{"operation":"document","citation":"CPF 520075019M","title":"CONOCOPHILLIPS ALASKA, INC. — Notice of Amendment","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2007-04-26","effective_on":null,"summary":"CLOSED notice of amendment citing 195.452(h), 195.452(h)(4), 195.452(i), 195.452(i)(2), 195.452(j), 195.583.","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-520075019m.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-520075019m.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-520075019m","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/520075019M","body":"Notice of Amendment involving CONOCOPHILLIPS ALASKA, INC.. PHMSA's enforcement data identifies the cited regulations as 195.452(h),  195.452(h)(4),  195.452(i),  195.452(i)(2),  195.452(j),  195.583. The case was opened on 2007-04-26 and is reported as closed as of 2008-04-08. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n520075019M_notice of amendment_04262007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520075019M/520075019M_notice%20of%20amendment_04262007.pdf\n\n520075019m_notice of amendment_04262007_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520075019M/520075019m_notice%20of%20amendment_04262007_text.pdf\n\n520075019M_operator_response_and_request_for_extension_05162007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520075019M/520075019M_operator_response_and_request_for_extension_05162007.pdf\n\n520075019m_notice of amendment_04262007_text.pdf\n\nU. S. Department\nof Transportation\nPipeline and\nHazardous Materials Safety\nAdministration\n12300 W Dakota Ave, Suite 110\nLakewood, CO 80228\nNOTICE OF AMKNDMKNT\nCERTIFIED MAIL - RETURN RECEIPT RE UESTED\nApril 26, 2007\nMr. Darren C. Jones\nVice President, Commercial Assets\nATO 2100\nConocoPhillips Alaska, Inc. (CPAI)\n700 G Street\nAnchorage, AK 99510-0360\nSENT TO COMPLIANCE REGISTRY\nHardcopy Electronicall\n¹of Copies&/Date &/p'7\nCPF 5-2007-5019M\nDear Mr. Jones:\nOn November 14 to 16, 2006, representatives of the Pipeline and Hazardous Materials Safety\nAdministration (PHMSA) pursuant to Chapter 601 of 49 United States Code inspected your\nprocedures for Integrity Management and various Part 195 requirements in Anchorage, Alaska.\nIt was noted that segment identification for new High Consequence Areas (HCA) has a start\ndate May of 2006 when CPAI determined the PHMSA position related to work camps and an\nUnusually Sensitive Area (USA) (spectacled eiders) being considered HCAs.\nOn the basis of the inspection, PHMSA has identified the apparent inadequacies found within\nCPAI's plans or procedures, as described below:\n1. $195. 452 (f) An operator must include, at minimum, each of the following elements\nin its written integrity management program: (8) A process for review of integrity\nassessment results and information analysis by a person qualified to evaluate the\nresults and information (see paragraph (h)(2) of this section)\n$195. 452 (h) (2) Discovery of a condition. Discovery of a condition occurs when an\noperator has adequate information about the condition to determine that the\ncondition presents a potential threat to the integrity of the pipeline. An operator\nmust promptly, but no later than 180 days after an integrity assessment, obtain\nsufficient information about a condition to make that determination, unless the\noperator can demonstrate that the 180-day period is impracticable.\n\n\n\nConocoPhillips Alaska, Inc. (CPAI) considers a tool tolerance of 10% on the\n\"immediate\" through-wall anomalies. An analogous tolerance is not applied to the 180-\nday conditions.\n2. $195. 452 (h) (1) General requirements. An operator must take prompt action to\naddress all anomalous conditions that the operator discovers through integrity\nassessment or information analysis . . . evaluate all anomalous conditions and\nremediate those that could reduce a pipeline's integrity . . . demonstrate that the\nremediation of the condition will ensure the condition is unlikely to pose a threat to\nthe long-term integrity of the pipeline. A reduction in operating pressure cannot\nexceed 365 days without an operator taking further remedial action to ensure the\nsafety of the pipeline. An operator must comply with g 195. 422 when making a\nrepair.\n$195. 452 (h) (3) Schedule for evaluation and remediation. An operator must\ncomplete remediation of a condition according to a schedule that prioritizes the\nconditions for evaluation and remediation. . . . the operator must justify the reasons\nwhy it cannot meet the schedule and that the changed schedule will not jeopardize\npublic safety or environmental protection. An operator must notify OPS if the\noperator cannot meet the schedule and cannot provide safety through a temporary\nreduction in operating pressure\n$195. 452 (h) (4) Special requirements for scheduling remediation. Immediate repair\nconditions. . . . To maintain safety, an operator must temporarily reduce operating\npressure or shut down the pipeline . . . callculate the temporary reduction in\noperating pressure using the formula in section 451. 7 of ASME/ANSI B31. 4. . . .\nConocoPhillips Alaska, Inc. 's (CPAI) Integrity Management (IM) manual stated the\nfollowing:\n\"Section 7. 11 Temporary Operating Pressure Reduction:\n7. 11. 1 Previous Maximum Operating Pressures\nTo meet temporary operattng pressure reduction requirements, CPAI\ndepressurizes the defect location to a maximum of 75% of the highest operating\npressure actually experienced within the two months preceding the inspection\nuntil additional engineering analysis is completed. The Field Mechanical/Piping\nEngineer completes the analysis within one week of discovery; at which time\neither a repair will be completed, the line shut-in and de-pressurized, or a\nlonger-term operating strategy established by the Engineering and Corrosion\nand Pipeline Operations Supervisors\n*** \"Immediate \"pressure reduction therefore taken as 7 days. \"\nThe Section 7. 11. 1 of your IM manual indicated that it will take seven days to\nimplement a pressure reduction in response to \"immediate\" repair conditions. While\n\n\n\n\"immediate\" has not been defined by PHMSA, a nominal one-week response time is\nexcessive for responding to this type of serious integrity condition.\n3. $195. 452(e) What are the risk factors for establishing an assessment schedule (for\nboth the baseline and continual integrity assessments) P . . . .\n$195. 452(i)(2) Risk analysis criteria. In identifying the need for additional\npreventive and mitigative measures, an operator must evaluate the likelihood of a\npipeline release occurring and how a release could affect the high consequence\narea. This determination must consider all relevant risk factors, including, but not\nlimited to: . . . .\nConocoPhillips Alaska, Inc. 's (CPAI) Integrity Management (IM) manual stated the\nfollowing:\n\"List of Risk Factors from IM Plan:\nSection 5. 6. 2, DATA GATHERING, REVIEWAND INTEGRATION\nThe second risk assessment component involves gathering all pertinent data to\ncharacterize individual pipeline segments and the potential threats of a release to\nthe HCAs. The IMP Coordinator gathers relevant information pertaining to the\ndesign, operation, maintenance, operating history, corrosion program,\nsurveillance and specific failures and concerns. Specific information includes:\nCPAI incident reports (TapRoot), spill reports, vehicular accidents in the\npipeline right-of-way, third party damage, corrosion data (inspections, coupons,\nSd'c W reports, etc), product characteristics, and management of change. Sources\ninclude operating personnel, documentation, and third party knowledge.\nPreviously unrecognized risks are identified during the data integration meeting\nconducted by the Kuparuk Corrosion Team as described in the Kuparuk\nCorrosion Team Desktop Guideline (KCT Guideline), DOT Lines Data\nIntegration These previously unrecognized risks are reviewed and revised by\nthe SMET and incorporated into the risk assessment as necessary so the index\nmodel adequately addresses all rislcs to the pipeline. \"\nCPAI's Integrity Management program does not include all risk factors (e. g. ,\n\"seam\ntype,\n\" \"manufacturing information\") in the risk analysis model and/or the basis for\nexclusion is not documented.\n4. $195. 452(e) What are the risk factors for establishing an assessment schedule (for\nboth the baseline and continual integrity assessments) P . . . .\n$195. 452(f) An operator must include, at minimum, each of the following elements\nin its written integrity management program: (3) An analysis that integrates all\navailable information about the integrity of the entire pipeline and the\nconsequences of a failure (see paragraph (g) of this section);\n$195. 452(g) What is an information analysis' In periodically evaluating the\nintegrity of each pipeline segment (paragraph (j) of this section), an operator must\nanalyze all available information about the integrity of the entire pipeline and the\n3\n\n\n\nconsequences of a failure\n$195. 452(i)(2) Risk analysis criteria In identifying the need for additional\npreventive and mitigative measures, an operator must evaluate the likelihood of a\npipeline release occurring and how a release could affect the high consequence\narea. This determination must consider all relevant risk factors, including, but not\nlimited to: . . . .\nConocoPhillips Alaska, Inc. 's (CPAI) Integrity Management (IM) manual stated the\nfollowing:\n\"Section 5. 6. 3, Risk Assessment:\nThe itemization of the events potentially leading to a failure is categorized into\nfour indices corresponding to areas having historically resulted in pipeline\nfailures. The four indices are:\n1 Third Party Damage Index: Examines the potential of harmPom activities\nperformed by someone other than the pipeline operating personnel.\n2. Corrosion Index: Examines the type of corrosion plan in use and gives credit\nbased on the potential for atmospheric corrosion, internal corrosion and\nburied metal corrosion.\n3. Design Index: Examines how well the design process was performed and\ntakes into account whether the pipeline is operating at pressure and flows\nbelow the design point\n4. Incorrect Operations Index: Examines the actual operation of the pipeline\nsystem by looking at operations, maintenance, construction and the design\nprocess. This index is the most subjective as it relies, in part, on operating\npersonnel j udgments.\nThe Leak Impact Factor determines the consequence by examining the product\ncharacteristics, line pipe location, spill volume, and the affect of a leak\ncondition. Each index has a score between 0 and 100 added together to provide\nan Index Sum. This Index Sum, divided by the Leak Impact Factor, provides a\nRelative Risk score (from 0 to 2000). A lower risk score indicates a higher risk.\nFigure 5-1, The Muhlbauer Model Diagram, illustrates the evaluation process\napplied to each pipeline segment \"\n*** All for major indices weighted equally (original Muhlbauer default). \"\nThe major risk indices in the modified Muhlbauer model — Design, Corrosion, Third\nParty, and Incorrect Operation — were weighted equally (default Muhlbauer model\nvalues). This is not reflective of CPAI's actual risk profile on your pipeline system (e. g. ,\ncorrosion threats is not equal to third party damage threats for the CPAI lines), and\nshould be justified.\n5. $195. 452 (f) 8'hat are the elements of an integrity management program?\n(6) Identification of preventive and mitigative measures to protect the high\nconsequence area (see paragraph of this section)\n\n\n\n$195. 432(i) What preventive and mitigative measures must an operator take to protect\nthe high consequence area?(1) General requirements. An operator must take\nmeasures to prevent and mitigate the consequences of a pipeline failure that could\naffect a high consequence area. These measures include conducting a risk analysis\nof the pipeline segment to identify additional actions to enhance public safety or\nenvironmental protection. Such actions may include, but are not limited to,\nimplementing damage prevention best practices, better monitoring of cathodic\nprotection where corrosion is a concern, establishing shorter inspection intervals,\ninstalling KFRDs on the pipeline segment, modifying the systems that monitor\npressure and detect leaks, providing additional training to personnel on response\nprocedures, conducting drills with local emergency responders and adopting other\nmanagement controls.\nConocoPhillips Alaska, Inc, 's (CPAI) Integrity Management (IM) manual stated the\nfollowing:\n\"Section 9. 11. 1, \"Effectiveness Evaluation \":\nWAen sufficient additional objective data, such as that prescribed in paragraph\n195. 452(g) and relevant to the North Slope Pipelines is located that may affect\nthe outcome and corresponding rankings or following an actual unplanned\nproduct release the IMP Coordinator works with a SMET to revise the risk\nassessment and measures profile, and evaluate the effectiveness of preventive\nand mitigative measures\nAt a minimum, the previous measures evaluation will be reviewed, and revised as\nnecessary, during the IMP annual review following the completion of each\npipeline assessment and any associated repairs or mitigation activities. New\ninformation, received from activities such as pipeline assessments, modificattons,\nor repairs, and addktional operating modifications and experience is\nincorporated into the analysis, priorities are adjusted based on the outcomes,\nand the IMP is revised to reflect the current status of pipeline integrity\nmanagement utilizing this process in conjunction with those described in Section\nI2, Change Management, and Section 13, Program Review. \"\nA maximum interval or other criteria to initiate the re-evaluation of Preventive and\nMitigative (P&M) measures was not well defined. The present \"criteria\" for re-\nevaluation includes a significant change in the line configuration, operation, risk\nassessment change, etc. . . P&M measures were evaluated for the first time in 2004;\nhowever, CPAI revised the risk model in 2005 and did not re-evaluate the P&M\nmeasures of the revised risk results.\n7. $195. 452 (f) An operator must include, at minimum, each of the following elements\nin its written integrity management program: (5) A continual process of assessment\nand evaluation to maintain a pipeline's integrity (see paragraph (j) of this section);\n$195, 452 (j) What is a continual process of evaluation and assessment to maintain a\npipeline's integrity? (1) General. After completing the baseline integrity assessment,\nan operator must continue to assess the liine pipe at specified intervals and\nperiodically evaluate the integrity of each pipeline segment that could affect a high\n5\n\n\n\nconsequence area. (2) Evaluation. An operator must conduct a periodic evaluation\nas frequently as needed to assure pipeline integrity. An operator must base the\nfrequency of evaluation on risk factors specific to its pipeline, including the factors\nspecified in paragraph (e) of this section. The evaluation must consider the results\nof the baseline and periodic integrity assessments, information analysis (paragraph\n(g) of this section), and decisions about remediation, and preventive and mitigative\nactions (paragraphs (h) and of this sectiion).\nWhile CPAI did establish the methods of integrating IM data; however, the IM program\ndoes not include an explicit \"Periodic Evaluation\" process as required by 195. 452(j)(2).\nMeanwhile, the data integration meeting is conducted every six months and an annual\nreview is conducted to determine if risk analysis needs to be revised. It appears that\nCPAI did not include all of the required periodic evaluation considerations.\n7. $195. 583 What must I do to monitor atmospheric corrosion control?\n(a) You must inspect each pipeline or portion of pipeline that is exposed to the\natmosphere for evidence of atmospheric corrosion, as follows:\nIf the pipeline is located:\nThen the frequency of\ninspection is:\nOnshore.\nOffshore.\nAt least once every 3\ncalendar years, but with\nintervals not exceeding 39\nmonths.\nAt least once each calendar\nyear, but with intervals\nnot exceeding 15 months.\n(b) During inspections you must give particular attention to pipe at soil-to-air\ninterfaces, under thermal insulation, under disbonded coatings, at pipe supports, in\nsplash zones, at deck penetrations, and in spans over water.\n(c) If you find atmospheric corrosion during an inspection, you must provide\nprotection against the corrosion as required by $195. 581.\nCPAI's method of atmospheric corrosion control did not comply with 195. 583\nrequirements (modified ECDA not doing entire line condition). A waiver must be\nsubmitted to PHMSA to support the current approach. The presentation of the activities\nconducted in place of in-line inspection (ILI) or hydrotest were discussed at length. In\ngeneral, your adaptation of the ECDA for aboveground piping has merit but does not\nappear to meet the requirements of 195. 583 especially in the areas of pipe supports and\nunder thermal insulation.\n\n\n\nRes onse to this Notice\nThis Notice is provided pursuant to 49 U. S. C. $ 60108(a) and 49 C. F. R. $ 190. 237. Enclosed as\npart of this Notice is a document entitled Response Options for Pipeline Operators in\nCompliance Proceedings. Please refer to this document and note the response options. Be\nadvised that all material you submit in response to this enforcement action is subject to being\nmade publicly available. If you believe that any portion of your responsive material qualifies\nfor confidential treatment under 5 U. S. C. 552(b), along with the complete original document\nyou must provide a second copy of the document with the portions'you believe qualify for\nconfidential treatment redacted and an explanation of why you believe the redacted information\nqualifies for confidential treatment under 5 U. S. C. 552(b). If you do not respond within 30 days\nof receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this\nNotice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in\nthis Notice without further notice to you and to issue a Final Order.\nIf„after opportunity for a hearing, your plans or procedures are found inadequate as alleged in\nthis Notice, you may be ordered to amend your plans or procedures to correct the inadequacies\n(49 C. F. R. $ 190. 237). If you are not contesting this Notice, we propose that you submit your\namended procedures to my office within 60 days of receipt of this Notice. This period may be\nextended by written request for good cause. Once the inadequacies identified herein have been\naddressed in your amended procedures, this enforcement action will be closed.\nIn correspondence concerning this matter, please refer to CPF 5-2007-5019M and, for each\ndocument you submit, please provide a copy in electronic format whenever possible.\nSincerely,\nC ' oia\nDirector, Western Region\nPipeline and Hazardous Materials Safety Administration\nEnclosure: Response Options for Pipeline Operators in Compliance Proceedings\ncc: PHP-60 Compliance Registry\nPHP-500 B. Hansen (¹118171)","truncated":false,"body_characters":18558}