{"operation":"document","citation":"CPF 420075015","title":"ENTERPRISE PRODUCTS OPERATING LLC — Notice of Probable Violation","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2007-05-07","effective_on":null,"summary":"CLOSED notice of probable violation citing 195.406(b), 195.410(a)(1), 195.420(c), 195.432, 195.573, 195.579(a).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-420075015.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-420075015.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-420075015","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/420075015","body":"Notice of Probable Violation involving ENTERPRISE PRODUCTS OPERATING LLC. PHMSA's enforcement data identifies the cited regulations as 195.406(b),  195.410(a)(1),  195.420(c),  195.432,  195.573,  195.579(a). The case was opened on 2007-05-07 and is reported as closed as of 2011-07-13. Proposed civil penalty: $31,000. Assessed civil penalty: $31,000. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n420075015_Closure Letter_07132011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075015/420075015_Closure%20Letter_07132011.pdf\n\n420075015_Closure Letter_07132011_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075015/420075015_Closure%20Letter_07132011_text.pdf\n\n420075015_Final Order_12022009.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075015/420075015_Final%20Order_12022009.pdf\n\n420075015_Final Order_12022009_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075015/420075015_Final%20Order_12022009_text.pdf\n\n420075015_operator response to notice letter_06082007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075015/420075015_operator%20response%20to%20notice%20letter_06082007.pdf\n\n420075015_operator response to notice letter_061107.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075015/420075015_operator%20response%20to%20notice%20letter_061107.pdf\n\n420075015_Region Notice Letter_05072007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420075015/420075015_Region%20Notice%20Letter_05072007.pdf\n\n420075015_Closure Letter_07132011_text.pdf\n\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\nJuly 13, 2011\nMr. Terry Hurlburt\nSenior Vice President of Operations\nEnterprise Products Operating, LLC\n1100 Louisiana Street\nHouston, Texas 77002\nCPF 4-2007-5015\nDear Mr. Hurlburt:\nOn December 2, 2009, the Pipeline and Hazardous Materials Safety Administration\n(PHMSA) issued to Enterprise Products Operating, LLC a Final Order in the above-\nreferenced case. This Order included a Compliance Order and Civil Penalty\nassessment. Based on our review of the documentation you provided and confirmation\nof payment of the civil penalty, it has been determined that you have complied with the\nterms of this Order.\nAccordingly, this case is now closed and no further action is contemplated with respect\nto the matters involved in this case. Thank you for your cooperation in this matter.\nSincerely,\nR. M. Seeley\nDirector, Southwest Region\nPipeline and Hazardous\nMaterials Safety Administration\n\n420075015_Region Notice Letter_05072007.pdf\n\nof Transportation\nU.S. Department\n8701 S. Gessner, Suite 1110\nHouston, TX 77074\nPipeline and\nHazardous Materials\nSafety Administration\nNOTICE OF PROBABLE VIOLATION\nPROPOSED CIVIL PENALTY\nPROPOSED COMPLIANCE ORDER\nand\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\nMay 7, 2007\nMr. Terry Hurlburt\nEnterprise Products Operating, LP\nVice-President, Eastern Operations\n2727 North Loop West\nHouston, TX 77008-1044\nCPF 4-2007-5015\nDear Mr. Hurlburt:\nDuring the months of February, April and May, 2005 a representative of the Pipeline and\nnited States Code, conducted pipeline safety inspections of Enterprise Product\nazardous Materials Safety Administration (PHMSA), pursuant to Chapter 601 of 4\nOperating, LP (Enterprise) facilities and records pertaining to the Four Corners Area\nSighway ll Pip Are Syst West Systems, Skelytown Area Systems and the Cameron\nAs a result of the inspection, it appears that you have committed probable violations of\nthe Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items\ninspected and the probable violations are:\nI. §195.406 Maximum operating pressure\n(b) No operator may permit the pressure in a pipeline during surges or othe\nariations from normal operations to exceed 110 percent of the operating\nressure limit established under paragraph (a) of this section. Each operato\nmust provide adequate controls and protective equipment to control the\npressure within this limit.\n\n\n\nEnterprise could not show evidence that surge pressures had been considered,on all of\ntheir pipelines. Enterprise should be able to show that their pipelines are adequately\nprotected and that surge pressures have been eonsidered on all of their pipelines.\n2. $195.410(a)(1) Line markers\n(a) Except as provlded in paragraph (b) of this section, each operator shall\nplace and maintain line markers over each buried pipeline in accordance with\nthe following:\n(1) Markers must be located at each public road crossing, at each railroad\ncrossing, and in sufficient number along the remainder of each buried line so\nthat its location is accurately known.\nEnterprise does not have sufficient markers to adequately mark their pipelines. When\ncrossing cultivated agricultural fields, often the markers on the far side of the field could\nnot be seen. From valve sites, looking in both directions, the next marker for the pipeline\ncould not be seen. The lack of pipeline marking is a widespread problem with the\nEnterprise pipelines that were inspected.\n3. 5195.420 Valve maintenance\n(c) Each operator shall provide protection for each valve from unauthorized\noperation and from vandalism.\nDuring the inspections it was noted that Enterprise uses a mixture of methods of\ncomplying with 195.420c. The CHOPS Pipeline has installed locked chain link fencing\naround the valves or locating the valves within secured facilities. The methods of\nprotection used in the six Enterprise units that were inspected, range from no fencing or\nsecurity, to pipe post and beam enclosures with locked valves, to cyclone fencing with\nbarbed wire around top, to enclosing the valves in welded steel plate, and covering the\nentire valve with concrete.\nA review of your procedures by our inspector did not reveal a plan or procedure to\nconsistently specify the method of security for valve sites that is acceptable to you.\nEnterprise should review their program, procedures, and facilities to ensure they are\nconsistent and compliant with this regulation.\n4. $195.432 Breakouttanks.\n(a) Except for breakout tanks ins.pected under paragraphc (b) and (c) of this\nsection, each operator shall, at intervals not exceeding 15 month$, but at least\nonce each ca|endar year, inspect each in-service breakout talak.\n(b) Each operator shall inspect the physical integrity of in-service atmospheric\nand low-pressure steel aboveg,round breakout tanks according to sect,ion 4 of\nAPI Standard S53. However, ff structural conditions prevent access to the tank\nbottom, the bottom integrity may be assessed according to a plan includsd in\nthe operations and maintenance manual under g195.402(c)(3).\n(c) Each operator shall inspect the physfcal integrity of in-service steel\nabovxground breakout tanks built to API Standard 2510 accordi,ng to section 6\nof API 510.\n(d) The intervals of inspection specified by documents referenced in\nparagraphs (b) and (c) of this section begin on May 3, '1999, or on the\noperator's last recorded date of the inspection, whichever is earlier.\n\n\n\nEnterprise had not set up an API-653 and/or API-S10 inspection program, as required by\n5195.432, Enterprise could not demonstrate that breakout tanks have been inspected\nper the regulation.\n5- 5195.573 What must I do to monitor external corrosion control?\n(a) Protected nipefines, You must do the following to determine whether\ncathodic protection required by this subpart complies with Sec. 195.571:\n1. CIonduct tests on the protected pipeline at least once each calendar year,\nbut with intervals not exceeding 15 months. However, if tests at those intervals\nare lmpractical for separately protected short sections of hane or ino.ffectlvely\ncoated pipelines, testing may be done at least once every 3 calendar. years, but\nwith intervals not exceeding 39 months.\n(d) Breakout tanks. You must inspect each cathodic protection system used to\ncontrol corroslon on the bottorn of an aboveground breakout tank to ensure\nthat operation and maintenance of the system are in accordance with API\nRecomrnended Practice 651. However, this inspection is not reguired if you\nnote in the corrosion control procedu:re$ established under Sec. 19S\"402(cX3)\nwhy compliance with all or certain operation and maintenance previsions of\nAPI Recomrnended Practice 651 is not necessary for the safety of the t*lk.\nEnterprise is just beginning to implement surveys that consider lR drop. There is not\ndedicated Cathodic Protection (CP) for tank bottoms, and the tank bottoms are not\nsurveyed during annual Cathodic Protection survey. The first interrupted survey (to\naccount for lR drop)was being conducted on the Four Corners Pipeline, during the 2005\nDOT inspection.\n6. 5195.579 What must I do to mitigate internal corrosion?\n(a) General. lf you transport any hazardous liquid or carbon dioxide that would\ncorrode the pipeline, you must investigate the corrosive effect of the\nhazardous liquid or carbon dioxide on the pipeline and take adequate steps to\nmitigate internal corrosion.\nEnterprise has not done investigations to determine whether lhere is internaN corrosion\nor the potential for internal corrosion. Fnterprise has performed little monitoring, and has\nnot done inspections to investigate whether there could be internal conosion. The\ninvestigation of internal corosion appears to be based upon internal coupo,ns, which are\nimproperly iocated on pipelines, and no otherevidence could be produced. No records\nof internal inspection of removed pipe could be located.\nProposed Civil ?enaltv\nUnder 49 United States Code, E 60122, you arc subject to a civil penalty not to exceed\n$100,000 for each violation for each day the violations persists up to a maximr.rm of\n$1,000,000 for any related series of violations. The Compliance Officer has reviewed\nthe circumstances and supportlng documentation involved in the above probabie\nviolation(s) and has recommended that you be prelirninarily assessed a civil penalty of\n$31,000 as follows:\nltem number\n1\nPENALTY -fu1,ooo\n\n\n\nWarninq ltems\nWith respect to item #3, we have reviewed the circumstances and supporting documents\ninvolved in this case and have decided not to conduct additional enforcement action or\npenalty assessment proceedings at this time. We advise you to promptly correct this\nitem. Be advised that failure to do so may result in Enterprise being subject to additional\nenforcement action.\nProposed Compliance Order\nWith respect to items 1\n, 2, 4,5, and 6 pursuant to 49 United States Code $ 601 18, the\nPipeline and Hazardous Materials Safety Administration proposes to issue a Compliance\nOrder to Enterprise Products Operating, L.P. Please refer to the Proposed Compliance\nOrderwhich is enclosed and made a part of this Notice.\nRespp,nse to this Notice\nEnclosed as parl of this Notice is a document entitled Response Options for Pipeline\nOperators in Comptiartce Proceedings. Please refer to this document a,nd note the\nresponse options. Be advised that all material you submit in response to this\nenforcement action is subject to being made publicly available. [f you believe that any\nportion of your responsive material qualifies for confidentia! treatment undor 5 U.S.C.\n552(b), along with the complete original document you must provide a second copy of\nthe document with the portions you believe qualify for confidential treatment redacted\nand an explanation of why you believe the redacted information quallfles for confidential\nireatment under 5 U.S.C. 552(b). lf you do not respond within 30 days of receipt of this\nNotice, this constitutes a waiver of your right to contest the allegations in this Notice and\nauthorizes th'e Associate Administrator for Pipeline Safety to find facts as alleged in this\nNotice without further notice to you and to issue a Final Order.\nln your correspondence on this rnatter, please refer to CPF 4.2007-50'15 and for each\ndocument you submit, please provide a copy in eleetronic format whe,never possible.\nSincerely,\n4@\"M4\nR. M. Seeley\nDirector, Southwest Region\nPipeline and Hazardous Materials Safety Administration\nEnclosures: PraposedComplianceOrder\nResponse Opfions for Pipeline Operators in Compliance Proceedings\n\n\n\nPffiOPOSED COMPLTANCE ORDER\nPursuant to 49 United States Code $ 60118, the Pipeline and Hazardous Materials\nSafety Administration (PHMSA) proposes to issue to Enterprise Products Operating, L.P.\na Compliance Order incorporating the following remedial requirements to ensure the\ncompliance of Enterprise Products Operating, L.P with the pipeline safety regulations:\n1. Perform an audit to ensure Enterprise is in compliance with 5195.406(b). This audit\nshall consist of:\nr Demonstrate that all of Enterprise's pipelines listed in this letter are protected\nfrom overpressure from surges or other variations from normal operations and\nthat they are in compliance with applicable procedures.\nr Based upon the review, develop a plan for installation of adequate controls and\nprotective equipment to protect the pipelines and control the pressure within this\nlimit.\n2. Perform an audit to ensure Enterprise is in compliance $195.410(aX1). This audit\nshall consist of:\nI Survey of your pipeline markers throughout the Enterprise's pipeline system.\nThe survey is to evaluate the line markers currently posted along the right-of-way\nas well as identify those areas where additional markers are needed. The survey\nshall also ensure markers comply with applicable procedures.\nr Based upon the review and s,urvey develop a ptan for replacemenV,installation of\nthe line markers to bring Enterprise into compliance.\n3.\nPerform an audit to ensure Enterprise is in compliance $195.432. This audit shall\nconsist of:\nI Survey all break out tanks, on all of Enterprise's pipelines listed in this letter,\nr Based upon review and survey, develop a plan for API 653 and API 510\ninspection programs to bring Enterprise into compliance.\n4 ,\nPerform an audit to ensure Enterprise is in compliance $195.573(a). This audit shall\nconsist of:\nr Survey all applicable segments of Enterprise's pipelines to insure that cathodic\nprotection testing meets applicable criteria, and that the pipelines are protected.\nr Based upon the review and survey, develop a plan for conducting cathodic\nprotection surveys to bring Enterprise into compliance, and ensure that all\npipelines are protected by adequate cathodic protection.\nPerform an audit to ensure Enterprise is in compliance $195.579(a). This audit shall\nconsist of:\nr Survey all applicable facilities and segments of Enterprise's pipelines to ensure\nthat internaI corrosion inspection, testing and,monitoring meet applicable criteria,\nand that the pipelines are protected from internal corrosion.\nr Based upon the review and survey, develop a,plan for conducting internal\n\n\n\no .\n7.\ncorrosion surveys to bring Enterprise into compliance.\na. Results of surveys and plans, with time tables, must be submitted within 30 days\nfollowing the receipt of the Final Order.\nb. All items shall be completed within 365 days following the receipt of the Final\nOrder.\nEnterprise shall maintain documentation of the safety improvement costs associated\nwith fulfilling this Compliance Order and submit the tolal to Rod Seeley, Director,\nSouthwest Region, Pipeline and Hazardous Materials Safety Administration. Costs\nshall be reported in two categories: 1) total cost associated with preparation/revision\nof plans, procedures, studies and analyses, and 2) total cost associated with\nreplacements, additions and other changes to pipeline infrastructure.\n\n420075015_Final Order_12022009_text.pdf\n\nDEC 02 2009\nMr. Terry Hurlburt\nSenior Vice President of Operations\nEnterprise Products Operating, LLC\n1100 Louisiana Street\nHouston, TX 77002\nRe: CPF No. 4-2007-5015\nDear Mr. Hurlburt:\nEnclosed is the Final Order issued in the above-referenced case. It makes findings of violation,\nassesses a civil penalty of $31,000, and specifies actions to be taken to comply with the pipeline\nsafety regulations. The penalty payment terms are set forth in the Final Order. When the civil\npenalty has been paid and the terms of the compliance order completed, as determined by the\nDirector, Southwest Region, this enforcement action will be closed. Your receipt of the Final\nOrder constitutes service of that document under 49 C.F.R. § 190.5.\nThank you for your cooperation in this matter.\nSincerely,\nJeffrey D. Wiese\nAssociate Administrator\nfor Pipeline Safety\nEnclosure\ncc: Mr. R. M. Seeley, Director, Southwest Region\nVIA CERTIFIED MAIL – RETURN RECEIPT REQUESTED [7005 0390 0005 6162 5098]\n\n\n\nU.S. DEPARTMENT OF TRANSPORTATION\nPIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION\nOFFICE OF PIPELINE SAFETY\nWASHINGTON, D.C. 20590\n____________________________________\nIn the Matter of )\nEnterprise Products Operating, LLC, ) CPF No. 4-2007-5015\n)\n)\n)\nRespondent. )\n____________________________________)\nFINAL ORDER\nOn February 21–25, April 5–8, 18–22, and May 2–6, 16–20, 2005, pursuant to 49 U.S.C.\n§ 60117, a representative of the Pipeline and Hazardous Materials Safety Administration’s\nOffice of Pipeline Safety (PHMSA) conducted an on-site pipeline safety inspection of the\nhazardous liquid pipeline facilities operated by Enterprise Products Operating, LLC (Enterprise\nor Respondent) in New Mexico, Texas, and Oklahoma. Enterprise operates over 20,000 miles of\nhazardous liquid and natural gas pipeline facilities in those and other states, as well as offshore in\nthe Gulf of Mexico. The facilities and records of the following systems were inspected: Four\nCorners, Hobbs East, Hobbs West, Skellytown, and the Cameron Highway Oil Pipeline.\nAs a result of the inspection, the Director, Southwest Region (Director), issued to Respondent,\nby letter dated May 7, 2007, a Notice of Probable Violation, Proposed Civil Penalty, and\nProposed Compliance Order (Notice). In accordance with 49 C.F.R. § 190.207, the Notice\nproposed finding that Respondent had committed violations of 49 C.F.R. Part 195, proposed\nassessing a civil penalty of $31,000 for the alleged violations, and proposed ordering Respondent\nto take certain measures to correct them. In accordance with 49 C.F.R. § 190.205, the Notice\nalso proposed finding that Respondent had committed certain probable violations of 49 C.F.R.\nPart 195 and warned Respondent to take appropriate corrective action to address them or be\nsubject to future enforcement action.\nRespondent responded to the Notice by letter dated June 8, 2007 (Response). Respondent\ncontested the allegations and requested that the Notice be withdrawn. Respondent did not\nrequest a hearing, and therefore has waived its right to one.\nFINDINGS OF VIOLATION\nThe Notice alleged that Respondent violated 49 C.F.R. Part 195, as follows:\n\n\n\n2\nItem 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.406, which states:\n§ 195.406 Maximum operating pressure.\n(a) Except for surge pressures and other variations from normal\noperations, no operator may operate a pipeline at a pressure that exceeds\nany of the following . . . .\n(b) No operator may permit the pressure in a pipeline during surges or\nother variations from normal operations to exceed 110 percent of the\noperating pressure limit established under paragraph (a) of this section.\nEach operator must provide adequate controls and protective equipment to\ncontrol the pressure within this limit.\nThe Notice alleged that Respondent violated § 195.406(b) by failing to provide adequate controls\nand protective equipment to control pressure within 110 percent of the established maximum\noperating pressure (MOP) during surges and other variations from normal operations.\nSpecifically, the Notice alleged that Enterprise had not considered the potential for surge\npressure on all of its pipelines, and therefore could not demonstrate its pipelines had adequate\nprotective equipment to control pressure within 110 percent of MOP during surges.\nIn its Response, Enterprise contended that § 195.406(b) does not require consideration of\npressure surges. Respondent also claimed that surges are not an issue for the inspected pipelines,\nwhich have never had any incidents of overpressure caused by surges. Based on its operating\nexperience, Respondent contended that its controls and protective equipment were adequate.\nSection 195.406 requires that operators establish a safe MOP for normal operations, and further\nprovides that in order to protect a pipeline during momentary pressure excursions caused by\nsurges, operators must have adequate controls and protective equipment to control pressure\nduring surges to within 110 percent of the established MOP. While I agree with Respondent that\nthe text of the regulation does not explicitly state an operator shall “consider” the potential for\nsurges, I disagree with the company’s contention that consideration of surges is not a\nrequirement of the regulation. In order for an operator to understand if its controls and protective\nequipment are “adequate” to protect a pipeline from spikes in pressure caused by surges, it is\nnecessary for the operator to consider the potential for such surges and to understand and account\nfor their potential effects when designing appropriate controls and protective equipment. If an\noperator has not at least considered the potential for surges on its pipeline, there cannot be an\ninformed judgment about the adequacy of the operator’s controls to prevent pressure from\nexceeding 110 percent of MOP during surges.\nThe evidence shows that during the inspection of Respondent’s facilities, the PHMSA\nrepresentative requested documentation to verify that Enterprise’s controls and protective\nequipment were adequate to control pressure. His request included records to show that\nRespondent had analyzed the potential for surges on its pipelines. Respondent was able to\nproduce surge analyses for several but not all of the inspected pipelines. In its Response,\nRespondent did not produce any additional surge analyses but contended that surge pressures\nwere simply not an issue for its pipelines.\n\n\n\n3\nRespondent’s claim that surge pressures are not an issue is unsubstantiated by the evidence in the\nrecord. Furthermore, even if a particular pipeline has no known incident of overpressure in the\npast, that does not guarantee the pipeline will never experience an overpressure caused by a\nsurge in the future. Simply noting that a pipeline has not experienced a surge in the past does not\ndemonstrate that controls and protective equipment are adequate to control pressure within 110\npercent of MOP in the event a surge or other variation from normal operations were to occur.\nAfter considering all the evidence, I find that Respondent violated 49 C.F.R. § 195.406(b) by\nfailing to provide controls and protective equipment demonstrated to be adequate to control\npressure within 110 percent of MOP during surges and other variations from normal operations.\nItem 4: The Notice alleged that Respondent violated 49 C.F.R. § 195.432, which states:\n§ 195.432 Inspection of in-service breakout tanks.\n(a) Except for breakout tanks inspected under paragraphs (b) and (c)\nof this section, each operator shall, at intervals not exceeding 15 months,\nbut at least once each calendar year, inspect each in-service breakout tank.\n(b) Each operator shall inspect the physical integrity of in-service\natmospheric and low-pressure steel aboveground breakout tanks according\nto section 4 of API Standard 653. However, if structural conditions\nprevent access to the tank bottom, the bottom integrity may be assessed\naccording to a plan included in the operations and maintenance manual\nunder § 195.402(c)(3).\n(c) Each operator shall inspect the physical integrity of in-service steel\naboveground breakout tanks built to API Standard 2510 according to\nsection 6 of API 510.\n(d) The intervals of inspection specified by documents referenced in\nparagraphs (b) and (c) of this section begin on May 3, 1999, or on the\noperator’s last recorded date of the inspection, whichever is earlier.\nThe Notice alleged that Respondent violated § 195.432(b) and (c) by failing to inspect the\nphysical integrity of in-service atmospheric and low-pressure steel aboveground breakout tanks\naccording to section 4 of API Standard 653, and by failing to inspect steel aboveground breakout\ntanks built to API Standard 2510 according to section 6 of API 510.1 The Notice further alleged\nthat Enterprise did not have a written inspection program for breakout tanks.2 The PHMSA\nrepresentative noted during the inspection that Enterprise employees were not aware of the need\nto determine inspection intervals in accordance with API 653 and API 510 and that the company\nhad been performing annual inspections pursuant to an outdated requirement in § 195.432.3\n1 American Petroleum Institute (API) Standard 653, “Tank Inspection, Repair, Alteration, and Reconstruction,” and\nAPI Standard 510, “Pressure Vessel Inspection Code: Maintenance Inspection, Rating, Repair, and Alteration,” are\nboth incorporated by reference at 49 C.F.R. § 195.3.\n2 See also 49 C.F.R. § 195.402(c)(3), “Procedural manual for operations, maintenance, and emergencies,” which\nspecifies that operators must prepare and follow written procedures for conducting operations and maintenance\nactivities in accordance with § 195.432, among other requirements.\n3 PHMSA amended § 195.432 in 1999 by incorporating the API consensus standards in order to improve the level of\nsafety applicable to maintenance inspections of breakout tanks. Before the revision, § 195.432 only generally\nrequired that all breakout tanks be inspected annually. See Pipeline Safety: Adoption of Consensus Standards for\nBreakout Tanks, 64 Fed. Reg. 15,926 (Apr. 2, 1999).\n\n\n\n4\nIn its Response, Enterprise contested the allegation of violation and contended that the subject\nbreakout tanks had been inspected in full compliance with both API 653 and API 510.\nRespondent submitted records from two breakout tank examinations that occurred on April 20,\n2004 (tank numbers VSP-2010 and VSP-2020). Respondent also submitted an inspection\nschedule that demonstrated the next visual inspections for the two tanks, among others, were to\nbe performed in 2009 and the next ultrasonic inspections were to be performed in 2014.\nSection 195.432(b) and (c) requires operators to perform maintenance inspections of breakout\ntanks at periodic intervals established in accordance with API 653 and API 510. In particular,\nAPI 653 provides that periodic inspection intervals for atmospheric and low-pressure breakout\ntanks shall be determined on the basis of specific factors listed therein; further, API 510 provides\nthat inspection intervals for breakout tanks built to API 2510 shall be based on a calculated\ncorrosion rate. Section 195.402(c)(3) also requires that operators have written procedures for\nperforming inspections of breakout tanks in accordance with § 195.432, including the\nestablishment of inspection intervals.\nWhile Respondent claimed in its Response that it had performed inspections consistent with all\nof these requirements, the operator failed to submit evidence that demonstrated full compliance.\nNeither the inspection records for the two tanks nor the inspection schedule show that Enterprise\nhad performed inspections at intervals determined in accordance with API 653 and API 510.\nFurthermore, the evidence does not include any written procedures demonstrating that\nRespondent had prepared (and followed) a program for conducting breakout tank inspections,\nincluding the establishment of inspection intervals based on the consideration of the specific\nfactors listed in those standards.\nAccordingly, after considering all the evidence, I find that Respondent violated 49 C.F.R.\n§ 195.432(b) and (c) by failing to inspect the physical integrity of in-service atmospheric and\nlow-pressure steel aboveground breakout tanks according to section 4 of API Standard 653, and\nsteel aboveground breakout tanks built to API Standard 2510 according to section 6 of API 510.\nItem 5: The Notice alleged that Respondent violated 49 C.F.R. § 195.573, which states:\n§ 195.573 What must I do to monitor external corrosion control?\n(a) Protected pipelines. You must do the following to determine\nwhether cathodic protection required by this subpart complies with\n§195.571:\n(1) Conduct tests on the protected pipeline at least once each calendar\nyear, but with intervals not exceeding 15 months. However, if tests at\nthose intervals are impractical for separately protected short sections of\nbare or ineffectively coated pipelines, testing may be done at least once\nevery 3 calendar years, but with intervals not exceeding 39 months . . . .\n(d) Breakout tanks. You must inspect each cathodic protection system\nused to control corrosion on the bottom of an aboveground breakout tank\nto ensure that operation and maintenance of the system are in accordance\nwith API Recommended Practice 651. However, this inspection is not\nrequired if you note in the corrosion control procedures established under\n\n\n\n5\n§195.402(c)(3) why compliance with all or certain operation and\nmaintenance provisions of API Recommended Practice 651 is not\nnecessary for the safety of the tank.\nThe Notice alleged that Respondent violated § 195.573(a) and (d) by failing to conduct tests on\nprotected pipelines to determine whether cathodic protection complied with § 195.571, and by\nfailing to inspect cathodic protection used to control corrosion on the bottom of aboveground\nbreakout tanks to ensure that it complied with API Recommended Practice (RP) 651.4\nSpecifically, the Notice alleged that Enterprise had not considered voltage (IR) drop when\nsurveying cathodic protection systems, did not have dedicated cathodic protection systems for\nbreakout tank bottoms, and failed to survey tank bottoms during annual cathodic protection\nsurveys. The Notice further alleged that Respondent’s first-ever interrupted survey (to account\nfor IR drop) was conducted during the 2005 PHMSA inspection.\nDuring that inspection, the PHMSA representative noted that Enterprise’s survey methods did\nnot account for the revised safety standards established in 2002 by the promulgation of\n§§ 195.571 and 195.573.\n5 Until then, operators were required only to test cathodic protection\nsystems to determine whether the protection was “adequate.”6 Effective January 28, 2002,\n§ 195.571 established paragraphs 6.2 and 6.3 of NACE Standard RP 0169 as the standard for\ndetermining the adequacy of cathodic protection systems for pipelines.\nfurther requires that operators conduct tests on protected pipelines to determine if cathodic\nprotection complies with those standards. Likewise, § 195.573(d) establishes API RP 651 as the\nstandard for determining the adequacy of cathodic protection systems for breakout tanks. Both\nparagraphs 6.2.2.1.1 of NACE RP0169 and 8.2.2.1 of API RP 651 state that an operator may use\nthe -850 mV criterion for determining the adequacy of cathodic protection, but both standards\nprovide that “[v]oltage drops other than those across the structure [or tank bottom]-to-electrolyte\nboundary must be considered for valid interpretation of this voltage measurement.”\n7 Section 195.573(a)\nProtected Pipelines\nIn its Response, Enterprise contested the allegations of violation and contended that the company\nhas always considered IR drop for its pipelines. Respondent explained that it considered IR drop\nin a variety of ways, including: measurement of IR drop via interrupted annual or close-interval\ncathodic protection surveys; use of “IR-free” coupon test stations; visual observation and\nmeasurement of pipe-wall thickness when lines are exposed; use of internal inspection devices;\ncorrosion leak history analysis; at-grade versus in-the-ditch pipe-to-soil potential measurements\nat pipeline excavation sites; and potential measurement techniques that consider proper reference\ncell placement and pipeline location.\n4 API Recommended Practice 651, “Cathodic Protection of Aboveground Petroleum Storage Tanks,” is incorporated\nby reference at 49 C.F.R. § 195.3.\n5 See Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines, 66 Fed. Reg. 66,994 (Dec. 27,\n2001).\n6 See 49 C.F.R. § 195.416 (2001).\n7 NACE International (NACE) Standard RP0169, “Control of External Corrosion on Underground or Submerged\nMetallic Piping Systems,” is incorporated by reference at 49 C.F.R. § 195.3.\n\n\n\n6\nWith respect to the interrupted annual or close-interval surveys, Respondent stated that in 2003,\nthe company conducted 396 miles of “interrupted/IR-free” annual or close-interval cathodic\nprotection surveys across all of its pipeline systems. Respondent also indicated that in 2004, it\nconducted 65 miles of interrupted close-interval cathodic protection surveys and developed a\nplan to accomplish several goals within five years, such as: conducting 20 percent of its annual\ncathodic protection surveys for all of its pipeline systems using interrupted/IR-free surveys;\nperforming all close-intervals in an interrupted/IR-free manner; and installing IR-free coupon\ntest stations. Respondent indicated that pursuant to this five-year plan, it had completed more\nthan 7,000 miles of interrupted/IR-free annual or close-interval surveys and installed 263 IR-free\ncoupon test stations throughout its pipeline system.\nEnterprise further indicated that it had conducted 396 miles of surveys across all of its pipeline\nsystems in 2003, but did not indicate what portion of the 3,200 miles of pipelines subject to this\nenforcement action were included in that total. Regardless, I note that Respondent did not claim\nthat it performed interrupted or close interval surveys on all 3,200 miles of its pipelines in 2003.\nFrom 2004 through 2007, Respondent indicated it conducted 7,000 miles of interrupted or close-\ninterval surveys on all of its pipelines; but for 2004 the company has only accounted for 65 miles\nof the pipelines subject to this enforcement action, and did not specifically account for any of the\nsubject pipelines for individual survey years 2005, 2006, or 2007.\nWith respect to the various other methods that Enterprise claimed to have used to consider IR\ndrop, the evidence in the record does not reflect the actual use of them all. Respondent’s annual\ncathodic protection survey records do not show they were all used, nor did Respondent submit\nany other documentation, such as reports or summaries, that document the use of all these\nmethods in a manner that would enable Respondent to determine whether its cathodic protection\nsystems complied with applicable standards. Without such supporting evidence, I am unable to\nfind the use of all of these various methods actually met the specifications of § 195.573.\nBreakout tanks\nThe Notice further alleged that Respondent did not have dedicated cathodic protection systems\nfor breakout tank bottoms. In its Response, Enterprise contended that such allegation, even if\ntrue, did not state a violation of any PHMSA regulation because neither the code nor industry\nstandards required dedicated cathodic protection for tank bottoms. Respondent explained that\nthe cathodic protection system protecting the breakout tank at Skellytown Station is a\ndeepwell/impressed-current system that also protects below-grade station piping.\nAfter reviewing the relevant safety requirements, I do not find any apparent requirement in\n§ 195.573(d) that an operator must have a dedicated cathodic protection system for its breakout\ntank bottoms. Accordingly, I am withdrawing the allegation that Respondent’s failure to provide\na dedicated cathodic protection system for breakout tank bottoms constituted a violation of\n§ 195.573(d).\nIn addition, the Notice alleged that Respondent failed to survey tank bottoms in accordance with\n§ 195.432(d) during annual cathodic protection surveys. In its Response, Enterprise contended\nthat cathodic protection potentials were measured at the four compass bearing locations (North,\nSouth, East and West) around the perimeter of the subject breakout tank and were recorded\n\n\n\n7\nduring annual cathodic protection surveys of the station. Respondent submitted records of those\nsurveys.\nThe records show that Respondent inspected the cathodic protection system used to control\ncorrosion on the bottom of the breakout tank at Skellytown Station during calendar years 2003,\n2004, and 2005; however, the records do not demonstrate that these cathodic protection surveys\nconsidered IR drop for valid interpretation of the -850 mV criterion in accordance with\n§ 195.432(d) and API RP 651.\nAccordingly, after considering all the evidence, I find Respondent violated 49 C.F.R.\n§ 195.573(a) and (d) by failing to conduct tests on protected pipelines to determine whether\ncathodic protection complies with § 195.571, and by failing to inspect each cathodic protection\nsystem used to control corrosion on the bottom of aboveground breakout tanks to ensure that the\nsystems comply with API RP 651.\nItem 6: The Notice alleged that Respondent violated 49 C.F.R. § 195.579, which states:\n§ 195.579 What must I do to mitigate internal corrosion?\n(a) General. If you transport any hazardous liquid or carbon dioxide\nthat would corrode the pipeline, you must investigate the corrosive effect\nof the hazardous liquid or carbon dioxide on the pipeline and take\nadequate steps to mitigate internal corrosion . . . .\n(c) Removing pipe. Whenever you remove pipe from a pipeline, you\nmust inspect the internal surface of the pipe for evidence of corrosion. If\nyou find internal corrosion requiring corrective action under §195.585,\nyou must investigate circumferentially and longitudinally beyond the\nremoved pipe (by visual examination, indirect method, or both) to\ndetermine whether additional corrosion requiring remedial action exists in\nthe vicinity of the removed pipe . . . .\nThe Notice alleged that Respondent violated § 195.579(a) and (c) by failing to investigate the\ncorrosive effect of the hazardous liquid transported by pipeline. Specifically, the Notice alleged\nRespondent failed to sufficiently investigate and monitor for internal corrosion and to perform\ninspections to determine whether internal corrosion could develop in its pipeline system. The\nNotice further alleged that Respondent used coupons to check for internal corrosion but did not\nproperly locate the coupons so they would accurately detect the corrosion. It also alleged\nRespondent did not inspect pipe that had been removed from service for evidence of internal\ncorrosion.\nIn its Response, Enterprise contended that it did investigate, detect, prevent, and mitigate internal\ncorrosion through its integrity management (IM) program and its operations and maintenance\n(O&M) program. Through its IM program, Respondent stated it conducted inline inspections\n(ILI) using a smart pig to identify various pipe-wall anomalies such as internal corrosion, and it\ninvestigated anomalies that met remediation criteria. In addition, through its O&M program,\nRespondent stated it used internal coupons throughout its pipeline system to yield data on\ninternal corrosion. The validity of the coupons data was demonstrated, according to Respondent,\nby the fact that the data corresponded with results from the IM anomaly investigations. Finally,\n\n\n\n8\nRespondent indicated it inspected pipe removed from service for internal corrosion, as evidenced\nby a sample report submitted for the record.\nBy regulation, Respondent is required to implement its IM program for each pipeline segment\nthat could affect a “high consequence area” (HCA).8\nAccording to Respondent’s annual report,\nless than one-fifth of Respondent’s hazardous liquid pipeline system could affect an HCA. Since\nRespondent’s IM program is required to cover only a fraction of the pipelines, the use of ILI\npursuant to Respondent’s IM program would be inadequate to monitor for corrosive effects on\nthe entire system. In addition, inline inspections of mainline pipe are not representative of the\nentire pipeline system because internal corrosion generall","truncated":true,"body_characters":56819}