{"operation":"document","citation":"CPF 520112001W","title":"MARATHON OIL COMPANY — Warning Letter","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2011-04-29","effective_on":null,"summary":"CLOSED warning letter citing 192.465(b), 192.479(a), 192.481(a), 192.619, 192.743(a).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-520112001w.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-520112001w.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-520112001w","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/520112001W","body":"Warning Letter involving MARATHON OIL COMPANY. PHMSA's enforcement data identifies the cited regulations as 192.465(b),  192.479(a),  192.481(a),  192.619,  192.743(a). The case was opened on 2011-04-29 and is reported as closed as of 2011-04-29. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n520112001W_operator response_05182011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520112001W/520112001W_operator%20response_05182011.pdf\n\n520112001W_warning letter_04292011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520112001W/520112001W_warning%20letter_04292011.pdf\n\n520112001W_warning letter_04292011_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520112001W/520112001W_warning%20letter_04292011_text.pdf\n\n520112001W_warning letter_04292011_text.pdf\n\nWARNING LETTER\nVIA UPS – TRACKING # 1Z WR2 588 02 9465 4207\nApril 29, 2011\nMr. James Bowzer\nVice President, North America Production Operations\nMarathon Oil Company\n5555 San Felipe Rd.\nHouston, TX 77056\nCPF 5-2011-2001W\nDear Mr. Bowzer:\nOn September 1-2, 2010, a representative of the Pipeline and Hazardous Materials Safety\nAdministration (PHMSA), pursuant to Chapter 601 of 49 United States Code, inspected\nMarathon Oil Company’s Spark/Spur natural gas transmission pipeline in Kenai, Alaska.\nAs a result of the inspection, it appears that you have committed probable violations of the\nPipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and\nthe probable violation(s) are:\n1. §192.465 External corrosion control: Monitoring\n(b) Each cathodic protection rectifier or other impressed current power source\nmust be inspected six times each calendar year, but with intervals not exceeding\n2 1/2 months, to insure that it is operating.\nThe operator failed to provide evidence that all cathodic protection rectifiers were inspected\nwithin intervals not exceeding 2 ½ months. Records indicate that the rectifiers on the Spark\nPlatform were inspected on June 19, 2009 and December 17, 2009, and do not indicate\nrectifier inspections were performed between these two dates.\n\n\n\n2. §192.479 Atmospheric corrosion control: General\n(a) Each operator must clean and coat each pipeline or portion of pipeline that\nis exposed to the atmosphere, except pipelines under paragraph (c) of this\nsection.\n(b) Coating material must be suitable for the prevention of atmospheric\ncorrosion.\nPHMSA personnel observed numerous soil-to-air interfaces on the 3-inch diameter pipeline\nsection that were not coated.\n3. §192.481 Atmospheric corrosion control: Monitoring\n(a) Each operator must inspect each pipeline or portion of pipeline that is\nexposed to the atmosphere for evidence of atmospheric corrosion, as follows:\nIf the pipeline is\nlocated:\nthe frequency of inspection is:\nOnshore At least once every 3 calendar years, but with\nintervals not exceeding 39 months\nOffshore At least once each calendar year, but with intervals\nnot exceeding 15 months\nThe operator failed to provide evidence that all atmospherically exposed portions of the 3-\ninch diameter pipeline were inspected for atmospheric corrosion. Evidence provided\nindicates atmospheric corrosion inspections were conducted at locations identified as 1+00,\n1+10, and 2+00. No documentation was presented to show that atmospheric corrosion\ninspections were conducted between the locations identified as 1+10 and 2+00, where there\nare several atmospherically exposed portions of the pipeline.\n4. §192.619 Maximum allowable operating pressure: Steel or plastic pipelines\n(a) No person may operate a segment of steel or plastic pipeline at a pressure\nthat exceeds a maximum allowable operating pressure determined under\nparagraph (c) or (d) of this section, or the lowest of the following:\n(1) The design pressure of the weakest element in the segment, determined in\naccordance with subparts C and D of this part. However, for steel pipe in\npipelines being converted under §192.14 or uprated under subpart K of this\npart, if any variable necessary to determine the design pressure under the design\nformula (§192.105) is unknown, one of the following pressures is to be used as\ndesign pressure:\n(i) Eighty percent of the first test pressure that produces yield under section N5\nof Appendix N of ASME B31.8 (incorporated by reference, see §192.7), reduced\nby the appropriate factor in paragraph (a)(2)(ii) of this section; or\n(ii) If the pipe is 12¾ inches (324 mm) or less in outside diameter and is not\ntested to yield under this paragraph, 200 p.s.i. (1379 kPa) gage.\n2\n\n\n\n(2) The pressure obtained by dividing the pressure to which the segment was\ntested after construction as follows:\n(i) For plastic pipe in all locations, the test pressure is divided by a factor of 1.5.\n(ii) For steel pipe operated at 100 p.s.i. (689 kPa) gage or more, the test pressure\nis divided by a factor determined in accordance with the following table:\nFactors (see Note), segment\nClass location\nInstalled Before\nNov. 12,1970\nInstalled After\nNov. 11, 1970\nConverted under\n§192.14\n1 1.1 1.1 1.25\n2 1.25 1.25 1.25\n3 1.4 1.5 1.5\n4 1.4 1.5 1.5\nNote: For offshore segments installed, or updated, or converted after July 31,\n1977, that are not located on an offshore platform, the factor is 1.25. For\nsegments installed, uprated, or converted after July 31, 1977 that are located on\nan offshore platform or on a platform in inland navigable waters (including a\npipe riser), the factor is 1.5\n(3) The highest actual operating pressure to which the segment was subjected\nduring the 5 years preceding the applicable date in the second column. This\npressure restriction applies unless the segment was tested according to the\nrequirements in paragraph (a)(2) of this section after the applicable date in the\nthird column or the segment was uprated according to the requirements in\nsubpart K of this part:\nPipeline segment Pressure date Test date\n-Onshore gathering line\nthat first became subject\nto this part (other than\n§192.612) after April 13,\n2006.\nMarch 15, 2006, or date\nline becomes subject to\nthis part, whichever is\nlater.\n5 years preceding\napplicable date in\nsecond column.\n-Onshore transmission\nline that was a gathering\nline not subject to this\npart before March 15,\n2006.\nOffshore gathering lines. July 1, 1976 July 1, 1971.\nAll other pipelines. July 1, 1970 July 1, 1965.\n(4) The pressure determined by the operator to be the maximum safe pressure\nafter considering the history of the segment, particularly known corrosion and\nthe actual operating pressure.\n3\n\n\n\n(b) No person may operate a segment to which paragraph (a)(4) of this section is\napplicable, unless overpressure protective devices are installed on the segment in\na manner that will prevent the maximum allowable operating pressure from\nbeing exceeded, in accordance with §192.195.\n(c) The requirements on pressure restrictions in this section do not apply in the\nfollowing instance. An operator may operate a segment of pipeline found to be in\nsatisfactory condition, considering its operating and maintenance history, at the\nhighest actual operating pressure to which the segment was subjected during the\n5 years preceding the applicable date in the second column of the table in\nparagraph (a)(3) of this section. An operator must still comply with §192.611.\n(d) The operator of a pipeline segment of steel pipeline meeting the conditions\nprescribed in § 192.620(b) may elect to operate the segment at a maximum\nallowable operating pressure determined under § 192.620(a)\nThis pipeline has been operated under a MAOP of 1030 psig. The operator failed to provide\nevidence that MAOP for the 3-inch diameter pipeline section was determined in accordance\nwith §192.619. The MAOP determination for the 3-inch pipeline was based solely on the\nmaximum pressure experienced by the pipeline during a 1 ¼ year period, from October 2007\nto January 2009.\n5. §192.743 Pressure limiting and regulating stations: Capacity of relief devices\n(a) Pressure relief devices at pressure limiting stations and pressure regulating\nstations must have sufficient capacity to protect the facilities to which they are\nconnected. Except as provided in §192.739(b), the capacity must be consistent\nwith the pressure limits of §192.201(a). This capacity must be determined at\nintervals not exceeding 15 months, but at least once each calendar year, by\ntesting the devices in place or by review and calculations\nThe operator failed to provide evidence that the capacity of the relief devices had been\ndetermined at intervals not exceeding 15 months, but at least once each calendar year.\nPHMSA issued a Warning Letter to Marathon Pipe Line, LLC regarding this same issue\n(CPF 5-2010-0001W, Item 6, dated January 4, 2010). In response to the warning letter,\nMarathon Pipe Line, LLC initiated an Alaska Gas Pressure Control Oversight Transition Plan\nto remedy the issue. Marathon Oil Company has indicated that the Spark/Spur natural gas\ntransmission pipeline’s pressure relief system is included in the transition plan and its\ncapacity will be determined at intervals in accordance with §192.743.\nUnder 49 United States Code, § 60122, you are subject to a civil penalty not to exceed\n$100,000 for each violation for each day the violation persists up to a maximum of\n$1,000,000 for any 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\n4\n\n\n\nthe items identified in this letter. Failure to do so will result in Marathon Oil Company being\nsubject to additional enforcement action.\nNo reply to this letter is required. If you choose to reply, in your correspondence please send\nall documents to our office at 188 W. Northern Lights Blvd., Suite 520, Anchorage, AK\n99503 and refer to CPF 2011-2001W. Be advised that all material you submit in response to\nthis enforcement action is subject to being made publicly available. If you believe that any\nportion of your responsive material qualifies for confidential treatment under 5 U.S.C.\n552(b), along with the complete original document you must provide a second copy of the\ndocument with the portions you believe qualify for confidential treatment redacted and an\nexplanation of why you believe the redacted information qualifies for confidential treatment\nunder 5 U.S.C. 552(b).\nSincerely,\nDennis Hinnah\nDeputy Director, Western Region\nPipeline and Hazardous Materials Safety Administration\ncc: PHP-60 Compliance Registry\nPHP-500 T. Johnson (#130350)\n5","truncated":false,"body_characters":10635}