{"operation":"document","citation":"CPF 520180013W","title":"ALYESKA PIPELINE SERVICE CO — Warning Letter","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2018-12-27","effective_on":null,"summary":"CLOSED warning letter citing 192.479(a), 192.479(b), 192.605(a), 192.709(c), 192.807(a), 192.907(a), 192.919(b), 192.919(c).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-520180013w.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-520180013w.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-520180013w","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/520180013W","body":"Warning Letter involving ALYESKA PIPELINE SERVICE CO. PHMSA's enforcement data identifies the cited regulations as 192.479(a),  192.479(b),  192.605(a),  192.709(c),  192.807(a),  192.907(a),  192.919(b),  192.919(c). The case was opened on 2018-12-27 and is reported as closed as of 2018-12-27. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n520180013W_Operator Response to Notice_01282019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520180013W/520180013W_Operator%20Response%20to%20Notice_01282019.pdf\n\n520180013W_Warning Letter_12272018.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520180013W/520180013W_Warning%20Letter_12272018.pdf\n\n520180013W_Warning Letter_12272018_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520180013W/520180013W_Warning%20Letter_12272018_text.pdf\n\n520180013W_Warning Letter_12272018_text.pdf\n\nWARNING LETTER\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\nDecember 27, 2018\nMr. Thomas Barrett\nPresident and CEO\nAlyeska Pipeline Service Company\nPO Box 196660\nAnchorage, AK 99519\nCPF 5-2018-0013W\nDear Mr Barrett:\nOn multiple occasions between April 24, 2017 and March 16, 2018, a representative of the\nPipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety\n(OPS), pursuant to Chapter 601 of 49 United States Code (U.S.C.), inspected your Fuel Gas\nPipeline between Pump Stations 1 and 4, and reviewed records and procedures in Anchorage,\nAlaska.\nAs a result of the inspection, it is alleged that you have committed probable violations of the\nPipeline Safety Regulations, Title 49, Code of Federal Regulations (CFR). The items inspected\nand the probable violation(s) are:\n1. § 192.479 Atmospheric corrosion control: General.\n(a) Each operator must clean and coat each pipeline or portion of pipeline that is\nexposed to the atmosphere, except pipelines under paragraph (c) of this section.\n(b) Coating material must be suitable for the prevention of atmospheric corrosion.\nThe Operator failed to properly coat each pipeline that is exposed to the atmosphere. Several\nabove ground valve stations had exposed inadequate coating, particularly at soil-to-air interfaces.\n\n\n\nAccording to the Operator, the Atigan River Bridge span over the river has a “coating system”\ncomprised of a Fusion Bonded Epoxy (FBE) coating and a tape wrap that protects the FBE\ncoating from ultraviolet rays. The tape coating is in decrepit condition, peeling off\napproximately 50% of the pipeline, and, therefore, exposing the once underlying FBE coating to\ndamaging ultraviolet rays. Suitable coating must be applied to prevent atmospheric corrosion.\nTape wrap is not considered suitable.\n2. § 192.605 Procedural manual for operations, maintenance, and emergencies\n(a) General. Each operator shall prepare and and follow for each pipeline, a\nmanual of written procedures for conducting operations and maintenance activities\nand for emergency response. For transmission lines, the manual must also include\nprocedures for handling abnormal operations. The manual must be reviewed and\nupdated by the operatorat intervals not exceeding 15 months, but at least once each\ncalendar year. This manual must be prepared before operations of a pipeline\nsystem commence. Appropriate parts of the manual must be kept at locations\nwhere operations and maintenance activities are conducted.\nThe Operator failed to following their written operations and maintenance procedure for annual\ntesting of the compressor station gas detection system. The Operator's procedure FG-78\nOperating, Maintenance and Emergency Plans for the Fuel Gas Pipeline for testing of the\ncompressor station gas detection system is labeled “Annual” and states that it is a “procedure for\nAnnual testing.” Records show tests were performed on December 12, 2015 and February 4,\n2017. Contrary to the Operator’s procedure no testing was conducted in 2016, therefore the\noperator failed to following their written operations and maintenance procedure.\n3. § 192.605 Procedural manual for operations, maintenance, and emergencies.\n(a) General. Each operator shall prepare and follow for each pipeline, a manual of\nwritten procedures for conducting operations and maintenance activities and for\nemergency response. For transmission lines, the manual must also include\nprocedures for handling abnormal operations. This manual must be reviewed and\nupdated by the operator at intervals not exceeding 15 months, but at least once each\ncalendar year. This manual must be prepared before operations of a pipeline system\ncommence. Appropriate parts of the manual must be kept at locations where\noperations and maintenance activities are conducted.\nThe Operator did not review and update its operations, maintenance and emergency procedures\neach calendar year not exceeding 15 months. § 192.605(a) requires that an operator do a review,\nnot exceeding 15 months, but at least once a calendar year, of operations and maintenance\nprocedures and emergency procedures. The Operator’s document FG78 Operating,\nMaintenance, and Emergency Plans for the Fuel Gas Line has a revision history without a 2014\ncalendar year review. The Operator’s System Integrity Monitoring Procedures MP166 2.02 Fuel\nGas Line Monitoring has a large gap on the revision history between 2009 and 2013.\n2\n\n\n\n4. § 192.709 Transmission lines: Record keeping.\nEach operator shall maintain the following records for transmission lines for the\nperiods specified:\n…\n(c) A record of each patrol, survey, inspection, and test required by subparts L and\nM of this part must be retained for at least 5 years or until the next patrol, survey,\ninspection, or test is completed, whichever is longer.\nThe Operator failed to keep proper records for emergency valve testing over a several year\nperiod. During the inspection, PHMSA requested 2014-2016 DOT annual valve records for four\n(4) valves: 2014-2016 MGV-2, 00-V159(FG), 15-V400(FG), and MGV-9. None of the\nrequested documents were provided. The Operator only provided a 2016 record for MGV-2 and\nthe 2015 and 2016 records for MGV-9. Furthermore, the provided records failed to adequately\ndocument proper inspection and partial operation of emergency transmission line valves as some\nof the records were undated.\n5. § 192.807 Recordkeeping.\nEach operator shall maintain records that demonstrate compliance with this\nsubpart.\n(a) Qualification records shall include:\n(1) Identification of qualified individual(s);\n(2) Identification of the covered tasks the individual is qualified to perform;\n(3) Date(s) of current qualification; and\n(4) Qualification method(s).\nThe Operator failed to have qualified individuals performing an ongoing covered task. The\nOperator has a covered task labeled PC-PIT/027 which is an active and ongoing task involving\ntesting of Emergency Shutdown Devices for the fuel gas line. Operator’s records revealed that,\nalthough the covered task was ongoing, no personnel were qualified for the task.\n3\n\n\n\n6. § 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 § 192.911 and that addresses the risks on each\ncovered transmission pipeline segment. The initial integrity management program\nmust consist, at a minimum, of a framework that describes the process for\nimplementing each program element, how relevant decisions will be made and by\nwhom, a time line for completing the work to implement the program element, and\nhow information gained from experience will be continuously incorporated into the\nprogram. The framework will evolve into a more detailed and comprehensive\nprogram. An operator must make continual improvements to the program.\nAlyeska Pipeline Service Company (APSC) failed to develop and follow a written integrity\nmanagement program within one year from the date of identification of the initial High\nConsequence Area (HCA) and associated covered pipeline segment on the Fuel Gas Line.\nAlyeska does appear to be in compliance with this requirement but was not before December 11,\n2013.\nAPSC began reporting HCA mileage to PHMSA for their Fuel Gas Line in 2009, and has\ncontinued to do so on its annual reports as required by § 191.17. However, APSC did not\ndevelop its baseline integrity management plan for the segment of the Fuel Gas Line that was\nfirst reported in 2009 as being located within a HCA until December 11, 2013. APSC’s initial\nwritten integrity management program (IM-246, Fuel Gas Line Integrity Management Plan for\nHigh Consequence Area Covered Segments, Rev. 0) is dated December 11, 2013.\nThe regulation at issue imposes a continuing obligation on operators to follow a baseline\nintegrity management plan, one which the regulation requires to continually evolve based on\ninformation gained from experience. Further, § 192.907(a) requires that an operator develop and\nfollow a written integrity management program for a covered pipeline segment located within a\nHCA, and that the written integrity management program must contain all the elements described\nin § 192.911. Pursuant to § 192.911, an integrity management program must contain several\nelements, including a baseline assessment plan. Pursuant to § 192.905(c), a newly identified\nHCA must be incorporated into a baseline assessment plan within one year from the date the\nHCA was identified. Other required elements of an integrity management program must be\nutilized in the development of a baseline assessment plan, including threat identification, data\ngathering and integration, and risk assessment. As such, an operator must develop and follow a\nwritten integrity management program for covered pipeline segment(s) located within a HCA\nwithin one year from the date of which the pipeline’s initial HCA was identified, and\ncontinuously follow and update the baseline assessment plan.\nAPSC reported HCA mileage to PHMSA for the Fuel Gas Line continuously since 2009.\nConservatively assuming that the initial HCA on the Fuel Gas Line was identified on December\n31, 2009, APSC was required to develop and follow a written integrity management program\n4\n\n\n\nthat contains all the elements described in § 192.911 and addresses the risks on each covered\ntransmission pipeline segment by December 31, 2010. APSC's initial written integrity\nmanagement program (Integrity Management Plan IM-246, Rev. 0) is dated December 11, 2013,\napproximately 4 years after the identification of the Fuel Gas Line’s initial HCA and covered\npipeline segment, or approximately 3 years after the required date for development of a written\nintegrity management program for the covered pipeline segment. Once the initial plan is\ndeveloped, § 192.907(a) requires the operator to continuously modify and update the plan.\nAPSC was in continuous violation of the regulation from at least December 31, 2010 until\nDecember 11, 2013, when it first developed its integrity management plan for the covered\nsegment.\n7. § 192.919 What must be in the baseline assessment plan?\nAn operator must include each of the following elements in its written baseline\nassessment plan:\n…\n(b) The methods selected to assess the integrity of the line pipe, including an\nexplanation of why the assessment method was selected to address the identified\nthreats to each covered segment. The integrity assessment method an operator uses\nmust be based on the threats identified to the covered segment. (See §192.917.) More\nthan one method may be required to address all the threats to the covered pipeline\nsegment;\nThe Operator failed to give details as to why specific in-line inspection tools and testing were\nselected to address identified threats. The Operator’s Baseline Assessment Plan specifies\nassessment methods, but does not explain why the tools were selected for identified threats to the\ncovered segment.\n8. § 192.919 What must be in the baseline assessment plan?\nAn operator must include each of the following elements in its written baseline\nassessment plan:\n…\n(c) A schedule for completing the integrity assessment of all covered segments,\nincluding risk factors considered in establishing the assessment schedule;\nThe Operator’s Baseline Assessment Plan does not contain a schedule for completing further\nassessment activities. The Operator’s IM-246 Fuel Gas Line Integrity Management Plan dated\nDec 15, 2015 contains two sections regarding the Baseline Assessment Plan: Section 7 and\nAppendix C2. Neither section provides a schedule for completing the assessment activities as\nrequired by 192.919(c).\n5\n\n\n\nUnder 49 U.S.C. § 60122 and 49 CFR § 190.223, you are subject to a civil penalty not to exceed\n$209,002 per violation per day the violation persists, up to a maximum of $2,090,022 for a\nrelated series of violations. For violations occurring prior to November 2, 2015, the maximum\npenalty may not exceed $200,000 per violation per day, with a maximum penalty not to exceed\n$2,000,000 for a related series of violations. We have reviewed the circumstances and\nsupporting documents involved in this case, and have decided not to conduct additional\nenforcement action or penalty assessment proceedings at this time. We advise you to correct the\nitem(s) identified in this letter. Failure to do so will result in Alyeska Pipeline Service Company\nbeing subject to additional enforcement action.\nNo reply to this letter is required. If you choose to reply, in your correspondence please refer to\nCPF 5-2018-0013W. Be advised that all material you submit in response to this enforcement\naction is subject to being made publicly available. If you believe that any portion of your\nresponsive material qualifies for confidential treatment under 5 U.S.C. 552(b), along with the\ncomplete original document you must provide a second copy of the document with the portions\nyou believe qualify for confidential treatment redacted and an explanation of why you believe\nthe redacted information qualifies for confidential treatment under 5 U.S.C. 552(b).\nSincerely,\nChris Hoidal\nActing Director, Western Region\nPipeline and Hazardous Materials Safety Administration\ncc: PHP-60 Compliance Registry\nPHP-500 J. Owens/T. Johnson (# 155098)\n6","truncated":false,"body_characters":14295}