of ASME/ANSI B31.8S when those Appendices, or sections thereof, are\nreferenced in the rule, even though the standard indicates that the appendices are non-mandatory.\nFAQ-159. What constitutes an \"incident\" of the kind for which operators implementing\nperformance-based programs must evaluate for implications to their pipelines and IM programs\n(192.913(b)(1)(v)? [03/09/2005]\nIncidents are as defined for incident reporting in 49 CFR 191.3. OPS expects, however, that operators\ndeviating from the requirements of prescriptive programs on the basis of \"exceptional performance\" under\n192.913(b) will evaluate events that involve unintentional release of gas but which do not reach the reporting\nthreshold. Such events can illuminate lessons that, if acted upon, can avoid additional events, some of which\nmay produce greater consequences. OPS expects that operators with mature programs (i.e., those\ndemonstrating \"exceptional performance\") will seek to acquire and act on these lessons, and that their\nevaluations of such events will have a degree of transparency that allows OPS to also learn from the\nevaluations\nFAQ-161. Can prior assessments be relied upon to meet the requirement that operators begin\nassessment activities by June 17, 2004? [05/26/2004]\nYes, provided the assessment meets the requirement of Subpart O and can be used as a baseline\nassessment.\n\n<<<PAGE 3>>>\n\n[Top]\nRule Basics FAQ\nFAQ-167. How should the operator address \"must\" and \"shall\" statements in the standard? In\nsome cases, the standard provides for an alternative action if the \"must\" and \"shall\" statements\nare not implemented. [06/29/2004]\nWhen standards are incorporated into a rule by reference, the requirements of the standard become\nrequirements of the rule. Operators are required to implement \"must\" and \"shall\" statements in the standard.\nWhere the standard provides an alternative, e.g., in the event an action that \"must\" be done cannot be\naccomplished, the alternative must be implemented with appropriate justification. (In the event of conflicts\nbetween provisions in the standard and the Rule, the Rule takes precedence).\nFAQ-244. What is the OPS position with regard to implementation of \"should\" statements in\nindustry standards that are invoked by the rule? [01/11/2006]\nOPS expects operators to implement \"should\" statements in industry standards that are invoked by the rule.\nOperators may choose to implement an alternative approach in meeting the recommendations of invoked\nstandards. If this approach is taken, program requirements for the alternative approach must exist in IM\nProgram documents and records must be generated by the alternative approach. The IM Program documents\nmust also technically justify that the alternative approach provides an equivalent level of protection. If an\noperator chooses not to implement a \"should\" statement in an invoked standard, a sound technical basis for\nwhy it has not been implemented must be documented in the IM Program documents.\n[Top]\nRule Applicability FAQ\nFAQ-7. Do the requirements of the rule apply to \"idle\" pipe? [02/20/2004]\nThe regulations do not define \"idle\" pipe. Pipe is considered either active or abandoned. OPS understands\n\"idle\" pipe, as used in the context of this question, as pipe not currently being used to move gas but that\ncould be put back in service at a future date. All pipe is subject to the requirements of the integrity\nmanagement rule. However, idle pipe presents different risks and different treatment is appropriate.\nIn-service pipe (i.e., that contains gas, but is not presently being used to transport gas) represents a\npotential hazard to public health and the environment, even though idle. If such pipe leaks or ruptures, an\nexplosion could result. Leaks may go undetected for some time, since idle pipe may not be covered by\noperator's SCADA systems. For these reasons, operators must meet all requirements and deadlines for pipe\nthat contains gas. Such pipe must be included when determining if the requirement to assess 50% of\ncovered pipeline mileage by December 17, 2007, has been met.\nOut-of-service pipe (i.e., pipe laid up with nitrogen) represents much less hazard. Degradation of such pipe\ncan occur, but is not likely to result in safety impacts. OPS will accept deferral of activities required by the\nrule for out-of-service pipe. All deferred activities must be completed as part of any later return of that line\nto service. A baseline assessment need not be run immediately if the deadline for completing baseline\nassessments (i.e., December 17, 2012) has not yet expired, unless the risk posed by the line would require\nan earlier assessment. The baseline assessment plan should be modified to assure that a baseline\nassessment is completed by the appropriate deadline. If the deadline has expired, then a baseline\nassessment must be completed as part of returning the line to service.\nAdding an idle line into the IM program would be considered a substantive program change and would\nrequire notification under 192.909(b).\nFAQ-84. The Integrity Management Program portion of the rule [192.907] applies to all portions\nof a pipeline system that are in HCAs, including compressor stations, metering stations, and\nother equipment. What must an operator do to comply with the rule for these\nfacilities? [03/04/2005]\nThe integrity assessment provisions of the rule apply only to line pipe, including pipe that may be within the\nboundaries of facilities (e.g., compressor stations, metering stations). The other provisions of the rule apply\n\n<<<PAGE 4>>>\n\nto the equipment in these facilities (e.g., compressors) if the locations meet the criteria to be designated\nHCAs. Thus, operators must consider facilities when establishing potential impact circles (the diameter of the\npipe into/out of the equipment should be used), and should include in their integrity management program\nprocesses for addressing these facilities. These processes should integrate all available information affecting\nthe likelihood and the consequences of equipment or facility failure and identify and implement additional\npreventive or mitigative measures to reduce risk at these facilities, if needed. An operator's performance\nmonitoring process should evaluate the effectiveness of these processes and the risk controls that are\nimplemented to reduce facility risk.\nFAQ-150. What requirements must an operator meet if there are no high consequence areas on\nany of its transmission pipelines. [06/20/2005]\nAn operator need not develop an integrity management program if there are no high consequence areas on\nits system. The operator must have completed an evaluation to determine that no high consequence areas\nexist, and this evaluation must be maintained available for inspection. Even if no HCAs exist, however, there\nare some requirements in Subpart O with which an operator must comply:\n- An operator must have a process to periodically evaluate its pipeline to determine if new HCAs have been\ncreated. Changes along the pipeline route, including housing construction and creation of new facilities\nmeeting criteria in the definition of identified sites could cause HCAs to come into existence. An operator\nmust be able to demonstrate that it has periodically evaluated its pipeline to assure that there continue to\nbe no HCAs.\n- For transmission pipelines operating below 30 percent of SMYS in class 3 or 4 locations but not in an HCA,\nenhanced protection against third-party damage must be implemented in accordance with 192.935(d).\n- An operator must submit semi-annual \"performance measure\" reports in accordance with 192.945(a)\nindicating that there are no HCAs on its system.\nIf the periodic evaluation identifies that a new HCA exists, then the operator must prepare an integrity\nmanagement plan and meet all the requirements of subpart O.\nFAQ-188. Are jurisdictional gathering lines covered? [06/09/2004]\nNo. See 192.9.\nFAQ-190. How do LDC operators and/or regulators define \"distribution center\"? (necessary to\ndetermine amount of transmission line.) [06/29/2004]\n\"Distribution center\" is not defined in federal pipeline safety regulations. State definitions can vary. OPS\nrecognizes the actions of each state in defining what constitutes a distribution center.\nFAQ-247. For plastic transmission pipeline, must I meet all of the requirements in the sections\nspecified in Section 192.901 or just those requirements specifically directed at plastic\npipe? [08/31/2009]\nSection 192.901 states that of the requirements in subpart O only the requirements in Sections 192.917,\n192.921, 192.935 and 192.937 apply to plastic transmission pipeline. Each of these sections contains\nrequirements specifically applicable to plastic pipelines. Operators of plastic transmission pipelines must\nmeet the requirements in these sections that are specifically directed at plastic pipelines and need not\ncomply with other requirements in the designated sections.\n[Top]\nTime Periods FAQ\nFAQ-124. The rule includes many requirements that do not have specified time periods for\ncompletion. Examples include gathering and integrating data and information on the entire\npipeline, updating risk assessments when the results of assessments are available and\nidentifying HCAs for new pipe. How soon must these actions be completed? [03/09/2005]\nOPS expects operators to diligently pursue completion of actions required by the rule. At the same time, OPS\nrecognizes that these actions cannot occur immediately. OPS inspectors will assess an operator's plans,\nactions, and progress to verify that an operator is making a good faith effort to comply.\n\n<<<PAGE 5>>>\n\nFor immediate repairs, physical remediation may take some time, but should be done promptly. Immediate\naction is needed, however, to assure safety. OPS expects that actions to reduce pressure or shut in the line\nwill begin as soon as a defect meeting immediate repair criteria is identified.\nFor the specific example of identifying HCAs for newly-installed pipe, the requirements for newly-identified\nHCAs apply. Any HCAs on the new pipe must be identified and included in the baseline assessment plan\nwithin one year (192.905(c)). These new HCAs must be assessed within ten years from date of installation\nof the new pipe (192.921(g)).\nFAQ-179. How long does an operator that has had no HCAs, and therefore no integrity\nmanagement program, have to develop an integrity management program after it discovers a\nnew HCA? [08/19/2004]\nSection 192.905(c) requires that newly-identified HCAs be incorporated into an operator’s baseline\nassessment plan within one year from the date the area is identified. This requirement applies to operators\nwho previously had no HCAs and thus no IM program. They must develop a program, which includes a\nbaseline assessment plan, within one year to address the new areas (and any that may be identified later).\nFAQ-196. Is there any time limit between step 2 and step 3 in the ECDA process (indirect exam\nand direct exam)? [01/14/2005]; [Revised 01/15/2021]\nThe provisions of NACE RP0502-2010, which is incorporated into the rule by reference, govern the use of\nECDA. The recommended practice does not specify any time limit between step 2, Indirect Inspection, and\nstep 3, Direct Examination. OPS expects that operators would perform direct examinations shortly after\ncompleting the indirect inspection step, particularly if any severe indications are identified. Operators must\nbe prepared to justify that any delay between these two steps does not affect the continued validity of the\nindirect inspection results or represent an imminent threat to pipeline integrity. Also, refer to FAQ-232.\nFAQ-237. When must the baseline assessment be completed for piping installed after the\neffective date of the rule? [12/12/2006]\nAny newly-constructed gas transmission pipeline placed into service after the effective date of the integrity\nmanagement rule, February 14, 2004, is considered \"newly-installed\" for purposes of the rule. Therefore,\nthe baseline assessment on such piping is not due until 10 years following the installation of the pipeline.\nThe same applies to pipe in covered segments that operators replace. In this case, the operator may credit\nthis mileage as \"assessed\" for determining compliance with the 50% progress milestone. The ten-year due\ndate for conducting the baseline assessment for new pipe would also apply to pipe replaced under this\ncircumstance. This does not, however, relieve the operator of requirements to conduct tests required under\nother provisions of Part 192 associated with placing pipeline into service.\nFAQ–281. How do I extend the assessment schedule beyond 7 years? [02/11/2019]\nNotify PHMSA, in accordance with 49 CFR 192.949, of the need for an extension, which may not exceed 6\nmonths. The notification must be made 180 days prior to end of the calendar 7-year assessment deadline\nand include sufficient information to justify the extension. If unexpected conditions (such as weather-related\nconditions, assessment tool malfunctions, changes in field or operating conditions, or local gas supply issues)\nmake the 180-day notification impracticable, the operator must make the notification as soon as practicable\nand justify why shorter notice was necessary.\nFAQ–282. What constitutes sufficient information to justify extension of the assessment interval?\n[02/11/2019]\nDocumentation is required to comply with 49 CFR 192.947 and must include: An explanation as to why the\ndeadline could not be met and how it will not compromise safety, and identification of any additional actions\nnecessary to ensure public safety during the extension time period.\n[Top]\nIntegrity Management Programs FAQ\nFAQ-72. When must the Baseline Assessment Plan and Framework be completed?[05/20/2004]\nThe Baseline Assessment Plan and the Framework both must be prepared by December 17, 2004.\nFAQ-73. Will OPS prepare templates for Baseline Assessment Plans or Integrity Management\nProgram Frameworks that operators can use? [05/20/2004]\nNo. Because of the significant diversity in operator integrity management programs and processes, OPS does\n\n<<<PAGE 6>>>\n\nnot believe it is possible to develop a useful template that is broadly applicable across the industry. As long as\nthe basic requirements for these documents as specified in 49 CFR 192, Subpart O, are clearly and\ncompletely addressed, an operator is free to use a format for these documents that best supports its internal\nmanagement and operational needs.\nFAQ-74. What is the difference between an acceptable Integrity Management Framework and a\nfully developed Integrity Management Program? [05/18/2004]\nThe integrity management rule requires operators to develop and implement an Integrity Management\nProgram. The Integrity Management Program Framework lays the foundation for how the operator intends\nto develop and implement its program. As described in 192.911, the elements of an integrity management\nprogram must include several management, analytical, and operational processes. OPS expects that a\n\n<<<PAGE 7>>>\n\nnumber of operators may not have fully developed these aspects of their integrity management programs at\nthis time. OPS also recognizes that making significant, fundamental changes in operator management,\nanalytical, and operational processes and implementing new analytical tools takes time. As such, OPS does\nnot expect operators to have fully mature integrity management programs by the initial deadline (December\n17, 2004).\nAs described in 192.907, OPS expects the integrity management framework to describe how an operator\ncurrently addresses each element of an integrity management program, and their plans for how they intend\nto improve these processes to reach a fully-developed integrity management program. (OPS expects that an\noperator will have an established process or procedure for any activities that are being implemented).\nHence, the framework is a roadmap for developing a full integrity management program, and should include\ntimeframes for completing intended improvements. A fully developed integrity management program would\ninclude complete, well-documented, and effectively implemented processes for all integrity management\nprogram elements defined in 192.911. During OPS inspections, each operator's performance in implementing\nits framework will be examined.\nFAQ-76. What is an Integrity Management Program? [05/20/2004]\nAn Integrity Management Program begins with a written framework describing how the elements which\nfollow will be implemented. Elements required to be part of the program (and the paragraphs of the rule in\nwhich they are described) are:\n• An identification of all high consequence areas (192.905).\n• A baseline assessment plan (192.919 and 192.921).\n• An identification of threats to each covered pipeline segment, which must include data integration and a risk\nassessment. An operator must use the threat identification and risk assessment to prioritize covered segments for\nassessment (192.917) and to evaluate the merits of additional preventive and mitigative measures (192.935) for\neach covered segment.\n• A direct assessment plan, if applicable (192.923, and depending on the threat assessed, 192.925, 192.927, or\n192.929).\n• Provisions for remediating conditions found during an integrity assessment (192.933).\n• A process for continual evaluation and assessment (192.937).\n• If applicable, a plan for confirmatory direct assessment (192.931).\n• Provisions for adding preventive and mitigative measures to protect the high consequence area (192.935).\n• A performance plan as outlined in ASME/ANSI B31.8S, Section 9 that includes performance measures meeting the\nrequirements of 192.943.\n• Record keeping provisions (192.947).\n• A management of change process as outlined in ASME/ANSI B31.8S, Section 11.\n• A quality assurance process as outlined in ASME/ANSI B31.8S, Section 12.\n• A communication plan that includes the elements of ASME/ANSI B31.8S, Section 10, and that includes procedures\nfor addressing safety concerns raised by OPS and a State or local pipeline safety authority when a covered\nsegment is located in a State where OPS has an interstate agent agreement.\n• Procedures for providing (when requested), by electronic or other means, a copy of the operator’s risk analysis or\nintegrity management program to OPS and a State or local pipeline safety authority when a covered segment is\nlocated in a State where OPS has an interstate agent agreement.\n• Procedures for ensuring that each integrity assessment is being conducted in a manner that minimizes\nenvironmental and safety risks.\n• A process for identification and assessment of newly-identified high consequence areas. (192.905 and 192.921.)\nA fully-developed program involves complete documentation of how each element noted above will be\nperformed.\nFAQ-85. Can pipeline integrity management programs required by Subpart O be part of broader\ncorporate safety or integrity management systems (e.g., as described in API Publication 9100A,\nModel Environmental, Health and Safety (EHS) Management System)? [05/10/2004]\nPipeline integrity management programs must meet the requirements of Subpart O. As long as those\nrequirements are met, the programs may be part of broader company management systems. Elements of\nexisting management systems that can meet the requirements of the rule can be incorporated into the\npipeline integrity management program. Alternatively, operators may decide that processes and methods\n\n<<<PAGE 8>>>\n\nused in their pipeline integrity management programs could be useful for other purposes, and may integrate\nthem into broader company systems. OPS expects to see a description of the pipeline integrity management\nprogram that meets the requirements of the rule. OPS is willing to consider elements of broader company\nprograms and systems as part of this program description, provided they are sufficiently complete and robust\nto meet rule requirements. It is the operator’s responsibility to demonstrate how such existing corporate\nmanagement systems meet the requirements of the rule.\nFAQ-140. What level of detail does OPS expect to see in initial IM frameworks for each of the\nrequired program elements? [06/09/2004]\nThe level of detail in the framework will vary depending on the level of maturity of each program element. In\ngeneral, OPS expects that elements that must be implemented early will have considerable detail. This\nincludes identification of all high consequence areas, threat identification, and baseline assessment plans. The\ndescription in the framework of elements that will be implemented later may be more sketchy. These include\na continual process for evaluation and assessment, process for adding preventive and mitigative measures,\nand plans for confirmatory direct assessment. OPS would expect a reasonably complete description of the\nelements that relate to managing the IM program, e.g., quality assurance, management of change, and\nrecord keeping, although the IM program descriptions of these elements may become more detailed as\nexperience is gained.\nOPS would find unacceptable a situation in which a program element was being actively implemented but\nlittle or no description of that element is included in the IM framework/program. Program elements should\nbe thought out, documented, and receive the internal approvals the operator considers necessary before\nthey are implemented.\nFAQ-202. DA vendors offer processes that include proprietary analysis techniques (similar to how\nILI vendors use algorithms to classify anomalies). If my IMP written plan has to document my\nprocess for CIS/DCVG/etc. acceptance limits, how can I use vendors that wouldn’t give away\ntheir intellectual property? [12/06/2004]\nOperators are responsible for assuring accurate results. OPS expects that operators will have enough\nunderstanding to assure that the process accurately identifies pipeline anomalies and sufficiently assures\npipeline integrity. Operators will need to obtain enough information from their vendors to assure that they\nunderstand the capabilities and limitations of the vendor’s techniques including the tolerances of tools to be\nused.\nFAQ-238. What documentation must I include in my IM program to describe a \"process\" required\nby the rule? [04/18/2007]\nIM program documentation should include sufficient detail that an employee with appropriate experience\nand training can follow the procedure/process to achieve the desired objective consistently. The\nprocedure/process should address, as applicable:\n• Who is responsible for completing the process/procedure;\n• What are the objectives of the process/procedure;\n• What data/information is necessary for completing the process/procedure and where it is acquired;\n• How and When are the objectives of the process/procedure to be performed (detailed process/procedure steps);\n• How are key steps/results of the process/procedure documented (designated format) and where is the\ndocumentation stored;\n• How are process/procedure results communicated to key personnel;\n• What is the method for identifying and incorporating process/procedure improvements (reviews/feedback loops)\nFAQ-239. How much detail must I include when the rule requires that I \"justify\" an action or\ndecision? [08/02/2006]\nA documented justification should include technical rationale completely describing the basis or reason for\nthe decision. It is not sufficient simply to re-state the decision without describing why it was made.\n[Top]\nHCA Identification FAQ\n\n<<<PAGE 9>>>\n\nFAQ-14. When must covered pipeline segments subject to the rule be identified?[05/19/2004]\nAll High Consequence Areas (HCAs) must be identified as part of an operator’s initial integrity management\nframework, which must be completed by December 17, 2004. OPS will expect to see the operator's process\nfor identifying HCAs described in the initial framework. The rule allows operators to use existing data on the\ndensity of buildings intended for human occupancy near the pipelines, pro-rating any potential impact circles\nlarger than 660 feet in radius, until December 17, 2006.\nFAQ-15. Many operators have pre-defined segments on their pipeline (e.g., the length of pipe\nbetween two compressor stations or between consecutive isolation valves is considered a\nsegment). When OPS refers to segments in HCAs in the rule, in what context is the term segment\nused? [05/17/2004]\nAs used in the rule \"covered segment\" means a continuous segment of pipeline located in an HCA. If the\npotential impact circle methodology is used to identify HCAs, then, at a minimum, the covered segment\nbegins at the outermost edge of the first potential impact circle that meets the HCA criteria and extends\naxially to the outermost edge of the last contiguous potential impact circle that meets the HCA criteria. This\nlength of pipe may be subdivided to facilitate integrity assessments. Examples include such divisions as\npressure limiting stations, pipe size changes or other practical divisions.\nFAQ-16. How will an operator determine if a pipeline is in an HCA? [05/19/2004]\nThe potential impact radius must be calculated along the pipeline using the following formula:\nPIR = 0.69 * (p*d2)0.5\nWhere:\nPIR = Potential Impact Radius (in feet)\np = maximum allowable operating pressure (in pounds per square inch)\nd = nominal pipeline diameter (in inches), and\n0.69 is a constant applicable to natural gas (constants for other gases must be determined in\naccordance with Section 3.2 of ASME B31.8S-2001)\nPipeline segments for which the circle defined by the potential impact radius includes 20 or more buildings\nintended for human occupancy or an identified site are considered high consequence areas.\nAlternatively, Operators may treat all class 3 and 4 locations on their pipelines as high consequence areas. If\nthey elect to use this option, the use of potential impact circles is limited to looking for identified sites in any\nareas of their pipeline which are not class 3 or class 4 or to considering housing density and identified sites in\nareas where the potential impact circle radius would exceed 660 feet (i.e., for large-diameter, high- pressure\npipelines).\nOperators can select either method for use on their entire pipeline system, or may use each method only on\nselected portions of their pipeline.\nFAQ-17. What is an identified site? [05/19/2004]\nAn identified site is an area where people congregate near the pipeline meeting one of three criteria:\n• It is an outside area or open structure occupied by 20 or more persons on more than 50 days in any\n12-month period (the days need not be consecutive).\n• It is a building occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month\nperiod (the days and weeks need not be consecutive), or\n• It is a facility occupied by persons of limited mobility, e.g., hospitals, prisons, day-care facilities, schools,\nretirement communities or assisted living centers.\nFAQ-18. Are there practical limits on an operator’s search for identified sites?[05/17/2004]\nYes. An operator is expected to make a reasonable effort to identify sites meeting the criteria for \"identified\nsites\". The rule requires that operators consider information they glean from routine operations and\nmaintenance activities along the pipeline and from public officials responsible for safety or emergency\nresponse/planning who indicate to the operator that they would know of locations near the pipeline meeting\nthese criteria. If no public officials have such knowledge, then the operator must identify facilities that\neither: have visible signs; are licensed by a Federal, State, or local government agency; or appear on a list\n\n<<<PAGE 10>>>\n\nor map available from such an agency. See OPS’s Advisory Bulletin ADB-03-03 dated July 17, 2003,\n(available on this web site -- http://primis.phmsa.dot.gov/gasimp under \"key documents\") for additional\nguidance.\nFAQ-19. What are OPS expectations for operators to determine new or changed\nHCAs? [05/17/2004]\nOperators must continually monitor conditions along their pipeline. When they become aware of population\nor usage changes that create or change an HCA (e.g., population expands to encompass more of the area\nnear the pipeline right-of-way), this information should be factored, at least once per calendar year, into\ntheir integrity assessment planning, risk analysis, and consideration of the need for additional preventive\nand mitigative risk controls.\nFAQ-20. When must newly-identified HCAs be included in the program?[08/17/2004]\nOver time, new HCAs may be identified, such as when population distributions change or new sites that are\noccupied by 20 or more persons are identified. Operators must consider such changes to determine whether\nnew HCAs have been created. A newly-identified HCA must be incorporated into the integrity management\nprogram (including the baseline assessment plan) within one year of its identification. A baseline assessment\nfor pipeline segments in newly identified HCAs must be performed within ten years of its identification.\nFAQ-21. Must non-pipe elements of a pipeline system in HCAs (e.g., compressor stations) be\nidentified by 12/17/04? [05/17/2004]\nYes. While the assessment requirements of 49 CFR 192 Subpart O are applicable to line pipe, all other\nrequirements, including covered segment identification, are applicable to the entire pipeline, which is defined\nin 49 CFR 192.3 as all parts of those physical facilities through which gas moves in transportation. OPS\nexpects operators to understand which compressor stations and other facilities meet criteria to be treated as\ncovered segments in HCAs.\nFAQ-22. Why is it important that operators know the specific characteristics of high consequence\nareas their pipelines traverse? [08/14/2006]\nOperators need to know the characteristics of HCAs along their pipeline to make decisions required by the\nintegrity management rule. For example, the number/nature of housing units (e.g., large apartment\nbuildings) can affect the consequences of a leak or rupture, and thus affect the relative risk ranking of a\nsegment or decisions regarding preventive and mitigative measures. Section 3.3 of ASME/ANSI B31.8S\nspecifies additional consequence factors to consider, including security of gas supply, public convenience and\nnecessity, and the potential for secondary failures.\nFAQ-117. How often must an operator update its building density survey and list of identified\nsites to determine if new HCAs have been created? [06/09/2004]\nThe rule does not specify a frequency for updating data used to identify HCAs. Instead, the rule states that\noperators must complete an evaluation when they have information that the area around a segment not\npreviously identified as an HCA has changed so that it might now be one. Operators are expected to assure\nthat their HCA definitions are current. In an area in which there is rapid growth or change in the use of\nbuildings near the pipeline, that may require frequent updating. In an area where less growth is occurring,\nupdates could occur more infrequently. In any event, OPS would expect that operators would evaluate\nconditions along their pipelines at least annually to determine if they have changed.\nFAQ-119. Can I use normal operating pressure in my potential impact circle calculations if that\npressure is significantly below MAOP? [05/11/2004]\nNo. The rule requires that MAOP be used in calculating potential impact circles (PIC) to identify HCAs.\nPipelines can operate up to their MAOP, and integrity must be assured for such operation. Operators whose\nMAOP is significantly higher than their operating pressure could choose to derate their pipeline to reduce the\ncalculated size of PICs. In such a case, subsequent increases in MAOP would be subject to the requirements\nof Subpart K for uprating and would require that PICs be re-calculated.\nFAQ-120. Who is an appropriate safety authority for locating identified sites?[05/17/2004]\nSection 192.905 requires that information on identified sites be obtained from \"public officials with safety or\nemergency response or planning responsibilities\". That section also states that this \"could include officials on\n\n<<<PAGE 11>>>\n\na local emergency planning commission or relevant Native American tribal officials.\" The precise titles of the\nappropriate officials are likely to vary from community to community. They may include the fire chief, or\nequivalent, or public officials who would be responsible for evacuations in the event of a natural disaster.\nEach operator is responsible for identifying appropriate public officials. If an operator cannot locate public\nofficials who can provide information about locations meeting the criteria for identified sites, then the\noperator must use one of the other methods identified in Section 192.905 to locate them. See OPS’ Advisory\nBulletin ADB-03-03 dated July 17, 2003, (available on this web\nsite, http://primis.phmsa.dot.gov/gasimp/, under \"key documents\") for additional guidance.\nFAQ-121. Must facilities occupied by an operator's employees be considered in identifying\nHCAs? [05/11/2004]\nYes. The rule is intended to provide enhanced protection for gatherings of people, and gatherings of operator\nemployees are expected to gain the same enhanced protection. Areas, including buildings and facilities,\nwhere operator employees gather in sufficient numbers and on a sufficient number of days to meet criteria in\nthe definition of HCAs should be so classified.\nFAQ-143. When determining \"identified sites\", does one have to consider standing traffic on\nroads/expressways under the \"outside area or open structure\" portion of the definition? If so, is\nthere any guidance on how many people per vehicle should be used to compute the total of\n20? [02/20/2004]\nIdentified sites are defined as areas that are \"occupied\" by more than 20 persons for specified periods. While\nroads and expressways near pipelines could well carry enough traffic that more than 20 persons are in\nproximity to the pipeline at one time, these travelers can not be said to \"occupy\" that location. The definition\nof identified sites is intended to provide additional protection for areas where people stay for more than a few\nseconds or minutes. Most roads and expressways need not b","truncated":true,"body_characters":213813}