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Summary:Advanced Notice of Proposed RulemakingReleased August 2011By John BeetsPrincipal GIS Technologist, Willbros Engine...
Summary: Advanced Notice of Proposed Rulemaking   of HCAs. This could involve the following:   a. Revision of the repair c...
Summary: Advanced Notice of Proposed Rulemaking   d. Establish standards for conducting Internal Corrosion Direct Assessme...
Summary: Advanced Notice of Proposed Rulemaking   b. Alternatively, require specific types of pipe with an operating histo...
Summary: Advanced Notice of Proposed Rulemaking8. Modifying the regulation of gas gathering lines: Recent developments in ...
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Willbros - Summary: Advanced Notice of Proposed Rulemaking

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The purpose of this document is to provide a brief summary of the content of the ANPRM in order to present a snapshot of issues that may be under consideration for a revised final rule. An analysis of the information contained in the ANPRM is not included.

http://blog.willbros.com/category/pipeline-integrity/

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Transcript of "Willbros - Summary: Advanced Notice of Proposed Rulemaking"

  1. 1. Summary:Advanced Notice of Proposed RulemakingReleased August 2011By John BeetsPrincipal GIS Technologist, Willbros EngineeringAn Advanced Notice of Proposed Rulemaking (ANPRM) was released by the Pipeline and Hazardous Materials SafetyAdministration (PHMSA) in August 2011. High profile incidents, such as the PG&E failure in San Bruno, CA, haveinstigated a push by Federal regulatory agencies for additional safety measures for gas transmission pipelines. ThisANPRM is requesting public comment on 14 specific topics in two broad categories. At some point following the reviewperiod, PHMSA will release a Notice of Proposed Rulemaking (NPRM) that will incorporate comments/questions theyreceive as a result of this ANPRM. This will allow another round of public comment/questions before a final rule isreleased. It is difficult to predict the time frame for release of a final rule – past experience might indicate this couldoccur very late in 2012, but more likely sometime in 2013.The purpose of this document is to provide a brief summary of the content of the ANPRM in order to present a snapshotof issues that may be under consideration for a revised final rule. An analysis of the information contained in theANPRM is not included.Category 1: Should integrity management requirements be revised and strengthened to bring more pipeline mileageunder integrity management requirements and to better assure safety of pipeline segments in high-consequenceareas (HCAs)?Topics:1. Modify HCA definition to expand pipeline mileage in HCAs? This could be done by: a. Revising (decreasing) the count for buildings intended for human occupancy b. Expanding the definition of identified sites c. Making all Class 3 and 4 locations HCA – also increase the width for determining class location on pipelines over 24” outside diameter (OD) operating above 1,000 pounds per square inch gauge (psig) d. Increasing the HCA buffer beyond that determined by the potential impact radius (PIR) e. Considering presence of electric transmission lines or other critical infrastructure within the pipeline right-of-way (ROW) f. Allowing general public/local communities to provide input into identification of HCAs2. Strengthen requirements to implement preventative and mitigative measures for pipeline segments in HCAs: The current rule requires operators to take additional preventative and mitigative measures in HCAs, but these measures are not specified. Risk analysis is to be used to identify additional measures appropriate to the HCA, but the current rule does not establish objective criteria or standards on how to determine what measures should be taken. PHMSA is considering additional prescriptive requirements to improve selection and implementation decisions for preventative and mitigative measures within and, potentially, outside of HCAs.3. Modification of repair criteria: Changes to repair criteria to provide greater assurance of anomalies/defects being repaired before leading to a leak or rupture and whether these criteria need to be expanded to segments outsideWillbros Group, Inc. • 4400 Post Oak Parkway, Suite 1000, Houston, Texas 77027 • 713.403.8000 • www.willbros.com 1© 2011 Willbros • All Rights Reserved.
  2. 2. Summary: Advanced Notice of Proposed Rulemaking of HCAs. This could involve the following: a. Revision of the repair criterion to add an additional safety margin b. Risk ranking – conditions in HCAs addressed first, followed by non-HCA areas c. Adjustment of repair schedules in both HCA and non-HCA areas d. Potential standards to account for known accuracy of inline inspection (ILI) tools that are consistent across all ILI vendors and operator e. Potential methods for validation of tool performance such as validation digs or analysis of as-found versus as-predicted defect dimensions f. Standards for conducting inline inspections, specific interpretation of personnel qualifications, integration of other data sources with ILI4. Improving requirements for collecting, validating and integrating pipeline data: a. Require validation methods be in place, such as pipeline excavations b. Require collection of data during pipeline exposure to validate information in the operator’s records c. Verify critical pipe data, coating, testing, and operations and maintenance (O&M) records on a periodic basis (requirements become more prescriptive)5. Making requirements related to the nature and application of risk models more prescriptive: PHMSA’s experience indicates that majority of operators use relative index-model approaches to risk assessment. PHMSA is not convinced as to the robustness of this method. Possible changes discussed: a. Strengthen requirements on functions risk models perform b. Mandate usage of a specific risk model c. Improve existing models to assure usefulness d. Push to use more quantitative models is contemplated6. Strengthening requirements for applying knowledge gained through the integrity management (IM) program: This is related to the current regulation requiring operators to consider other portions of their systems if an assessment identifies corrosion requiring repair. Intention is to strengthen requirements related to operator’s use of insights gained from implementation of their IM program: a. Potential requirements for updating risk models as additional knowledge is gained b. Guidelines or requirements related to data integration and/or updating of aerial imagery or patrolling c. Specification of a maximum time period for review and validation of risk assessments d. Potential data requirements for data integration7. Strengthening requirements on the selection and use of assessment methods: Currently four methods – ILI, pressure test, direct assessment and other technology demonstrated to provide an equivalent understanding of pipe condition. Possible changes discussed: a. Require ILI wherever possible – include requirements to expand line modifications to accommodate ILI b. Restrictions on use of other assessment technologies c. Establish standards for conducting ILI assessments – incorporate by reference into regulationsWillbros Group, Inc. • 4400 Post Oak Parkway, Suite 1000, Houston, Texas 77027 • 713.403.8000 • www.willbros.com 2© 2011 Willbros • All Rights Reserved.
  3. 3. Summary: Advanced Notice of Proposed Rulemaking d. Establish standards for conducting Internal Corrosion Direct Assessment (ICDA) and Stress Corrosion Cracking Direct Assessment (SCCDA) – incorporate by reference into regulations e. Require a onetime pressure test to address manufacturing and construction defectsCategory 2: Should non-IM requirements be strengthened or expanded to address other issues associated withpipeline system integrity?Topics:1. Valve spacing and the need for remotely or automatically controlled valves: Current regulation specifies block valve spacing by class location on newly built lines. Remotely operating and/or automatic valves are not currently required. Potential changes: a. Change spacing requirements for new lines b. Explicitly require new valves in the event of class change to meet spacing requirements c. Explicitly require new valves under other (non-class change) conditions d. Require remotely controlled sectionalizing block valves e. Require prescriptive design criteria for operator evaluation of additional valves, remote closure and/or valve automation2. Corrosion control: Requirements related to external, internal and atmospheric corrosion: a. Require post-construction surveys for coating damage or to determine Cathodic Protection (CP) adequacy b. Require periodic interference current surveys (such as Close Interval Survey – CIS) c. Add additional measures to prevent internal corrosion (such as ILI runs or accumulated liquids sampling) d. Include practices or standards addressing prevention, detection, assessment and remediation of SCC – requiring additional surveys or shorter internal surveys based on pipeline operating temperatures and coating types e. Prescribe CIS external corrosion control survey timing intervals for both HCAs and non-HCAs that are used to determine CP effectiveness f. Provide specific HCA and non-HCA corrosion control measures with clearly defined conditions and appropriate mitigation efforts g. Perform a critical analysis of all factors influencing SCC to determine if a credible threat exists for each pipeline segment h. Require SCC integrity assessment in segments where a credible threat has been identified i. Require a periodic analysis of operator corrosion management programs, integrating all relevant data j. Require operators to periodically submit corrosion management performance metric data3. Pipe manufactured using longitudinal weld seams: This is meant to address longitudinal seam weld issues with pipe manufactured primarily before 1970 and pressure test grandfathering for lines built prior to 1971 (allowing operations at a maximum allowable operating pressure (MAOP) based on the highest 5-year operating pressure prior to July 1, 1970 in lieu of a pressure test): a. Require all pipelines that have not been pressure tested at or above 1.1 times MAOP or class location test criteria to be pressure tested in accordance with present regulationWillbros Group, Inc. • 4400 Post Oak Parkway, Suite 1000, Houston, Texas 77027 • 713.403.8000 • www.willbros.com 3© 2011 Willbros • All Rights Reserved.
  4. 4. Summary: Advanced Notice of Proposed Rulemaking b. Alternatively, require specific types of pipe with an operating history that demonstrates systemic integrity issues to be pressure tested in accordance with present regulation, e.g., low-frequency electric resistance welded (LF-ERW), direct current electric resistance welded (DC-ERW), lap-welded, electric flash welded (EFW), furnace butt welded, submerged arc welded or other longitudinal seams c. Define alternative minimum test pressures d. Provide additional pressure test requirements to all pipelines, or only pipelines in HCAs, or only pipelines in Class 2, 3, or 4 areas e. Specify other technologies that may reliably find and remediate seam integrity issues4. Establishing requirements applicable to underground gas storage: PHMSA may develop standards covering underground gas storage facilities. This could include: a. Safety standards for casing, tubing, isolation packer and wellbore communication and wellhead equipment b. Standards for monitoring of external/internal corrosion c. Standards for welding, pressure testing and design safety factors of casing and tubing d. Emergency shutdowns for wellhead valves e. Integrity and O&M intervals for key safety and CP systems f. Standards for emergency shutdowns, emergency shutdown stations, gas monitors, local emergency response communications, public communications and O&M procedures5. Management of change: PHMSA pipeline safety regulations do not now address management process subjects such as management of change. PHMSA is considering adding requirements in this area to provide a greater degree of control over this element of pipeline risk: a. Development of standards governing the management of change process including requirements for IM proce- dures, O&M manuals, facility drawings, emergency response plans and procedures and documents required to be maintained for the life of the pipeline b. Consider incorporating like standards from other industries6. Quality Management Systems (QMS): Quality management includes the activities and processes that an organization uses to achieve quality. These include formulating policy, setting objectives, planning, quality control, quality assurance, performance monitoring and quality improvement. PHMSA’s pipeline safety regulations do not now address process management issues such as QMS. PHMSA may institute formal requirements for QMS into the regulation. They are asking the industry for information on existing quality assurance standards and practices currently in use that might be adopted. Should QMS be applied to all or some pipelines and does it apply to the complete lifecycle? Do operators commonly require their contractors to maintain and use formal QMS?7. Exemption of facilities installed prior to the regulations: This is to address the MAOP exemption for pre-1970 pipelines that operate above 72% specified minimum yield strength (SMYS) and also includes use of materials manufactured prior to 1970. The changes could include requirements for periodic pressure tests, in-line inspections, coating examination, CP surveys and expanded requirements on interference currents and depth of cover maintenance for these lines. This could be for all pipelines or targeted to those with a vintage history of systemic integrity issues in areas such as longitudinal weld seams or steel quality.Willbros Group, Inc. • 4400 Post Oak Parkway, Suite 1000, Houston, Texas 77027 • 713.403.8000 • www.willbros.com 4© 2011 Willbros • All Rights Reserved.
  5. 5. Summary: Advanced Notice of Proposed Rulemaking8. Modifying the regulation of gas gathering lines: Recent developments in the field of gas exploration and production, such as shale gas, indicate that the existing framework for regulating gas gathering lines may no longer be appropri- ate. Gathering lines are being constructed to transport shale gas that range from 12 to 36 inches in diameter with an MAOP of 1,480 psig, far exceeding the historical operating parameters of such lines. Moreover, enforcement of the current requirements has been hampered by the conflicting and ambiguous language of American Petroleum Institute Recommended Practice 80 (API RP 80), a complex standard that can produce multiple classifications for the same pipeline system. Gathering regulation may be modified as follows: a. Require submission of annual incident and safety-related conditions reports b. Include a new definition for gathering in the regulation c. Establish new, risk-based safety requirements for large diameter, high pressure gathering lines in rural locations d. Consider short sections of pipeline downstream of processing, compression and similar equipment to be a continuation of gathering e. Adopt specific requirements for pipelines associated with landfill gas systems (due to increased concentrations of hydrogen sulfide and/or carbon dioxide) f. Enhance requirements for internal corrosion control g. Apply gas integrity management requirements to all onshore gas gatheringWillbros Group, Inc. • 4400 Post Oak Parkway, Suite 1000, Houston, Texas 77027 • 713.403.8000 • www.willbros.com 5© 2011 Willbros • All Rights Reserved.

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