# Gas Distribution Integrity Management: FAQs - **operation:** document - **citation:** PHMSA Guidance, Gas Distribution Integrity Management: FAQs - **title:** Gas Distribution Integrity Management: FAQs - **source type:** guidance - **agency:** Pipeline and Hazardous Materials Safety Administration - **status:** guidance - **official:** true - **published on:** 2015-10-26 - **effective on:** 2015-10-26 - **summary:** Gas Distribution Integrity Management: FAQs Document faqsdimp20180727.docx (168.88 KB) The Integrity Management Program for Gas Distribution Pipelines Final Rule included a revision to 49 CFR Part 192.383 Excess Flow Valve Installation which mandated the installation of excess flow valves (EFV) in certain new and replaced residential service lines. Issued Date: Monday, October 26, 2015 - **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-guidance-gas-distribution-integrity-management-faqs-4824fb09.json - **markdown:** https://regulus.evalyn.ai/document/phmsa-guidance-gas-distribution-integrity-management-faqs-4824fb09.md - **app url:** https://regulus.evalyn.ai/document/phmsa-guidance-gas-distribution-integrity-management-faqs-4824fb09 - **source url:** https://www.phmsa.dot.gov/pipeline/gas-distribution-integrity-management/gas-distribution-integrity-management-faqs **body:** Gas Distribution Integrity Management: FAQs Document faqsdimp20180727.docx (168.88 KB) The Integrity Management Program for Gas Distribution Pipelines Final Rule included a revision to 49 CFR Part 192.383 Excess Flow Valve Installation which mandated the installation of excess flow valves (EFV) in certain new and replaced residential service lines. Issued Date: Monday, October 26, 2015 Distribution Integrity Management Frequently Asked Questions Revision Date: October 26, 2015 A. Excess Flow Valve RequirementsA. Excess Flow Valve Requirements A. Excess Flow Valve Requirements A. Excess Flow Valve Requirements The Integrity Management Program for Gas Distribution Pipelines Final Rule included a revision to 49 CFR Part 192.383 Excess Flow Valve Installation which mandated the installation of excess flow valves (EFV) in certain new and replaced residential service lines. Must an operator install an EFV in branch (split) service lines serving single‐family residences? No. Operators are required to install EFVs in new or replaced service lines serving single‐family residences. A service line serving a single‐family residence means a gas service line that begins at the fitting that connects the service line to the main and serves only one single‐family residence. Operators are not required but may choose to install EFVs in other applications as part of their risk mitigation strategy. Last Revision: 8/2/10 Must operators retrofit excess flow valves into existing service lines? Operators are only required to install EFVs where single family residential service lines are newly installed or are replaced for other reasons. The rule defines “replaced” as where the fitting that connects the service line to the main is replaced or the piping that is connected to this fitting is replaced. Replacement of other portions of a service line (e.g., near the meter) would not trigger the requirement to install an EFV. Last Revision: 8/2/10 Will excess flow valves provide protection for gas line breaks on customer piping inside a residence? EFVs required by this regulation are not designed or intended to protect against breaks or leaks on customer piping inside a home. EFVs are intended to cut off the supply of gas to the downstream service line in the event of major damage (e.g., a line severed by excavation damage). Last Revision: 8/2/10 Where must the EFV be installed on a service line? An operator is required to locate an excess flow valve as near as practical to the fitting connecting the service line to its source of gas supply. Examples of acceptable locations include installing an EFV that is built into the service tee, installing a short section of pipe between the service tee and the EFV to allow for the pipeline to be squeezed off upstream of the EFV, and installing an EFV out from under pavement to facilitate future access. Operators may use reasonable judgment in determining the most appropriate location for an EFV. Last Revision: 8/2/10 Will an operator have to notify other customer classifications of the availability of excess flow valves? No. The notification requirement was repealed. Last Revision: 8/2/10 Since installation of EFVs is mandated for all new and replaced service lines serving single‐family residences where EFVs are feasible, why do operators still need to report them? PHMSA is required by the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (PIPES) to collect this data. Last Revision: 8/2/10 Does the operator report the number of EFVs installed per year or the total number of EFVs installed on an operator’s system on the Annual Report form? Does the number include EFVs installed on services other than single‐family residences? Operators are to report the total number of EFVs installed in the system on service lines serving single‐ family residences and the estimated number of EFVs in their system at the end Of the year. Both metrics are reported on the Annual Report form in Part E – Excess Flow Valve (EFV) Data. Operators may, but are not required, include EFVs installed on branched services serving single‐family residences in the total. PHMSA is revised the Annual Report form for the 2010 calendar year to accommodate this information. Last Revision: 2/9/11 The regulation exempts the installation of EFVs on services which do not operate at a pressure of 10 psig or greater throughout the year. Can you give examples of types of documentation that would be acceptable in demonstrating this issue? Two possible methods to demonstrate that services operate at a pressure less than 10 PSIG include; (1) distribution system design documents, validated with actual pressure readings, which show that the main and therefore the associated services are designed to operate below 10 PSIG, or (2) actual pressure recordings or readings on all feeds which are upstream of the service(s) which are less than 10 psig. Last Revision: 8/2/10 B. General Distribution Integrity Management Program QuestionsB. General Distribution Integrity Management Program Questions B. General Distribution Integrity Management Program Questions B. General Distribution Integrity Management Program Questions DIMP Fundamentals Why did PHMSA mandate integrity management requirements for distribution pipeline systems? PHMSA’s regulations in part 192 have contributed to producing an admirable safety record. Nevertheless, incidents continue to occur, some of which involve significant consequences, including death and injury. It is not possible to significantly reduce high consequence pipeline incidents without reducing the likelihood of their occurrence on distribution pipelines. PHMSA used an integrity management approach similar to that used for transmission pipelines, with appropriate modification to reflect the different nature of distribution pipelines, to accomplish this safety improvement. These incidents often involve unique circumstances or characteristics of a particular pipeline system/ segment or its operation. The Pipeline Integrity, Protection, Enforcement, and Safety Act of 2006 (PIPES) mandated that PHMSA prescribe minimum standards for integrity management programs for distribution pipelines. The law provided for PHMSA to require operators of distribution pipelines to continually identify and assess risks on their distribution lines, to remediate conditions that present a potential threat to pipeline integrity, and to monitor program effectiveness. Instead of imposing additional prescriptive requirements for integrity management, PHMSA concluded that a requirement for operator‐specific programs to manage pipeline system integrity would be more effective given the diversity in distribution systems and the threats to which they may be exposed. Last Revision: 8/2/10 Why don’t distribution integrity management requirements focus on high consequence areas? The integrity management requirements for transmission pipelines are focused on portions of the pipeline where significant consequences could result if an incident occurs — so‐called “high consequence areas”. Transmission pipelines often traverse rural areas. This approach requires safety‐ improvement efforts to be focused on areas where consequences of an event would be more significant, in areas with greater human density, or more sensitive environment. Distribution pipelines are largely in developed, more populated areas, since they exist to deliver gas to those populations. As the population is in close proximity to much of these distribution systems, the consequences of an incident are similar throughout. For distribution pipelines, PHMSA concluded it is more appropriate that operators consider their entire pipelines under their integrity management programs. Last Revision: 8/2/10 Why aren’t distribution pipeline operators required to physically inspect their pipelines as are operators of other types of pipelines? The assessment techniques used on hazardous liquid and gas transmission pipelines (e.g., in‐line inspection, pressure testing, direct assessment) are not transferable to distribution pipe. Additionally, distribution pipelines are not subject to the same pressures as transmission pipelines and thus tend to leak rather than rupture. It is important that distribution integrity management programs be focused on identifying the conditions that can cause leaks and addressing them before the failures occur and on managing leaks effectively when and if they do occur. Last Revision: 8/2/10 Have State Agencies and PHMSA communicated with operators about Distribution Integrity? What has been discussed? States periodically host PHMSA Training and Qualifications (TQ) pipeline safety seminars for operators including those of municipal, master meters, and small LPG systems. The seminars included updates regarding proposed rules and recent final rulemakings. Communications about DIMP covered information such as the anticipated final rule date, GPTC guidance development, the purpose of the regulation, and the proposed requirements for the rule. PHMSA's Regional offices also hold safety seminars which cover new and proposed rules, current initiatives, and advisory bulletins. PHMSA and some States have and continue to speak at national and statewide operator association meetings as well as both statewide and local emergency assistance meetings. In 2007, prior to the DIMP Notice of Proposed Rulemaking PHMSA and the States, through NAPSR, created the DIMP State‐Federal Team. PHMSA and the States have been working together to advance a consistent understanding of the DIMP. We have worked jointly to identify frequently asked questions, write responses and to develop inspection forms and guidance. Our joint efforts promote more uniform and knowledgeable inspections. Additionally, PHMSA’s TQ organization is working to prepare and provide timely training to state and federal pipeline safety inspectors. The group continues to meet and work together through the implementation phase. Last Revision: 8/2/10 State and Federal Enforcement How does PHMSA foresee this rule being enforced for compliance? Inspectors will review the IM plan for quality and completeness and ensure that operators are doing what their plan says; and then inspect to see if their plan is effective. The procedures and records will be reviewed to verify that the operator performed them as written and in compliance with required dates. Enforcement will be consistent with current practice by the jurisdictional agencies. Last Revision: 8/2/10 Will operators be compared against other operators or national leak or safety data? PHMSA recognizes that operators need to develop a DIMP plan appropriate for the applicable threats, the operating characteristics of their specific distribution delivery system, and the customers that they serve. PHMSA and State partners intend to focus on each individual operator’s performance trends. Last Revision: 8/2/10 GPTC Guidance Must an operator follow the Gas Piping Technology Committee (GPTC) DIMP guidelines? No. The GPTC DIMP guidelines provide options which operators can use in implementing the high‐level requirements of the rule. The GPTC DIMP guidelines are not incorporated into the rule, and thus are not regulatory requirements. Operators may use other approaches to meet the high‐level requirements of the regulation as well, but in doing so they should be prepared to demonstrate to their regulators that their actions meet the rule requirements. PHMSA, State pipeline safety regulators and industry all participated in the development of the GPTC guidelines and have confidence that operators who use them in their programs will comply with the requirements of the rule. Last Revision: 8/2/10 How will the GPTC guidance be used by regulators? The GPTC Guide provides operators with valuable, consensus written guidance that can assist them in preparing their DIMP plan. The GPTC Guide is not regulation. An operator needs to follow the procedures they include in their plan. If their plan references the GPTC guidance, the regulator may verify that the operator has implemented the referenced guidance as written. However, as referenced in B.3.1 above, an operator may choose to use practices other than those in the Guide to meet compliance. The inspection is based on the regulation, not on GPTC guidance. Last Revision: 8/2/10 SHRIMP What is SHRIMP? SHRIMP (Simple, Handy, Risk‐based Integrity Management Plan) is a software application designed to assist operators in developing plans to manage the integrity of their distribution piping. It is geared toward the needs of small utilities that lack in‐house engineering and/or risk management expertise. The American Public Gas Association (APGA) Security and Integrity Foundation (SIF) received funding from PHMSA for development. Contact APGA www.apga.org or the SIF www.apgasif.org for information or questions pertaining to SHRIMP. Last Revision: 8/2/10 Is there a threshold size of an operator’s distribution system above which the SHRIMP tool should not be used? SHRIMP was designed to facilitate development of a distribution integrity management plan for smaller distribution systems that are not overly complex. While there is no system size or level of complexity for which use of SHRIMP is excluded, an operator must develop a plan that demonstrates to its oversight agency it has used reasonably available information to develop knowledge, identify threats, and determine how to manage system risks. Ongoing analysis of SHRIMP for larger, more complex systems indicates that these operators will very likely need to significantly expand upon a SHRIMP‐generated plan to demonstrate it has used reasonably available information to understand and determine how to manage system risks. These findings are being incorporated into inspection guidance. Last Revision: 11/10/10 Will my plan be in compliance if I use SHRIMP? The American Public Gas Association’s (APGA) Security and Integrity Foundation (SIF) developed the Simple Handy Risk based Integrity Management Plan (SHRIMP) to assist small operators in creating their written DIMP plan. Using SHRIMP does not necessarily mean that an operator will be in compliance with DIMP requirements. SHRIMP contains generic procedures. An operator's plan needs to reflect their own procedures, information sources, and practices. The APGA SIF is identifying areas where a SHRIMP user may need to enhance or modify the plan generated by this application to be in compliance with the pipeline safety regulations. Refer to APGA SIF website, www.apgasif.org, for the latest information. Last Revision: 7/15/11 C. Subpart P – Gas Distribution Pipeline Integrity ManagementC. Subpart P – Gas Distribution Pipeline Integrity Management C. Subpart P – Gas Distribution Pipeline Integrity Management C. Subpart P – Gas Distribution Pipeline Integrity Management C.1 §192.1001 What definitions apply to this subpart? C.1.1 What was used as a basis for defining “hazardous leaks”? The definition for hazardous leaks was drawn from the Gas Pipeline Technology Committee’s (GPTC), Guide for Gas Transmission and Distribution Piping Systems (The Guide) in Appendix G‐192‐11, Section 5.5 Leak grades. GPTC ANSI Z380 is an accredited American National Standards Institute (ANSI) standards committee that develops and publishes The Guide to assist natural gas pipeline operators in complying with Part 192. PHMSA’s Office of Pipeline Safety (OPS) is represented on this committee. Many operators now use the guidelines to classify leaks. Last Revision: 8/2/10 C.1.2 How was the definition “excavation damage” developed? PHMSA’s definition for excavation damage closely matches the definition used in the Common Ground Alliance’s (CGA) Damage Information Reporting Tool (DIRT). CGA is a national group involving operators of all types of underground facilities, as well as representatives of excavators and others who play an important part in preventing damage to underground facilities. PHMSA has omitted the phrase ‘‘or exposure’’ used in the DIRT definition, since this refers to damage from causes other than excavation (e.g., washout). Last Revision: 8/2/10 C.2 §192.1003 What do the regulations in this subpart cover? C.2.1 Must peak shaving and LNG facilities connected to our distribution pipeline system be considered in our DIMP? A DIMP plan must include all parts of a gas distribution pipeline subject to Part 192. Liquefied petroleum gas (LPG) facilities are regulated under Part 192. Where an LPG peak shaving facility is part of an operator’s distribution pipeline, it must be included in its DIMP plan. LNG facilities are regulated under Part 193 and therefore are not required to be included in a DIMP plan. However, PHMSA encourages operators to manage the risk from all of their facilities, and operators may elect to include LNG plants connected to their distribution pipelines in their DIMP plans as a means of doing so. Last Revision: 8/24/11 §192.1005 What must a gas distribution operator (other than a master meter or small LPG operator) do to implement this subpart? If an operator has both natural gas and LPG systems, must it have two separate DIMP plans or may it have a single plan? The operator has an option. An operator may choose to have a single DIMP plan, but it must address the requirements for both types of systems. The plan must take into account the different threats associated with the different products. Or an operator may choose to have separate DIMP plans for the natural gas and for the LPG system. Last Revision: 8/2/10 Must an operator have one DIMP plan covering all of its systems or could it have separate plans for different systems or service areas? An operator may have one master plan or separate plans, so long as its entire service area is covered. However, data from multiple plans is required to be consolidated for annual reporting purposes by state. Last Revision: 8/2/10 Will companies operating in several states need to develop individual DIMP plans for each state? Multi‐state operators may have one or more plans but must be able to filter by state their risk ranking, measures to reduce risk, performance measures and baselines, and other related data and information. The operator must address any additional requirements for each state since individual states may have the authority to impose additional requirements on intrastate lines the state regulates. Last Revision: 5/1/12 What is the relationship between an operations & maintenance manual and a DIMP plan? An O&M manual contains written procedures describing how operators conduct operations and maintenance activities on their system in accordance with Federal and State pipeline safety regulations. The activities address various threats to a pipeline’s integrity. A DIMP plan is a written integrity management plan which describes the analysis of the operator’s system, provides a relative risk analysis based on threats to the system, and prescribes additional or accelerated actions as needed to address risks identified in the plan. An operator may find it convenient to incorporate additional or accelerated actions, as determined to be necessary under its DIMP plan, into its O&M manual. As the operator evaluates the effectiveness of these actions, it may identify a need to modify those actions, potentially requiring additional modifications to its O&M plan. Note that States may require a revision history, a record of modifications to the O & M manual. Last Revision: 8/2/10 Is there a deadline by which operators must satisfy these requirements? Yes, by no later than August 2, 2011, operators of gas distribution pipelines, including master meter or small LPG operators, must develop and implement an integrity management program that includes a written integrity management plan. PHMSA recognizes that implementing IM plans involves learning leading to improvement and expects that programs will evolve over time as experience is gained. However, the program developed by August 2, 2011, must address all of the required plan elements. Last Revision: 8/2/10 How does the new DIMP rule impact operators of gas piping systems on military bases, Federal Government, or Indian Tribal Government land? PHMSA does not regulate pipeline systems owned and operated by the Military, Federal Government, or an Indian Tribal Government. A "person" is defined in Section 192.3 of the pipeline safety regulations as "any individual, firm, joint venture, partnership, corporation association, State, municipality, cooperative association, or joint stock association, and including any trustee, receiver, assignee, or personal representative thereof." The definition of "person" does not include the "Federal Government", "Military" or "Indian Tribal Governments". Gas pipeline systems owned and operated by the Military, Federal Government or Indian Tribal Governments are exempt from compliance with the pipeline safety regulations. However, if the system is owned and/or operated by a private entity, such as a contractor, then it must comply with the regulations under 49 C.F.R. 192. Therefore, the DIMP rule also impacts gas systems on military bases, land owned by the Federal Government, or on land owned by Indian Tribal Governments if the system is owned or operated by private entities. Last Revision: 11/10/10 Are operators required to include “farm taps” in their distribution integrity management plan? In the past, distribution, gathering, and transmission operators connected landowners directly to transmission and gathering pipelines often in exchange for the right to install the pipeline across a landowner’s property. This connection to the gas pipeline is commonly referred to as a “farm tap”. Although new farm taps are not installed nearly as frequently as they were in the past, “farm taps” are very common. The vast majority of “farm taps” meet the definition of a distribution line given that they do not meet the criteria to be classified as a gathering line or a transmission line. The “farm tap” is pipeline upstream of the outlet of the customer meter or connection to the customer meter, whichever is further downstream, and is responsibility of the operator. The pipeline downstream of this point is the responsibility of the customer. Some States require the operator to maintain certain portions of customer owned pipeline. The pipeline maintained by the operator must be in compliance with 49 Part 192. Operators of distribution, gathering, and transmission lines with “farm taps” must have a distribution integrity management program meeting the requirements of Subpart P for this distribution pipeline. The DIMP plan is not required to include the customer‐owned pipeline (unless required otherwise by State law). The operator having responsibility for operations and maintenance activities for the facility is responsible for developing and implementing the DIMP plan. Last Revision: 8/2/10 What do operators need to have implemented by August 2, 2011? By August 2, 2011, operators of gas distribution systems (other than a master meter or small LPG operator) must have developed and implemented an integrity management program that includes a written integrity management plan. The plan must include the operator’s procedures used to develop the seven elements listed in § 192.1007(a)‐(g) At a minimum, an operator must have taken the following actions: Developed and demonstrated an understanding of their system; Identified and considered threats to each gas distribution facility; Completed a risk evaluation and ranking of their distribution system; Developed criteria for deciding when risks require measures to reduce them; Determined the measures to reduce risk; Begun implementing the measures to reduce risk or have a plan to implement measures to reduce risk which includes an implementation schedule; Assessed the effectiveness of their leak management program and taken steps, if necessary, to correct deficiencies; Established a baseline measurement for each performance measure required by 192.1007(e)(1)(i)‐(v); Developed performance measures to evaluate the effectiveness of measures to reduce risk, have a plan to collect the performance measure data, and begun collecting data to establish a baseline measurement; Determined the appropriate period for conducting DIMP program evaluations; Reported performance measures required by 192.1007(g) for calendar year 2010; Collected data as needed for mechanical fitting failures resulting in hazardous leaks beginning January 1, 2011; and Identified records requiring retention and have maintained them. Last Revision: 3/10/11 Can PHMSA provide a generic DIMP plan that operators can use to develop their plan? PHMSA has not developed a generic DIMP plan. Commercially developed DIMP tools are available. Any tool will need to be customized for each specific operator. PHMSA has developed a template that can be used by Master Meter and small LPG operators subject to the requirements of §192.1015. That template can be found on the DIMP Resources page of the DIMP website (http://primis.phmsa.dot.gov/dimp/docs/GuidanceForMasterMeterAndSmallLiquefiedPetroleumGasPip elineOperators_11_09.pdf). Last Revision: 7/15/11 What are the requirements for distribution systems put in service after 8/2/2011? At the time a new distribution system is put into service, an operator must have developed and implemented an integrity management program that includes a written integrity management plan as specified by 49 CFR 192.1007 or 192.1015(b). Last Revision: 8/24/11 What are the requirements for distribution systems acquired after 8/2/2011? Operators must have a DIMP plan in place before taking over the operation of an acquired pipeline system. For purposes of distribution integrity management, an operator acquiring an existing pipeline system would be expected to either use the existing plan, after verifying its adequacy, or integrate the newly acquired system into their integrity management program. The new operator inherits the risk mitigation measures implemented and planned for implementation from the original operator’s plan unless they justify alternative measures to reduce risk. Last Revision: 8/24/11 §192.1007 What are the required elements of an integrity management plan? What does PHMSA see as the most critical elements of the regulation? All of the elements are critical. The plan must have written procedures for developing and implementing all the elements. Last Revision: 8/2/10 Can the DIMP plan incorporate by reference the operator’s procedures from their other manuals or plans? Yes, operators may reference and incorporate procedures from their operating and maintenance manual or other plans in their DIMP plan. Last Revision: 7/15/11 Knowledge The rule requires that an operator know its system. Must an operator excavate simply to gather information about parts of its system where it may not now have complete knowledge? No. Operators need to gather the information that they have reasonably available to develop an understanding of their pipeline systems. The data may currently reside in different locations or be the responsibility of different groups within the company. Part of this development includes identifying information that is not now known, but which is needed to develop an understanding of the characteristics of the pipeline and necessary to assess applicable threats and to analyze its risk. Last Revision: 8/2/10 There are some characteristics about an operator’s system that may not be known during the development of the IM plan. What are PHMSA’s expectations for filling those voids? Operators need to use opportunities that arise, such as the pipeline being excavated for operation, maintenance, or other reasons, to collect additional information needed to better understand their pipeline system. Operators are required to incorporate into their plan and implement procedures to gather this information when the opportunity exists. This information may or may not prompt a reevaluation of the plan, but at a minimum, will be considered for analysis during the next scheduled evaluation. Records need to be maintained and updated to reflect changes to the system. Over time, PHMSA expects that an operator’s understanding of its pipeline system and the quality of their risk analyses will improve. If an operator’s records have been destroyed or are no longer available, the operator must collect sufficient information, perform appropriate tests, and create records or maps for the safer operation, maintenance, and emergency response of the system. Last Revision: 8/2/10 Who qualifies as a “subject matter expert”? Subject matter experts are simply people who have specific knowledge of topics and/or facilities under consideration. This includes the operator’s operations and maintenance personnel – the people who construct, inspect, maintain and oversee its distribution facilities day‐to‐day. For some operators, this may include contractor personnel that have performed construction or operation and maintenance activities for a long period of time or for unique and/or special circumstances. In some instances, an operator may want to involve subject matter experts beyond its employees. For example, if analysis shows that an operator is having difficulty minimizing the detrimental effects of stray currents, the operator may want to involve in its program an outside person with expertise or specialized knowledge in this area. Last Revision: 8/2/10 What data will be required to be collected for new gas pipelines going in the ground? The DIMP regulation prescribes two minimum data elements that must be captured and retained on any new distribution pipelines: the location where the new pipeline is installed and the material of which it is constructed. Pipeline, defined in §192.3, means all parts of those physical facilities through which gas moves in transportation, including pipe, valves, and other appurtenance attached to pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies. Additionally, operators must collect data about new gas pipelines which will be needed to assess current and future threats and risks to the pipeline’s integrity. This includes information about the characteristics of the pipeline’s design, operations, and the environmental factors where the pipeline is installed. In addition, an operator must also consider the data it needs to comply with the various record keeping requirements in Part 192 such as those for pipeline design, testing, construction, corrosion control, customer notification, uprating, surveying, patrolling, monitoring, inspection, operation, maintenance, emergencies, and operator qualification. The GPTC Guide, Appendix G‐192‐17, provides operators with guidance on explicit requirements for reports, inspections, tests, written procedures, records and similar actions. States may have additional requirements. Last Revision: 8/2/10 What comprises "reasonably available" information? PHMSA does not intend that operators expend excessive effort, review every record available in their archives, or explore every nuance about their pipelines. At the same time, PHMSA expects that operators will devote sufficient effort to develop as thorough an understanding of their pipelines as they can while using reasonable effort. The availability of records will vary among operators. Some operators may retain records for many years and others only for the length of time required by Part 192. Some data is stored electronically, and some is paper based. Additionally, some records are stored on‐site, and other records may be stored off‐site, such as at regional offices or long-term storage facilities. Any record which the operator can access is reasonably available. All records required by Parts 191 and 192 are reasonably available. Operators need to review all records that are relevant to the current condition of the pipe or have a significant impact on the integrity of the pipe. For example, a steel pipe may have been brought under adequate cathodic protection five years ago but was not under cathodic protection in prior years. Any records showing that the pipe was not under cathodic protection, is relevant to the current condition of the pipe. Operators must identify additional information that is needed to fill gaps due to missing, inaccurate, or incomplete records and develop a plan to collect it. They may collect this information through their normal activities including those that go beyond those activities specified in Part 192. For example, missing facility location, material and condition data can be gained when the pipe is located and/or exposed. Operators could involve maintenance personnel in their information collection activities, surveying them about unusual circumstances they have encountered in their activities and/or asking them to review resulting system descriptions and identify any information they believe is useful that is not already included. Last Revision: 3/10/11 Must an operator’s plan include the sources used to demonstrate an understanding of its gas distribution system? An operator needs to be able to demonstrate to regulators that they have an understanding of their gas distribution system developed using sources of information that are “reasonably available”. The plan should identify the information sources. Examples of sources that are reasonably available include documents, records, field notes, maps, historical procedures and design standards, bill of materials, procurement records and specifications, and information obtained from subject matter experts. These sources are used to identify the characteristics of the pipeline’s design, operations and environmental factors that are necessary to assess the applicable threats and risks to the distribution system. Operators also need to consider information gained from past design, operations, and maintenance. In order to verify that an operator has met this requirement, the inspector may ask the operator for information about the sources such as: the name of the documents, the time period covered by the documents, the document’s location and format (e.g. electronic, paper, or subject matter expert interview, etc.), the forms used to collect data, the fields on the forms, the instructions used to complete the forms, and a history of how this information collection changed over time. Last Revision: 3/10/11 With the incorporation of ASTM D2513‐09a for Polyethylene (PE) effective March 6, 2015, would the Ultraviolet (UV) exposure limits be retroactive? In other words, if pipe that is manufactured before the effective date meets the new UV exposure limits, would those limits apply or would it still fall under the old 2 year limit per ASTM D2513‐99? It depends when the PE pipe was put into use (i.e. installed) based on the code language in §192.59 (a) and considering that 49 CFR Subpart B is not a retroactive subpart. If the PE pipe was not put into use until on or after the effective date, and an operator can demonstrate it meets ASTM D2513‐09a, the UV exposure limit (or more appropriately Outdoor Storage Stability) requirements in Section 4.10 of ASTM D2513‐09a would apply even if the PE pipe was manufactured prior to the effective date. If the PE pipe was put into use prior to the effective date, the Outdoor Storage Stability limits in A1.5.7 of ASTM D2513‐99 would apply. Records are critical for determination of adequacy, with the onus on the operator, to demonstrate which version(s) the PE pipe was manufactured to. What constitutes adequate records would likely vary, but it could include purchasing orders or other records between the operator and manufacturer, certificates of conformance from the manufacturer, and potentially other documentation from an operator’s QA/QC program. Such records should be tied to the specific lot numbers and segments in question (i.e. general certificates of conformance from a manufacturer not tied to lot numbers would typically not suffice.) Ultimate determination of adequacy would be up to whichever entity regulates the operator. If an operator cannot properly demonstrate PE pipe manufactured prior to the effective date meets ASTM D2513‐09a, it is reasonable for a regulator to determine that the more conservative limits in ASTM D2513‐99 would apply. Last Revision: 7/1/15 Identify Threats Must an operator use a computer‐based risk analysis model? No. Risk analysis is a process of understanding what factors affect the risk posed by a pipeline system and which are most important. For a complex system, use of a computer‐based risk model may make this process easier, but the use of a computer-based modeling system is not required. For a simple distribution pipeline system, it is possible to do a credible analysis that leads to an understanding of factors/areas that are important to risk without use of such a model. The GPTC guidelines include suggestions for simpler approaches. Last Revision: 8/2/10 Must each of the 8 threats be considered for every pipeline type? Yes, an operator’s DIMP plan must consider each of the 8 threats for the pipeline system. The eight threats categories are corrosion, natural forces, excavation damage, other outside force damage, material or welds, equipment failure, incorrect operations, and other concerns that could threaten the integrity of its pipeline. Some threats may not be relevant to all pipe types or all operators’ circumstances. Some threats may apply but are not obvious. For example, corrosion is not a threat to plastic facilities but could be a threat to tracer wires, transition fittings, or to short pieces of metal main or services in a plastic system. Material or weld failures could apply to plastic (the brittle failure issue and potential for faulty fusion joints, for instance). Excavation damage occurs regardless of the pipe material. Last Revision: 2/9/11 The DIMP requirements include knowing the condition of facilities that are at risk for potential damage from external sources. Cross bores of gas lines in sewers have been reported at 2‐3 per mile in high risk areas – predominately where trenchless installation methods were used for gas line installs and where sewers and gas lines are in the proximity of each other. Does the potential for cross bores of sewers resulting in gas lines intersecting with sewers need to be determined? Yes, the threat of excavation damage includes consideration of potential or existing cross bore of sewers which have resulted in gas lines intersecting with sewers. Pursuant to § 192.1007(a)(2), the operator must consider information gained from past design, operations, and maintenance. If operators used trenchless technologies without taking measures to locate sewer laterals and other unmarked facilities during construction, there may be a risk that their facilities were installed through the foreign facility. If this excavation damage threat applies to the operator, they must evaluate its risk to their system. Depending on the results of the risk evaluation, they may need to identify and implement measures to reduce this risk to existing and future facilities. Last Revision: 3/10/11 Are pipeline “overbuilds” a threat? Should the “other concerns” threat category contain pipeline overbuilds (building put over a pipeline)? A pipeline “overbuild” occurs when an existing pipeline facility is enclosed within or a building is built on top of the pipeline. Pipeline overbuilds are an environmental factor to be considered in evaluating the degree of risk to a pipeline. A gas line under a building - **truncated:** true - **body characters:** 94822