# Pipeline Safety: Safety of Gas Transmission Pipelines

- **operation:** document
- **citation:** 76 FR 53086
- **title:** Pipeline Safety: Safety of Gas Transmission Pipelines
- **source type:** rulemaking
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** proposed
- **official:** true
- **published on:** 2011-08-25
- **effective on:** Not available
- **summary:** PHMSA is considering whether changes are needed to the regulations governing the safety of gas transmission pipelines. In particular, PHMSA is considering whether integrity management (IM) requirements should be changed, including adding more prescriptive language in some areas, and whether other issues related to system integrity should be addressed by strengthening or expanding non-IM requirements. Among the specific issues PHMSA is considering concerning IM requirements is whether the definition of a high-consequence area (HCA) should be revised, and whether additional restrictions should be placed on the use of specific pipeline assessment methods. With respect to non-IM requirements, PHMSA is considering whether revised requirements are needed on new construction or existing pipelines concerning mainline valves, including valve spacing and installation of remotely operated or automatically operated valves; whether requirements for corrosion control of steel pipelines should be strengthened; and whether new regulations are needed to govern the safety of gathering lines and underground gas storage facilities. Additional issues PHMSA is considering are addressed in the SUPPLEMENTARY INFORMATION Section under background.
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Federal Register, Volume 76 Issue 165 (Thursday, August 25, 2011) [Federal Register Volume 76, Number 165 (Thursday, August 25, 2011)] [Proposed Rules] [Pages 53086-53102] From the Federal Register Online via the Government Publishing Office [ www.gpo.gov ] [FR Doc No: 2011-21753] ======================================================================= ----------------------------------------------------------------------- DEPARTMENT OF TRANSPORTATION Pipeline and Hazardous Materials Safety Administration 49 CFR Part 192 [Docket No. PHMSA-2011-0023] RIN 2137-AE72 Pipeline Safety: Safety of Gas Transmission Pipelines AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA), Department of Transportation (DOT). ACTION: Advance notice of proposed rulemaking (ANPRM). ----------------------------------------------------------------------- SUMMARY: PHMSA is considering whether changes are needed to the regulations governing the safety of gas transmission pipelines. In particular, PHMSA is considering whether integrity management (IM) requirements should be changed, including adding more prescriptive language in some areas, and whether other issues related to system integrity should be addressed by strengthening or expanding non-IM requirements. Among the specific issues PHMSA is considering concerning IM requirements is whether the definition of a high-consequence area (HCA) should be revised, and whether additional restrictions should be placed on the use of specific pipeline assessment methods. With respect to non-IM requirements, PHMSA is considering whether revised requirements are needed on new construction or existing pipelines concerning mainline valves, including valve spacing and installation of remotely operated or automatically operated valves; whether requirements for corrosion control of steel pipelines should be strengthened; and whether new regulations are needed to govern the safety of gathering lines and underground gas storage facilities. Additional issues PHMSA is considering are addressed in the SUPPLEMENTARY INFORMATION Section under background. DATES: Persons interested in submitting written comments on this ANPRM must do so by December 2, 2011. PHMSA will consider late filed comments as far as practicable. FOR FURTHER INFORMATION CONTACT: Mike Israni, by telephone at 202-366- 4571, by fax at 202-366-4566, or by mail at U.S. DOT, PHMSA, 1200 New Jersey Avenue, SE., PHP-1, Washington, DC 20590-0001. ADDRESSES: You may submit comments identified by the docket number PHMSA-2011-0023 by any of the following methods: Web Site: http://www.regulations.gov . Follow the online instructions for submitting comments. Fax: 1-202-493-2251. Mail: Hand Delivery: U.S. DOT Docket Management System, West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue, SE., Washington, DC 20590-0001 between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. Instructions: If you submit your comments by mail, submit two copies. To receive confirmation that PHMSA received your comments, include a self-addressed stamped postcard. Note: Comments are posted without changes or edits to http://www.regulations.gov , including any personal information provided. There is a privacy statement published on http://www.regulations.gov . A glossary of terms used in this document can be found at the following Web site: http://primis.phmsa.dot.gov/comm/ . SUPPLEMENTARY INFORMATION: I. Background Congress has authorized Federal regulation of the transportation of gas by pipeline under the Commerce Clause of the U.S. Constitution. The authorization is codified in the Pipeline Safety Laws (49 U.S.C. 60101 et seq.), a series of statutes that are administered by PHMSA. PHMSA promulgated comprehensive minimum safety standards for the transportation of gas by pipeline under the Pipeline Safety [[Page 53087]] Regulations (PSR; 49 CFR parts 190-199). Congress established the current framework for regulating natural gas pipelines in the Natural Gas Pipeline Safety Act of 1968, Public Law 90-481, which has since been recodified at 49 U.S.C. 60101 et seq. That law delegated to DOT the authority to develop, prescribe, and enforce minimum Federal safety standards for the transportation of gas, including natural gas, flammable gas, or toxic or corrosive gas, by pipeline. Congress has since enacted additional legislation that is currently codified in the Pipeline Safety Laws. In 1992, Congress required regulations be issued to define the term ``gathering line'' and establish safety standards for certain ``regulated gathering lines.'' In 1996, Congress directed that DOT conduct demonstration projects evaluating the application of risk management principles to pipeline safety regulations, and mandated that regulations be issued for the qualification and testing of certain pipeline personnel. In 2002, Congress required that DOT issue regulations requiring operators of gas transmission pipelines to conduct risk analyses and to implement IM programs under which pipeline segments in HCAs would be subject to a baseline assessment within ten years and re-assessments at least every seven years. PHMSA administers compliance with these statutes and has promulgated comprehensive safety standards and regulations for the transportation of natural gas by pipeline. That includes regulations for the: Design and construction of new pipeline systems or those that have been relocated, replaced, or otherwise changed (subparts C and D of 49 CFR part 192). Protection of steel pipelines from the adverse effects of internal and external corrosion (subpart I of 49 CFR part 192). Pressure tests of new pipelines (subpart J of 49 CFR part 192). Operation and maintenance of pipeline systems, including establishing programs for public awareness and damage prevention, and managing the operation of pipeline control rooms (subparts L and M of 49 CFR part 192). Qualification of pipeline personnel (subpart N of 49 CFR part 192). Management of the integrity of pipelines in HCAs (subpart O of 49 CFR part 192). The IM requirements of subpart O of 49 CFR part 192 apply to areas called high consequence areas or HCA's. An integrity management program is a documented set of policies, processes, and procedures that are implemented to ensure the integrity of a pipeline. In accordance with pipeline safety regulations for gas transmission pipelines (subpart O of 49CFR part 192) an operator's integrity management program must include, at a minimum, the following elements: a. An identification of all high consequence areas; b. A baseline assessment plan; c. An identification of threats to each covered pipeline segment, which must include data integration and a risk assessment. An operator must use the threat identification and risk assessment to prioritize covered segments for assessment and to evaluate the merits of additional preventive and mitigative measures for each covered segment; d. A direct assessment plan, if applicable; e. Provisions for remediating conditions found during an integrity assessment; f. A process for continual evaluation and assessment; g. If applicable, a plan for confirmatory direct assessment meeting the requirement; h. Provisions for adding preventive and mitigative measures to protect the high consequence area; i. A performance plan that includes performance measures; j. Record keeping provisions; k. A management of change process; l. A quality assurance process; m. A communication plan that includes procedures for addressing safety concerns raised by PHMSA or a State or local pipeline safety authority; n. Procedures for providing (when requested) a copy of the operator's risk analysis or integrity management program to PHMSA or a State or local pipeline safety authority; and o. Procedures for ensuring that each integrity assessment is being conducted in a manner that minimizes environmental and safety risks; p. A process for identification and assessment of newly-identified high consequence areas. A high consequence area is a location that is specially defined in the pipeline safety regulations as an area where pipeline releases could have greater consequences to health and safety or the environment. Regulations require a pipeline operator to take specific steps to ensure the integrity of a pipeline for which a release could affect an HCA and, thereby, the protection of the HCA. The PSR provide gas transmission pipeline operators with two options by which to identify which segments of their pipelines are in HCAs: (1) Reliance on class locations that historically have been part of the pipeline safety regulations for identifying pipelines in more-populated areas, or (2) determining segments for which a specified number of structures intended for human occupation or a so-called identified site (representing areas where people congregate) are located within the potential impact radius of a hypothetical pipeline rupture and subsequent explosion. Other recent rulemaking have addressed different but related issues relative to pipeline safety. On October 18, 2010 (75 FR 63774) PHMSA published an ANPRM titled ``Pipeline Safety: Safety of On-Shore Hazardous Liquid Pipelines.'' In that rulemaking, PHMSA is considering whether changes are needed to the regulations covering hazardous liquid onshore pipelines. In particular, PHMSA sought comment on whether it should extend regulation to certain pipelines currently exempt from regulation; whether other areas along a pipeline should either be identified for extra protection or be included as additional HCAs for IM protection; whether to establish and/or adopt standards and procedures for minimum leak detection requirements for all pipelines; whether to require the installation of emergency flow restricting devices (EFRDs) in certain areas; whether revised valve spacing requirements are needed on new construction or existing pipelines; whether repair timeframes should be specified for pipeline segments in areas outside the HCAs that are assessed as part of the IM; and whether to establish and/or adopt standards and procedures for improving the methods of preventing, detecting, assessing and remediating stress corrosion cracking (SCC) in hazardous liquid pipeline systems. On December 4, 2009, PHMSA issued the Distribution Integrity Management Final Rule, which extends the pipeline integrity management principles that were established for hazardous liquid and natural gas transmission pipelines, to the local natural gas distribution pipeline systems. This regulation, which became effective in August of 2011, requires operators of local gas distribution pipelines to evaluate the risks on their pipeline systems, to determine their fitness for service, and to take action to address those risks. For older gas distribution systems, the appropriate mitigation measures could involve major pipe rehabilitation, repair, and replacement programs. At a minimum, these measures are needed to requalify those systems as being fit for service. [[Page 53088]] II. Advance Notice of Proposed Rulemaking PHMSA believes that the IM requirements applicable to gas transmission pipelines contained in the Pipeline Safety Regulations (49 CFR parts 190-199) have increased the level of safety associated with the transportation of gas in HCA's. Still, incidents with significant consequences continue to occur on gas transmission pipelines (e.g., incident in San Bruno, CA September 9, 2010). PHMSA has also identified concerns during inspections of gas transmission pipeline operator IM programs that indicate a potential need to clarify and enhance some requirements. PHMSA is now considering whether additional safety measures are necessary to increase the level of safety for those pipelines that are in non-HCA areas as well as whether the current IM requirements need to be revised and enhanced to assure that they continue to provide an adequate level of safety in HCAs. Within this ANPRM, PHMSA is seeking public comment on 14 specific topic areas in two broad categories. 1. Should IM requirements be revised and strengthened to bring more pipeline mileage under IM requirements and to better assure safety of pipeline segments in HCAs? Specific topics include: Modifying the definition of an HCA. Strengthening the Integrity Management requirements in part 192. Modifying repair criteria. Revising the requirements for collecting, validating, and integrating pipeline data. Making requirements related to the nature and application of risk models more prescriptive. Strengthening requirements for applying knowledge gained through the IM program. Strengthening requirements on the selection and use of assessment methods, including prescribing assessment methods for certain threats (such as manufacturing and construction defects, SCC, etc.) or in certain situations such as when certain knowledge is not available or data is missing. 2. Should non-IM requirements be strengthened or expanded to address other issues associated with pipeline system integrity? Specific topics include: Valve spacing and the need for remotely- or automatically- controlled valves. Corrosion control. Pipe with longitudinal weld seams with systemic integrity issues. Establishing requirements applicable to underground gas storage. Management of Change. Quality Management Systems (QMS). Exemptions applicable to \1\ facilities installed prior to the regulations. --------------------------------------------------------------------------- \1\ As described below, these exemptions relate to allowable maximum operating pressure for pipelines that were in service before the initial gas pipeline safety regulations were published. These pipelines are commonly known as ``grandfathered'' pipelines. --------------------------------------------------------------------------- Gathering lines. Each topic is discussed in more detail in this document. A. Modifying the Definition of HCA Part 192 has historically included requirements delineating pipeline segments by class location based on the population density near the pipeline. Class locations are based on the number of buildings intended for human occupancy that exist within a ``class location unit,'' defined as an area extending 220 yards (100 meters) on either side of the centerline of any continuous one-mile (1.6 kilometers) length of pipeline. Class locations are defined in Sec. 192.5 as: Class 1--10 or fewer buildings intended for human occupancy within a class location unit. Class 2--more than ten but less than 46 buildings intended for human occupancy. Class 3--46 or more buildings intended for human occupancy. Class 4--any class location unit where buildings with four or more stories are prevalent. Part 192 provides additional protection for higher class location areas, principally through provisions that require pipe in these higher class locations to operate at lower stress levels. With the advent of IM requirements, PHMSA introduced a new mechanism in part 192 to define pipeline segments to which additional requirements should apply based on the population at risk in the vicinity of the pipeline. HCAs are defined in Sec. 192.903 using either of two methods. Operators are allowed to pick the method they use to identify their HCAs. Method 1 builds on the traditional concept of class locations. Under this method, all pipeline segments in Class 3 and 4 locations are within an HCA. In addition, pipeline segments in Class 1 and 2 locations are within an HCA if an ``identified site'' is located within the ``potential impact circle.'' Identified sites are defined as areas in which 20 or more persons congregate for a specified number of days each year or facilities occupied by persons who are confined, of impaired mobility, or would be difficult to evacuate. Method 2 defines HCAs based solely on potential impact circles. A potential impact circle is an estimated zone in which the failure of a pipeline could have significant impact on people or property. The radius of the potential impact circle is calculated using a formula specified in the regulations that is based on the diameter and operating pressure of the pipeline. A pipeline segment is identified as an HCA if the potential impact circle includes 20 or more buildings intended for human occupancy or an identified site, regardless of class location. Some gas transmission pipeline operators do not collect data concerning the number of buildings within class location units along their pipeline, but rather design all of their pipelines as though they were in a Class 3 or 4 location. This approach is often used by operators of gas distribution companies that also operate small amounts of pipeline meeting part 192's definition as transmission pipeline. Method 1 was included in the definition of an HCA in deference to these operators, allowing them to avoid the additional costs associated with collecting data on nearby buildings that they have not previously collected. Method 2 was presumed to identify pipeline segments where incidents could produce high consequences more accurately and is typically used by pipeline operators who have collected data on local structures to determine class locations. PHMSA regulates approximately 297,000 miles of onshore gas transmission pipelines. Of these, approximately 30,300 miles (10.2%) are in Class 2 locations, approximately 33,500 miles (11.3%) are in Class 3 locations, and approximately 1600 miles (0.54%) are in Class 4 locations. Operators have identified approximately 19,000 miles (6.4%) of gas transmission pipeline to be within an HCA. IM requirements in subpart O of part 192 specify how pipeline operators must identify, prioritize, assess, evaluate, repair and validate; through comprehensive analyses, the integrity of gas transmission pipelines in HCAs. Although operators may voluntarily apply IM practices to pipeline segments that are not in HCAs, the regulations do not require operators to do so. A gas transmission pipeline ruptured in San Bruno, California on September 9, 2010, resulting in eight deaths and considerable property damage. As a result of this event, public concern has been raised regarding whether safety requirements applicable to pipe in populated areas can be improved. PHMSA is thus considering expanding the definition of an HCA so that more [[Page 53089]] miles of pipe are subject to IM requirements. Questions A.1. Should PHMSA revise the existing criteria for identifying HCAs to expand the miles of pipeline included in HCAs? If so, what amendments to the criteria should PHMSA consider (e.g., increasing the number of buildings intended for human occupancy in Method 2?) Have improvements in assessment technology during the past few years led to changes in the cost of assessing pipelines? Given that most non-HCA mileage is already subjected to in-line inspection (ILI) does the contemplated expansion of HCAs represent any additional cost for conducting integrity assessments? If so, what are those costs? How would amendments to the current criteria impact state and local governments and other entities? A.2. Should the HCA definition be revised so that all Class 3 and 4 locations are subject to the IM requirements? What has experience shown concerning the HCA mileage identified through present methods (e.g., number of HCA miles relative to system mileage or mileage in Class 3 and 4 locations)? Should the width used for determining class location for pipelines over 24 inches in diameter that operate above 1000 psig be increased? How many miles of HCA covered segments are Class 1, 2, 3, and 4? How many miles of Class 2, 3, and 4 pipe do operators have that are not within HCAs? A.3. Of the 19,004 miles of pipe that are identified as being within an HCA, how many miles are in Class 1 or 2 locations? A.4. Do existing criteria capture any HCAs that, based on risk, do not provide a substantial benefit for inclusion as an HCA? If so, what are those criteria? Should PHMSA amend the existing criteria in any way which could better focus the identification of an HCA based on risk while minimizing costs? If so, how? Would it be more beneficial to include more miles of pipeline under existing HCA IM procedures, or, to focus more intense safety measures on the highest risk, highest consequence areas or something else? If so, why? A.5. In determining whether areas surrounding pipeline right-of- ways meet the HCA criteria as set forth in part 192, is the potential impact radius sufficient to protect the public in the event of a gas pipeline leak or rupture? Are there ways that PHMSA can improve the process of right-of-ways HCA criteria determinations? A.6. Some pipelines are located in right-of-ways also used, or paralleling those, for electric transmission lines serving sizable communities. Should HCA criteria be revised to capture such critical infrastructure that is potentially at risk from a pipeline incident? A.7. What, if any, input and/or oversight should the general public and/or local communities provide in the identification of HCAs? If commenters believe that the public or local communities should provide input and/or oversight, how should PHMSA gather information and interface with these entities? If commenters believe that the public or local communities should provide input and/or oversight, what type of information should be provided and should it be voluntary to do so? If commenters believe that the public or local communities should provide input, what would be the burden entailed in providing provide this information? Should state and local governments should be involved in the HCA identification and oversight process? If commenters believe that state and local governments be involved in the HCA identification and oversight process what would the nature of this involvement be? A.8. Should PHMSA develop additional safety measures, including those similar to IM, for areas outside of HCAs? If so, what would they be? If so, what should the assessment schedule for non-HCAs be? A.9. Should operators be required to submit to PHMSA geospatial information related to the identification of HCAs? A10. Why has the number of HCA miles declined over the years? A.11. If commenters suggest modification to the existing regulatory requirements, PHMSA requests that commenters be as specific as possible. In addition, PHMSA requests commenters to provide information and supporting data related to: The potential costs of modifying the existing regulatory requirements pursuant to the commenter's suggestions. The potential quantifiable safety and societal benefits of modifying the existing regulatory requirements. The potential impacts on small businesses of modifying the existing regulatory requirements. The potential environmental impacts of modifying the existing regulatory requirements. B. Strengthening Requirements To Implement Preventive and Mitigative Measures for Pipeline Segments in HCAs Section 192.935 requires gas transmission pipeline operators to take additional measures, beyond those already required by part 192, to prevent a pipeline failure and to mitigate the consequences of a potential failure in an HCA. The additional measures to be taken are not specified. Rather, operators are required to base selection and implementation of these measures on the threats the operator has identified to each pipeline segment. Operators must use their comprehensive risk analyses to identify additional measures appropriate to the HCA. However, the rule establishes no objective criteria by which decisions concerning additional measures must be made, nor does it establish a standard by which such evaluations are to be performed. PHMSA is considering revising the IM requirement to add new requirements governing selection of additional preventive and mitigative measures. The current regulations state that these additional measures might include: Installing Automatic Shut-off Valves or Remote Control Valves; Installing computerized monitoring and leak detection systems; replacing pipe segments with pipe of heavier wall thickness; providing additional training to personnel on response procedures; conducting drills with local emergency responders; and implementing additional inspection and maintenance programs, but does not require implementation of any of these measures. Operators are also required to enhance their damage prevention programs and to take additional measures to protect HCA segments subject to the threat of outside force damage (non-excavation). Operators are required to install automatic or remotely-operable valves if their risk analysis concludes these would be an efficient means of adding protection to the HCA in the event of a gas release. The requirements of Sec. 192.935 apply only to pipeline segments in HCAs. As discussed above, only 6.4 percent of gas transmission pipeline mileage is currently classified as ``located within HCAs.'' Revising the criteria for identifying HCAs could, of course, increase the number of pipeline miles to which the requirements of Sec. 192.935 apply. Still, PHMSA is considering whether these requirements, or other requirements for additional preventive and mitigative measures, should apply to pipelines outside of HCAs. [[Page 53090]] Questions B.1. What practices do gas transmission pipeline operators now use to make decisions as to whether/which additional preventive and mitigative measures are to be implemented? Are these decisions guided by any industry or consensus standards? If so, what are those industry or consensus standards? B.2. Have any additional preventive and mitigative measures been voluntarily implemented in response to the requirements of Sec. 192.935? How prevalent are they? Do pipeline operators typically implement specific measures across all HCAs in their pipeline system, or do they target measures at individual HCAs? How many miles of HCA are afforded additional protection by each of the measures that have been implemented? To what extent do pipeline operators implement selected measures to protect additional pipeline mileage not in HCAs? B.3. Are any additional prescriptive requirements needed to improve selection and implementation decisions? If so, what are they and why? B.4. What measures, if any, should operators be required explicitly to implement? Should they apply to all HCAs, or is there some reasonable basis for tailoring explicit mandates to particular HCAs? Should additional preventative and mitigative measures include any or all of the following: Additional line markers (line-of-sight); depth of cover surveys; close interval surveys for cathodic protection (CP) verification; coating surveys and recoating to help maintain CP current to pipe; additional right-of-way patrols; shorter ILI run intervals; additional gas quality monitoring, sampling, and in-line inspection tool runs; and improved standards for marking pipelines for operator construction and maintenance and one-calls? If so, why? B.5. Should requirements for additional preventive and mitigative measures be established for pipeline segments not in HCAs? Should these requirements be the same as those for HCAs or should they be different? Should they apply to all pipeline segments not in HCAs or only to some? If not all, how should the pipeline segments to which new requirements apply be delineated? B.6. If commenters suggest modification to the existing regulatory requirements, PHMSA requests that commenters be as specific as possible. In addition, PHMSA requests commenters to provide information and supporting data related to: The potential costs of modifying the existing regulatory requirements pursuant to the commenter's suggestions. The potential quantifiable safety and societal benefits of modifying the existing regulatory requirements. The potential impacts on small businesses of modifying the existing regulatory requirements. The potential environmental impacts of modifying the existing regulatory requirements. C. Modifying Repair Criteria The existing IM regulations establish criteria for the timely repair of injurious anomalies and defects discovered in the pipe (Sec. 192.933). These criteria apply to pipeline segments in an HCA, but not to segments outside an HCA. PHMSA is considering whether changes are needed to the IM rule related to the repair criteria to provide greater assurance that injurious anomalies and defects are repaired before the defect can grow to a size that leads to a leak or rupture. In addition, PHMSA is considering whether or not to establish repair criteria for pipeline segments located in areas outside an HCA, to provide greater assurance that defects on non-HCA pipeline segments are repaired in a timely manner. In 2000 and 2002, PHMSA published final rules (65 FR 75378; 12/1/ 2000 and 67 FR 2136; 1/16/2002) requiring IM Programs for hazardous liquid pipeline operators. In 2003, similar IM regulations were enacted for gas pipelines (68 FR 69778; 12/15/2003). Some 43.9% of the nation's hazardous liquid pipelines (77,421 miles) and 6.5% of the natural gas transmission pipelines (19,004 miles) can potentially affect HCAs and thus receive the enhanced level of integrity assessment mandated by the IM rule. As a result of assessments, over the six-year period between 2004 and 2009, hazardous liquid operators have made 6,419 repairs of anomalies in HCAs that required immediate attention and remediated 25,027 other conditions on a scheduled basis. Between 2004 and 2009, gas pipeline operators have repaired 1,052 anomalies that required immediate attention and 2,239 other conditions. During this six-year period, hazardous liquid pipelines repair rate was 41.3 repairs per 100 HCA miles and gas transmission pipelines repair rate was 17.3 repairs per 100 HCA miles. The gas IM regulations (Sec. 192.933) require ``prompt action'' to address all anomalous conditions discovered. More specifically, the IM regulation mandates ``immediate'' pressure reduction, pipeline shutdown, or repair of the following conditions: A predicted failure pressure less than or equal to 1.1 times ( The potential costs of modifying the existing regulatory requirements pursuant to the commenter's suggestions. The potential quantifiable safety and societal benefits of modifying the existing regulatory requirements. The potential impacts on small businesses of modifying the existing regulatory requirements. The potential environmental impacts of modifying the existing regulatory requirements. D. Improving Requirements for Collecting, Validating, and Integrating Pipeline Data IM regulations require that gas transmission pipeline operators gather and integrate existing data and information concerning their entire pipeline that could be relevant to pipeline segments in HCAs (Sec. 192.917(b)). Operators are then required to use this information in a risk assessment of the covered segments at (Sec. 192.917(c)) that must subsequently be used to determine whether additional preventive and mitigative measures are needed (Sec. 192.935) and to define the intervals at which IM reassessments must be performed (Sec. 192.939). Operators' risk analyses and the conclusions reached using them can only be as good as the information used to perform the analysis. Preliminary results from the investigation of the September 9, 2010, pipeline rupture and explosion in San Bruno, CA, indicate that the pipeline operator's records concerning the pipe segments involved in the incident were erroneous. The errors affected basic information about the pipeline. For example, the records indicated that pipe in the area was 30-inch diameter seamless pipe, whereas pipe fragments recovered after the incident showed that seamed pipe was present. Thus, analyses performed using the information in the operator's records before the incident could not have led to accurate conclusions concerning risk, whether or not additional preventive and mitigative measures were needed, or what the allowable MAOP should be. PHMSA issued an Advisory Bulletin (76 FR 1504; January 10, 2011) on this issue. PHMSA is considering whether more prescriptive requirements for collecting, validating, integrating and reporting pipeline data is necessary. Questions D.1. What practices are now used to acquire, integrate and validate data (e.g., review of mill inspection reports, hydrostatic tests reports, pipe leaks and rupture reports) concerning pipelines? Are practices in place, such as excavations of the pipeline, to validate data? D.2. Do operators typically collect data when the pipeline is exposed for maintenance or other reasons to validate information in their records? If discrepancies are found, are investigations conducted to determine the extent of record errors? Should these actions be required, especially for HCA segments? D.3. Do operators try to verify data on pipe, pipe seam type, pipe mechanical and chemical properties, mill inspection reports, hydrostatic tests reports, coating type and condition, pipe leaks and ruptures, and operations and maintenance (O&M) records on a periodic basis? Are practices in place to validate data, such as excavation and in situ examinations of the pipeline? If so, what are these practices? [[Page 53092]] D.4. Should PHMSA make current requirements more prescriptive so operators will strengthen their collection and validation practices necessary to implement significantly improved data integration and risk assessment practices? D.5. If commenters suggest modification to the existing regulatory requirements, PHMSA requests that commenters be as specific as possible. In addition, PHMSA requests commenters to provide information and supporting data related to: The potential costs of modifying the existing regulatory requirements pursuant to the commenter's suggestions. The potential quantifiable safety and societal benefits of modifying the existing regulatory requirements. The potential impacts on small businesses of modifying the existing regulatory requirements. The potential environmental impacts of modifying the existing regulatory requirements. E. Making Requirements Related to the Nature and Application of Risk Models More Prescriptive As described above, current regulations require that gas transmission pipeline operators perform risk analyses of their covered segments and use these analyses to make certain decisions concerning actions to assure the integrity of their pipeline and to enhance protection against the consequences of potential incidents. The regulations do not prescribe the type of risk analysis nor impose any requirements regarding its breadth and scope. PHMSA's experience in inspecting operator compliance with IM requirements has identified that most pipeline operators use a relative index-model approach to performing their risk assessments and that there is a wide range in scope and quality of the resulting analyses. It is not clear that all of the observed risk analyses can support robust decision making and management of the pipeline risk. PHMSA is considering making requirements related to the nature and application of risk models more prescriptive to improve the usefulness of these analyses in informing decisions to control risks from pipelines. Questions E.1. Should PHMSA either strengthen requirements on the functions risk models must perform or mandate use of a particular risk model for pipeline risk analyses? If so, how and which model? E.2. It is PHMSA's understanding that existing risk models used by pipeline operators generally evaluate the relative risk of different segments of the operator's pipeline. PHMSA is seeking comment on whether or not that is an accurate understanding. Are relative index models sufficiently robust to support the decisions now required by the regulation (e.g., evaluation of candidate preventive and mitigative measures, and evaluation of interacting threats)? E.3. How, if at all, are existing models used to inform executive management of existing risks? E.4. Can existing risk models be used to understand major contributors to segment risk and support decisions regarding how to manage these contributors? If so, how? E.5. How can risk models currently used by pipeline operators be improved to assure usefulness for these purposes? E.6. If commenters suggest modification to the existing regulatory requirements, PHMSA requests that commenters be as specific as possible. In addition, PHMSA requests commenters to provide information and supporting data related to: The potential costs of modifying the existing regulatory requirements pursuant to the commenters' suggestions. The potential quantifiable safety and societal benefits of modifying the existing regulatory requirements. The potential impacts on small businesses of modifying the existing regulatory requirements. The potential environmental impacts of modifying the existing regulatory requirements. F. Strengthening Requirements for Applying Knowledge Gained Through the IM Program IM assessments provide information about the condition of the pipeline segments assessed. Identified anomalies that exceed criteria in Sec. 192.933 must be remediated immediately (Sec. 192.933(d)(1)) or within one year (Sec. 192.933(d)(2)) or must be monitored on future assessments (Sec. 192.933(d)(3)). Operators are also expected to apply knowledge gained through these assessments to assure the integrity of their entire pipeline. Section 192.917(e)(5) explicitly requires that operators must consider other portions of their pipeline if an assessment identifies corrosion requiring repair under the criteria of Sec. 192.933. The operator must ``evaluate and remediate, as necessary, all pipeline segments (both covered and non-covered) with similar material coating and environmental characteristics.'' Section 192.917 also requires that operators conduct risk assessments that follow American Society of Mechanical Engineers/ American National Standards Institute (ASME/ANSI) B31.8S, Section 5, and use these analyses to prioritize segments for assessment, and to determine what preventive and mitigative measures are needed for segments in HCAs. Section 5.4 of ASME/ANSI B31.8S states that ``risk assessment methods should be used in conjunction with knowledgeable, experienced personnel * * * that regularly review the data input, assumptions, and results of the risk assessments.'' That Section further states ``An integral part of the risk assessment process is the incorporation of additional data elements or changes to facility data'' and requires that operators ``incorporate the risk assessment process into existing field reporting, engineering, and facility mapping processes'' to facilitate such updates. Neither part 192 nor ASME/ANSI B31.8S specifies a periodicity by which pipeline risk analyses must be reviewed and updated. This is considered a continuous ongoing process. PHMSA is considering strengthening requirements related to operators' use of insights gained from implementation of its IM program. Questions F.1. What practices do operators use to comply with Sec. 192.917(e)(5)? F.2. How many times has a review of other portions of a pipeline in accordance with Sec. 192.917(e)(5) resulted in investigation and/or repair of pipeline segments other than the location on which corrosion requiring repair was initially identified? F.3. Do pipeline operators assure that their risk assessments are updated as additional knowledge is gained, including results of IM assessments? If so, how? How is data integration used and how often is it updated? Is data integration used on alignment maps and layered in such a way that technical reviews can identify integrity-related problems and threat interactions? How often should aerial photography and patrol information be updated for IM assessments? If the commenter proposes a time period for updating, what is the basis for this recommendation? F.4. Should the regulations sp
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