{"operation":"document","citation":"CPF 520071004M","title":"NORTHWEST PIPELINE LLC — Notice of Amendment","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2007-04-04","effective_on":null,"summary":"CLOSED notice of amendment citing 192.905(a), 192.905(b), 192.905(c), 192.907(b), 192.909(b), 192.911(i), 192.911(k), 192.917(a), 192.917(b), 192.917(c), 192.917(e)(5), 192.921(a)(4), 192.921(f), 192.925(b)(1)(i), 192.925(b)(2), 192.925(b)(2)(i), 192.925(b)(3), 192.925(b)(3)(i), 192.933(a), 192.933(b), 192.933(c), 192.933(d)(1)(ii), 192.933(d)(3), 192.937(a), 192.945(a).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-520071004m.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-520071004m.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-520071004m","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/520071004M","body":"Notice of Amendment involving NORTHWEST PIPELINE LLC. PHMSA's enforcement data identifies the cited regulations as 192.905(a),  192.905(b),  192.905(c),  192.907(b),  192.909(b),  192.911(i),  192.911(k),  192.917(a),  192.917(b),  192.917(c),  192.917(e)(5),  192.921(a)(4),  192.921(f),  192.925(b)(1)(i),  192.925(b)(2),  192.925(b)(2)(i),  192.925(b)(3),  192.925(b)(3)(i),  192.933(a),  192.933(b),  192.933(c),  192.933(d)(1)(ii),  192.933(d)(3),  192.937(a),  192.945(a). The case was opened on 2007-04-04 and is reported as closed as of 2008-04-14. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n520071004M_notice letter_04042007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520071004M/520071004M_notice%20letter_04042007.pdf\n\n520071004m_notice letter_04042007_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520071004M/520071004m_notice%20letter_04042007_text.pdf\n\n520071004M_Operator Response_08152007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520071004M/520071004M_Operator%20Response_08152007.pdf\n\n520071004m_notice letter_04042007_text.pdf\n\nU. S. Department\nof Transportation\nPipeline and\nHazardous Materials Safety\nAdministration\n12300 W Dakota Ave, Surete 110\nLakewood, CO 80228\nNOTICE OF AMKNDMKNT\nCERTIFIED MAIL - RETU1Vf RECEIPT RE UESTED\nApril 4, 2007\nSENT TO COMPLIANCE REGISTRY\nHardcopy Electronically\n4 of Copies&/ Date ~+~'p +Jyl\nMr. Randy Barnard\nVP Operations and Gas Control\nWilliams Gas Pipeline\n2800 Post Oak Blvd\nP. O. Box 1396\nHouston, TX 77056\nCPF 5-2007-1004M\nDear Mr. Barnard:\nOn March 13-17 and March 27 — 30, 2006, a representative of the Pipeline and Hazardous\nMaterials Safety Administration (PHMSA), pursuant to Chapter 601 of 49 United States Code,\ninspected Williams Gas Pipeline's (WGP's) procedures for the Integrity Management\nProgram (IMP) in Salt Lake City, Utah.\nOn the basis of the inspection, PHMSA has identified the apparent inadequacies found within\nWGP's plan or procedure and are described below. Probable non-violations resulting from\nthat same inspection were already sent to you in our letter, CPF No. 5-2007-1001, dated\nJanuary 29, 2007.\n1. Identification of High Consequence Areas\n)192. 911 What are the elements of an integrity management program'?\n(a) An identification of all high consequence areas, in accordance with $192. 905.\n(p) A process for identification and assessment of newly-identified high consequence\nareas. (See $192. 905 and $192. 921. )\n$192. 905 How does an operator identify a high consequence area?\n(a) General. To determine which segments of an operator's transmission pipeline\nsystem are covered by this subpart, an operator must identify the high consequence\n\n\n\nareas. An operator must use method (1) or (2) from the definition in $192. 903 to\nidentify a high consequence area. An operator may apply one method to its entire\npipeline system, or an operator may apply one method to individual portions of the\npipeline system. An operator must describe in its integrity management program\nwhich method it is applying to each portion of the operator's pipeline system. The\ndescription must include the potential impact radius when utilized to establish a high\nconsequence area. (See appendix K. I. for guidance on identifying high consequence\nareas. )\n(b) Identified sites, An operator must identify an identified site, for purposes of this\nsubpart, from information the operator has obtained from routine operation and\nmaintenance activities and from public officials with safety or emergency response or\nplanning responsibilities who indicate to the operator that they know of locations that\nmeet the identified site criteria. These public officials could include officials on a\nlocal emergency planning commission or relevant Native American tribal officials.\n(c) Newly identified areas. When an operator has information that the area around a\npipeline segment not previously identified as a high consequence area could satisfy\nany of the definitions in $192. 903, the operator must complete the evaluation using\nmethod (1) or (2). If the segment is determined to meet the definition as a high\nconsequence area, it must be incorporated into the operator's baseline assessment\nplan as a high consequence area within one year from the date the area is identified.\n~ Item 1A: $192. 911(a) and $192. 905(a)\nWilliams Gas Pipeline's procedure 10. 09. 01. 10 and IMP Overview Chapter 4 define\nMethods 1 and 2 consistent with rule requirements. However, these documents do not\nprovide detailed information on how these HCA identification methods are implemented.\nThe procedure needs amending to include Process steps, responsibilities, data inputs and\noutputs, and documentation requirements.\n~ Item 1B: $192. 911(a) and $192. 905(a)\nProcedure 10. 09. 01. 10, Section 10. 1. 5 states that all WGP HCA locations shall be\npermanently recorded and that the recorded information \"may\" include the method used to\nidentify HCA. The procedure needs amending to reflect the rule requirement this\ninformation \"must\" be documented.\n~ Item 1C: $192. 911(a) and $192. 905(a)\nProcedure 10. 09. 01. 10, Section 10. 1. 6 is inadequate as it indicates system maps will be\nmaintained and updated with aerial photography for identifying HCAs without specifying\nwhat frequency the aerial photography is to be updated.\n~ Item 1D: $192. 911(a) and $192. 905(a)\nInstructions provided to the field (e. g. , Appendix A of IMP Overview Chapter 4) do not\nprovide data accuracy instructions on how to measure and locate piping and adjacent\nstructure/identified site locations.\n\n\n\n• Item 1E: §192.911(a) and §192.905(b)\nWGP does not have a formalized procedure or process for how facility use data is collected\nduring routine operation and maintenance activities to document if sites meet the identified\nsite criteria.\n• Item 1F: §192.911(a), §192.911(p) and §192.905(c)\nWGP's integrity management program does not include documented processes for how\nidentified and integrated with the integrity management program. These documented\nnew information indicating a pipeline segment impacts a high consequence area is\nprocesses do not include activity steps, responsibilities, data inputs and outputs, and\ndocumentation requirements.\n2. Baseline Assessment Plan\n§192.911 What are the elements of an integrity management program?\n(b) A baseline assessment plan meeting the requirements of §192.919 and §192.921.\n§192.921(a)(4) Other technology that an operator demonstrates can provide an\nequivalent understanding of the condition of the line pipe. An operator choosing this\noption must notify the Office of Pipeline Safety (OPS) 180 days before conducting the\nassessment, in accordance with $192.949. An operator must also notify a State or\nlocal pipeline safety authority when either a covered segment is located in a State\nwhere OPS has an interstate agent agreement, or an intrastate covered segment is\nregulated by that State.\n§192.921(f) Newly identified areas. When an operator identifies a new high\nconsequence area (see §192.905), an operator must complete the baseline assessment\nof the line pipe in the newly identified high consequence area within ten (10) years\nfrom the date the area is identified.\n• Item 2A: §192.911(b) and §192.921(a) (4)\nWGP's procedures for notifying OPS, State, or local pipeline safety authorities of the use\nof \"other technology\" are not included in their integrity management plan documentation.\n• Item 2B: §192.911(b) and §192.921(f)\nFor newly identified HAs or newly installed pipe that is covered by this subpart and\nimpacts an HCA, WGP does not have a procedural requirement to complete a baseline\nassessment for the applicable segments) within ten (10) years from the date the area is\nidentified.\n3. Identify Threats, Data Integration, and Risk Assessment\n§192.911 What are the elements of an integrity management program?\n- 3.\n\n\n\n(c) An identification of threats to each covered pipeline segment, which must include\ndata integration and a risk assessment. An operator must use the threat\nidentification and risk assessment to prioritize covered segments for assessment\n($192. 917) and to evaluate the merits of additional preventive and mitigative\nmeasures ($192. 935) for each covered segment.\n$192. 917 How does an operator identify potential threats to pipeline integrity and use\nthe threat identification in its integrity program?\n(a) Threat identification. An operator must identify and evaluate all potential threats\nto each covered pipeline segment. Potential threats that an operator must consider\ninclude, but are not limited to, the threats listed in ASMK/ANSI B31. 8S (ibr, see\n$192. 7), section 2, which are as follows:\n(1) Time dependent threats such as internal corrosion, external corrosion, and stress\ncorrosion cracking;\n(2) Static or resident threats, such as fabrication or construction defects;\n(3) Time independent threats such as third party damage and outside force damage;\nand\n(4) Human error.\n(b) Data gathering and integration. To identify and evaluate the potential threats to a\ncovered pipeline segment, an operator must gather and integrate existing data and\ninformation on the entire pipeline that coulld be relevant to the covered segment. In\nperforming this data gathering and integration, an operator must follow the\nrequirements in ASMK/ANSI B31. 8S, section 4. At a minimum, an operator must\ngather and evaluate the set of data specified in Appendix A to ASMK/ANSI B31. 8S,\nand consider both on the covered segment and similar non-covered segments, past\nincident history, corrosion control records, continuing surveillance records,\npatrolling records, maintenance history, internal inspection records and all other\nconditions specific to each pipeline.\n(c) Risk assessment. An operator must conduct a risk assessment that follows\nASME/ANSI B31. 8S, section 5, and considers the identified threats for each covered\nsegment. An operator must use the risk assessment to prioritize the covered segments\nfor the baseline and continual reassessments (@192. 919, 192. 921, 192. 937), and to\ndetermine what additional preventive and mitigative measures are needed ($192. 935)\nfor the covered segment.\n$192. 917(e)(5) Corrosion. If an operator identifies corrosion on a covered pipeline\nsegment that could adversely affect the integrity of the line (conditions specified in\n$192. 933), the operator must evaluate and remediate, as necessary, all pipeline\nsegments (both covered and non- covered) with similar material coating and\nenvironmental characteristics. An operator must establish a schedule for evaluating\nand remediating, as necessary, the similar segments that is consistent with the\noperator's established operating and maintenance procedures under part 192 for\ntesting and repair.\n~ Item 3A: $192. 911(c) and $192. 917(a)\nWGP threat identification process has not provided sufficient technical justification for the\nelimination of the SCC threat.\n\n\n\n~ Item 38: $192. 911(c) and $192. 917(a)\nIt is not apparent interactive threats have been considered in the WGP threat identification\nprocess. SMEs have ability to recognize interactive threats and adjust risk based on their\nknowledge of the threats, but WGP has not provided guidance in procedures for this\nactivity. The inspection team recognized that the Threat Identification Checklists have the\npotential to provide for consideration of interacting threats.\n~ Item 3C: $192. 911(c) and $192. 917(b)\nProcedure 10. 25. 01, Section 4. 0 provides high level requirements for data collection and\nintegration. Integrity Sheet 1400. 13-101A shows data integration for an ECDA project.\nHowever, procedioes are not in place to provide instructions on how data is to be included\non the Integrity Sheet. Documented procedures that include required activity steps,\nresponsibilities, data inputs and outputs, and documentation requirements have not been\nestablished.\n~ Item 3D: $192. 911(c) and $192. 917(b)\nProcesses have not been defined for the responsibilities for data collection or how the data\nsets are assembled, how accuracy is verified, how the data is maintained, or defining the\nsets of data that must be collected. WGP has the intent and is in the process of developing\na GIS that they will use to integrate data comprehensively by the end of 2006.\n~ Item 3K: $192. 911(c) and $192. 917(b)\nData sources listed in ASME B31. 8S Table 2 are not specified as required data sets in the\nWGP risk assessment process.\n~ Item 3F: $192. 911(c) and $192. 917(b)\nWGP procedures for data gathering and integration are inadequate as they do not include\nprocesses for verifying data quality as required by ASME/ANSI B31. 8S Section 4.\nProcedures do not require that conservative assumptions be applied if data is missing or\nsuspect. The procedures do not specify additional inspections or field data collection\nefforts must be initiated for missing/suspect data.\n~ Item 3C: $192. 911(c) and $192. 917(c)\nProcedure 10. 25. 01, Section 9. 1. 1 specifies that risk assessment validation activities are to\nbe conducted each calendar year. The procedures are inadequate as a specific performance\ndate or link to an activity milestone is not defined in IMP procedures to trigger the activity.\nAdditionally, procedures have not been established describing how SMEs perform the\nvalidation process to ensure risk results are logical and consistent with the operator's and\nother industry experience.\n\n\n\n~ Item 3H: $192. 911(c) and $192. 917(e)(5)\nWGP's procedures do not describe the process by which all covered and non-covered\nsegments with similar environmental character istics and coating will be evaluated when\ncorrosion is discovered on a covered segment that can adversely affect the integrity of the\npipeline.\n4. External Corrosion Indirect Assessment\n$192. 911 What are the elements of an integrity management program?\n(d) A direct assessment plan, if applicable, meeting the requirements of $192. 923, and\ndepending on the threat assessed, of g192. 925, 192. 927, or 192. 929.\n$192. 925(b) General requirements. An operator that uses direct assessment to assess\nthe threat of external corrosion must follow the requirements in this section, in\nASME/ANSI B31. 8S (ibr, see $192. 7), section 6. 4, and in NACE RP 0502-2002 (ibr,\nsee $192. 7). An operator must develop and implement a direct assessment plan that\nhas procedures addressing preassessment, indirect examination, direct examination,\nand post-assessment. If the ECDA detects pipeline coating damage, the operator\nmust also integrate the data from the ECDA with other information from the data\nintegration ($192. 917{b)) to evaluate the covered segment for the threat of third party\ndamage, and to address the threat as required by $192. 917(e)(1).\n(1) Preassessment. In addition to the requirements in ASME/ANSI B31. 8S section 6. 4\nand NACE RP 0502-2002, section 3, the plan's procedures for preassessment must\ninclude-\n(i) Provisions for applying more restrictive criteria when conducting ECDA for the\nfirst time on a covered segment;\n(2) Indirect examination. In addition to the requirements in ASME/ANSI B31. 8S\nsection 6. 4 and NACE RP 0502-2002, sectiion 4, the plan's procedures for indirect\nexamination of the ECDA regions must include-\n(i) Provisions for applying more restrictive criteria when conducting ECDA for the\nfirst time on a covered segment;\n(ii) Criteria for identifying and documenting those indications that must be\nconsidered for excavation and direct examination. Minimum identification criteria\ninclude the known sensitivities of assessment tools, the procedures for using each tool,\nand the approach to be used for decreasing the physical spacing of indirect\nassessment tool readings when the presence of a defect is suspected;\n{iii) Criteria for defining the urgency of excavation and direct examination of each\nindication identified during the indirect examination. These criteria must specify\nhow an operator will define the urgency of excavating the indication as immediate,\nscheduled or monitored; and\n(iv) Criteria for scheduling excavation of indications for each urgency level.\n(3) Direct examination. In addition to the requirements in ASME/ANSI B31. 8S\nsection 6. 4 and NACE RP 0502-2002, section 5, the plan's procedures for direct\nexamination of indications from the indirect examination must include-\n(i) Provisions for applying more restrictive criteria when conducting ECDA for the\nfirst time on a covered segment;\n\n\n\n(ii) Criteria for deciding what action should be taken if either:\n(A) Corrosion defects are discovered that exceed allowable limits (Section 5.5.2.2 of\n(B) Root cause analysis reveals conditions for which ECDA is not suitable (Section\nNACE RP0502-2002), or\n5.6.2 of NACE RP0502-2002);\n(iii) Criteria and notification procedures for any changes in the ECDA Plan,\nreprioritize any of the provisions that are specified in section 5.9 of NACE RP0502-\n• Item 4A: §192.911(d) and §192.925(b)(1)(i)\nThe ECDA procedure 20.19.01.02 does not include the 192.925 requirement initial ECDA\nassessments include more restrictive criteria for the pre-assessment and that this be\ndocumented.\n• Item 4B: §192.911(d) and 192.925(b)(2)\nThere is no reference to industry standards for conducting and analyzing ECDA indirect\ninspection results for each of the selected tools. The physical spacing of each tool is not\nreferenced in the ECDA procedure.\n• Item 4C: §192.911(d) and 192.925(b)(2)\nThe NACE RP requires that conflicting results be documented and resolved. The ECDA\nprocedure does not address this issue nor was there any documentation that this was\nconsidered or what actions are taken if this occurs.\n• Item 4D: §192.911(d) and 192.925(b)(2)(i)\nThe ECDA procedure 20.19.01.02 does not include the 192.925 requirement that initial\nECDA assessments include more restrictive criteria for the indirect inspection and that this\nbe documented.\n• Item 4E: §192.911(d) and §192.925(b)(3)\nThe ECDA procedure does not follow the NACE RP for all required excavations.\n• Item 4F: §192.911(d) and §192.925(b)(3)\nThe ECDA procedure 20.19.01.02 section 6.1.2.3.1.1 requires that if significant external\ncorrosion is discovered it must be evaluated by a root cause analysis and consideration of\nanother method of assessment. There is no definition of the term \"significant\".\n- 7.\n\n\n\n~ Item 4G: $192. 911(d) and $192. 925(b)(3)\nThe %'GP ECDA procedure does not require an evaluation of the indirect inspection data\nusing the results of the remaIning strength calculations and root cause analysis as required\nby NACE RP 0502-2002, section 5.\n~ Item 4H: $192. 911(d) and $192. 925(b)(3)\nThe ECDA procedure does not address the need to use other assessment methods if defects\nother than EC are discovered during an ECDA.\n~ Item 4I: $192. 911(d) and $192. 925(b)(3)(i)\nThe ECDA procedure 20. 19. 01. 02 does not include the 192. 925 requirement that initial\nECDA assessments include more restrictive criteria for direct examinations and that this be\ndocumented.\n5. Remediation\n$192. 911 What are the elements of an integrity management program?\n(e) Provisions meeting the requirements of $192. 933 for remediating conditions found\nduring an integrity assessment.\n$192. 933(a) General requirements. An operator must take prompt action to address\nall anomalous conditions that the operator discovers through the integrity\nassessment. In addressing all conditions, an operator must evaluate all anomalous\nconditions and remediate those that could reduce a pipeline's integrity. An operator\nmust be able to demonstrate that the remediation of the condition will ensure that the\ncondition is unlikely to pose a threat to the integrity of the pipeline until the next\nreassessment of the covered segment. If an operator is unable to respond within the\ntime limits for certain conditions specified in this section, the operator must\ntemporarily reduce the operating pressure of the pipeline or take other action that\nensures the safety of the covered segment. If pressure is reduced, an operator must\ndetermine the temporary reduction in operating pressure using ASME/ANSI B31G\n(ibr, see $192. 7) or AGA Pipeline Research Committee Project PR-3-805\n(\"RSTRENG\"; ibr, see $192. 7) or reduce the operating pressure to a level not\nexceeding 80'/o of the level at the time the condition was discovered. (See appendix A\nto this part 192 for information on availability of incorporation by reference\ninformation). A reduction in operating pressure cannot exceed 365 days without an\noperator providing a technical justification that the continued pressure restriction\nwill not jeopardize the integrity of the pipeline.\n$192. 933(b) Discovery of condition. Discovery of a condition occurs when an\noperator has adequate information about a condition to determine that the condition\npresents a potential threat to the integrity of the pipeline. A condition that presents a\npotential threat includes, but is not limited to, those conditions that require\nremediation or monitoring listed under paragraphs (d)(1) through (d)(3) of this\nsection. An operator must promptly, but no later than 180 days after conducting an\n\n\n\nintegrity assessment, obtain sufficient information about a condition to make that\ndetermination, unless the operator demonstrates that the 180-day period is\nimpracticable.\n$192. 933(c) Schedule for evaluation and reniediation. An operator must complete\nremediation of a condition according to a schedule that prioritizes the conditions for\nevaluation and remediation. Unless a special requirement for remediating certain\nconditions applies, as provided in paragraph (d) of this section, an operator must\nfollow the schedule in ASME/ANSI B31. 8S (ibr, see $192. 7), section 7, Figure 4. If an\noperator cannot meet the schedule for any condition, the operator must justif'y the\nreasons why it cannot meet the schedule and that the changed schedule will not\njeopardize public safety. An operator must notif'y OPS in accordance with $192. 949\nif it cannot meet the schedule and cannot provide safety through a temporary\nreduction in operating pressure or other action. An operator must also notify a State\nor local pipeline safety authority when either a covered segment is located in a State\nwhere OPS has an interstate agent agreement, or an intrastate covered segment is\nregulated by that State.\n$192. 933(d) Special requirements for scheduling remediation.\n1. Immediate repair conditions. An operator's evaluation and remediation schedule\nmust follow ASME/ANSI B31. 8S, Section / in providing for immediate repair\nconditions. To maintain safety, an operator must temporarily reduce operating\npressure in accordance with paragraph (a) of this section or shut down the pipeline\nuntil the operator completes the repair of these conditions. An operator must treat\nthe following conditions as immediate repair conditions:\ni. A calculation of the remaining strength of the pipe shows a predicted failure\npressure less than or equal to1. 1 times the maximum allowable operating pressure at\nthe location of the anomaly. Suitable remaining strength calculation methods\ninclude, ASME/ANSI B31G (\" Manual for Determining the Remaining Strength of\nCorroded Pipelines\" (1991); AGA Pipeline Research Committee Project PR-3-805\n(\"A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe\"\n(December 1989)); or an alternative equivalent method of remaining strength\ncalculation. These documents are incorporated by reference and available at the\naddresses listed in Appendix A to Part 192.\nii. A dent that has any indication of metal loss, cracking or a stress riser.\niii. An indication or anomaly that in the judgment of the person designated by the\noperator to evaluate the assessment results requires immediate action. (1)(ii) A dent\nthat has any indication of metal loss, cracking or a stress riser.\n3. Monitored conditions. An operator does not have to schedule the following\nconditions for remediation, but must record and monitor the conditions during\nsubsequent risk assessments and integrity assessments for any change that may\nrequire remediation:\ni. A dent with a depth greater than 6% of the pipeline diameter (greater than 0. 50\ninches in depth for a pipeline diameter less than NPS 12) located between the 4\no' clock position and the 8 o' clock position (bottom 1/3 of the pipe).\nii. A dent located between the 8 o' clock and 4 o' clock positions (upper 2/3 of the pipe)\nwith a depth greater than 6% of the pipeline diameter {greater than 0. 50 inches in\n\n\n\ndepth for a pipeline diameter less than Nominal Pipe Size (NPS) 12), and engineering\nanalyses of the dent demonstrate critical strain levels are not exceeded.\niii. A dent with a depth greater than 2'/0 of the pipeline's diameter (D. 25D inches in\ndepth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth\nweld or a longitudinal seam weld, and engineering analyses of the dent and girth or\nseam weld demonstrate critical strain levels are not exceeded. These analyses must\nconsider weld properties.\n~ Item 5A: $192. 911(e) and $192. 933(a)\nThe ECDA procedure for determining remaining strength does not require that the\noperating pressure be reduced to 80'/0 or less of the operating pressure if there is an\nimmediate repair per 192. 933.\n~ Item 5B: $192. 911(e) and $192. 933(a)\nPer Procedure 70. 17. 01. 07, Figure 7, a pressure reduction for an immediate repair\ncondition can be made using either a reduction to 80'/0 of operating pressure or based on\n0. 9 x Pburst as calculated by RSTRENG. A pressure reduction must be taken based upon\nPsafe as calculated by B31G or RSTRENG. WGP procedures do not reflect this\nrequirement.\n~ Item 5C: $192. 911(e) and $192. 933(a)\nWGP's repair procedure does not meet code requirements for using Type B sleeves for\nrepairs involving anomalies greater than 80'/0 wall loss.\n~ Item 5D: $192. 911(e) and $192. 933(b)\nPer Section 8. 1. 4 of Procedure 70. 17. 01. 07, \"Pigging — Inline Inspection\" a separate\ndiscovery date is established for a geometry and MFL tool run when performed 120 days\nor more apart; however, the analysis shall still be a joint analysis. This is inconsistent with\nrule requirements. If any anomalies are discovered from the geometry tool assessment\nresults, a one year repair condition may not be addressed in accordance with IM rule repair\nschedule requirements.\n~ Item 5E: $192. 911(e) and $192. 933(c)\nPer Section 8. 2. 3 of Procedure 70. 17. 01. 07, scheduled anomalies will be excavated within\n365 days. Figure 4 of ASME B31. 8S provides a time frame for addressing scheduled\nanomalies that have a Pf/MAOP ) 1. 1. In some cases the time frames are less than 365\ndays. WGP's procedures do not require examination or remediation in the appropriate\ntimeframe. Per Section 192. 933(c), \"An operator must complete remediation of a\ncondition according to a schedule that prioritizes the conditions for evaluation and\nremediation. \" Section 8. 2. 3 of Procedure 70. 17. 01. 07 does not provide sufficient detail or\nguidance for the development of a prioritized schedule.\n\n\n\n• Item 5F: §192.911(e) and §192.933(c)\nWGP's procedures do not meet the provisions of ASME B31.8S, Figure 4 for scheduling\nanomalies for examination or remediation.\n• Item 5G: §192.911(e) and §192.933(d)(1)(ii)\nIn Section 8.2.3 of Procedure 70.17.01.07, WGP states: \"All dents with metal loss (where\nthe metal loss is believed to be corrosion) shall be considered a higher priority than other\nscheduled anomalies and shall be excavated first.\" Per the IM rule 192.933(d)(ii): \"A dent\nthat has an indication of metal loss, cracking, or a stress riser\" is an immediate repair\ncondition.\n• Item 5H: §192.911(e) and §192.933(d)(3)\nProcedure 20.19.01.02 does not address \"monitored\" conditions as required by the Gas\nIMP rule for external corrosion direct assessment.\n• Item 5I: §192.911(e) and §192.933(d)(3)\nWGP procedures allow a priority I coating indication to wait up to one year before\nexcavation which is inconsistent with PHMSA guidance. All required digs must be\ncompleted within 6 months after the indirect inspection surveys.\n6. Preventive and Mitigative Measures\n§192.911 What are the elements of an integrity management program?\n(h) Provisions meeting the requirements of §192.935 for adding preventive and\nmitigative measures to protect the high consequence area.\n§192.937(a) General requirements. An operator must take additional measures\nmitigate the consequences of a pipeline failure in a high consequence area. An\nbeyond those already required by Part 192 to prevent a pipeline failure and to\noperator must base the additional measures on the threats the operator has identified\nto each pipeline segment. (See §192.917) An operator must conduct, in accordance\nwith one of the risk assessment approaches in ASME/ANSI B31.8S (ibr, see §192.7),\nsection 5, a risk analysis of its pipeline to identify additional measures to protect the\nhigh consequence area and enhance public safety. Such additional measures include,\nbut are not limited to, installing Automatic Shut-off Valves or Remote Control\nValves, installing computerized monitoring and leak detection systems, replacing pipe\nsegments with pipe of heavier wall thickness, providing additional training to\npersonnel on response procedures, conducting drills with local emergency responders\nand implementing additional inspection and maintenance programs.\n• Item 6A: §192.911(h) and §192.937(a)\nWGP's ECDA procedure does not require that mitigative actions be completed and\ndocumented.\n- 11 -\n\n\n\n• Item 6B: §192.911(h) and §192.937(a)\nSection 9.0 of procedure 10.25.01.02 describes the process for identifying additional\npreventive and mitigative measures. The procedure does not delineate how risk analysis\nwill be used in the decision making process.\n• Item 6C: §192.911(h) and §192.937(a)\nPer section 9.0 of WGP procedure 10.25.01.02, decisions regarding preventive and\nmitigative measures are made during the annual SME review of risk assessment results.\nThis procedure does not address the process of how the SMEs shall identify, evaluate, and\nrecommend additional preventive and mitigative measures. In addition, this procedure\ndoes not delineate how the risk model will be used in the decision making process.\n7. Performance Measures\n§192.911 What are the elements of an integrity management program?\n(i) A performance plan as outlined in ASME/ANSI B31.8S, Section 9 that includes\nperformance measures meeting the requirements of $192.945.\n§192.945(a) General. An operator must include in its integrity management program\nmethods to measure, on a semi-annual basis, whether the program is effective in\nassessing and evaluating the integrity of each covered pipeline segment and in\nprotecting the high consequence areas. These measures must include the four overall\nperformance measures specified in ASME/ANSI B31.8S (ibr, see §192.7), section 9.4,\nand the specific measures for each identified threat specified in ASME/ANSI B31.8S,\nelectronic or other means, on a semi-annual frequency to OPS in accordance with\nAppendix A. An operator must submit the four overall performance measures, by\n$192.951. An operator must submit its first report on overall performance measures\nby August 31, 2004. Thereafter, the performance measures must be complete\nthrough June 30 and December 31 of each year and must be submitted within 2\nmonths after those dates.\n• Item 7A: §192.911(i) and §192.945(a)\nThe WGP procedure 10.24.01.02 does not provide sufficient detail for the responsibility of\nwho should collect information for submittal. [I.01.a]\n8. Management of Change\n§192.911 What are the elements of an integrity management program?\n(k) A management of change process as outlined in ASME/ANSI B31.8S, section 11.\n§192.909(b) Notification. An operator must notify OPS, in accordance with §192.949,\nimplementation or may significantly modify the program or schedule for carrying out\nof any change to the program that may substantially affect the program's\nthe program elements. An operator must also notify a State or local pipeline safety\n- 12-\n\n\n\nauthority when either a covered segment is located in a State where OPS has an\ninterstate agent agreement, or an intrastate covered segment is regulated by that\nState. An operator must provide the notification within 30 days after adopting this\ntype of change into its program.\nASMK B31. 8S-2001, Section 11\n(a) Formal management of change procedures shall be developed in order to identify\nand consider the impact of changes to pipeline systems and their integrity. These\nprocedures should be flexible enough to accommodate both major and minor\nchanges, and must be understood by the personnel that use them. Management of\nchange shall address technical, physical, procedural and organizational changes to\nthe system whether permanent or temporary. The process should incorporate\nplanning for each of these situations and consider the unique circumstances of each.\nA management of change process includes the following:\n(1) Reason for change\n(2) Authority for approving changes\n(3) Analysis of implications\n(4) Acquisition of required work permits\n(5) Documentation\n(6) Communication of change to affected parties\n(7) Time limitations\n(8) Qualification of staff\n(b) The operator shall recognize that system changes can require changes in the\nintegrity management program and conversely, results from the program can cause\nsystem changes. The following are examples that are gas pipeline specific but are by\nno means all inclusive.\n~ Item 8A: $192. 911(k) and ASME B31. 8S-2001, Section 11(a)\nWGP has requirements for an annual review to keep the BAP up-to-date with respect to\nnewly arising information, applicable threats, and risks that may require changes to the\nsegment prioritization or assessment method. A specific performance date or link to an\nactivity milestone must be defined in IMP procedures for the performance of the annual\nreviews.\n~ item 88: $192. 911(k) and ASMK B31. 8S-2001, Section 11(a)\nWGP IMP procedures do not address reasons for changes to the BAP, authority for\napproving the change, analysis of implications of the change, or communication of the\nchange to affected parties.\n~ item 8C: $192. 911(k) and ASMK B31. 8S-2001, Section 11(a)\nWGP procedure 10. 25. 01, Section 9. 1. 1 requires an annual update of the risk assessment\nbut does not provide a process or define responsibilities for ensuring new information is\nincorporated in a timely manner or to establish an interface with the management of\n\n\n\nchange process to ensure changes are appropriately reflected in risk analysis data.\nAdditionally a specific performance date or link to an activity milestone is not defined in\nIMP procedures for the performance of the annual update.\n~ Item SD: $192. 911{k) and ASMK B31. 8S-2001, Section 11(a)\nProcedure 10. 29. 01. 02 addresses the MOC process; however, the process does not address\nprocedural and organizational changes.\n~ Item SE: $192. 911(k) and ASME B31. 8S-2001, Section 11(a)\nNot all of the requirements of ASME B31. 8S, Section 11 are addressed by WGP's\nManagement of Change procedures.\n~ Item SFi $192. 911{k) and ASME B31. 8S-2001, Section 11(b)\nSome important system changes were not reported to the IMP team that could have\naffected pipeline integrity.\n~ Item SG: $192. 911(k) and $192. 909(b)\nWGP's Integrity Management Procedures do not require notification of OPS or the State or\nlocal pipeline safety authorities of significant changes to the program, program\nimplementation, or schedules. Additionally, the definition of what constitutes a significant\nchange has not been identified in IMP procedures. It was noted that WGP did have a\nchange log that listed changes that have occurred and the log included limited examples of\nwhat are considered to be significant changes.\n9. Quality Assurance\n$192. 911 What are the elements of an integrity management program?\n(l) A quality assurance process as outlined in ASMK/ANSI B31. 8S, Section 12.\n$192. 907(b) Implementation Standards. In carrying out this subpart, an operator\nmust follow the requirements of this subpart and of ASME/ANSI B31. 8S (ibr, see\n$192. 7) and its appendices, where specified. An operator may follow an equivalent\nstandard or practice only when the operator demonstrates the alternative standard or\npractice provides an equivalent level of safety to the public and property. In the\nevent of a conflict between this subpart and ASME/ANSI B31. 8S, the requirements in\nthis subpart control.\nASME B31. 8S-2001, Section 12. 2, Quality Management Control.\n(b) Specifically, activities that should be included in the quality control program are\nas follows:\n(2) The responsibilities and authorities under this program shall be clearly and\nformally defined.\n\n\n\n(3) Results of the integrity management program and the quality control program\nshall be reviewed at predetermined intervals, making recommendations for\nimprovement.\n(4) The people involved in the integrity management program shaH be competent,\naware of the program and all of its activities and shall be properly trained to execute\nthe activities within the program. Documentation of such competence, awareness and\nqualification, and the processes for their achievement, shall be part of the quality\ncontrol plan.\n(7) Corrective actions to improve the integrity management program or quality plan\nshall be documented and the effectiveness of their implementation monitored.\n(c) When an operator chooses to use outside resources to conduct any process, for\nexample pigging, that affects the quality of the integrity management program, the\noperator shall ensure control of such processes and document them within the quality\nprogram.\n$192. 915(a) Supervisory personnel. The integrity management program must\nprovide that each supervisor whose responsibilities relate to the integrity\nmanagement program possesses and maintains a thorough knowledge of the integrity\nmanagement program and of the elements for which the supervisor is responsible.\nThe program must provide that any person who qualifies as a supervisor for the\nintegrity management program has appropriate training or experience in the area for\nwhich the person is responsible.\n$192. 915(b) Persons who carry out assessments and evaluate assessment results. The\nintegrity management program must provide criteria for the qualification of any\nperson-\n(1) Who conducts an integrity assessment allowed under this subpart; or\n(2) Who reviews and analyzes the results from an integrity assessment and\nevaluation; or\n(3) Who makes decisions on actions to be taken based on these assessments.\n~ Item 9A: $192. 911(l) and ASMK B31. 8S-2001, section 12. 2(b)(2)\nChapter 2 of the WGP Integrity Management Program Overview delineates\nresponsibilities; however, these responsibilities do not align with those delineated in\nindividual WGP O&M procedures applicable to the IM Program.\n~ Item 9B: $192. 911(1) and ASMK B31. 8S-2001, section 12. 2(b)(3)\nThe WGP O&M manual has no procedures describing how internal Integrity Management\nreviews are conducted or documented. Requirements for the conduct of annual reviews\nshould be tied to a specific calendar timeframe or event milestone.\n~ Item 9C: $192. 911(l) and ASMK B31. 8S-2001, section 12. 2(b)(7)\nWGP procedures do not document or track corrective actions identified by audits of the\nIntegrity Management Program.\n\n\n\n~ Item 9D: $192. 911(l) and ASMK B31. 8S-2001, section 12. 2(c)\nWGP needs to identify the minimum qualification requirements for vendor and WGP\npersonnel involved in the control of the outsourced resources affecting the quality of the\nIntegrity Management Program. In addition, to identifying the minimum qualification\nrequirements, WGP needs to ensure that personnel performing IM activities meet those\nrequirements.\n~ Item 9E: $192. 911(1), ASMK B31. 8S-2001, section 12. 2{b){4) and $192. 915(a)\nChapter 14 of the Integrity Management Overview does not provide minimum\nqualification requirement","truncated":true,"body_characters":42953}