{"operation":"document","citation":"CPF 520070019M","title":"PAIUTE PIPELINE CO — Notice of Amendment","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2007-07-30","effective_on":null,"summary":"CLOSED notice of amendment citing 192.905(a), 192.905(b), 192.905(c), 192.909(a), 192.911(c), 192.911(d), 192.911(e), 192.911(j), 192.911(k), 192.911(l), 192.917(a), 192.919(c), 192.921(a)(4), 192.925(b), 192.925(b)(1), 192.925(b)(2), 192.925(b)(3), 192.925(b)(3)(i), 192.925(b)(3)(ii)(b), 192.925(b)(3)(iii), 192.925(b)(3)(iv), 192.927(c)(1), 192.947(d).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-520070019m.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-520070019m.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-520070019m","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/520070019M","body":"Notice of Amendment involving PAIUTE PIPELINE CO. PHMSA's enforcement data identifies the cited regulations as 192.905(a),  192.905(b),  192.905(c),  192.909(a),  192.911(c),  192.911(d),  192.911(e),  192.911(j),  192.911(k),  192.911(l),  192.917(a),  192.919(c),  192.921(a)(4),  192.925(b),  192.925(b)(1),  192.925(b)(2),  192.925(b)(3),  192.925(b)(3)(i),  192.925(b)(3)(ii)(b),  192.925(b)(3)(iii),  192.925(b)(3)(iv),  192.927(c)(1),  192.947(d). The case was opened on 2007-07-30 and is reported as closed as of 2009-02-03. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n520070019M_notice of amendment_07302007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520070019M/520070019M_notice%20of%20amendment_07302007.pdf\n\n520070019m_notice of amendment_07302007_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520070019M/520070019m_notice%20of%20amendment_07302007_text.pdf\n\n520070019M_operator response to notice_09112007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520070019M/520070019M_operator%20response%20to%20notice_09112007.pdf\n\n520070019m_notice of amendment_07302007_text.pdf\n\no\nU S. Department\nof Transportation\nPipeline and\nHazardous Materials Safety\nAdministration\n$ENT TO COMPLIANCE REGISTiPP\nHardcopy Electrontcal y\n¹ of Copiesg /Date o'7\n12300 W Dakota Ave, SuIte 110\nLakewood, CO 80228\nNOTICE OF AMENDMENT\nCERTIFIED MAIL - RETURN RECEIPT RE UESTED\nJuly 30, 2007\nMs. Marti Marek\nDirector, Engineering Staff\nSouthwest Gas Corporation\n5421 Spring Mountam Road\nLas Vegas, NV 89150\nCPF 5-2007-0019M\nDear Ms. Marek:\nOn August 14-17 and August 28-31, 2006, representatives of the Pipeline and Hazardous\nMaterials Safety Administration (PHMSA), pursuant to Chapter 601 of 49 Umted States Code,\ninspected Southwest Gas Corporation and Paiute Pipeline Company's (SWG/Paiute) integrity\nmanagement program in Las Vegas, Nevada. Both entities are covered under the one Integrity\nManagement Program identified as Transmission Integrity Management Program (TRIMP).\nOn the basis of the inspection, PHMSA has identified the apparent inadequacies found within the\nTRIMP plans or procedures, as described below:\nHigh Consequence Area (HCA) Identification\ng 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\nconsequence areas. An operator must use method (1) or (2) from the definition\nin $192. 903 to identify a high consequence area. An operator may apply one\nmethod to its entire pipeline system, or an operator may apply one method to\n\n\n\nindividual portions of the pipeline system. An operator must describe in its\nintegrity management program which method it is applying to each portion of\nthe operator's pipeline system. The description must include the potential\nimpact radius when utilized to establish a high consequence area.\n(b)(1) Identi Jted sites. An operator must identify an identified site, for purposes\nof this subpart, from information the operator has obtained from routine\noperation and maintenance activities and from public officials with safety or\nemergency response or planning responsibilities who indicate to the operator\nthat they know of locations that meet the identified site criteria. These public\nofficials could include officials on a local emergency planning commission or\nrelevant Native American tribal officials.\n(2) If a public official with safety or emergency response or planning\nresponsibilities informs an operator that it does not have the information to\nidentify an identified site, the operator must use one of the following sources, as\nappropriate, to identify these sites. (i) Visible marking (e. g. ,\na sign); or (ii) The\nsite is licensed or registered by a Federal, State, or local government agency; or\n(iii) The site is on a list (including a list on an internet web site) or map\nmaintained by or available from a Federal, State, or local government agency\nand available to the general public.\n(c) Newly identified areas. When an operator has information that the area\naround a pipeline segment not previously identified as a high consequence area\ncould satisfy any of the definitions in g 192. 903, the operator must complete the\nevaluation using method (1) or (2). If the segment is determined to meet the\ndefinition as a high consequence area, it must be incorporated into the\noperator's baseline assessment plan as a high consequence area within one year\nfrom the date the area is identified.\ng 192. 907 What must an operator do to implement this subpart?\n(a) General. No later than December 17, 2004, an operator of a covered pipeline\nsegment must develop and follow a written integrity management program that\ncontains all the elements described in g 192. 911 and that addresses the risks on\neach covered transmission pipeline segment.\ng 192. 911 What are the elements of an integrity management program?\nAn operator's initial integrity management program begins with a framework\n(see g 192. 907) and evolves into a more detailed and comprehensive integrity\nmanagement program, as information is gained and incorporated into the\nprogram. An operator must make continual improvements to its program. The\ninitial program framework and subsequent program must, at minimum, contain\nthe following elements. (When indicated, refer to ASME/ANSI B31. 8S (ibr, see g\n192. 7) for more detailed information on the listed element. )\n\n\n\n(a) An identiTication of all high consequence areas, in accordance with g 192. 905.\ng 192. 947 What records must an operator keep?\nAn operator must maintain, for the useful life of the pipeline, records that\ndemonstrate compliance with the requirements of this subpart. At minimum, an\noperator must maintain the following records for review during an inspection.\n(d) Documents to support any decision, analysis and process developed and used\nto implement and evaluate each element of the baseline assessment plan and\nintegrity management program. Documents include those developed and used in\nsupport of any identification, calculation, amendment, modification,\njustification, deviation and determination made, and any action taken to\nimplement and evaluate any of the program elements.\n~ Item 1A: g 192. 905(a), g 192. 903(2), (3), and (4), g 192. 907(a) and g 192. 911(a)\nThe SWGiPaiute TRIMP and hnked Operations Manual sections do not define all\nrequired process steps for identifying High Consequence Areas (HCA) in sufficient detail\nto support consistent implementation of the segment identification process. A\nconsiderable number of the HCA identification process steps that were described verbally\nare not documented m the current TRIMP and hnked sections of the Operations Manual.\nFor example: The hnk from the TRIMP Plan to the \"Mam and Service Design\" portion of\nOperations Manual does not provide process details (field measurements, use of field\nmeasurements, processing of data and use of maps, how often it is done, who has to do\nit).\n~ Item 1B: g 192. 905(b), g 192. 903(4), and g 192. 947(d)\nDecisions on which structures were considered identified sites are not documented. Field\ninformation on excluded structures is not recorded. Examples that were included in the\n\"Main and Service Design\" procedure and trainmg on HCA identification provide\nincomplete guidance on what should be considered identified sites (e. g. ,\n\"stadium\" and\n\"lake\" examples). Consistent criteria for inclusion of specific types of areas (e. g. ,\nparking lots) are not documented.\n~ Item 1C: g 192. 905(b) and g 192. 947(d)\nThere is no documented program requirement to contact pubhc officials to obtain\ninformation on potential identified sites. There are insufficient details provided for\ncontacting pubhc officials, such as a description of the method for establishing identified\nsites, to ensure that the process is repeatable and thorough.\n\n\n\n~ Item 1D: g 192. 903(c)\nThe process for revising HCAs or identifying new HCAs is not defined in sufficient\ndetail nor represented by procedures that describe how information on changes is\nobtained, how the information is communicated to personnel responsible for updating\nHCAs, how the information is used to update HCAs, how often this information is, —\nobtained and used, and who is responsible for obtaining it. Changes that are required to\nbe addressed, but are not currently addressed by the TRIMP and implementing\nprocedures include:\na. Changes in pipehne maximum allowable operating pressure (MAOP),\nb. Pipeline modifications affecting piping diameter,\nc. Changes in the commodity transported in the pipeline,\nd. Identification of new construction m the vicinity of the pipehne that results in\nadditional buildings intended for human occupancy or additional identified sites,\ne Change in the use of existing buildings (e. g. ,\nhome),\nhotel or house converted to nursing\nf. Installation of new pipeline,\ng. Change in pipeline class location (e. g. ,\nclass 2 to 3) or class location boundary,\nh. Pipeline reroutes\nCorrections to erroneous pipeline center hne data.\nAs a specific example, there is no detailed process description or procedure that addresses\nhow field personnel obtain and communicate information on new development along the\npipeline that could lead to additional HCAs being defined.\n2. Baseline Assessment Plan\ng 192. 911 What are the elements of an integrity management program'?\nAn operator's initial integrity management program begins with a framework (see g\n192. 907) and evolves into a more detailed and comprehensive integrity management\nprogram, as information is gained and incorporated into the program. An operator\nmust make continual improvements to its program. The initial program framework\nand subsequent program must, at minimum, contain the following elements. (When\nindicated, refer to ASME/ANSI B31. 8S (ibr, see g 192. 7) for more detailed\ninformation on the listed element. )\n(k) A management of change process as outlined in ASME/ANSI B31. 8S, section 11.\ng 192. 919 What must be in the baseline assessment plan?\n\n\n\nAn operator must include each of the following elements in its written baseline\nassessment plan:\n(c) A schedule for completing the integrity assessment of all covered segments,\nincluding risk factors considered in establishing the assessment schedule;\ng 192. 921 How is the baseline assessment to be conducted?\n(a) Assessment methods. An operator must assess the integrity of the line pipe in\neach covered segment by applying one or more of the following methods depending\non the threats to which the covered segment is susceptible. An operator must select\nthe method or methods best suited to address the threats identified to the covered\nsegment (See g 192. 917).\n(4) Other technology that an operator demonstrates can provide an equivalent\nunderstanding of the condition of the line pipe. An operator choosing this option\nmust 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~ Item 2A: g 192. 921 (a)(4)\nA notification to PHMSA has not been filed for the use of guided wave or Long Range\nUltra Sonic (LRUT) technology as an \"other\" technology for assessing the carrier pip8 m\ncasings. The basis for this failure to notify is that SWG/Paiute is using guided wave as a\ncomplementary tool to Pipehne Current Mapping (PCM) for these situations. However,\nPCM is not considered an effective tool to assess pipe within a casing. In fact, NACE RP\n0502-2002, Table 2 indicates that additional considerations are needed for External\nCorrosion Direct Assessment (ECDA) tool selection for all cased piping. Therefore, use\nof guided wave is considered \"new\" technology and requires notification.\n~ Item 2B: g 192. 919 (c)\nThe SWG/Paiute Basehne Assessment Plan (BAP) does not contain proposed assessment\ncompletion dates. As such, it is not possible to verify that assessments are completed on\nschedule and in accordance with the plan.\n~ Item 2C: g 192. 911(k)\nThere are insufficient program procedures to describe the method by which the Operator\nkeeps the BAP up-to-date with any newly arising information. Procedures to describe the\nprocess by which the Operator makes needed BAP in accordance with referenced\nStandard ASME B31. 85-2001 do not include:\n\n\n\nReasons for changes to the BAP,\nii. Authority for approving changes,\nni. Analysis of imphcations,\niv. Communication of changes to affected parties.\nIdentify Threats, Data Integration, and Risk Assessment\ng 192. 911 What are the elements of an integrity management program?\nAn operator's initial integrity management program begins with a framework (see g\n192. 907) and evolves into a more detailed and comprehensive integrity management\nprogram, as information is gained and incorporated into the program. An operator\nmust make continual improvements to its program. The initial program framework\nand subsequent program must, at minimum, contain the following elements.\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 (g\n192. 917) and to evaluate the merits of additional preventive and mitigative measures\n(g 192. 935) for each covered segment.\ng 192. 917 How does an operator identify potential threats to pipeline integrity and\nuse the 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 ASME/ANSI B31. 8S (ibr, see g\n192. 7), section 2, which are grouped under the following four categories: (1) Time\ndependent threats such as internal corrosion, external corrosion, and stress\ncorrosion cracking; (2) Static or resident threats, such as fabrication or construction\ndefects; (3) Time independent threats such as third party damage and outside force\ndamage; and (4) Human error.\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\nsegments for the baseline and continual reassessments (gg 192. 919, 192. 921,\n192. 937), and to determine what additional preventive and mitigative measures are\nneeded (g 192. 935) for the covered segment.\n~ Item 3A: g 192. 911(c) and g 192. 917(a)\nThe documented process for threat identification and evaluation does not specify timing\nof steps and the relation of threat evaluation steps to the conduct of basehne assessments.\n\n\n\nThe timmg of steps m the current threat identification does not support the scheduling of\nintegrity assessments in the BAP, because the specific required assessment methods\nwould not be known until after completion of threat identification and evaluation\n(performed at the time of the assessment). Depending on the threats found to apply to a\nspecific HCA, all of the following methods could be necessary: External Corrosion\nDirect Assessment (ECDA), Internal Corrosion Direct Assessment (ICDA), Stress, —\nCorrosion Cracking Direct Assessment (SCCDA), and hydro-testing for manufacturing or\nconstruction defects or Low Frequency Electric Resistance Welded (LFERW) pipe.\n~ Item 3B: g 192. 911(c) and g 192. 917(a)\nThe screening criteria used in the evaluation of Stress corrosion Cracking (SCC) do not\naddress near neutral SCC.\n~ Item 3C: g 192. 911(c) and g 192. 917(a)\nThe method of evaluation for interactive threats is not documented. No evaluation was\nperformed or documented for those HCAs that had completed threat and basehne\nassessments. In addition, there is no adjustment made for these threats in the risk\nalgorithm.\n~ Item 3D: g 192. 911(c) and g 192. 917(c)\nThe risk assessment process is not sufficiently detailed to identify how the risk\nassessment supports the objectives required by ASME B31. 8S.\nSection 5. 3. For\n,\nexample, the use of risk assessment to support preventive and mitigative measure\nevaluations or determination of assessment intervals is not addressed.\n~ Item 3E: g 192. 911(c) and g 192. 917(c)\nThe scoring in the population consequences index shows some logical inconsistencies. A\nsingle identified site would be given a higher score than any number of residences within\nthe Potential Impact Radius (PIR) used to estabhsh the HCA. The use of a calculated\nradius based on the equation in B31. 8S (CFER Circle equation) as a vanable is used\nwithout consideration of the number of residences or identified sites that exist within the\ncircle.\n~ Item 3F: g 192. 911(c) and g 192. 917(c)\nThe risk assessment model does not adequately reflect leak/incident data. The current\ntreatment is to associate the occurrence of a leak or incident with a specific pipeline\nsegment. The applicability of the leak or incident to other HCAs is not considered in the\ncurrent risk assessment process.\n\n\n\n~ Item 3G: g 192. 911(c) and g 192. 917(c)\nThe basis for the risk model weights for threat categories is not documented. The weight\nused for third party damage is considerably higher than the average for transmission\npipelines. Although it may be suitable for the distribution portions of the SWG/Paiute\nsystem, whether the same weights should be apphed to Pasute or certain transmission\nsections of the SWG/Paiute system (e. g. ,\nSouthwest Gas Transmiss&on Co. ) have not been\nevaluated.\n~ Item 3H: g 192. 911(c) and g 192. 917(c)\nNeither the TRIMP Plan nor the TRIMP Procedure adequately defines steps for revisions\nto the risk assessment if new information is obtained or conditions change on the pipehne\nsegments.\n~ Item 3I: g 192. 911(c) and g 192. 917(c)\nThe method for validation of the risk assessment results by SMEs is not documented in\nthe TRIMP Plan or TRIMP Procedure.\nDirect Assessment (DA) Plan\ng 192. 911 What are the elements of an integrity management program?\nAn operator's initial integrity management program begins with a framework (see g\n192. 907) and evolves into a more detailed and comprehensive integrity management\nprogram, as information is gained and incorporated into the program. An operator\nmust make continual improvements to its program. The initial program framework\nand subsequent program must, at minimum, contain the following elements.\n(d) A direct assessment plan, if applicable, meeting the requirements of g 192. 923,\nand depending on the threat assessed, of g 192. 925, 192. 927, or 192. 929.\ng 192. 925 What are the requirements for using External Corrosion Direct\nAssessment (ECDA)?\n(b) General requirements. An operator that uses direct assessment to assess the\nthreat of external corrosion must follow the requirements in this section, in\nASMEIANSI B31. 8S (ibr, see g 192. 7), section 6. 4, and in NACE RP 0502 — 2002 (ibr,\nsee g 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 (g 192. 917(b)) to evaluate the covered segment for the threat of third\nparty damage, and to address the threat as required by g 192. 917(e)(1).\n\n\n\n(1) Preassessment. In addition to the requirements in ASME/ANSI B31. 8S section\n6. 4 and NACE RP 0502 — 2002, section 3, the plan's procedures for preassessment\nmust include—\n(i) Provisions for applying more restrictive criteria when conducting ECDA for the\nfirst time on a covered segment.\n(ii) The basis on which an operator selects at least two different, but complementary\nindirect assessment tools to assess each ECDA Region. If an operator utilizes an\nindirect inspection method that is not discussed in Appendix A of NACE RP0502—\n2002, the operator must demonstrate the applicability, validation basis, equipment\nused, application procedure, and utilization of data for the inspection method.\n(2) Indirect Examination. In addition to the requirements in ASME/ANSI B31. 8S\nsection 6. 4 and NACE RP 0502 — 2002, section 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\ntool, and 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(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\nNACE RP0502 — 2002), or\n\n\n\n(B) Root cause analysis reveals conditions for which ECDA is not suitable (Section\n5. 6. 2 of NACE RP0502 — 2002).\n(iii) Criteria and notification procedures for any changes in the ECDA Plan,\nincluding changes that affect the severity classification, the priority of direct\nexamination, and the time frame for direct examination of indications; and (iv)\nCriteria that describe how and on what basis an operator will reclassify and\nreprioritize any of the provisions that are specified in section 5. 9 of NACE RP0502—\n2002.\n(4) Post assessment and continuing evaluation. In addition to the requirements in\nASME/ANSI B31. 8S section 6. 4 and NACE RP 0502 — 2002, section 6, the plan's\nprocedures for post assessment of the effectiveness of the ECDA process must\ninclude—\n(i) Measures for evaluating the long-term effectiveness of ECDA in addressing\nexternal corrosion in covered segments;\nand\n(ii) Criteria for evaluating whether conditions discovered by direct examination of\nindications in each ECDA region indicate a need for reassessment of the covered\nsegment at an interval less than that specified in g 192. 939. (See Appendix D of\nNACE RP0502 — 2002. )\n~ Item 4A: g 192. 911(d) and g 192. 925(b)\nThe TRIMP Procedure, Part 2, does not provide adequate procedural requirements\nsufficient to describe how the ECDA Plan is to be conducted in a repeatable consistent\nmanner. This lack of program detail is noted through several of the PHMSA protocols\nfor the Direct Assessment processes, including [D. Ol. a] [D. 02. a] [D. 02. b] [D. 02. d]\n[D. 03. a] [D. 04. e] [D. 04. g].\n~ Item 4B: g 192. 925(b)\nFor the INA Road line, the pipeline is compressed of 4\", 6\", 8\" and 12\" diameter pipe;\nhowever the preassessment only discusses 4\", 6\" and 12\". Three sections of 8\" pipe were\nnot mentioned. The final report only discusses 6\" and 12\" without an explanation of why\nall sizes were not addressed, or how SWG/Paiute determmed preassessment information\nof the 4\", 6\" and 12\" lines was adequate and why the information m the final report on\nthe 6\" and 12\" lines was sufficient.\n~ Item 4C: g 192. 925(b) and $192. 947(d)\nThe ECDA process for the INA Road does not fully integrate all leak data. The ECDA\nprocess considered a total of 35 leak mamtenance reports (LMRs) for that segment.\nHowever, records provided mdicated that only 8 were reviewed and utihzed in pre-\n- 10-\n\n\n\nassessment to capture coating data. No explanation of how the data was analyzed or why\nonly 8 leak records were considered in the ECDA assessment.\n~ Item 4D: g 192. 925(b)(1) and $192. 947(d)\nThe NACE requirements for selecting and documenting the basis for indirect assessment\ntools are not described in SWG's TRIMP, Part 2, Table 9. The basis for deviation from\nthe NACE indirect tool selection matrix has not been documented.\n~ Item 4K: g 192. 925(b)\nThe SWG/Paiute TRIMP does not provide sufficient details within its procedures for\nECDA Region definition based on indirect inspection tools selected, corrosion histories,\nand new data and information received from field surveys and indirect tool readings.\n~ Item 4F: Q 192. 925(b)(1), Q 192. 925(b)(3)(i) and Q 192. 925(c)(5)(ii)\nThe operator's Direct Assessment (DA) Plan does not provide criteria for performance of\nECDA activities m each of the program phases, i. e.\n, pre-assessment, indirect\nexamination, and direct examination.\n~ Item 4G: g 192. 925(b)(2)\nTRIMP Procedure, Part 2 does not provide proper linkage to the abnormal operations\nprocedure for cathodic protection (CP). The operator stated that the ECDA process stops\nwhen a low CP reading is identified until the CP can be brought within acceptance\ncriteria and the abnormal operations procedural requirements are performed. No\ndocumentation of this approach exists within the TRIMP.\n~ Item 4H: g 192. 947(d)\nPHMSA inspection team review of the SWG/Paiute use of LRUT in the Paradise Pipehne\nFlamingo Wash location, determined that the indication locations did not match when\nperforming LRUT from both directions. There was no documentation or process by\nwhich this discrepancy was resolved.\n~ Item 4I: g 192. 925(b)(3)\nA review of the Paradise pipehne ECDA Records indicated that the appropriate number\nof ECDA direct examinations was not performed. Only one \"C-level\" anomaly was\nexcavated in region 1, only one \"C\" and no \"no-indication\" locations were excavated in\nRegion 2. In region 1 in accordance with NACE (5. 10 and (6. 4 criteria, SWG/Paiute did\nnot excavate an additional \"B\" and in region 2 SWG/Paiute did not excavate an\nadditional \"C\" and a \"no-indication\" location.\n-11-\n\n\n\n~ Item 4J: g 192. 925(b)(3)(ii)(b)\nSWG/Paiute does not have a documented root cause determination process that will\nenable them to determine if ECDA is or is not well-suited for assessing pipeline integrity.\n~ Item 4K: g 192. 925(b)\nTRIMP Procedure, Part 2, Section 9. 18. 1 states that an evaluation to assess the indirect\ninspection data and the results from the remaining strength evaluation and the root cause\nanalyses must be performed.\nTRIMP Procedure, Part 2, Section 9. 18. 2 states that the purpose of the evaluation is to\ncritically assess the criteria used to categorize the need for repair, and to critically assess\nthe criteria used to classify the severity of individual indications.\nThese sections are simply a restatement of NACE RP0502, Section 5. 8 which requires\nthe operator to conduct an In-Process Evaluation. The TRIMP wording does not describe\nhow Paiute will actually carry out the evaluation, and Paiute was unable to provide\ndocumentation to demonstrate they performed the evaluation.\n~ Item 4L: g 192. 925(b)(3)(iv)\nA review of the Victorville, California ECDA data revealed that the Baseline Assessment\nResults report, the ECDA Severity Analysis Table produced by Mears (contractor), and\nthe \"Direct Examinations Dig Locations Listing\" contain the indirect examination\npriorities for indications. These documents do not match in their priorities for the\nindirect inspections. There is no documentation of the process to establish the final dig\nlist. It is also not clear how feedback is given to Mears to ensure that they make the\nproper priority call on indirect examination indications in the future.\n~ Item 4M: g 192. 925(b)(3)(iii), g 192. 909, and g 192. 911(k)\nRegarding establishing and implementing criteria and internal notification procedures for\nchanges in the ECDA Plan (including those affecting severity classification, priority of\ndirect examination, and the time frame for direct examination of indications),\nSWG/Paiute identified ECDA procedure (TRIMP Procedure, Part 2, Section 9. 23) which\naddresses FEEDBACK AND CONTINUOUS IMPROVEMENT, as well as TRIMP Plan\nSection 16. 5 which states \"Company management and other appropriate personnel will\nbe involved in the TRIMP communication process and support the integrity management\nprogram\", and \"Changes to the integrity management program shall be communicated as\nnecessary\". This wording is too general to require effective internal communication of\nchanges in ECDA plan.\n— 12-\n\n\n\n~ Item 4N: g 192. 927(c)(1) and g 192. 927(c)(5)(i)\nSWG/Paiute was unable to demonstrate a structured process for data gathering and\nintegration to support performance of the ICDA methodology. The SWG/Paiute ICDA\nPlan repeats the requirements contained in the proposed NACE RP ICDA Methodology.\n~ Item 40: g 192. 927(c)(5)(i).\nThe PHMSA inspection team reviewed the Paradise Pipehne assessment and determined\nthat critical angles were not identified although dig locations were identified and\nexcavated.\n5. Remediation\ng 192. 911 What are the elements of an integrity management program?\nAn operator's initial integrity management program begins with a framework (see g\n192. 907) and evolves into a more detailed and comprehensive integrity management\nprogram, as information is gained and incorporated into the program. An operator\nmust make continual improvements to its program. The initial program framework\nand subsequent program must, at minimum, contain the following elements.\n(e) Provisions meeting the requirements of g 192. 933 for remediating conditions\nfound during an integrity assessment.\ng 192. 933 What actions must be taken to address integrity issues?\n(a) General requirements. . . An operator must be able to demonstrate that the\nremediation of the condition will ensure that the condition is unlikely to pose a\nthreat to the integrity of the pipeline until the next reassessment of the covered\nsegment. . .\n. . . A reduction in operating pressure cannot exceed 365 days without an operator\nproviding a technical justification that the continued pressure restriction will not\njeopardize the integrity of the pipeline.\n(b) Discovery of condition. Discovery of a condition occurs when an operator has\nadequate information about a condition to determine that the condition presents a\npotential threat to the integrity of the pipeline. A condition that presents a potential\nthreat includes, but is not limited to, those conditions that require remediation or\nmonitoring listed under paragraphs (d)(1) through (d)(3) of this section. An\noperator must promptly, but no later than 180 days after conducting an integrity\nassessment, obtain sufficient information about a condition to make that\ndetermination, unless the operator demonstrates that the 180-day period is\nimpracticable.\n-13-\n\n\n\n(c) Schedule for evaluation and remediation. An operator must complete remediation\nof a condition according to a schedule that prioritizes the conditions for evaluation\nand remediation. Unless a special requirement for remediating certain conditions\napplies, as provided in paragraph (d) of this section, an operator must follow the\nschedule in ASME/ANSI B31. 8S (ibr, see $192. 7), section 7, Figure 4. If an operator\ncannot meet the schedule for any condition, the operator must justify the reasoits\nwhy it cannot meet the schedule and that the changed schedule will not jeopardize\npublic safety.\n(d) Special requirements for scheduling remediation. —\n(3) 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:\n(i) 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).\n(ii) A dent located between the 8 o' clock and 4 o' clock positions (upper 2 /3 of the\npipe) with a depth greater than 6% of the pipeline diameter (greater than 0. 50\ninches in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12), and\nengineering analyses of the dent demonstrate critical strain levels are not exceeded.\n(iii) A dent with a depth greater than 2% of the pipeline's diameter (0. 250 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.\ng 192. 947 What records must an operator keep?\nAn operator must maintain, for the useful life of the pipeline, records that\ndemonstrate compliance with the requirements of this subpart. At minimum, an\noperator must maintain the following records for review during an inspection.\n(f) Schedule required by g 192. 933 that prioritizes the conditions found during an\nassessment for evaluation and remediation, including technical justifications for the\nschedule\n~ Item 5A: g 192. 911(e) and g 192. 933(b)\nThe SWG/Paiute TRIMP does not provide information on where the date when the\n\"Discovery of Condition\" as defined in 192. 933(b) is to be documented.\n- 14-\n\n\n\n~ Item 5B: g 192. 911(e) and g 192. 933(d)(1)\nThe SWG/Paiute Remediation Design procedure does not contam provisions to require a\ntemporary pressure reduction or the pipehne to be shut down upon discovery of all\nimmediate repair conditions.\n~ Item 5C: g 192. 911(e) and g 192. 933(d)(3)\nThe SWG/Paiute TRIMP does not contam program requirements for the recording and\nmonitoring of anomahes that are classified as \"monitored conditions\" during subsequent\nrisk or integrity assessments for any change in their status that would require remediation.\nItem 5D: g 192. 911(e), g 192. 933(a), g 192. 933(c), and g 192. 947(f)\nThere are no program requirements that specify how and by whom technical justifications\nfor schedule change contingencies are to be developed and documented.\nRecordkeeping\ng 192. 911 What are the elements of an integrity management program?\nAn operator's initial integrity management program begins with a framework (see g\n192. 907) and evolves into a more detailed and comprehensive integrity management\nprogram, as information is gained and incorporated into the program. An operator\nmust make continual improvements to its program. The initial program framework\nand subsequent program must, at minimum, contain the following elements.\n(j) Record keeping provisions meeting the requirements of g 192. 947.\ng 192. 947 What records must an operator keep?\nAn operator must maintain, for the useful life of the pipeline, records that\ndemonstrate compliance with the requirements of this subpart. At minimum, an\noperator must maintain the following records for review during an inspection.\n(a) A written integrity management program in accordance with g 192. 907;\n(b) Documents supporting the threat identification and risk assessment in\naccordance with g 192. 917;\n(c) A written baseline assessment plan in accordance with g 192. 919;\n(d) Documents to support any decision, analysis and process developed and used to\nimplement and evaluate each element of the baseline assessment plan and integrity\nmanagement program. Documents include those developed and used in support of\nany identification, calculation, amendment, modification, justification, deviation\n\n\n\nand determination made, and any action taken to implement and evaluate any of the\nprogram elements;\n(e) Documents that demonstrate personnel have the required training, including a\ndescription of the training program, in\naccordance with g 192. 915;\n(f) Schedule required by g 192. 933 that prioritizes the conditions found during an\nassessment for evaluation and remediation, including technical justifications for the\nschedule;\n(g) Documents to carry out the requirements in gg 192. 923 through 192. 929 for a\ndirect assessment plan;\n(h) Documents to carry out the requirements in g 192. 931 for confirmatory direct\nassessment;\n(i) Verification that an operator has provided any documentation or notification\nrequired by this subpart to be provided to OPS, and when applicable, a State\nauthority with which OPS has an interstate agent agreement, and a State or local\npipeline safety authority that regulates a covered pipeline segment within that State.\n~ Item 6A: g 192. 911(j) and g 192. 947\nThe SWG/Paiute TRIMP and implementing procedures do not have instructions on\ndeveloping records and archivmg them appropnately. As an example, there is no record\nof decisions made for identified site surveys and the basis for inclusion or exclusion.\n7. Management of Change\ng 192. 909 How can an operator change its integrity management program?\n(a) General. An operator must document any change to its program and the reasons\nfor the change before implementing the change.\n(b) Notification. An operator must notify OPS, in accordance with $192. 949, of any\nchange to the program that may substantially affect the program's implementation\nor may significantly modify the program or schedule for carrying out the program\nelements. An operator must also notify a State or local pipeline safety authority\nwhen either a covered segment is located in a State where OPS has an interstate\nagent agreement, or an intrastate covered segment is regulated by that State. An\noperator must provide the notification within 30 days after adopting this type of\nchange into its program.\ng 192. 911 What are the elements of an integrity management program?\n- 16-\n\n\n\nAn operator's initial integrity management program begins with a framework (see g\n192. 907) and evolves into a more detailed and comprehensive integrity management\nprogram, as information is gained and incorporated into the program. An operator\nmust make continual improvements to its program. The initial program framework\nand subsequent program must, at minimum, contain the following elements. (When\nindicated, refer to ASME/ANSI B31. 8S (ibr, see g 192. 7) for more detailed\ninformation on the listed element. )\n(k) A management of change process as outlined in ASME/ANSI B31. 8S, section 11.\n~ Item 7A: g 192. 909(a), g 192. 909(b) and g 192. 911(k)\nThe SAG/Paiute Management of Change (MOC) process is fragmented and does not\ncontain sufficient detail to ensure that changes are thoroughly evaluated, tracked and\nreviewed and that all required aspects of the changes are documented. This issue\nincludes changes to the IMP, documents developed by the IMP, procedure changes, and\nphysical system changes, such as pipehne replacements, MOP revisions where uprating\nto a value greater than 20% SMYS is bemg considered.\nQuality Assurance\ng 192. 911 What are the elements of an integrity management program?\nAn operator's initial integrity management program begins with a framework (see g\n192. 907) and evolves into a more detailed and comprehensive integrity management\nprogram, as information is gained and incorporated into the program. An operator\nmust make continual improvements to its program. The initial program framework\nand subsequent program must, at minimum, contain the following elements. (When\nindicated, refer to ASME/ANSI B31. 8S (ibr, see g 192. 7) for more detailed\ninformation on the listed element. )\n(l) A quality assurance process as outline","truncated":true,"body_characters":42567}