{"operation":"document","citation":"CPF 420125007","title":"ENTERPRISE CRUDE PIPELINE LLC — Notice of Probable Violation","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2012-03-12","effective_on":null,"summary":"CLOSED notice of probable violation citing 195.264, 195.432, 195.505.","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-420125007.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-420125007.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-420125007","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/420125007","body":"Notice of Probable Violation involving ENTERPRISE CRUDE PIPELINE LLC. PHMSA's enforcement data identifies the cited regulations as 195.264,  195.432,  195.505. The case was opened on 2012-03-12 and is reported as closed as of 2012-09-28. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n420125007_ NOPV PCO_ 03122012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420125007/420125007_%20NOPV%20PCO_%2003122012_text.pdf\n\n420125007_Final Order_09282012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420125007/420125007_Final%20Order_09282012.pdf\n\n420125007_Final Order_09282012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420125007/420125007_Final%20Order_09282012_text.pdf\n\n420125007_NOPV PCO_03122012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420125007/420125007_NOPV%20PCO_03122012.pdf\n\n420125007_Operator Response to Notice_04262012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420125007/420125007_Operator%20Response%20to%20Notice_04262012.pdf\n\n420125007_ NOPV PCO_ 03122012_text.pdf\n\nNOTICE OF PROBABLE VIOLATION\nand\nPROPOSED COMPLIANCE ORDER\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\nMarch 12, 2012\nMr. Kevin Bodenhamer\nSenior Vice President\nEnterprise Crude Pipeline, LLC\n1100 Louisiana Street\nHouston, TX 77002\nCPF 4-2012-5007\nDear Mr. Bodenhamer:\nOn April 11-15, 2011, a representative of the Pipeline and Hazardous Materials Safety\nAdministration (PHMSA) pursuant to Chapter 601 of 49 United States Code were onsite and\ninspected your Enterprise East Cushing Terminal in Cushing, OK.\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 the\nprobable violation(s) are:\n1. 195.264 Impoundment, protection against entry, normal/emergency venting or\npressure/vacuum relief for aboveground breakout tanks.\nImpoundment, protection against entry, normal/emergency venting\n(a) A means must be provided for containing hazardous liquids in the event of spillage\nor failure of an aboveground breakout tanks.\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 Specification 12F, API Standard 620, and others (such as API\nStandard 650 or its predecessor Standard 12C), the installation of impoundment must\n\n\n\nbe in accordance with the following sections of NFPA 30:\n(i) Impoundment around a breakout tank must be installed in accordance with section\n4.3.2.3.2; and\n(ii) Impoundment by drainage to a remote impounding area must be installed in\naccordance with section 4.3.2.3.1.\n(2) For tanks built to API 2510, the installation of impoundment must be in accordance\nwith section 5 or 11 of API 2510 (incorporated by reference, see §195.3).\nEnterprise (the Operator) did not have documentation (surveys, calculations) verifying that the\ncontainment dike volume at the East Cushing Terminal met the applicable NFPA 30\nrequirements after constructing additional tanks within the diked area as recently as 2006. The\ndocumentation was requested during the inspection but not provided by the Operator. The\nEnterprise procedure EGS E-6310, Secondary Containment & Leak Detection, Section 5.0,\nDiking, specifies requirements but the Operator was not able to produce documentation showing\nthat these procedures had been followed.\n2. 195.432 Inspection of in-service breakout tanks.\n(a) Except for breakout tanks inspected under paragraphs (b) and (c) of this section,\neach operator shall, at intervals not exceeding 15 months, but at least once each calendar\nyear, inspect each in-service breakout tank.\n(b) Each operator must inspect the physical integrity of in-service atmospheric and low-\npressure steel aboveground breakout tanks according to API Standard 653\n(incorporated by reference, see § 195.3). However, if structural conditions prevent access\nto the tank bottom, the bottom integrity may be assessed according to a plan included in\nthe operations and maintenance manual under § 195.402(c)(3).\n(c) Each operator shall inspect the physical integrity of in-service steel aboveground\nbreakout tanks built to API Standard 2510 according to section 6 of API 510.\n(d) The intervals of inspection specified by documents referenced in paragraphs (b) and\n(c) of this section begin on May 3, 1999, or on the operator's last recorded date of the\ninspection, whichever is earlier.\nThe corrosion rate used by Enterprise to establish the external inspection intervals was not based\non actual shell thickness measurements for a given tank or a documented similar service\nassessment performed according to the requirements the version of API 653, Appendix H.\nAccording to interviews performed during the inspection and email correspondence from\nEnterprise, a corrosion rate of 0.003 inches per year was used if there was no known corrosion\nrate. The incorporated version of API 653 requires that the external inspection “…be conducted\nat least every 5 years or RCA/4N years (where RCA is the difference between the measured shell\nthickness and the minimum required thickness in mils, and N is the shell corrosion rate in mils\nper year) whichever is less.” Therefore, an Operator must determine an actual corrosion rate\nthrough measurement or determine a corrosion rate based on a similar service study performed\naccording to the requirements of API 653 Appendix H to establish the external inspection\ninterval.\n2\n\n\n\nPertaining to the Operator’s procedural requirements for external inspections, at the time of the\ninspection or afterwards, Enterprise presented several breakout tank inspection procedures that\nincluded external inspection requirements, so it is not clear which procedure(s) the Operator\nused. The procedures included Enterprise Products STD.9502, Inspection and Testing of\nAboveground Storage Tanks, EPCO, Inc., STD.9503, DOT Breakout Tank Integrity Testing, and\nEPCO, Inc., EGS E-6320, Tank Inspection Repair, Alteration and Reconstruction. The wording\nfor the external inspection requirements varied between procedures but each intended to convey\nthe external inspection requirements of API 653, although sometimes incorrectly. For example,\nEPCO, Inc., STD.9503 states that a risk-based inspection assessment may be used to establish\nthe external inspection interval. However, the version of API 653 incorporated by reference\nstates in Section E.3, Technical Inquiry Responses, 653-I-02/03, “RBI can be applied to internal\ninspection intervals only.” If the operator followed this procedure, it would not be consistent\nwith the requirements of Part 195 for external breakout tank inspections.\nAlso, at the time of the inspection, Enterprise had set the ultrasonic thickness inspection intervals\nto the maximum of 15 years. For ultrasonic inspections the version of API 653 incorporated by\nreference states, “When the corrosion rate is not known, the maximum interval shall be 5 years.\nCorrosion rates may be estimated from tanks in similar service based on thickness measurements\ntaken at an interval not exceeding 5 years.” API 653 goes on to state “When the corrosion rate is\nknown, the maximum interval shall be the smaller of RCA/2N years (where RCA is the\ndifference between the measured shell thickness and the minimum required thickness in mils,\nand N is the shell corrosion rate in mils per year) or 15 years.” According to interviews with\nEnterprise personnel during the inspection and email correspondence from Enterprise, the\noperator did not determine actual corrosion rates or perform a similar service assessment to\nestablish a corrosion rate that would provide the basis allow the ultrasonic corrosion inspection\ninterval to be 15 years. Enterprise has notified PHMSA after the inspection that it was changing\nits ultrasonic inspection intervals to 5 years.\nPertaining to internal breakout tank inspections, Enterprise employs a risk-based inspection\n(RBI) methodology to determine the internal inspection intervals. This is allowed by section\n6.4.3 of the version of API 653 incorporated by reference. However, the analysis methods used\nto determine the product side, soil side, and external corrosion rates and the accuracy of these\nmethods and corrosion rates must be considered in the risk-based methodology. Interviews\nduring the inspection as well as email correspondence from Enterprise did not provide adequate\njustification for the basis of the floor corrosion rates used in the risk-based methodology (from\nactual measurements or similar service) to determine the internal inspection intervals. As an\nexample of the issue, the API 653 inspection report for tank 1003 in Cushing, OK, performed in\nApril-May 2009, states “A new bottom is to be installed (per client). Consideration should be\ngiven to inspecting the new bottom within ten (10) years to establish a corrosion rate (ref. API\n653, Para. 6.4.2.2).” Despite not having a measured corrosion rate for the floor, a documented\nsimilar service assessment, or other justified means for the floor corrosion rates used, Enterprise\nset the internal inspection interval for tank 1003 to 15 years as shown on the Tank Data form\ncompleted by the Operator. According to API 653, section 6.4.3, Alternative Internal Inspection\n3\n\n\n\nInterval, the Operator must consider in an RBI assessment, “c. The methods used for\ndetermination of the shell and bottom plate thickness,” “d. The availability and effectiveness of\nthe inspection methods and quality of the data collected,” and “e. The analysis methods used to\ndetermine the product side, soil side, and external corrosion rates and the accuracy of these\nmethods and corrosion rates.”\n3. 195.432 Inspection of in-service breakout tanks.\n(a) Except for breakout tanks inspected under paragraphs (b) and (c) of this section,\neach operator shall, at intervals not exceeding 15 months, but at least once each calendar\nyear, inspect each in-service breakout tank.\n(b) Each operator must inspect the physical integrity of in-service atmospheric and low-\npressure steel aboveground breakout tanks according to API Standard 653\n(incorporated by reference, see § 195.3). However, if structural conditions prevent access\nto the tank bottom, the bottom integrity may be assessed according to a plan included in\nthe operations and maintenance manual under § 195.402(c)(3).\n(c) Each operator shall inspect the physical integrity of in-service steel aboveground\nbreakout tanks built to API Standard 2510 according to section 6 of API 510.\n(d) The intervals of inspection specified by documents referenced in paragraphs (b) and\n(c) of this section begin on May 3, 1999, or on the operator's last recorded date of the\ninspection, whichever is earlier.\nEnterprise did not make the repairs recommended by the API 653 inspections or did not have\nadequate documentation to show that the Operator evaluated the recommended repairs and made\na determination that the repairs were not needed. For example, notes taken during the inspection\nfrom the review of an API 653 inspection report for tank 1007 at the Enterprise East Cushing,\nOK terminal indicated that there were cracks in the ringwall that needed to be addressed by the\nOperator. Photographs of the ringwall taken during the PHMSA field inspection showed that the\ncracks had not been repaired. No documentation was found in the Operator’s records indicating\nthe ringwall repair recommendations had been evaluated and that a decision made and justified\nthat repairs were not required. Another similar example of unrepaired ringwall cracks was found\nfor tank 1008 during the field inspection. Examples of additional significant inspection findings\ncan be found in the API 653 inspection reports for tank 1008 dated August 2, 2001 and tank\n1009 dated March 6, 2000. Documentation for repair of each of the findings or justification why\nthe repairs were not made was not found in the Enterprise breakout tank files. The field\ninspection could not verify that all of the repairs were made. The Enterprise breakout tank\nrecords must address the API 653 inspection significant findings and document the repairs or\nprovide justification why the repairs were not needed to ensure the safety of the tank.\n4. 195.505 Qualification program.\nEach operator shall have and follow a written qualification program. The program shall\ninclude provisions to:\n4\n\n\n\n(a) Identify covered tasks;\n(b) Ensure through evaluation that individuals performing covered tasks are qualified;\n(c) Allow individuals that are not qualified pursuant to this subpart to perform a covered\ntask if directed and observed by an individual that is qualified;\n(d) Evaluate an individual if the operator has reason to believe that the individual's\nperformance of a covered task contributed to an accident as defined in Part 195;\n(e) Evaluate an individual if the operator has reason to believe that the individual is no\nlonger qualified to perform a covered task;\n(f) Communicate changes that affect covered tasks to individuals performing those covered\ntasks; and\n(g) Identify those covered tasks and the intervals at which evaluation of the individual's\nqualifications is needed.\n(h) After December 16, 2004, provide training, as appropriate, to ensure that individuals\nperforming covered tasks have the necessary knowledge and skills to perform the tasks in a\nmanner that ensures the safe operation of pipeline facilities; and\n(i) After December 16, 2004, notify the Administrator or a state agency participating\nunder 49 U.S.C. Chapter 601 if the operator significantly modifies the program after the\nAdministrator or state agency has verified that it complies with this section.\nDuring a Protocol 9 Operator Qualification inspection an Operator employee was asked to\nperform a routine monthly breakout tank inspection and the technician did not use the prescribed\ninspection checklist during the inspection, had difficulty in recalling specific items to be\nchecked, difficulty in explaining the basis for determining when an issue should be documented,\nand difficulty recalling the specific Abnormal Operating Conditions identified by the operator for\nthe task.\nWarning Items\nWith respect to item(s) 2 through 4 we have reviewed the circumstances and supporting\ndocuments involved in this case and have decided not to conduct additional enforcement action\nor penalty assessment proceedings at this time. We advise you to promptly correct these item(s).\nBe advised that failure to do so may result in Enterprise being subject to additional enforcement\naction.\nProposed Compliance Order\nWith respect to item(s) 1 pursuant to 49 United States Code § 60118, the Pipeline and Hazardous\nMaterials Safety Administration proposes to issue a Compliance Order to Enterprise. Please\nrefer to the Proposed Compliance Order, which is enclosed and made a part of this Notice.\nResponse to this Notice\nEnclosed as part of this Notice is a document entitled Response Options for Pipeline Operators\nin Compliance Proceedings. Please refer to this document and note the response options. Be\nadvised that all material you submit in response to this enforcement action is subject to being\nmade publicly available. If you believe that any portion of your responsive material qualifies for\n5\n\n\n\nconfidential treatment under 5 U.S.C. 552(b), along with the complete original document you\nmust provide a second copy of the document with the portions you believe qualify for\nconfidential treatment redacted and an explanation of why you believe the redacted information\nqualifies for confidential treatment under 5 U.S.C. 552(b). If you do not respond within 30 days\nof receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this\nNotice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in\nthis Notice without further notice to you and to issue a Final Order.\nIn your correspondence on this matter, please refer to CPF 4-2012-5007 and for each document\nyou submit, please provide a copy in electronic format whenever possible.\nSincerely,\nR. M. Seeley\nDirector, Southwest Region\nPipeline and Hazardous Materials Safety Administration\nEnclosures: Proposed Compliance Order\nResponse Options for Pipeline Operators in Compliance Proceedings\n6\n\n\n\nPROPOSED COMPLIANCE ORDER\nPursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety\nAdministration (PHMSA) proposes to issue to Enterprise Crude Pipeline (Enterprise), LLC a\nCompliance Order incorporating the following remedial requirements to ensure the compliance\nof Enterprise with the pipeline safety regulations:\n1. In regard to Item Number 1 of the Notice pertaining to verifying the containment\ndike volume at the East Cushing, OK terminal, Enterprise must provide\ndocumentation to PHMSA in the form of surveys, drawings, and calculations that\nshow the secondary containment after the addition of the most recent tank at the\nEast Cushing, OK terminal complies with the applicable requirements of NFPA\n30, incorporated by reference into Part 195.\n3. Enterprise must complete the required documentation within 90 days of the date\nof the Compliance Order.\n4. It is requested (not mandated) that Enterprise maintain documentation of the\nsafety improvement costs associated with fulfilling this Compliance Order and\nsubmit the total to R. M. Seeley, Director, Southwest Region, Pipeline and\nHazardous Materials Safety Administration. It is requested that these costs be\nreported in two categories: 1) total cost associated with preparation/revision of\nplans, procedures, studies and analyses, and 2) total cost associated with\nreplacements, additions and other changes to pipeline infrastructure.\n7\n\n420125007_Final Order_09282012_text.pdf\n\nSEPTEMBER 28, 2012\nMr. Michael A. Creel\nDirector, President and Chief Executive Officer\nEnterprise Crude Pipelines, LLC\n1100 Louisiana Street\nHouston, TX 77002\nRe: CPF No. 4-2012-5007\nDear Mr. Creel:\nEnclosed please find the Final Order issued in the above-referenced case. It makes a finding of\nviolation and finds that Enterprise Crude Pipelines, LLC has completed the actions specified in\nthe Notice to comply with the pipeline safety regulations. Therefore, this case is now closed.\nService of the Final Order by certified mail is deemed effective upon the date of mailing, or as\notherwise provided 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. Rodrick M. Seeley, Director, Southwest Region, OPS\nMr. Kevin Bodenhamer, Enterprise Crude Pipelines, LLC, 1100 Louisiana Street\nHouston, TX 77002\nMr. Alan Mayberry, Deputy Associate Administrator for Field Operations, OPS\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\n\n\n\nU.S. DEPARTMENT OF TRANSPORTATION\nPIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION\nOFFICE OF PIPELINE SAFETY\nWASHINGTON, D.C. 20590\n____________________________________\n)\nIn the Matter of )\n)\nEnterprise Crude Pipelines, LLC, ) CPF No. 4-2012-5007\n)\nRespondent. )\n____________________________________)\nFINAL ORDER\nOn April 11-15, 2011, pursuant to 49 U.S.C. § 60117, a representative of the Pipeline and\nHazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS),\nconducted an on-site pipeline safety inspection of the facilities and records of Enterprise Crude\nPipelines, LLC’s (Enterprise or Respondent) East Cushing Terminal in Cushing, Oklahoma.\nEnterprise Crude Pipelines is a subsidiary of Enterprise Products Partners L.P. whose system\nconsists of approximately 4,700 miles of crude oil pipelines and 11 million barrels of crude oil\nstorage.\nAs a result of the inspection, the Director, Southwest Region, OPS (Director), issued to\nRespondent, by letter dated March 12, 2012, a Notice of Probable Violation and Proposed\nCompliance Order (Notice), which also included a warning pursuant to 49 C.F.R. § 190.205. In\naccordance with 49 C.F.R. § 190.207, the Notice proposed finding that Enterprise violated\n49 C.F.R. § 195.264 and proposed ordering Respondent to take certain measures to correct the\nalleged violation. The warning items required no further action, but warned the operator to\ncorrect the probable violations or face possible enforcement action.\nEnterprise responded to the Notice by letter dated April 26, 2012 (Response). The company did\nnot contest the allegation of violation but provided information concerning corrective actions it\nhas taken in response to the Notice. Respondent did not request a hearing and therefore has\nwaived its right to one.\nFINDING OF VIOLATION\nIn its Response, Enterprise did not contest the allegation in the Notice that it violated 49 C.F.R.\nPart 195, as follows:\nItem 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.264, which states in\nrelevant part:\n\n\n\n2\n§ 195.264 Impoundment, protection against entry, normal/emergency venting or\npressure/vacuum relief for aboveground breakout tanks.\n(a) A means must be provided for containing hazardous liquids in the\nevent of spillage or failure of an aboveground breakout tank.\n(b) After October 2, 2000, compliance with paragraph (a) of this\nsection requires the following for the aboveground breakout tanks\nspecified:\n(1) For tanks built to API Specification 12F, API Standard 620, and\nothers (such as API Standard 650 or its predecessor Standard 12C), the\ninstallation of impoundment must be in accordance with the following\nsections of NFPA 30:\n(i) Impoundment around a breakout tank must be installed in\naccordance with section 4.3.2.3.2; and\n(ii) Impoundment by drainage to a remote impounding area must be\ninstalled in accordance with section 4.3.2.3.1.\n(2) For tanks built to API 2510, the installation of impoundment must\nbe in accordance with section 5 or 11 of API 2510 (incorporated by\nreference, see § 195.3).\nThe Notice alleged that Respondent violated 49 C.F.R. § 195.264 by failing to provide a means\nfor containing hazardous liquids in the event of a spillage or failure of an aboveground breakout\ntank, as required by the applicable NFPA 30 requirements. Specifically, the Notice alleged that\nEnterprise was unable to provide either surveys or calculations demonstrating that the\ncontainment dike volume at the East Cushing Terminal was established according to NFPA 30.\nEnterprise constructed the additional breakout tanks as recently as 2006, but was unable to\nprovide documentation establishing that the impoundment around the tanks was installed in\naccordance with NFPA 30.\nRespondent did not contest this allegation of violation, but provided further information\nregarding actions taken after receiving the Notice.\nAccordingly, based upon a review of all of the evidence, I find that Respondent violated\n49 C.F.R. § 195.264 by failing to install impoundment around its breakout tanks according to\nNFPA 30.\nThis finding of violation will be considered a prior offense in any subsequent enforcement action\ntaken against Respondent.\nCOMPLIANCE ORDER\nThe Notice proposed a compliance order with respect to Item 1 in the Notice for violation of\n49 C.F.R. § 195.264. Under 49 U.S.C. § 60118(a), each person who engages in the\ntransportation of hazardous liquids or who owns or operates a pipeline facility is required to\ncomply with the applicable safety standards established under chapter 601. The Director\nindicates that Respondent has taken the following actions specified in the proposed compliance\norder:\n\n\n\n3\n1. With respect to the violation of § 195.264 (Item 1), Respondent has provided\ndocumentation, including secondary containment diagrams demonstrating the\nsecondary containment after addition of the most recent tank at Enterprise’s East\nCushing, Oklahoma terminal. The current survey confirms compliance with the\napplicable requirements of NFPA 30, incorporated by reference into Part 195.\nAccordingly, I find that compliance has been achieved with respect to this violation. Therefore,\nthe compliance terms proposed in the Notice are not included in this Order.\nWARNING ITEMS\nWith respect to Items 2, 3 and 4, the Notice alleged probable violations of Part 195 but did not\npropose a civil penalty or compliance order for these items. Therefore, these are considered to\nbe warning items. The warnings were for:\n49 C.F.R. § 195.432 (Item 2) ─ Respondent’s alleged failure to inspect in-\nservice breakout tanks in accordance with the requirements of § 195.432(a)-(d);\n49 C.F.R. § 195.432 (Item 3) ─ Respondent’s alleged failure to make repairs\nrecommended by API 653 inspections or have adequate documentation to\ndemonstrate that the operator evaluated such repairs and determined that they\nwere not necessary; and\n49 C.F.R. § 195.505 (Item 4) ─ Respondent’s alleged failure to have and follow a\nwritten qualification program with provisions to ensure through evaluation that\nindividuals performing covered tasks are qualified.\nEnterprise presented information in its Response showing that it took certain actions to address\nthe cited items and providing certain documentation that was not submitted prior to issuance of\nthe Notice. If OPS finds a violation of any of these items, Respondent may be subject to future\nenforcement action.\nThe terms and conditions of this Final Order are effective upon service in accordance with\n49 C.F.R. § 190.5.\n___________________________________ __________________________\nJeffrey D. Wiese Date Issued\nAssociate Administrator\nfor Pipeline Safety","truncated":false,"body_characters":25542}