{"operation":"document","citation":"CPF 520195003W","title":"CHEVRON PRODUCTS COMPANY — Warning Letter","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2019-01-21","effective_on":null,"summary":"CLOSED warning letter citing 194.121(a), 194.121(b), 195.264(b)(1)(i), 195.432(b), 195.434, 195.577(a), 195.579(c), 195.581, 195.583(a).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-520195003w.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-520195003w.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-520195003w","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/520195003W","body":"Warning Letter involving CHEVRON PRODUCTS COMPANY. PHMSA's enforcement data identifies the cited regulations as 194.121(a),  194.121(b),  195.264(b)(1)(i),  195.432(b),  195.434,  195.577(a),  195.579(c),  195.581,  195.583(a). The case was opened on 2019-01-21 and is reported as closed as of 2019-01-21. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n520195003W_Warning Letter_01212019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520195003W/520195003W_Warning%20Letter_01212019.pdf\n\n520195003W_Warning Letter_01212019_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520195003W/520195003W_Warning%20Letter_01212019_text.pdf\n\n520195003W_Warning Letter_01212019_text.pdf\n\nWARNING LETTER\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\nJanuary 21, 2019\nMr. John S. Watson\nChairman and Chief Executive Officer\nChevron Products Company\n6001 Bollinger Canyon Road\nSan Ramon, CA 94583\nCPF 5-2019-5003W\nDear Mr. Watson:\nFrom July 25 through 29, 2016, representatives of the Pipeline and Hazardous Materials Safety\nAdministration (PHMSA), Office of Pipeline Safety (OPS), pursuant to Chapter 601 of 49\nUnited States Code (U.S.C.), inspected your Willbridge Facilities in Portland, Oregon. As part\nof that inspection we reviewed your operation and maintenance procedures, and supporting\nimplementation records and documentation. I sincerely apologize for our late transmittal of these\nfindings to Chevron, but still hope that by detailing our observations and regulatory findings that\nyou can further improve public safety.\nBased on our inspection findings, PHMSA determined you may have committed probable\nviolations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations (CFR). The\ndeficiencies noted and probable violations were:\n1. § 194.121 Response plan review and update procedures.\n(a) Each operator shall update its response plan to address new or different\noperating conditions or information. In addition, each operator shall review its\nresponse plan in full at least every 5 years from the date of the last submission or the\nlast approval as follows…\n(b) If a new or different operating condition or information would substantially\naffect the implementation of a response plan, the operator must immediately modify\n\n\n\nits response plan to address such a change and, within 30 days of making such a\nchange, submit the change to PHMSA. Examples of changes in operating conditions\nthat would cause a significant change to an operator's response plan are:…\nThe operator did not update its response plan to address new or different operating conditions or\ninformation. The most recent version of the operator’s facility response plan was submitted to\nPHMSA in February 2016 and, prior to that submission, in 2014, 2010, 2008, and 2004\n(Submissions). Each of those Submissions, or the letters received by the operator in response to\nthe Submissions, generally describes new or different operating conditions or information\nreflected or to be included in the updated response plans. However, the operator produced no\nrecords that demonstrate that the operator reviewed (and updated where necessary) its response\nplan to address the new or different operating conditions or information described in the\nSubmissions.\nThe operator provided p. 43 of the table of contents of the facility response plan entitled “Record\nof Changes.” The Record of Changes simply details two changes made on August 2, 2016 and\nfails to fill out any of the columns entitled “Section/Amended/Page Number,” “Department\nNotified Yes/No,” and “Initials of Person Making Changes.” Furthermore, the Record of\nChanges did not capture the historic changes reflected in the response plan Submissions to\nPHMSA or the resulting correspondence. The current Record of Changes document is not\nsufficient to show that the operator reviewed and updated the facility response plan as required in\n§ 194.121(a).\n2. § 195.264 Impoundment, protection against entry, normal/emergency venting or\npressure/vacuum relief for aboveground breakout tanks.\n...\n(b) After October 2, 2000, compliance with paragraph (a) of this section requires the\nfollowing for the aboveground breakout tanks specified:\n(1) For tanks built to API Spec 12F, API Std 620, and others (such as API Std 650\n(or its predecessor Standard 12C)), the installation of impoundment must be in\naccordance with the following sections of NFPA-30 (incorporated by reference, see\n§ 195.3);\n(i) Impoundment around a breakout tank must be installed in accordance with\nsection 22.11.2; and...\nRegarding its 2009 Chevron Willbridge Terminal Expansion Project, the operator did not\ndemonstrate that the impoundment areas were installed according to § 195.264 or NFPA-30\nSection 22.11.2.1. The operator provided the August 5, 2016 “Chevron Willbridge Terminal\nNFPA-30 Impoundment Evaluation” (Evaluation) to demonstrate compliance with NFPA-30\nSection 22.11.2 for its 2009 Chevron Willbridge Terminal Expansion Project, which installed\ntwo large gasoline/diesel storage tanks and corresponding impoundments. However, several\ndeficiencies exist as to demonstrating compliance using this sole document. Compliance with\nNFPA-30 Section 22.11.2.1 requires “[a] slope of not less than 1 percent away from the tank\n2\n\n\n\nshall be provided for at least 50 ft (15 m) or to the dike base, whichever is less.” The operator\nstated in the Evaluation that the slope was “[c]onfirmed visually and through observations that\nrainwater freely drains away from tanks.” Visual confirmation for a quantifiable requirement is\nnot sufficient to satisfy either § 195.264 or NFPA-30 Section 22.11.2.1. Chevron should have\nused a quantifiable measure of the slope to demonstrate compliance.\n3. § 195.432 Inspection of in-service breakout tanks.\n...\n(b) Each operator must inspect the physical integrity of in-service atmospheric and\nlow-pressure steel above-ground breakout tanks according to API Std 653 (except\nsection 6.4.3, Alternative Internal Inspection Interval) (incorporated by reference,\nsee § 195.3). However, if structural conditions prevent access to the tank bottom, its\nintegrity may be assessed according to a plan included in the operations and\nmaintenance manual under § 195.402(c)(3). The risk-based internal inspection\nprocedures in API Std 653, section 6.4.3 cannot be used to determine the internal\ninspection interval.\nThe operator did not inspect the physical integrity of in-service atmospheric and low-pressure\nsteel above-ground breakout tanks according to API Standard 653, as required by § 195.432.\nAPI Standard 653 (Third Edition, December 2001) requires that “[a]ll tanks shall be given a\nvisual external inspection by an authorized inspector” in Section 6.3.2.1. PHMSA inspectors in\nthe field observed the following on Tank 47: a petroleum sheen high on the side of the riveted\ntank, a gouge a few feet above the ground on the side of the tank, and a coating failure hole that\nappeared to contain corrosion pits. None of these deficiencies were noted in the May 21, 2013\nTank #47 API 653 External Inspection Report. These observed deficiencies are inconsistent with\nadequate regular inspection and maintenance of the facilities.\n4. § 195.434 Signs.\nEach operator must maintain signs visible to the public around each pumping\nstation and breakout tank area. Each sign must contain the name of the operator\nand a telephone number (including area code) where the operator can be reached at\nall times.\nThe operator did not maintain signs visible to the public around each pumping station and\nbreakout tank area that included name of the operator and a telephone number where the operator\ncan be reached at all times. Inspectors observed inadequate signage on both the terminal area\nand the impoundment area of the Willbridge Facilities. On the terminal side of the street (the\ngated side), inspectors observed only one sign sufficient to meet requirements on hundreds of\nfeet of available space of fencing, which included several entrances and exits from the facilities.\nOn the tank farm/impoundment wall side of the street, only one sign was observed containing\nemergency information and that sign did not contain the name of the operator. On that same\nside, hundreds of feet of unmarked impoundment walls, including numerous vehicle and\n3\n\n\n\npersonnel access points, were lacking proper signage. The main “Chevron” sign on the tank\nfarm side of the property was buried in shrubs and was not visible to the general public. Signage\nat the operator’s Chevron Willbridge Facilities did not fully comply with the visibility\nrequirements of § 195.434.\n5. § 195.577 What must I do to alleviate interference currents?\n(a) For pipelines exposed to stray currents, you must have a program to identify,\ntest for, and minimize the detrimental effects of such currents.\nThe operator did not demonstrate that the Chevron Willbridge Facilities were tested and\ndetermined not to be exposed to stray currents nor did they produce documentation of an\ninterference current program. The “Chevron Distribution Terminals O&M Manual,” Procedure\n602.3 Interference Currents, does not meet § 195.577(a) because no testing for interference\ncurrents is required by the procedure. The operator stated that no interference current testing has\never been performed in the Willbridge Facilities despite the presence of numerous potential\nsources of interference current such as other pipelines and terminals in the area, as well as\nadjacent tank farms. The operator’s personnel stated that they understood that identification,\ntesting, and minimizing the effects of stray currents, in accordance with § 195.577, applies to the\nbreakout tanks and other facilities at the Willbridge Facilities. The operator made no effort to\ndetermine whether stray currents existed at the facilities and concluded, with no data or analysis,\nthat no stray current existed. Without testing for stray current, the operator’s assumption that no\nstray current exists is unfounded and violates § 195.577(a).\n6. § 195.579 What must I do to mitigate internal corrosion?\n...\n(c) Removing pipe. Whenever you remove pipe from a pipeline, you must inspect the\ninternal surface of the pipe for evidence of corrosion. If you find internal corrosion\nrequiring corrective action under § 195.585, you must investigate circumferentially\nand longitudinally beyond the removed pipe (by visual examination, indirect\nmethod, or both) to determine whether additional corrosion requiring remedial\naction exists in the vicinity of the removed pipe.\nThe operator did not inspect the internal surface of the pipe whenever pipe was removed from a\npipeline at the Willbridge Facilities. The operator verified that removed pipe was never\ninspected for internal corrosion as required for compliance with § 195.579(c). Further, there are\nno records documenting internal corrosion inspections on removed pipe sections.\n7. § 195.581 Which pipelines must I protect against atmospheric corrosion and what\ncoating material may I use?\n(a) You must clean and coat each pipeline or portion of pipeline that is exposed to\nthe atmosphere, except pipelines under paragraph (c) of this section.\n4\n\n\n\n(b) Coating material must be suitable for the prevention of atmospheric corrosion.\n(c) Except portions of pipelines in offshore splash zones or soil-to-air interfaces, you\nneed not protect against atmospheric corrosion any pipeline for which you\ndemonstrate by test, investigation, or experience appropriate to the environment of\nthe pipeline that corrosion will:\n(1) Only be a light surface oxide; or\n(2) Not affect the safe operation of the pipeline before the next scheduled inspection.\nChevron Products Company (Chevron) did not protect its pipelines at the Willbridge facilities\nfrom atmospheric corrosion as required by 49 C.F.R. § 195.581(a). Specifically, Chevron did\nnot clean and coat each pipeline or portion of pipeline that is exposed to the atmosphere, or by\ndemonstrating by test, investigation, or experience appropriate to the environment of the\npipelines, that corrosion will only be a light surface oxide, or that the corrosion will not affect the\nsafe operation of the pipeline before the next scheduled inspection. Visual observation of\nChevron’s Willbridge facilities by PHMSA inspectors showed numerous areas of regulated\npipeline, pipeline P-110 in particular, without coating and with severe atmospheric corrosion.\nVisual evidence revealed that the current conditions are inconsistent with a light surface oxide,\nas the corrosion appears severe and to have existed for several years.\nChevron asserts that even if the corroded infrastructure is not simply a light surface oxide, the\ncorrosion does not affect the safe operation of pipeline P-110. In response to PHMSA\ninspectors’ questions about observable pipeline corrosion, Chevron submitted a document\nentitled “§ 195.581(c) Discussion” (Discussion). The Discussion addresses two Chevron-\nselected locations on a single pipe, P-110, comparing Ultrasonic (UT) inspections from 2005 and\n2011 to demonstrate compliance with § 195.581(c)(2). (Pictures of P-110 and schematics of the\nultrasound location are attached as exhibits to the Violation Report.) The Discussion shows little\nto no metal loss in the two locations addressed, and the wall thickness is shown to have slightly\nincreased in certain o’clock positions at the locations on the two Chevron-selected points on\npipeline P-110.\nIn response to PHMSA inspectors’ questions, Chevron provided a report after the inspection\nfrom its own expert, Mr. Phil Meyers, entitiled the January 18, 2011 “Willbridge Cathodic\nProtection Justification.” In that report, Mr. Meyers opined that a volume expansion occurs\nduring the corrosion process which may show a false increase in wall thickness. Further,\nChevron stated that the data from pipe P-110, as listed in the Discussion, illustrates the worst\ncase scenario of pipeline corrosion on P-110. The “worst case scenario” refers to the most\nprogressed corrosion on the pipe. The data from points P01-01 and P01-02 on P-110, the two\nChevron-selected locations addressed in the Discussion, produced average corrosion rates of 1.2\nmils/year and 0.2 mils/year, respectively. However, the PHMSA inspectors observed significant\npitting at area P01-02, in contrast to the UT data and photographs supplied by the operator. The\nPHMSA inspectors also question the area P02-01, a third point listed in the Discussion on the\nsame pipe, which showed significant (30+%) metal loss and consistent (4 out of 4 measurements\nin excess of 0.1 inches) metal loss for the 2005 - 2011 time period. The average corrosion rate at\nP02-01 was 17 mils/year, one and two orders of magnitude over the “worst case scenario” points\n5\n\n\n\nchosen by Chevron. Accordingly, Chevron incorrectly identified its worst case scenario of\npipeline corrosion on P-110. The rate of corrosion is shown to be greatly increased in a third\narea of the P-110 pipeline simply by looking at the UT data Chevron provided in the Discussion.\nEven by UT testing, Chevron fails to demonstrate that the corrosion will not affect the safe\noperation of the pipeline before the next scheduled inspection, particularly if 30+% corrosion\nloss over 6 years is seen on parts of the P-110 pipeline.\nThe documents provided by Chevron did not demonstrate by test, investigation, or experience\nappropriate to the operating environment of the pipeline, that corrosion will only be light surface\noxide, or that the corrosion will not affect the safe operation of the pipeline before the next\nscheduled inspection.\n8. § 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 onshore then the frequency of inspection is: At least once\nevery 3 calendar years, but with intervals not exceeding 39 months.\nFor all pipelines at the Willbridge Terminal, the operator did not produce records demonstrating\ncompliance with 49 C.F.R. § 195.583(a). The pipelines at the Willbridge Terminal are onshore\npipelines and are exposed to the atmosphere. Accordingly, Chevron is required to inspect each\npipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric\ncorrosion at least once every 3 calendar years, but with intervals not exceeding 39 months.\nChevron stated that weekly checks, monthly checks, and 5-year API 570 inspections, in\ncombination, satisfy § 195.583(a). Chevron provided May - July 2016 records of weekly and\nmonthly checks of the pipelines at the Willbridge Terminal, which showed no mention of any\natmospheric corrosion as opposed to what the PHMSA inspectors saw in the field. More detailed\nAPI 570 inspections were disclosed which note some atmospheric corrosion issues, however,\nthese inspections are performed on a 5-year interval.\nAdditionally, Chevron’s internally developed weekly and monthly checklists were not completed\nby qualified atmospheric corrosion inspectors. Also, the weekly and monthly checks were not\nfocused on atmospheric corrosion but instead, the foci were the “Willbridge Terminal Routine\nDuties” and the “Willbridge Terminal Monthly In-Service Tank Inspection,” respectively. The\noperator’s current practices of a combination of weekly and monthly checks and 5-year\ninspections are insufficient to comply with the requirements of § 195.583(a).\nAs of April 27, 2017, under 49 U.S.C. § 60122 and 49 CFR § 190.223, you are subject to a civil\npenalty not to exceed $209,002 per violation per day the violation persists up to a maximum of\n$2,090,022 for a related series of violations. We have reviewed the circumstances and\nsupporting documents involved in this case, including the extensive time to transmit our\nfindings, and have decided not to conduct additional enforcement action or penalty assessment\n6\n\n\n\nproceedings at this time. We advise you to correct the item(s) identified in this letter. Failure to\ndo so will result in Chevron being subject to additional enforcement action.\nNo reply to this letter is required. If you choose to reply, in your correspondence please refer to\nCPF 5-2019-5003W. 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 (#152513)\n7","truncated":false,"body_characters":18970}