{"operation":"document","citation":"CPF 420071005M","title":"ENABLE GAS TRANSMISSION, LLC — Notice of Amendment","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2007-03-29","effective_on":null,"summary":"CLOSED notice of amendment citing 192.903(c), 192.905(a), 192.907(a), 192.911(k), 192.911(l), 192.917(b), 192.917(e)(3), 192.917(e)(5), 192.921(a)(1), 192.925(b)(2), 192.927(c), 192.929(b)(1), 192.933(a), 192.933(c), 192.935(a), 192.935(b)(2), 192.937(b), 192.947(d).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-420071005m.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-420071005m.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-420071005m","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/420071005M","body":"Notice of Amendment involving ENABLE GAS TRANSMISSION, LLC. PHMSA's enforcement data identifies the cited regulations as 192.903(c),  192.905(a),  192.907(a),  192.911(k),  192.911(l),  192.917(b),  192.917(e)(3),  192.917(e)(5),  192.921(a)(1),  192.925(b)(2),  192.927(c),  192.929(b)(1),  192.933(a),  192.933(c),  192.935(a),  192.935(b)(2),  192.937(b),  192.947(d). The case was opened on 2007-03-29 and is reported as closed as of 2008-01-30. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n420071005M_operator response to notice letter_06292007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071005M/420071005M_operator%20response%20to%20notice%20letter_06292007.pdf\n\n420071005M_Operator Response_10052007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071005M/420071005M_Operator%20Response_10052007.pdf\n\nCPF 4-2007-1005M CenterPoint Engergy - NOA.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071005M/CPF%204-2007-1005M%20CenterPoint%20Engergy%20-%20NOA.pdf\n\nCPF 4-2007-1005M CenterPoint Engergy - NOA.pdf\n\nU.S. Department\nof Transportation\nPipeline and\nHazardous Materials Safety\nAdminlstration\n8701 South Gessner, Suite 11 10\nHouston. TX 77074\nNOTICE OF AMENDMENT\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\nMarch 29,2007\nWalter Ferguson\nSenior Vice President and COO, Pipeline Services\nCenterPoint Energy Gas Transmission\n525 Milam\nShreveport, LA 71101\nCPF 4-2007-1 005M\nDear Mr. Ferguson:\nOn September 12 - 16 and November 14 - 18,2005, representatives of the Pipeline and\nHazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United\nStates Code inspected CenterPoint Energy Gas Transmission's (CE) procedures for Integrity\nManagement in Shreveport, Louisiana.\nOn the basis of the inspection, PHMSA has identified the apparent inadequacies found within\nCE1s plans or procedures, as described below:\n1. § 192.903 What definitions apply to this subpart?\nThe following definitions apply to this subpart:\nHigh consequence area means an area established by one of the methods\ndescribed in paragraphs (1) or (2) as follows:\n1. An area defined as-\ni.\nA Class 3 location under 5 192.5; or\n..\n11. A Class 4 location under § 192.5; or\niii. Any area in a Class 1 or Class 2 location where the potential impact\nradius is greater than 660 feet (200 meters), and the area within a potential\nimpact circle contains 20 or more buildings intended for human\noccupancy; or\n\n\n\niv. Any area in a Class 1 or Class 2 location where the potential impact\ncircle contains an identified site.\n2. The area within a potential impact circle containing-\ni. 20 or more buildings intended for human occupancy, unless the\nexception in paragraph (4) applies; or\nii. An identified site.\n5 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 (a) or (b) from the definition in\nCFR: 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\nindividual portions of the pipeline system. An operator must describe in its\nintegrity management program which method it is applying to each portion of the\noperator's pipeline system. 'The description must include the potential impact\nradius when utilized to establish a high consequence area. (See appendix E.I. for\nguidance on identifying high consequence areas.)\nCE must modify its procedures to describe how and when either of the two HCA\nidentification methods in document PS-03-01-200, section 2.6 will be utilized and where\nthe information will be maintained or stored.\n5 192.903 (see above)\n(c) Newly-identified areas. When an operator has information that the area around\na pipeline segment not previously identified as a high consequence area could\nsatisfy any of the definitions in 5192.903, 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 operator's\nbaseline assessment plan as a high consequence area within one year from the\ndate the area is identified.\nCE must modify its procedure so that it clearly describes the process for updating and\ndocumenting the HCA analysis. It must include procedures which clearly define reviews\nfor charlges in pipeline systems which could impact HCA identification results, and it\nmust provide sufficient detail to ensure all new HCAs are identified through processes\nCE describes as routine. Accordingly, CE procedure PS-03-01-105, \"HCA-Class\nReview\" describes the process for updating the HCA analysis. However, it was noted\nthat the annual and ongoing updates to the HCA identification did not include a review of\nappropriate informational sources for changes in buildirrg use that may impact identified\nsite determinations. Additionally, changes in pipeline systems must be reviewed for\npotential impact to HCA identification results. These types of changes are not\nadequately addressed in CE's procedures. Finally, CE's procedure is not sufficiently\ndetailed to provide the needed level of specificity to assure that all HCAs are routinely\nfound.\n\n\n\n3. 3 192.907 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 CFR: 192.91 1 and that addresses the risks\non each covered transmission pipeline segment. The initial integrity management\nprogram must consist, at a minimum, of a framework that describes the process\nfor implementing each program element, how relevant decisions will be made and\nby whom, a time line for completing the work to implement the program element,\nand how information gained from experience will be continuously incorporated\ninto the program. The framework will evolve into a more detailed and\ncomprehensive program. An operator must make continual improvements to the\nprogram.\nA. B. With regard to the following CE Procedures, CE must modify its procedures\nbeyond a framework into more detailed and comprehensive programs which\ndescribe the 'who,' 'what,' 'where,' 'how,' and 'when' of the procedures to ensure\nthat they are consistently implemanted. Currently the procedures do not\nsufficiently detail the implementation of the processes to ensure that they are\nconsistently implemented. CE must modify the following procedures and ensure\nthat each provides the necessary specificity to ensure consistent application\nacross the CE pipeline systems.\nPS-03-01-105 HCA-Class Review\nPS-03-01-110 Gather, Review, and Integrate Data\nPS-03-01-200 HCA Segment Identification\nPS-03-01-216 Threat Identification and Risk Assessment\nPS-03-01-258 Preventive and Mitigative Measures\nPS-03-01-264 IMP Communications Plan\nIn order to assure that there are continual improvements made to the prograni,\nCE must modify procedures to ensure that there is continual feedback from the\nperformance of ongoing direct assessments on future direct assessments.\nAccordingly, CE must modify procedures PS-03-01-232, \"External Corrosion\nDirect Assessment,\" PS-03-01-230, \"Direct Assessment Plan,\" and PS-03-01-\n268, \"IMP Quality Assurance.\" CE must modify these procedures to ensure that\nthe continual improvement process is implemented consistently. Accordingly,\nthese requirements are due to the fact that during the inspection there was no\ndocumentation that feedback from direct assessments performed early in the\nschedule was used for assessments performed later. CE procedures PS-03-01-\n232, \"External Corrosion Direct Assessment,\" PS-03-01-230, \"Direct Assessment\nPlan,\" and PS-03-01-268, \"IMP Quality Assurance\", Appendix A states that CE\nwill apply the lessons learned on one ECDA assessment to future assessments\nvia the continual improvement process and the in-process evaluation step.\nNACE RP 0502 S6.5 and §192.925(3) (iii) require operators to continually\nirr~prove and use feedback to improve ECDA assessments. On the lines that\nhave had ECDA assessments, there were no completed post assessments, no\ndocumentation that the lessons learned on one or more the ECDA assessments\nwere factored into future assessments, and there were no notifications of\nchanges made in the ECDA process as the result of any lessons learned.\n\n\n\n4. 5. 3 192.911 What are the elements of an integrity management program?\nAn operator's initial integrity management program begins with a framework (see\nCFR: 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 subserjuent program must, at minimum, contain\nthe following elements. (When indicated, refer to ASMEIANSI 831.8s for more\ndetailed information on the listed element.)\n(k) A management of change process as outlined in ASMEIANSI B31.8S, Section\n11.\nASME /ANSI B31.8S, Section 11\n(a) Formal management of change procedures shall be developed in order to\nidentify and consider the impact of changes to pipeline systems and their\nintegrity. 'These procedures should be flexible enough to accommodate both\nmajor and minor changes, and must be understood by the personnel that use\nthem. Etc.\n(b) The operator shall recognize that system changes can require changes in the\nintegrity management program and conversely, results from the program can\ncause system changes. Etc.\nCE must modify its Management of Change procedure and process to ensure that\nimpacts of changes to organizations and changes to pipeline systems and their integrity\nare considered before being implemented. Accordingly, CE addresses their\nManagement of Change (MOC) process in procedure PS-03-01-266. The \"Purpose\"\nsection of the document limits the MOC process to changes in the IMP Program.\nAdditionally, the MOC process does not snsure that integrity management chauges are\nproperly reflected in the pipeline system and that pipeline system changes are properly\nreflected in the integrity management program. CE's procedure PS-03-01-266, \"IMP\nManagement of Change,\" describes the types of changes covered by CE's company-\nwide management of change process, including changes to a process, policy,\nprocedure, standard, handbook or manual. However, changes to organizations and\nchanges to pipeline systems and their integrity are not addressed in this process and CE\nmust modify these procedures to address these requirements. Further, while the CE\nIMP management of change process discusses impacts from pipeline equipment\nadditions, deletions or modifications, changes to product being transported, and\nowrating condition changes, the procedure does not adequately address how these\ntypes of changes are monitored and evaluated for IMP impact. Thus CE must change\nthe procedure to address how these changes are monitored and evaluated for IMP\nimpact.\n3 192.91 1 (see above)\n(I) Quality assurance process as outlined in ASMEIANSI B31.8S, Section 12.\nASMEIANSI B31.8S, Section 12.2 Quality Management Control\n(b) Specifically, activities that should be included in the quality control program\nare as follows:\n\n\n\n6. 7. (7) Corrective actions to improve the integrity management program or quality\nplan shall be documented and the effectiveness of their implementation\nmonitored.\nCE must modify its procedures to ensure it has an effective quality control program to\ndetermine the criteria and methods needed to ensure that both the operation and control\nof IM processes are effective and accurate through documentation, implementation, and\nmaintenance. Accordingly, CE's IM quality control procedure, PS-03-01-268, section 2.2\nstates that the operator has assessed and developed processes to determine the criteria\nand methods needed to ensure that both the operation and control of IIV processes are\neffective. However, the inspection team identified numerous processes where the lack\nof established quality criteria contributed to poor process implementation, including: risk\nanalysis data collection and evaluation; direct assessment minimum data requirements;\npreventive and mitigative decision-making; post assessment evaluations; documentation\nof remediation efforts; and periodic evaluations.\n§ 192.91 1 (1) (see above)\n12.2 Quality Management Control\n(c) When an operator chooses to use outside resources to conduct any process,\nfor example pigging, that affects the quality of the integrity management program,\nthe operator shall ensure control of such processes and document them within\nthe quality program.\nCE must modify its procedures to ensure a formal process exists which can be\nimplemented consistently for providing oversight of outside resources. Accordingly, CE\nprocedure PS-03-01-268, \"IMP Quality Assurance\" describes the quality assurance\nactivities related to the IM program. This process does not adequately address quality\nrequirements for providing oversight of outside resources, such as assessment,\nexcavation, and remediation of pipeline anomalies.\n5 192.917 How does an operator identify potential threats to pipeline integrity and\nuse the threat identification in its integrity program?\n(b) Data gathering and integration. To identify and evaluate the potential threats\nto a covered pipeline segment, an operator must gather and integrate existing\ndata and information on the entire pipeline that could be relevant to the covered\nsegment. In performing this data gathering and integration, an operator must\nfollow the requirements in ASMElANSl 631 .8S, section 4. At a minimum, an\noperator must gather and evaluate the set of data specified in Appendix A to\nASMElANSl 631.8S, and consider both on the covered segment and similar non-\ncovered segments, past incident history, corrosion control records, continuing\nsurveillance records, patrolling records, maintenance history, internal inspection\nrecords and all other conditions specific to each pipeline.\nA. CE must modify its procedures to ensure that it provides technical justifications\nfor assumptions used in the risk assessment process. In addition, CE must\nmodify its procedures to ensure data integration is thorough, complete, and\nconsistent and it must develop evaluation procedures to ensure the consistent\napplication of data integration. This requirement is consistent with Section 4 of\nASNIEIANSI 831.85 4.4 \"Data Collection, Review, and Analysis\" states \"A plan\n\n\n\nB. for collecting, reviewing, and analyzing the data shall be created and in place\nfrom the conception of the data collection effort. These processes are needed to\nverify the quality and consistency of the data. Records shall be maintained\nthroughout the process that identify where, and how unsubstantiated data is used\nin the risk assessment process so its potential impact on the variability and\naccuracy of assessment results can be considered.\" Similarly, Section 2.4 of CE\nprocedure PS-03-01-216, states that \"When data is missing or is questionable,\nconservative assumptions shall be used when performing the risk assessment or\nalternatively the pipe segment shall be prioritized to a higher level. For missing or\nquestionable data, default values shall be used. The default values shall be\ndocumented and the reason for their selection shall also be documented. Efforts\nshall be taken to replace missing or questionable data with reliable, accurate\ndata. These efforts may include additional field surveys or inspections to obtain\nthe data.\" At the time of this inspection, CE had pulled all of the data available\nfrom segments in HCA areas. CE expected that they would complete their data\nacquisition on the entire pipeline system in about one year. The risk model\nfields reviewed by the inspection team (Line MRT ML2) contained numerous\nexamples where actual data was not entered. CE used a default value of 0.49\n(from 0 to 1 .O) when data was missing (refer to PS-03-01-216 Appendix B,\nsection 6.0 and Table, \"Risk Variables Used for Threat Calculations\"). This\ndefault value puts the risk factor in the middle of the possible risk range. No\ntechnical justification was provided that supported the use of this value for all\ninstances when data was missing from the risk analysis.\nCE must develop a process to incorporate new data into the risk analysis when\nchanges in data occur (e.g., assessment results such as identification of MIC).\nThe frequency should be sufficient to ensure that risks are appropriately\naddressed for any applicable HCAs. In addition, the identification of missing risk\ndata in the risk analysis must be expedited and tracked in a more formal manner.\nAccordirlgly, the inspection team reviewed data in the risk analysis data-base\n(vertical slice review of line MRT ML2) and determined that data was missing or\nunavailable. At the time of this inspection, CE had pulled all of the data available\nfrom segments in HCA areas. CE expected that they would complete their data\nacquisition on the entire pipeline system in about one year. In response to\ninquires made by the inspection team regarding the tracking of missing data, CE\nstated that they were not formally tracking missing data and could not provide a\nstatus of what data was missing for which segments.\n8. 3 192.917 (see above)\n(e) Actions to address particular threats. If an operator identifies any of the\nfollowing threats, the operator must take the following actions to address the\nthreat.\n(3) Manufacturing and construction defects. If an operator identifies the threat of\nmanufacturing and construction defects (including seam defects) in the covered\nsegment, an operator must analyze the covered segment to determine the risk of\nfailure from these defects. The analysis must consider the results of prior\nassessments on the covered segmenk. An operator may consider manufacturing\nand construction related defects to be stable defects if the operating pressure on\nthe covered segment has not increased over the maximum operating pressure\n\n\n\n9. 10. experienced during the five years precedirlg identification of the high\nconsequence area. If any of the following changes occur in the covered segment,\nan operator must prioritize the covered segment as a high risk segment for the\nbaseline assessment or a subsequent reassessment.\ni. Operating pressure increases above the maximum operating\npressure experienced during the preceding five years;\nii. MAOP increases; or\niii. The stresses leading to cyclic fatigue increase.\nCE must modify its procedures to assure that threats to specific pipeline segments from\nmanufacturing and construction defects are reviewed against any MAOP increases in\norder to eliminate potential threats. Accordingly, neither section 2.3 nor section 2.5 in\nCE's document no. PS-03-01-216, \"Threat Identification and Risk Assessment\"\naddressed how the need for review against MAOP increases would be addressed. CE\nwas unable to produce documentation related to MAOP increases for the last five years.\nCE's procedure PS-03-01-216, \"Threat Identification and Risk Assessment\" must\naddress how MAOP will be reviewed to eliminate the threats from manufacturing and\nconstruction defects.\n§ 192.917 (e) (see above)\n(5) Corrosion. If an operator identifies corrosion on a covered pipeline segment\nthat 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\nevaluating and remediating, as necessary, the similar segments that is consistent\nwith the operator's established operating and maintenance procedures under Part\n192 for testing and repair.\nCE must modify its procedure, PS-03-01-258, \"Preventive and Mitigative Measures,\" to\ninclude the necessary specificity to address the need to evaluate other covered and non-\ncovered segments when corrosion exists on a covered segment that could adversely\nimpact the integrity of the line. During the inspection, the Inspection Team reviewed CE's\npreventive and mitigative flow chart which provides structure to this undocumented\nprocess.\n§ 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\ndepending on the threats to which the covered segment is susceptible. An\noperator must select the method or methods best suited to address the threats\nidentified to the covered segment.\n(1) Internal inspection tool or tools capable of detecting corrosion, and any other\nthreats to which the covered segment is susceptible. An operator must follow\nASlVlElANSl B31.8S, Section 6.2 in selecting the appropriate internal inspection\ntools for the covered segment.\n\n\n\n11. CE must modify its procedures to differentiate between the various types of ILI tools.\nAccordingly, CE's procedure only indicates to \"Perform ILI.\" CE describes the various\nassessment methods in PS-03-01-224, \"Assessment Methods Selection Process\" which\nreferences CE's \"BAP - Integrity Assessment Selection Guide.\" Neither the procedure\nnor the Guide specifies the type of ILI tot11 to be used for the threats to be assessed.\nASME B31.8S, Section 6.2, \"Pipeline In-Line Inspection,\" describes tool section for the\nvarious potential threats. According to ASME B31.8S section 6.2, \"In-line inspection (ILI)\nis an integrity assessment method used to locate and preliminarily characterize\nindications in a pipeline. The effectiveness of the ILI tool used depends on the\nconditions of the specific pipeline section to be inspected and how well the tool matches\nthe requirements set by the inspection objectives.\" To assure that the assessment\nmethod matches the requirements set by the inspection objectives, CE must specify the\nappropriate ILI tools planned for its assessments.\n5 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\nASMElANSl B31.8S (ibr, see §192.7), section 6.4, and in NACE RP 0502-2002 (ibr,\nsee 9192.7). An operator must develop and implement a direct assessment plan\nthat has procedures addressing preassessment, indirect examination, direct\nexamination, and post-assessment. If the ECDA detects pipeline coating damage,\nthe operator must also integrate the data from the ECDA with other information\nfrom the data integration (§192.917(b)) to evaluate the covered segment for the\nthreat of third party damage, and to address the threat as required by §192.917(e)\n(1 ).\n(2) Indirect Examination. In addition to the requirements in ASMElANSl 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..\n11. Criteria for identifying and documenting those indications that must\nbe considered for excavation and direct examination. Minimum\nidentification criteria include the known sensitivities of assessment tools,\nthe procedures for using each tool, and the approach to be used for\ndecreasing the physical spacing of indirect assessment tool readings when\nthe presence of a defect is suspected;\niii. Criteria for defining the urgency of excavation and direct\nexamination of each indication identified during the indirect examination.\nThese criteria must specify how an operator will define the urgency of\nexcavating the indication as immediate, scheduled or monitored; and\niv. Criteria for scheduling excavation of indications for each urgency\nlevel.\nCE must modify procedures PS-03-01-232, \"External Corrosion Direct Assessment,\" PS-\n03-01 -230, \"Direct Assessment Plan,\" and PS-03-01-268, \"IMP Quality Assurance\",\nAppendix A to ensure that whenever the spacing of the indirect tool readings is changed,\nthat the reason for the change will be documented and technically justified. CE must\nmodify procedures PS-03-01-232, \"External Corrosion Direct Assessment,\" and PS-03-\n01-230, \"Direct Assessment Plan,\" to ensure that CE uses the latest information to\nprioritize the urgency of the excavations based on the severity of the indication.\n\n\n\nAccordingly, for the ECDA assessments performed on lines ALE, BT-1 and A-206, there\nwas no documentation on the tool spacing changes for the indirect inspection tools.\n$192.925 (b) (2) (ii) requires that operators specify and document when the tool spacing\nis changed over areas that have indications. The reason for the change must be\nspecified. In addition, the table which was presented to the inspection team and was\nsaid to be used on one or more of the ECDA assessments regarding prioritization needs\nto be formally incorporated into one of CE's procedures concerniug ECDA.\n9 192.927 What are the requirements for using Internal Corrosion Direct\nAssessment (ICDA)?\n(c) The ICDA plan. An operator must develop and follow an ICDA plan that\nprovides for preassessment, identification of ICDA regions and excavation\nlocations, detailed examination of pipe at excavation locations, and post-\nassessment evaluation and monitoring.\n(2) ICDA region identification. An operator's plan must identify where all ICDA\nRegions are located in the transmission system, in which covered segments are\nlocated. An ICDA Region extends from the location where liquid may first enter\nthe pipeline and encompasses the entire area along the pipeline where internal\ncorrosion may occur and where further evaluation is needed. An ICDA Region\nmay encompass one or more covered segments. In the identification process, an\noperator must use the model in GRI 02-0057, \"Internal Corrosion Direct\nAssessment of Gas Transmission Pipelines - Methodology.\" An operator may use\nanother model if the operator demonstrates it is equivalent to the one shown in\nGRI 02-0057. A model must consider changes in pipe diameter, locations where\ngas enters a line (potential to introduce liquid) and locations down stream of gas\ndraw-offs (where gas velocity is reduced ) to define the critical pipe angle of\ninclination above which water film cannot be transported by the gas.\nCE must modify its procedures to properly identify the source of the flow model used in\nthe ICDA Plan. Accordingly, the inspection team noted that the model specified in CE\nprocedure PS-03-01-238, \"Dry Gas - Internal Corrosion Direct Assessment\" section 3.4,\nwas described as the GRI model but the model in the procedure is not the GRI model\nbut rather the IVACE model. There was no specific concern here because the NACE\nmodel has been validated against the GRI model and allowed for use. However, CE\nneeds to properly describe the model as the NACE model and not one that is based on\nthe Foude Number as in the GRI report.\n5 192.927 (c) (see above)\n(4) Post-assessment evaluation and monitoring. An operator's plan must provide\nfor evaluating the effectiveness of the ICDA process and continued monitoring of\ncovered segments where internal corrosion has been identified. 'The evaluation\nand monitoring process includes:\ni. Evaluating the effectiveness of ICDA as an assessment method for\naddressing internal corrosion and determining whether a covered segment\nshould be reassessed at more frequent intervals than those specified in\n9192.939. An operator must carry out this evaluation within a year of\nconducting an ICDA;\n\n\n\n14. CE must modify its procedures to ensure that post assessments for completed lnternal\nCorrosion (IC) direct assessments are complete and consistently applied. There is no\ndocumentation that feedback from IC direct assessments performed early in the\nschedule was used for assessments periormed later. Accordingly, CE procedures PS-\n03-01-238, \"Dry Gas - lnternal Corrosion Direct Assessment,\" PS-03-01-230, \"Direct\nAssessment Plan,\" and PS-03-01-268, \"IMP Quality Assurance\", Appendix A state that\nCE will apply the lessons learned from each ICDA assessment to future assessments.\ns192.927 requires operators to continually improve and use feedback to improve ICDA\nassessments. For the lines where the ICDA was complete there was no documentation\nthat the lessons learned were factored into future assessments and there was no\nnotification of changes made in the ICDA process as the result of any lessons learned.\nCE procedure PS-03-01-238, \"Dry Gas - lnternal Corrosion Direct Assessment,\" s6.2.1.2\nstates that improvements from one ICDA will be incorporated into future ICDA\nassessments.\n§ 192.927 (c) (4) (see above)\nii. Continually monitoring each covered segment where internal\ncorrosion has been identified using techniques such as coupons, UT\nsensors or electronic probes, periodically drawing off liquids at low points\nand chemically analyzing the liquids for the presence of corrosion\nproducts. An operator must base the frequency of the monitoring and\nliquid analysis on results from all integrity assessments that have been\nconducted in accordance with the requirements of this subpart, and risk\nfactors specific to the covered segment. If an operator finds any evidence\nof corrosion products in the covered segment, the operator must take\nprompt action in accordance with one of the two following required actions\nand remediate the conditions the operator finds in accordance with\n51 92.933.\n(A) Conduct excavations of covered segments at locations\ndownstream from where the electrolyte might have entered the pipe;\nor\n(B) Assess the covered segment using another integrity assessment\nmethod allowed by this subpart.\nCE must modify its procedures to ensure that the ICDA process provides assurance that\nthe monitoring actions for future internal corrosion will be accomplished. Accordingly,\nCE procedures PS-03-01-238, \"Dry Gas - lnternal Corrosion Direct Assessment,\" s5.10\nstates that \"once a dig site has been excavated and the Direct Examination activities\nhave been completed, corrosion monitoring devices such as a coupon, electronic probe,\nultrasonic sensor, or electrical resistance matrix may be installed. The Corrosion\nManager shall determine whether or not to install a corrosion monitoring device and the\nappropriate location within the DG-ICDA Region.\" CE must modify its procedures to\nensure mechanisms exist to inform the Corrosion Manager or other relevant personnel\nwhat has been discovered at direct examination sites and if there is a need for corrosion\nmonitorirrg on this pipeline. One instance was identified where this information was not\nforwarded to the Corrosion Manager.\n\n\n\n15. 5 192.929 What are the requirements for using Direct Assessment for Stress\nCorrosion Cracking (SCCDA)?\n(b) General Requirements. An operator using direct assessment as an integrity\nassessment method to address stress corrosion cracking in a covered pipeline\nsegment must have a plan that provides, at minimum, for -\n(1) Data gathering and integration. An operator's plan must provide for a\nsystematic process to collect and evaluate data for all covered segments to\nidentify whether the conditions for SCC are present and to prioritize the covered\nsegments for assessment. This process must include gathering and evaluating\ndata related to SCC at all sites an operator excavates during the conduct of its\npipeline operations where the criteria in ASMElANSl B31.8S, Appendix A3.3\nindicate the potential for SCC. This data includes at minimum, the data specified\nin ASMElANSl B31.8S, Appendix A3.\nA. CE must modify its SCCDA and related procedures to ensure that the gathering,\nevaluation, and quality control of data related to SCC is consistently applied and\ndocumented at all sites it excavates during the conduct of its pipeline operations\n(not just covered segments) where the criteria indicate the potential for SCC. CE\nmust provide a notification to OPS and modify procedures as necessary to\nensure the notification or any future modifications of its proposed near-neutral\nSCC plan. Finally, CE must modify its procedures to ensure the performance of\na spike test, per ASME B31.8S, when it experiences an in-service leak or rupture\nattributable to SCC. Accordingly, CE procedures PS-03-01-240, \"Stress\nCorrosion Cracking Direct Assessment,\" PS-03-01-230, \"Direct Assessment\nPlan,\" and PS-03-01-268, \"IMP Quality Assurance\", Appendix A describe how\nSCCDA assessments are to be conducted, the data to be collected and what\ndocumentation needs to be retained. None of those procedures mandate that CE\nobtain data on non-covered pipelines that may be susceptible to SCC. Studies\nhave shown that the screening criteria for both near neutral and high pH SCC\nonly cover 213 to 314 of the segments susceptible to SCC. Thus, operators are\nexpected to be looking for SCC in all areas of their pipelines. §192.917(e) (5)\nhas look beyond previsions for operators who have a history of any corrosion.\nThese previsions require operators to look at both covered and non-covered\nsegments that have sustained corrosion damage that is similar in physical and\nenvironmental characteristics.\nB. CE must modify procedures to ensure the quality of pre-assessment data for all\ncompleted SCC direct assessments and develop quality controls for use of data\nin future pre-assessments. During the review of SCC DA pre-assessments, data\nquality was determined to be poor or missing. Accordingly, section A3.3 of\nB31.8S states, \"Where the operator is missing data, conservative assumptions\nshall be used when performing the risk analysis or alternatively the segment shall\nbe prioritized higher.\" CE procedures PS-03-0 1-240, \"Stress Corrosion Cracking\nDirect Assessment,\" PS-03-01-230, \"Direct Assessment Plan,\" and PS-03-01-\n268, \"IMP Quality Assurance\", Appendix A require that the data elements used\nfor SCCDA be gathered. Based on some of the data elements that were\ninspected, CE did not review the data as required in their procedures. This poor\nquality data could lead to the incorrect bell hole locations being excavated. An\nineffective SCCDA may be the result of the poor quality data.\n\n\n\n16. C. D. CE must modify its procedures to ensure the notification of OPS andlor local\nregulatory authorities 180 days before proposing to use \"other technology.\"\nAccordingly, CE has not yet used its near neutral pH SCCDA process nor has it\nnotified any regulatory authority. However, section A3.1 of ASME 631.8s states,\n\"Near-neutral type of SCC similarly would require an inspection and alternative\nmitigation plan.\" CE procedures PS-03-01-240, \"Stress Corrosion Cracking\nDirect Assessment,\" and PS-03-01-230, \"Direct Assessment Plan,\" require CE\nnotify OPS and/or local regulatory authorities if CE plans to use \"Other\nTechnology\" as defined in 5192.921 (a)(4) (and follow the notification procedure\nin 5192.949). ASlWE 631.8s for SCCDA covers only high pH SCC and requires\noperators to develop a plan for near neutral pH SCC, which CE has done by\nfollowing the procedure in NACE RP 0204 for near neutral SCC. This\nrecommended practice is not referenced in the rule and thus is considered an\n\"Other Technology.\"\nCE must modify its procedures to ensure that a spike hydrostatic pressure test\nconsistent with ASME 631.8s is conducted after an in-service leak or rupture\noccurs which is attributed to SCC. Accordingly, section A3.4 of ASME 631.8s\nstates, \"If the pipeline experiences an in-service leak or rupture, which is\nattributed to SCC, the particular segment shall be subjected to a hydrostatic test\n(as described below) within 12 months.\" CE procedures PS-03-01-240, \"Stress\nCorrosion Cracking Direct Assessment,\" and PS-03-01-230, \"Direct Assessment\nPlan,\" state that CE can use a pressure test to check for SCC. There is no\nprocedure requirement to perforr.1 a spike test following an in-service leak or\nrupture attributable to SCC. ASME B31.8S specifically mandates that operators\nuse a spike hydrostatic pressure test following an in-service leak or rupture\nattributable to SCC.\n§ 192.933 What actions must be taken to address integrity issues?\n(a) General requirements. An operator must take prompt action to address all\nanomalous conditions that the operator discovers through the integrity\nassessment. In addressing all conditions, an operator must evaluate all\nanomalous conditions and remediate those that could reduce a pipeline's\nintegrity. An operator must be able to demonstrate that the remediation of the\ncondition will ensure that the condition is unlikely to pose a threat to the integrity\nof the pipeline until the next reassessment of the covered segment. If an operator\nis unable to respond within the time limits for certain conditions specified in this\nsection, the operator must temporarily reduce the operating pressure of the\npipeline or take other action that ensures the safety of the covered segment. If\npressure is reduced, an operator must determine the temporary reduction in\noperating pressure using ASMElANSl B31G or RSTRENG or reduce the operating\npressure to a level not exceeding 80% of the level at the time the condition was\ndiscovered. (See Appendix A to this part 192 for information on availability of\nincorporation by reference information). A reduction in operating pressure cannot\nexceed 365 days without an operator providing a technical justification that the\ncontinued pressure restriction will not jeopardize the integrity of the pipeline.\nA. CE must modify its procedures to ensure that ILI information is communicated to\nthe relevant departments in a timely manner to ensure the proper application of\nany and all necessary remedial actions. Accordingly, ILI assessments completed\n\n\n\nB. by CE identified internal corrosion but this information was not forwarded to\ncorrosion group for consideration of additional remedial actions. CE should\nformalize this action within the IM program. CE procedure PS-03-01-250,\n\"Pipeline Evaluation and Remediation\" describes the process for addressing\nanomalous conditions identified through integrity management assessments. CE\nprocedures PS-03-01-110, \"Gather, Review, and Integrate Data,\" describes the\nprocess for data integration. Neither procedure specifies requirements to forward\ninternal corrosion information identified during lLls to the corrosion group for\nevaluation. During the review of an ILI assessment (e.g., AT-5), the inspection\nteam identified an instance where internal corrosion was identified and this\ninformation was not forwarded to the corrosion group for evaluation. CE\nprovided documentation to the inspection team that they had forwarded internal\ncorrosion information from other :LI assessments to the internal corrosion group\nalthough the process was not formalized.\nCE must modify its procedures to ensure the proper communication and\ndocumentation of the operating pressure at the time of discovery related to an\nimmediate repair anomaly so that the required pressure reduction can be\naccurately determined and documented. Accordingly, records reviewed by the\ninspection team did not provide proper communications associated with\noperating pressure at the time of discovery. Section 2.5 of CE procedure PS-03-\n01 -250, \"Pipeline Evaluation and Remediation\" speci.fies the requirements for\ntemporary pressure reduction when an \"immediate\" repair anomaly is identified.\nHowever, this procedure does not require that the operator document the\noperating pressure at the time of discovery of the anomaly. During review of\nassessment results, the inspection team noted that the operator did not\ndocument the operating pressure at the time of discovery of anomalies. This lack\nof documentation made it difficult to confirm that the pressure reduction was\nappropriate.\n17. 9 192.933 (see above)\n(c) Schedule for evaluation and remediation. An operator must complete\nremediation","truncated":true,"body_characters":55344}