ALYESKA PIPELINE SERVICE CO — Warning Letter

party submissionOfficial PDF520180013W_Operator Response to Notice_01282019.pdf#

520180013W_Warning Letter_12272018_text.pdf, page 1Official PDFWARNING LETTER CERTIFIED MAIL - RETURN RECEIPT REQUESTED December 27, 2018 Mr. Thomas Barrett President and CEO Alyeska Pipeline Service Company PO Box 196660 Anchorage, AK 99519 CPF 5-2018-0013W Dear Mr Barrett: On multiple occasions between April 24, 2017 and March 16, 2018, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), pursuant to Chapter 601 of 49 United States Code (U.S.C.), inspected your Fuel Gas Pipeline between Pump Stations 1 and 4, and reviewed records and procedures in Anchorage, Alaska. As a result of the inspection, it is alleged that you have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations (CFR). The items inspected and the probable violation(s) are: 1. § 192.479 Atmospheric corrosion control: General. (a) Each operator must clean and coat each pipeline or portion of pipeline that is exposed to the atmosphere, except pipelines under paragraph (c) of this section. (b) Coating material must be suitable for the prevention of atmospheric corrosion. The Operator failed to properly coat each pipeline that is exposed to the atmosphere. Several above ground valve stations had exposed inadequate coating, particularly at soil-to-air interfaces.#

520180013W_Warning Letter_12272018_text.pdf, page 2According to the Operator, the Atigan River Bridge span over the river has a “coating system” comprised of a Fusion Bonded Epoxy (FBE) coating and a tape wrap that protects the FBE coating from ultraviolet rays. The tape coating is in decrepit condition, peeling off approximately 50% of the pipeline, and, therefore, exposing the once underlying FBE coating to damaging ultraviolet rays. Suitable coating must be applied to prevent atmospheric corrosion. Tape wrap is not considered suitable. 2. § 192.605 Procedural manual for operations, maintenance, and emergencies (a) General. Each operator shall prepare and and follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response. For transmission lines, the manual must also include procedures for handling abnormal operations. The manual must be reviewed and updated by the operatorat intervals not exceeding 15 months, but at least once each calendar year. This manual must be prepared before operations of a pipeline system commence. Appropriate parts of the manual must be kept at locations where operations and maintenance activities are conducted. The Operator failed to following their written operations and maintenance procedure for annual testing of the compressor station gas detection system. The Operator's procedure FG-78 Operating, Maintenance and Emergency Plans for the Fuel Gas Pipeline for testing of the compressor station gas detection system is labeled “Annual” and states that it is a “procedure for Annual testing.” Records show tests were performed on December 12, 2015 and February 4, 2017. Contrary to the Operator’s procedure no testing was conducted in 2016, therefore the operator failed to following their written operations and maintenance procedure. 3. § 192.605 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response. For transmission lines, the manual must also include procedures for handling abnormal operations. This manual must be reviewed and updated by the operator at intervals not exceeding 15 months, but at least once each calendar year. This manual must be prepared before operations of a pipeline system commence. Appropriate parts of the manual must be kept at locations where operations and maintenance activities are conducted. The Operator did not review and update its operations, maintenance and emergency procedures each calendar year not exceeding 15 months. § 192.605(a) requires that an operator do a review, not exceeding 15 months, but at least once a calendar year, of operations and maintenance procedures and emergency procedures. The Operator’s document FG78 Operating, Maintenance, and Emergency Plans for the Fuel Gas Line has a revision history without a 2014 calendar year review. The Operator’s System Integrity Monitoring Procedures MP166 2.02 Fuel Gas Line Monitoring has a large gap on the revision history between 2009 and 2013. 2#

520180013W_Warning Letter_12272018_text.pdf, page 34. § 192.709 Transmission lines: Record keeping. Each operator shall maintain the following records for transmission lines for the periods specified: … (c) A record of each patrol, survey, inspection, and test required by subparts L and M of this part must be retained for at least 5 years or until the next patrol, survey, inspection, or test is completed, whichever is longer. The Operator failed to keep proper records for emergency valve testing over a several year period. During the inspection, PHMSA requested 2014-2016 DOT annual valve records for four (4) valves: 2014-2016 MGV-2, 00-V159(FG), 15-V400(FG), and MGV-9. None of the requested documents were provided. The Operator only provided a 2016 record for MGV-2 and the 2015 and 2016 records for MGV-9. Furthermore, the provided records failed to adequately document proper inspection and partial operation of emergency transmission line valves as some of the records were undated. 5. § 192.807 Recordkeeping. Each operator shall maintain records that demonstrate compliance with this subpart. (a) Qualification records shall include: (1) Identification of qualified individual(s); (2) Identification of the covered tasks the individual is qualified to perform; (3) Date(s) of current qualification; and (4) Qualification method(s). The Operator failed to have qualified individuals performing an ongoing covered task. The Operator has a covered task labeled PC-PIT/027 which is an active and ongoing task involving testing of Emergency Shutdown Devices for the fuel gas line. Operator’s records revealed that, although the covered task was ongoing, no personnel were qualified for the task. 3#

520180013W_Warning Letter_12272018_text.pdf, page 46. § 192.907 What must an operator do to implement this subpart? (a) General. No later than December 17, 2004, an operator of a covered pipeline segment must develop and follow a written integrity management program that contains all the elements described in § 192.911 and that addresses the risks on each covered transmission pipeline segment. The initial integrity management program must consist, at a minimum, of a framework that describes the process for implementing each program element, how relevant decisions will be made and by whom, a time line for completing the work to implement the program element, and how information gained from experience will be continuously incorporated into the program. The framework will evolve into a more detailed and comprehensive program. An operator must make continual improvements to the program. Alyeska Pipeline Service Company (APSC) failed to develop and follow a written integrity management program within one year from the date of identification of the initial High Consequence Area (HCA) and associated covered pipeline segment on the Fuel Gas Line. Alyeska does appear to be in compliance with this requirement but was not before December 11, 2013. APSC began reporting HCA mileage to PHMSA for their Fuel Gas Line in 2009, and has continued to do so on its annual reports as required by § 191.17. However, APSC did not develop its baseline integrity management plan for the segment of the Fuel Gas Line that was first reported in 2009 as being located within a HCA until December 11, 2013. APSC’s initial written integrity management program (IM-246, Fuel Gas Line Integrity Management Plan for High Consequence Area Covered Segments, Rev. 0) is dated December 11, 2013. The regulation at issue imposes a continuing obligation on operators to follow a baseline integrity management plan, one which the regulation requires to continually evolve based on information gained from experience. Further, § 192.907(a) requires that an operator develop and follow a written integrity management program for a covered pipeline segment located within a HCA, and that the written integrity management program must contain all the elements described in § 192.911. Pursuant to § 192.911, an integrity management program must contain several elements, including a baseline assessment plan. Pursuant to § 192.905(c), a newly identified HCA must be incorporated into a baseline assessment plan within one year from the date the HCA was identified. Other required elements of an integrity management program must be utilized in the development of a baseline assessment plan, including threat identification, data gathering and integration, and risk assessment. As such, an operator must develop and follow a written integrity management program for covered pipeline segment(s) located within a HCA within one year from the date of which the pipeline’s initial HCA was identified, and continuously follow and update the baseline assessment plan. APSC reported HCA mileage to PHMSA for the Fuel Gas Line continuously since 2009. Conservatively assuming that the initial HCA on the Fuel Gas Line was identified on December 31, 2009, APSC was required to develop and follow a written integrity management program 4#

520180013W_Warning Letter_12272018_text.pdf, page 5that contains all the elements described in § 192.911 and addresses the risks on each covered transmission pipeline segment by December 31, 2010. APSC's initial written integrity management program (Integrity Management Plan IM-246, Rev. 0) is dated December 11, 2013, approximately 4 years after the identification of the Fuel Gas Line’s initial HCA and covered pipeline segment, or approximately 3 years after the required date for development of a written integrity management program for the covered pipeline segment. Once the initial plan is developed, § 192.907(a) requires the operator to continuously modify and update the plan. APSC was in continuous violation of the regulation from at least December 31, 2010 until December 11, 2013, when it first developed its integrity management plan for the covered segment. 7. § 192.919 What must be in the baseline assessment plan? An operator must include each of the following elements in its written baseline assessment plan: … (b) The methods selected to assess the integrity of the line pipe, including an explanation of why the assessment method was selected to address the identified threats to each covered segment. The integrity assessment method an operator uses must be based on the threats identified to the covered segment. (See §192.917.) More than one method may be required to address all the threats to the covered pipeline segment; The Operator failed to give details as to why specific in-line inspection tools and testing were selected to address identified threats. The Operator’s Baseline Assessment Plan specifies assessment methods, but does not explain why the tools were selected for identified threats to the covered segment. 8. § 192.919 What must be in the baseline assessment plan? An operator must include each of the following elements in its written baseline assessment plan: … (c) A schedule for completing the integrity assessment of all covered segments, including risk factors considered in establishing the assessment schedule; The Operator’s Baseline Assessment Plan does not contain a schedule for completing further assessment activities. The Operator’s IM-246 Fuel Gas Line Integrity Management Plan dated Dec 15, 2015 contains two sections regarding the Baseline Assessment Plan: Section 7 and Appendix C2. Neither section provides a schedule for completing the assessment activities as required by 192.919(c). 5#

520180013W_Warning Letter_12272018_text.pdf, page 6Under 49 U.S.C. § 60122 and 49 CFR § 190.223, you are subject to a civil penalty not to exceed $209,002 per violation per day the violation persists, up to a maximum of $2,090,022 for a related series of violations. For violations occurring prior to November 2, 2015, the maximum penalty may not exceed $200,000 per violation per day, with a maximum penalty not to exceed $2,000,000 for a related series of violations. We have reviewed the circumstances and supporting documents involved in this case, and have decided not to conduct additional enforcement action or penalty assessment proceedings at this time. We advise you to correct the item(s) identified in this letter. Failure to do so will result in Alyeska Pipeline Service Company being subject to additional enforcement action. No reply to this letter is required. If you choose to reply, in your correspondence please refer to CPF 5-2018-0013W. Be advised that all material you submit in response to this enforcement action is subject to being made publicly available. If you believe that any portion of your responsive material qualifies for confidential treatment under 5 U.S.C. 552(b), along with the complete original document you must provide a second copy of the document with the portions you believe qualify for confidential treatment redacted and an explanation of why you believe the redacted information qualifies for confidential treatment under 5 U.S.C. 552(b). Sincerely, Chris Hoidal Acting Director, Western Region Pipeline and Hazardous Materials Safety Administration cc: PHP-60 Compliance Registry PHP-500 J. Owens/T. Johnson (# 155098) 6#