{"operation":"document","citation":"CPF 520071010M","title":"CHEVRON PIPE LINE CO — Notice of Amendment","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2007-07-09","effective_on":null,"summary":"CLOSED notice of amendment citing 192.905(a), 192.905(c), 192.911(k), 192.917(a), 192.917(b), 192.917(c), 192.917(e)(5), 192.921(a)(4), 192.933(a), 192.933(c), 192.933(d)(1), 192.933(d)(3), 192.935(a).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-520071010m.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-520071010m.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-520071010m","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/520071010M","body":"Notice of Amendment involving CHEVRON PIPE LINE CO. PHMSA's enforcement data identifies the cited regulations as 192.905(a),  192.905(c),  192.911(k),  192.917(a),  192.917(b),  192.917(c),  192.917(e)(5),  192.921(a)(4),  192.933(a),  192.933(c),  192.933(d)(1),  192.933(d)(3),  192.935(a). The case was opened on 2007-07-09 and is reported as closed as of 2007-11-02. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n520071010M_notice of amendment_07092007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520071010M/520071010M_notice%20of%20amendment_07092007.pdf\n\n520071010m_notice of amendment_07092007_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520071010M/520071010m_notice%20of%20amendment_07092007_text.pdf\n\n520071010M_operator response to notice_09122007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520071010M/520071010M_operator%20response%20to%20notice_09122007.pdf\n\n520071010m_notice of amendment_07092007_text.pdf\n\no\nU. S. Department\nof Transportation\nPipeline and\nHazardous Materials Safety\nAdministration\nSENT TO COlv1PLIANCE REGISTR\nHardcopy Electronica y\n0 of Copies~i Date & 7\n12300 W Dakota Ave, Suite 110\nLakewood, CO 80228\nNOTICE OF AMENDMENT\nCERTIFIED MAIL - RETURN RECEIPT RE UESTED\nJuly 9, 2007\nMs. Rebecca B. Roberts\nPresident\nChevron Pipe Line Company\n4800 Fournace Place\nBellaire, TX 77401\nCPF 5-2007-1010M\nDear Ms. Roberts:\nBetween September 11-15 and September 25 — 29, 2006, a representative of the Pipeline and\nHazardous Materials Safety Administration (PHMSA), pursuant to Chapter 601 of Title 49\nUnited States Code, inspected your Integrity Management (IM) Program in Bellaire, Texas.\nOn the basis of the inspection, PHMSA identified apparent inadequacies within Chevron Pipe\nLine Company's (CPL's) Integrity Management Program; these procedural inadequacies are\ndescribed below. Probable violations resulting from that same inspection were already sent to\nyou in our letter, CPF 5-2007-1007, dated June 11, 2007.\n1. Identification of High Consequence Areas\n$192. 911 What are the elements of an integrity management program?\n(a) An identification of all high consequence areas, in accordance with $192. 905.\n(p) A process for identification and assessment of newly-identified high consequence\nareas. (See $192. 905 and $192. 921. )\n$192. 905 How does an operator identify a high consequence area?\n(a) General. To determine which segments of an operator's transmission pipeline\nsystem are covered by this subpart, an operator must identify the high consequence\nareas. An operator must use method (1) or (2) from the definition in $192. 903 to\nidentify a high consequence area. An operator may apply one method to its entire\n\n\n\npipeline system, or an operator may apply one method to individual portions of the\npipeline system. An operator must describe in its integrity management program\nwhich method it is applying to each portion of the operator's pipeline system. The\ndescription must include the potential impact radius when utilized to establish a high\nconsequence area. (See appendix E. I. for guidance on identifying high consequence\nareas. )\n(b) Identified sites. An operator must identify an identified site, for purposes of this\nsubpart, from information the operator has obtained from routine operation and\nmaintenance activities and from public officials with safety or emergency response or\nplanning responsibilities who indicate to the operator that they know of locations that\nmeet the identified site criteria. These public officials could include officials on a local\nemergency planning commission or relevant Native American tribal officials.\n(c) Newly identified areas. When an operator has information that the area around a\npipeline segment not previously identified as a high consequence area could satisfy any\nof the definitions in $192. 903, the operator must complete the evaluation using method\n(1) or (2). If the segment is determined to meet the definition as a high consequence\narea, it must be incorporated into the operator's baseline assessment plan as a high\nconsequence area within one year from the date the area is identified.\n~ Item 1A: $192. 911(a) and $192. 905(a)\nCPL's processes for implementing method I and 2 to identify High Consequence Areas\n(HCAs) lack sufficient guidance regarding how and when its personnel evaluate potential\n\"identified sites, \" utilize existing class location information, and determine building counts\nwithin potential impact radii.\n~ Item 1B: $192. 911(a) and $192. 905(c)\nCPL's processes do not contain adequate details regarding how and when its personnel will\ngather new data and information which may identify newly covered segments. In addition,\nCPL procedures do not describe how its personnel will identify construction in the vicinity\nof the pipeline that results in newly occupied buildings changes in the use of existing\nbuildings (e. g. ,\n\"identified sites. \"\nhotel or house converted to nursing home), or the creation of other\n2. Baseline Assessment Plan\n$192. 911 What are the elements of an integrity management program?\n(b) A baseline assessment plan meeting the requirements of $192. 919 and $192. 921.\n$192. 921(a)(4) Other technology that an operator demonstrates can provide an\nequivalent understanding of the condition of the line pipe. An operator choosing this\noption must notify the Office of Pipeline Safety (OPS) 180 days before conducting the\nassessment, in accordance with $192. 949. An operator must also notify a State or local\npipeline safety authority when either a covered segment is located in a State where\nOPS has an interstate agent agreement, or an intrastate covered segment is regulated\nby that State.\n\n\n\n~ Item 2A: $192. 911(b) and $192. 921(a)(4)\nCPL's procedures provide for the potential use of an Electro-Magnetic Acoustic Transducer\n(EMAT) In-Line Inspection (ILI) tool. This tool is not included within the ILI tools\ncurrently listed in B31. 8S. CPL must ensure its processes provide for notification to\nPHMSA regarding use of \"other technology\" such as the EMAT-based ILI tooI.\n3. Identify Threats, Data Integration, and Risk Assessment\n$192. 911 What are the elements of an integrity management program?\n(c) An identification of threats to each covered pipeline segment, which must include\ndata integration and a risk assessment. An operator must use the threat identification\nand risk assessment to prioritize covered segments for assessment ($192. 917) and to\nevaluate the merits of additional preventive and mitigative measures ($192. 935) for\neach covered segment.\n$192. 917 How does an operator identify potential threats to pipeline integrity and use\nthe threat identification in its integrity program?\n(a) Threat identification. An operator must identify and evaluate all potential threats\nto each covered pipeline segment. Potential threats that an operator must consider\ninclude, but are not limited to, the threats listed in ASME/ANSI B31. 8S (ibr, see\n$192. 7), section 2, which are as follows:\n(1) Time dependent threats such as internal corrosion, external corrosion, and stress\ncorrosion cracking;\n(2) Static or resident threats, such as fabrication or construction defects;\n(3) Time independent threats such as third party damage and outside force damage;\nand\n(4) Human error.\n(b) Data gathering and integration. To identify and evaluate the potential threats to a\ncovered pipeline segment, an operator must gather and integrate existing data and\ninformation on the entire pipeline that could be relevant to the covered segment. In\nperforming this data gathering and integration, an operator must follow the\nrequirements in ASME/ANSI B31. 8S, section 4. At a minimum, an operator must\ngather and evaluate the set of data specified in Appendix A to ASME/ANSI B31. 8S,\nand consider both on the covered segment and similar non-covered segments, past\nincident history, corrosion control records, continuing surveillance records, patrolling\nrecords, maintenance history, internal inspection records and all other conditions\nspecific to each pipeline.\n(c) Risk assessment. An operator must conduct a risk assessment that follows\nASME/ANSI B31. 8S, section 5, and considers the identified threats for each covered\nsegment. An operator must use the risk assessment to prioritize the covered segments\nfor the baseline and continual reassessments (g)192. 919, 192. 921, 192. 937), and to\ndetermine what additional preventive and mitigative measures are needed ($192. 935)\nfor the covered segment.\n$192. 917(e)(5) Corrosion. If an operator identifies corrosion on a covered pipeline\nsegment that could adversely affect the integrity of the line (conditions specified in\n$192. 933), the operator must evaluate and remediate, as necessary, all pipeline\n\n\n\nsegments (both covered and non- covered) with similar material coating and\nenvironmental characteristics. An operator must establish a schedule for evaluating\nand remediating, as necessary, the similar segments that is consistent with the\noperator's established operating and maintenance procedures under part 192 for\ntesting and repair.\n~ Item 3A: $192. 911(c) and $192. 917(a)\nThe original risk analysis used to support CPL's baseline assessment prioritization did not\naddress all of the threat categories specified in the IM rule and ASME B31. 8S-2001\nSpecifically, the original program risk manual did not address incorrect operations and\nequipment failures CPL's latest risk model includes these threats; however, at the time of\nthe inspection CPL had not developed risk results based on this new approach.\n~ Item 3B: $192. 911(c) and $192. 917(b)\nCPL procedure did not require all of the data sets to be assembled and evaluated for threat\nidentification and risk assessment as required by ASME B31. 8S-2001, Sections 4 2, 4. 3, 4. 4,\nand Appendix A (summarized in ASME B31. 8S-2001, Table 1). In part, CPL did not\nconsider the following on covered segments and similar non-covered segments:\n~ Past incident history\n~ Corrosion control records\n~ Continuing surveillance records\nPatrolling records\n~ Item 3C: $192. 911(c) and $192. 917(c)\nThe treatment of incident/leak data in the risk analysis process is not appropriate for\nassessing risk on covered segments. Incident/leak data are applied only in the risk scoring of\nthe segment containing the precise location of the leak or incident. The potential\napplicability of the leak/incident to other segments with similar characteristics is not\nconsidered\n~ Item 3D: $192. 911(c) and $192. 917(e)(5)\nCPL's IM program manual and procedures did not include methods to determine what may\nconstitute similar pipe segments, or requirements to establish a schedule for evaluating\nsimilar non-covered and covered segments should corrosion detrimental to the integrity of a\ncovered segment be discovered.\n4. Remediation\n$192. 911 What are the elements of an integrity management program?\n(e) Provisions meeting the requirements of $192. 933 for remediating conditions found\nduring an integrity assessment.\n\n\n\n)192. 933(a) General requirements. An operator must take prompt action to address\nall anomalous conditions that the operator discovers through the integrity assessment.\nIn addressing all conditions, an operator must evaluate all anomalous conditions and\nremediate those that could reduce a pipeline's integrity. An operator must be able to\ndemonstrate that the remediation of the condition will ensure that the condition is\nunlikely to pose a threat to the integrity of the pipeline until the next reassessment of\nthe covered segment. If an operator is unable to respond within the time limits for\ncertain conditions specified in this section, the operator must temporarily reduce the\noperating pressure of the pipeline or take other action that ensures the safety of the\ncovered segment. If pressure is reduced, an operator must determine the temporary\nreduction in operating pressure using ASME/ANSI 831G (ibr, see )192. 7) or AGA\nPipeline Research Committee Project PR-3-S05 (\"RSTRENG\"; ibr, see $192. 7) or\nreduce the operating pressure to a level not exceeding S0% of the level at the time the\ncondition was discovered. (See appendix A to this part 192 for information on\navailability of incorporation by reference information). A reduction in operating\npressure cannot exceed 365 days without an operator providing a technical\njustification that the continued pressure restriction will not jeopardize the integrity of\nthe pipeline.\n$192. 933(b) Discovery of condition. Discovery of a condition occurs when an operator\nhas adequate information about a condition to determine that the condition presents a\npotential threat to the integrity of the pipeline. A condition that presents a potential\nthreat includes, but is not limited to, those conditions that require remediation or\nmonitoring listed under paragraphs (d)(1) through (d)(3) of this section. An operator\nmust promptly, but no later than 1SO days after conducting an integrity assessment,\nobtain sufficient information about a condition to make that determination, unless the\noperator demonstrates that the 1SO-day period is impracticable.\n)192. 933(c) Schedule for evaluation and remediation. An operator must complete\nremediation of a condition according to a schedule that prioritizes the conditions for\nevaluation and remediation. Unless a special requirement for remediating certain\nconditions applies, as provided in paragraph (d) of this section, an operator must\nfollow the schedule in ASME/ANSI B31. SS (ibr, see $192. 7), section 7, Figure 4. If an\noperator cannot meet the schedule for any condition, the operator must justify the\nreasons why it cannot meet the schedule and that the changed schedule will not\njeopardize public safety. An operator must notify OPS in accordance with )192. 949 if\nit cannot meet the schedule and cannot provide safety through a temporary reduction\nin operating pressure or other action. An operator must also notify a State or local\npipeline safety authority when either a covered segment is located in a State where\nOPS has an interstate agent agreement, or an intrastate covered segment is regulated\nby that State.\n$192. 933(d) Special requirements for scheduling remediation.\n1. Immediate repair conditions. An operator's evaluation and remediation schedule\nmust follow ASME/ANSI B31. SS, Section 7 in providing for immediate repair\nconditions. To maintain safety, an operator must temporarily reduce operating\npressure in accordance with paragraph (a) of this section or shut down the pipeline\n\n\n\nuntil the operator completes the repair of these conditions. An operator must treat the\nfollowing conditions as immediate repair conditions:\ni. A calculation of the remaining strength of the pipe shows a predicted failure\npressure less than or equal to 1. 1 times the maximum allowable operating pressure at\nthe location of the anomaly. Suitable remaining strength calculation methods include,\nASME/ANSI B31G (\" Manual for Determining the Remaining Strength of Corroded\nPipelines\" (1991); AGA Pipeline Research Committee Project PR-3-805 (\"A Modified\nCriterion for Evaluating the Remaining Strength of Corroded Pipe\" (December\n1989)); or an alternative equivalent method of remaining strength calculation. These\ndocuments are incorporated by reference and available at the addresses listed in\nAppendix A to Part 192.\nii. A dent that has any indication of metal loss, cracking or a stress riser.\niii. An indication or anomaly that in the judgment of the person designated by the\noperator to evaluate the assessment results requires immediate action. (1)(ii) A dent\nthat has any indication of metal loss, cracking or a stress riser.\n3. Monitored conditions. An operator does not have to schedule the following\nconditions for remediation, but must record and monitor the conditions during\nsubsequent risk assessments and integrity assessments for any change that may require\nremediation:\ni. A dent with a depth greater than 6'/o of the pipeline diameter (greater than 0. 50\ninches in depth for a pipeline diameter less than NPS 12) located between the 4 o' clock\nposition and the 8 o' clock position (bottom 1/3 of the pipe).\nii. A dent located between the 8 o' clock and 4 o' clock positions (upper 2/3 of the pipe)\nwith a depth greater than 6'/o of the pipeline diameter (greater than 0. 50 inches in\ndepth for a pipeline diameter less than Nominal Pipe Size (NPS) 12), and engineering\nanalyses of the dent demonstrate critical strain levels are not exceeded.\niii. A dent with a depth greater than 2'/0 of the pipeline's diameter (0. 250 inches in\ndepth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth\nweld or a longitudinal seam weld, and engineering analyses of the dent and girth or\nseam weld demonstrate critical strain levels are not exceeded. These analyses must\nconsider weld properties.\n~ Item 4A: $192. 911(e) and $192. 933(d)(1)\nThe CPL IM program specifies that a pressure reduction shall be implemented for pipeline\nsegments with an immediate repair condition. However, the program document does not\nstate that the pressure be reduced, or the line be shut down, as soon as practicable once an\nimmediate repair condition is identified. \"As soon as practicable\" means as soon as pressure\ncan be safety reduced, and without undue delay.\n~ Item 4B: $192. 911(e) and $192. 933(d)(3)\nThe IM program requirements addressing \"monitored conditions\" do not have sufficient\ndetail to explain how these conditions are tracked and monitored during subsequent risk or\nintegrity assessments for any changes in their status that would require remediation. In\naddition, process does not define when these conditions are re-reviewed.\n\n\n\n~ Item 4C: $192. 911(e) and $192. 933(a)\nThe IM program document does not state that when calculating the needed pressure\nreduction under ASME B31. 6 or \"RSTRENG\" that the pressure must be lowered to the\ncalculated \"safe pressure\" (Psafe or P failure with the use of the appropriate safety factor).\n~ Item 4D: $192. 911(e) and $192. 933(c)\nThe CPL IM program document does not include a requirement that for any time a\nremediation schedule requirement cannot be met, the operator must document the reasons\nfor the delay and why the delay does not jeopardize pubic safety.\n5. Preventive and Mitigative Measures\n$192. 911 What are the elements of an integrity management program?\n(h) Provisions meeting the requirements of $192. 935 for adding preventive and\nmitigative measures to protect the high consequence area.\n$192. 93S What additional preventive and mitigative measures must an operator take?\n(a) General requirements. An operator must take additional measures beyond those\nalready required by Part 192 to prevent a pipeline failure and to mitigate the\nconsequences of a pipeline failure in a high consequence area. An operator must base\nthe additional measures on the threats the operator has identified to each pipeline\nsegment. (See $192. 917) An operator must conduct, in accordance with one of the risk\nassessment approaches in ASME/ANSI B31. 8S (ibr, see $192. 7), section 5, a risk\nanalysis of its pipeline to identify additional measures to protect the high consequence\narea and enhance public safety. Such additional measures include, but are not limited\nto, installing Automatic Shut-off Valves or Remote Control Valves, installing\ncomputerized monitoring and leak detection systems, replacing pipe segments with\npipe of heavier wall thickness, providing additional training to personnel on response\nprocedures, conducting drills with local emergency responders and implementing\nadditional inspection and maintenance programs.\n~ Item 5A: $192. 911(h) and $192. 935(a)\nCPL's IM program does not mclude a systematic, documented decision-making process to\ndetermine which preventive and mitigative measures are to be implemented. The current IM\nprogram describes how CPL's personnel complete the PTRAP process, however, the\nprocedure does not adequately describe the process details regarding:\n~ How or when pre and post assessment evaluations occur;\n~ How personnel use a risk analysis to evaluate potential preventive and mitigative\nmeasures;\n~ How the results of the decision-making process are documented, and\nWhat requirements and/or guidelines apply to the development of an implementation\nschedule.\n\n\n\n6. Management of Change\n$192. 911 What are the elements of an integrity management program?\n(k) A management of change process as outlined in ASME/ANSI B31. 8S, section 11.\n$192. 909(b) Notification. An operator must notify OPS, in accordance with $192;949,\nof any change to the program that may substantially affect the program's\nimplementation or may significantly modify the program or schedule for carrying out\nthe program elements. An operator must also notify a State or local pipeline safety\nauthority when either a covered segment is located in a State where OPS has an\ninterstate agent agreement, or an intrastate covered segment is regulated by that State.\nAn operator must provide the notification within 30 days after adopting this type of\nchange into its program.\nASME B31. 8S-2001, Section 11\n(a) Formal management of change procedures shall be developed in order to identify\nand consider the impact of changes to pipeline systems and their integrity. These\nprocedures should be flexible enough to accommodate both major and minor changes,\nand must be understood by the personnel that use them. Management of change shall\naddress technical, physical, procedural and organizational changes to the system\nwhether permanent or temporary. The process should incorporate planning for each\nof these situations and consider the unique circumstances of each.\nA management of change process includes the following:\n(1) Reason for change\n(2) Authority for approving changes\n(3) Analysis of implications\n(4) Acquisition of required work permits\n(5) Documentation\n(6) Communication of change to affected parties\n(7) Time limitations\n(8) Qualification of staff\n(b) The operator shall recognize that system changes can require changes in the\nintegrity management program and conversely, results from the program can cause\nsystem changes. The following are examples that are gas pipeline specific but are by\nno means all inclusive. . .\n~ Item 6A: $192. 911(k) and ASME B31. 8S-2001, Section 11(b)\nThe CPL IM program did not include measures to ensure that new information/data is\nincorporated into the risk analysis process in a timely and effective manner\n~ Item 6B: $192. 911(k) and ASME B31. 8S-2001, Section 11(a)\nCPL's IM program requires notifications to PHMSA and State/local pipeline safety\nauthorities when significant changes are made to its IM program or program\n-8-\n\n\n\nimplementation. However, the IM program does not provide any guidance regarding what is\nconsidered significant\nRes onse to this Notice\nThis Notice is provided pursuant to 49 U. S. C. $ 60108(a) and 49 C. F. R. $ 190. 237. Enclosed as\npart of this Notice is a document entitled Response Options for Pipeline Operators tn\nCompliance 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\nfor confidential treatment under 5 U. S. C. 552(b), along with the complete original document\nyou must 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.\nIf, after opportunity for a hearing, your plans or procedures are found inadequate as alleged in\nthis Notice, you may be ordered to amend your plans or procedures to correct the inadequacies\n(49 C. F. R, $ 190. 237). If you are not contesting this Notice, we propose that you submit your\namended procedures to my office within 30 days of receipt of this Notice. This period may be\nextended by written request for good cause. Once the inadequacies identified herein have been\naddressed in your amended procedures, this enforcement action will be closed.\nIn correspondence concerning this matter, please refer to CPF 5-2007-1010M and, for each\ndocument you submit, please provide a copy in electronic format whenever possible.\nSincerely\nC ' o'\nDirector, Western Region\nPipeline and Hazardous Materials Safety Administration\nEnclosure: Response Options for Pipeline Operators in Compliance Proceedings\ncc: PHP-60 Compliance Registry\nPHP-500 J. Gilliam (¹116459)","truncated":false,"body_characters":24942}