{"operation":"document","citation":"CPF 520080009M","title":"ENSTAR NATURAL GAS CO — Notice of Amendment","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2008-04-23","effective_on":null,"summary":"CLOSED notice of amendment citing 192.7(a), 192.907, 192.907(a), 192.911, 192.911(i), 192.911(k), 192.911(m), 192.915, 192.915(a), 192.915(b), 192.915(c), 192.917, 192.917(e)(1), 192.919, 192.919(c), 192.923, 192.925(b), 192.925(b)(1), 192.925(b)(2), 192.925(b)(3), 192.933, 192.933(a), 192.933(b), 192.933(c), 192.933(d), 192.935(a), 192.937(a), 192.939, 192.945, 192.945(a), 192.945(b).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-520080009m.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-520080009m.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-520080009m","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/520080009M","body":"Notice of Amendment involving ENSTAR NATURAL GAS CO. PHMSA's enforcement data identifies the cited regulations as 192.7(a),  192.907,  192.907(a),  192.911,  192.911(i),  192.911(k),  192.911(m),  192.915,  192.915(a),  192.915(b),  192.915(c),  192.917,  192.917(e)(1),  192.919,  192.919(c),  192.923,  192.925(b),  192.925(b)(1),  192.925(b)(2),  192.925(b)(3),  192.933,  192.933(a),  192.933(b),  192.933(c),  192.933(d),  192.935(a),  192.937(a),  192.939,  192.945,  192.945(a),  192.945(b). The case was opened on 2008-04-23 and is reported as closed as of 2008-07-23. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n520071009M_operator response_07102007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520080009M/520071009M_operator%20response_07102007.pdf\n\n520080009M_notice of amendment_04232008.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520080009M/520080009M_notice%20of%20amendment_04232008.pdf\n\n520080009m_notice of amendment_04232008_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520080009M/520080009m_notice%20of%20amendment_04232008_text.pdf\n\n520080009M_operator response to notice_05212008.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520080009M/520080009M_operator%20response%20to%20notice_05212008.pdf\n\n520080009m_notice of amendment_04232008_text.pdf\n\nU. S. Department\nof Transportation\nPipeline and\nHazardous Materials Safety\nAdministration\n12300 W Dakota Ave, Suite 110\nLakewood, CO 80228\nNOTICE OF AMENDMENT\nCERTIFIED MAIL - RETURN RECEIPT RE UESTED\nApril 23, 2008\nMr John Lau\nDirector, Transmission Operations\nAlaska Pipehne Company\n401 E. International Airport Road\nP. O Box 190288\nAnchorage, AK 99519-0288\nCPF 5-2008-0009M\nDear Mr. Lau\nOn May 7-11, 2007, representatives of the Pipehne and Hazardous Materials Safety\nAdmmistration (PHMSA), pursuant to Chapter 601 of 49 United States Code, mspected your\nintegrity management program in Anchorage, Alaska.\nAs a result of the inspection, it appears that your wntten procedures are madequate to assure safe\noperation of the pipeline as follows:\ng 192. 905 How does an operator identify a high consequence area?\n(b)(1) 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.\ng 192. 907 What must an operator do to implement this subpart?\n\n\n\n(a) General. No later than December 17, 2004, an operator of a covered pipeline\nsegment must develop and follow a written integrity management program that\ncontains all the elements described in g 192. 911 and that addresses the risks on each\ncovered transmission pipeline segment.\n1 a) Alaska Pipehne Company (APC) does not provide adequate procedures for the\ndocumentation of field verification of identified sites. As an example, AS&G offices in\nArea A7 were excluded as an identified site m 2004, but included as an identified site in\n2006 The annual review for 2005 stated that the identified sites were verified\" but there\nis no mdication of the depth of that verification process In addition, field data varies m its\ndepth based primarily on the personnel performmg the venfication\nlb) APC documents the defimtions of identified sites and the methods for their\nidentification m a memorandum that is not referenced by its procedures or program\ndocument,\ng 192. 911 'What are the elements of an integrity management program?\nAn operator's initial integrity management program begins with a framework (see $\n192. 907) and evolves into a more detailed and comprehensive integrity management\nprogram, as information is gained and incorporated into the program. An operator\nmust make continual improvements to its program. The initial program framework\nand subsequent program must, at minimum, contain the following elements. (When\nindicated, refer to ASME/ANSI B31. 8S (ibr, see g 192. 7) for more detailed\ninformation on the listed element. )\n(k) A management of change process as outlined in ASME/ANSI B31. 8S, section 11.\ng 192. 919 What must be in the baseline assessment plan?\nAn operator must include each of the following elements in its written baseline\nassessment plan:\n(c) A schedule for completing the integrity assessment of all covered segments,\nincluding risk factors considered in establishing the assessment schedule;\n2a) The APC process for developmg the BAP does not provide requirements for keepmg\nthe BAP up-to-date with respect to newly arismg information, apphcable threats, and risks\nthat may require changes to the segment prioritization or assessment method\ng 192. 907 What must an operator do to implement this subpart?\n(a) General. No later than December 17, 2004, an operator of a covered pipeline\nsegment must develop and follow a written integrity management program that\ncontains aB the elements described in g 192, . 911 and that addresses the risers on each\ncovered transmission pipeline segment.\n\n\n\n(b) Implementation Standards. In carrying out this subpart, an operator must follow\nthe requirements of this subpart and of ASME/ANSI B31. 8S (ibr, see $ 192. 7) and its\nappendices, where specified. An operator may follow an equivalent standard or\npractice only when the operator demonstrates the alternative standard or practice\nprovides an equivalent level of safety to the public and property. In the event of a\nconflict between this subpart and ASMK/ANSI B31. 8S, the requirements in this\nsubpart control.\ng 192. 917 How does an operator identify potential threats to pipeline integrity and\nuse the 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 ASMK/ANSI B31. 8S (ibr, see g\n192. 7), section 2, which are grouped under the following four categories: (1) Time\ndependent threats such as internal corrosion, external corrosion, and stress corrosion\ncracking; (2) Static or resident threats, such as fabrication or construction defects; (3)\nTime independent threats such as third party damage and outside force damage; and\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 ASMK/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,\npatrolling records, maintenance history, internal inspection records and all other\nconditions specific 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 (gg 192. 919, 192. 921, 192. 937), and to\ndetermine what additional preventive and mitigative measures are needed (g 192. 935)\nfor the covered segment.\n3a) There are no procedures to require documentmg the threat analysis performed by APC\nNo documented basis exists for the exclusion of cychc fatigue or other threats, and no\nevaluation is provided for apphcable threats.\n3b) APC has not used a conservative approach m its data analysis regardmg the fact that\nthere is an absence of records to demonstrate that pre-1970 piping is not low frequency\nERW pipmg\n3c) There are madequate procedures to ensure that the APC risk assessment supports the\nob]ectives identified in Sections 5. 3 and 5. 4 of ASME B32. 8S-2001\n\n\n\n3d) The APC IMP does not have a documented process for vahdatmg &ts nsk assessment\n4. g 192. 917 How does an operator identify potential threats to pipeline integrity and\nuse the threat identification in its integrity program?\n(e) Actions to address particuLar threats. If an operator identifies any of the following\nthreats, the operator must take the following actions to address the threat. (1) Third\nparty damage. An operator must utilize the data integration required in paragraph (b)\nof this section and ASME/ ANSI B31. 8S, Appendix A7 to determine the susceptibility\nof each covered segment to the threat of third party damage. If an operator identifies\nthe threat of third party damage, the operator must implement comprehensive\nadditional preventive measures in accordance with $192. 935 and monitor the\neffectiveness of the preventive measures. If, in conducting a baseline assessment\nunder $192. 921, or a reassessment under )192. 937, an operator uses an internal\ninspection tool or external\ng 192. 923 How is direct assessment used and for what threats?\n(a) General. An operator may use direct assessment either as a primary assessment\nmethod or as a supplement to the other assessment methods allowed under this\nsubpart. An operator may only use direct assessment as the primary assessment\nmethod to address the identified threats of external corrosion (ECDA), internal\ncorrosion (ICDA), and stress corrosion cracking (SCCDA). (b) Primary method. An\noperator using direct assessment as a primary assessment method must have a plan\nthat complies with the requirements in — (1) ASME/ANSI B31. 8S (ibr, see $192. 7),\nsection 6. 4; NACE RP0502 — 2002 (ibr, see g 192. 7); and g 192. 925 if addressing\nexternal corrosion (ECDA).\ng 192. 925 'What are the requirements for using External Corrosion Direct Assessment\n(ECDA)?\n(b) General requirements. An operator that uses direct assessment to assess the threat\nof external corrosion must follow the requirements in this section, in ASME/ANSI\nB31. 8S (ibr, see g 192. 7), section 6. 4, and in NACE RP 0502 — 2002 (ibr, see g 192. 7).\nAn operator must develop and implement a direct assessment plan that has\nprocedures addressing preassessment, indirect examination, direct examination, and\npost-assessment. If the ECDA detects pipeline coating damage, the operator must also\nintegrate the data from the ECDA with other information from the data integration\n(g 192. 917(b)) to evaluate the covered segment for the threat of third party damage,\nand to address the threat as required by g 192. 917(e)(1).\n(1) Preassessment. In addition to the requirements in ASME/ANSI B31. 8S section 6. 4\nand NACE RP 0502 — 2002, section 3, the plan's procedures for preassessment must\ninclude—\n(i) Provisions for applying more restrictive criteria when conducting ECDA for the\nfirst time on a covered segment.\n\n\n\n(\") h b\nii The basis on w ic an o\nh' h an operator selects at least two different, but complementary\nindirect assessment tools to assess each ECDA Reg' . p\ne ion. If an o erator utilizes an\nindirect ins ection method that is not discussed in Appendix A of NACE RP0502—\n2002, the operator must demonstrate the applica i i y, va i a i\n' '\nused, application proce ure, an u\nd d tilization of data for the inspection method.\n(2) Indirect Examination. In addition to the requiremen irements in ASME/ANSI B31. 8S\nsection 6. 4 and NACE RP 0502 — 2002, section 4, the plan's procedures for indirect\nexamination of the ECDA regions must include—\n(i) Provisions for applying more restrictive criteria w hen conductin ECDA for the\nfirst time on a covered segment;\nii Criteria for identifying and documenting those indications that must be\ne\ned for excavation and iree examin\n' d d' t mination. Minimum identification criteria\ninclude the known sensitivities of assessment too s, e proce\nls the rocedures for using each tool,\n'\nand the approach to be used for decreasing the h sical s acing of indirect\np y\np\nassessment tool readings when the presence of a defect is suspected;\n(iii) Criteria for defining the urgency of excava io\nf excavation and direct examination of each\nified durin the indirect examination. These criteria must speci y ow\nan operator will define the urgency of excavating the indication as imme ia e,\nscheduled or monitored; and\n(iv) Criteria for scheduling excavation of indications for each urgency level.\nt. In addition to the requirements in ASME/ANSI B31. 8S section\n6. 4 and NACE RP 0502 — 2002, section 5, the plan's procedures for iree exam'\nof indications from the indirect examination must include—\n(i) Provisions for applying more restrictive criteria whe n conductin ECDA for the\nfirst time on a covered segment;\n(ii) Criteria for deciding what action should be taken if either:\n(A) Corrosion defects are discovered that exceed allow able limits (Section 5. 5. 2. 2 of\nNACE RP0502 — 2002), or\n(B) Root cause analysis reveals conditions for whic\nhich ECDA is not suitable (Section\n5. 6. 2 of NACE RP0502 — 2002).\n(iii) Criteria and notification procedures for any g\nchan es in the ECDA Plan,\ninclu ing c anges\nI d' h s that affect the severity classification, the priority of direct\nexamination and the time frame or ire\nfor ire ' ' ' '\ns and iv)\nCzlterla that descrlbeho% and onw a asls 59. f ~ACE~0502\nreprioritize any of the y rovisions t at are s ecifierl in section\n2002.\n\n\n\n(4) Post assessmeni and continuing evaluation. In addition to the requirements in\nASMEIANSI B31. 8S section 6. 4 and NACE RP 0502 — 2002, section 6, the plan's\nprocedures for post assessment of the effectiveness of the ECDA process must\ninclude—\n(i) Measures for evaluating the long-term effectiveness of ECDA in addressing\nexternal corrosion in covered segments;\nand\n(ii) Criteria for evaluating whether conditions discovered by direct examination of\nindications in each ECDA region indicate a need for reassessment of the covered\nsegment at an interval less than that specified in g 192. 939. (See Appendix D of NACE\nRP 0502 — 2002. )\n~ Item 4A: g 192. 923 and g 192. 925(b)\nThe APC ECDA Procedure does not specify as a mmimum types of records identified m\nNACE section 3 as records to be obtamed during the pre-assessment phase of ECDA.\n~ Item 4B: g 192. 923 and g 192. 925(b)(1)\nThe APC IMP does not require that the basis for indirect exammation tool selection be\ndocumented and the basis is not provided m IMP records.\n~ Item 4C: g 192. 923 and g 192. 925(b)(1)\nThe APC ECDA Plan does not specify the more restrictive criteria to be applied durmg the\npre-assessment phase of the ECDA process\n~ Item 4D: g 192. 917(e)(1), g 192. 923 and g 192. 925(b)\nThe APC ECDA Plan provides no procedures for the mtegration of ECDA data with\nforeign lme crossings or encroachments\n~ Item 4E: g 192. 923 and g 192. 925(b)(2)\nAPC has not documented nor apphed more restrictive criteria during the mdirect\nexammation step of its ECDA process\n~ Item 4F: g 192. 923 and g 192. 925(b)(3)\nAPC has no documented process for determimng the root cause of significant corrosion\nactivity, nor is there any method documented for examining the imphcations of sigmficant\ncorrosion activity to other sections of the pipehne\n~ Item 4G: g 192. 923 and g 192. 925(b)(3)\n\n\n\nThe APC ECDA Plan does not require documentation of the basis upon which mdications\nare reclassified and reprioritized in accordance with any of the provisions that are specified\nm NACE RP0502-2002, Section 5 9\n~ Item 4H: g 192. 923, g 192. 925(b)(4) and g 192. 939\nThe APC IMP does not contam provisions for the performance of remammg hfe\ncalculations to determme the appropriate reassessment mtervals for its HCA pipelme\nsegments\n~ Item 4I: g 192. 923, g 192. 925(b)(4) and g 192. 939\nThe APC IMP does not specify any criteria for evaluating whether conditions discovered\nby direct exammation of mdications mdicate a need for reassessment at an interval less\nthan specified m 192 939.\n~ Item 4J: g 192. 923, g 192. 925 and g 192. 945(b)\nAPC has not estabhshed or monitored additional criteria to evaluate long-term ECDA\nprogram effectiveness.\n~ Item 4K: g 192. 907(a) and $ 192. 923\nThe APC IMP processes have not mcorporated feedback mechamsms that enable\ncontmuous improvement of the ECDA Plan.\n5. Remediation\ng 192. 907 What must an operator do to implement this subpart?\n(a) General. No later than December 17, 2004, an operator of a covered pipeline\nsegment must develop and follow a written integrity management program that\ncontains all the elements described in g 192. 911 and that addresses the risks on each\ncovered transmission pipeline segment.\ng 192. 933 What actions must be taken to address integrity issues?\n(a) General requirements An operator must take prompt action to address all\nanomalous conditions that the operator discovers through the integrity assessment. In\naddressing 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\nc'H(Qii cM'54Ms sgccYGc6 %% Gals sec4M, the opeva(ov mesc cemyovavily veh~ce the\noyerating yressure of the pipeline or take other action that ensures the safety of the\ncovered segment. If pressure is re uce, duced an operator must determine the temporary\n\n\n\nreduction in operating pressure using ASME/ANSI B31G (ibr, see g 192. 7) or AGA\nPipeline Research Committee Project PR — 3 — 805 (\"RSTRENG\", ibr, see g 192. 7) or\nreduce the operating pressure to a level not exceeding 80% 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(b) Discovery of condition. Discovery of a condition occurs when an operator has\nadequate 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 180 days after conducting an integrity assessment,\nobtain sufficient information about a condition to make that determination, unless\nthe operator demonstrates that the 180-day period is impracticable.\n(c) Schedule for evaluation and remediation. An operator must complete remediation\nof a condition according to a schedule that prioritizes the conditions for evaluation\nand remediation. Unless a special requirement for remediating certain conditions\napplies, as provided in paragraph (d) of this section, an operator must follow the\nschedule in ASME/ANSI B31. 8S (ibr, see $192. 7), section 7, Figure 4. If an operator\ncannot meet the schedule for any condition, the operator must justify the reasons why\nit cannot meet the schedule and that the changed schedule will not jeopardize public\nsafety.\n(d) Special requirements for scheduling remediation. —\n(3) 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\nrequire remediation:\n(i) A dent with a depth greater than 6% of the pipeline diameter (greater than 0. 50\ninches in depth for a pipeline diameter less than NPS 12) located between the 4\no' clock position and the 8 o' clock position (bottom 1/3 of the pipe).\n(ii) A dent located between the 8 o' clock and 4 o' clock positions (upper 2 /3 of the\npipe) with a depth greater than 6% of the pipeline diameter (greater than 0. 50 inches\nin depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12), and\nengineering analyses of the dent demonstrate critical strain levels are not exceeded.\n(iii) A dent with a depth greater than 2% of the pipeline's diameter (0. 250 inches in\ndepth for a pipeline diameter less than NPS 12) that affects gee curvature at a girth\nweM or a longitudinal seam weM, and engineering analyses of the dent and girth or\nseam weld demonstrate critical strain levels are uot exceeded. These analyses must\nconsider weld properties.\n\n\n\n~ Item 5A: g 192. 907 and g 192. 933(b)\nThe APC IMP does not provide a definition for discovery that defines when sufficient\nmformation is available to determme the significance of an anomaly.\n~ Item 5B: g 192. 907 and g 192. 933(b)\nThe APC IMP does not provide adequate procedures specifymg how the date of discovery\nis to be documented.\n~ Item 5C: g 192. 907 and g 192. 933(d)\nThe APC IMP does not require that a temporary pressure reduction or shutdown of the\npipehne occur upon discovery of all immediate repair conditions\n~ Item 5D: g 192. 907 and g 192. 933(d)\nThe APC IMP does not have adequate procedures for recording and trackmg anomahes\nidentified as monitored conditions.\n~ Item 5E: g 192. 907 and g 192. 933(a)\nThe APC IMP has no program procedures identifymg the appropriate actions to take when\nremediation timeframes cannot be met\n~ Item 5F: g 192. 907 and g 192. 933(c)\nThe APC IMP has no program procedures identifymg the appropriate actions to take to\n~ustify why a schedule cannot be met and why a schedule change will not jeopardize pubhc\nsafety.\n~ Item SG: g 192. 907 and g 192. 933(c)\nThe APC IMP has no program requirements to specify how notification is to be\naccomphshed m the event the operator cannot meet the remediation schedule or provide a\ntemporary reduction in operating pressure\n6. Continual Evaluation and Assessment\ng 192. 937 What is a continual process of evaluation and assessment to maintain a\npipeline's integrity?\n(a) Gezzeral. After completing the baseline integrity assessment of a covered segment,\nM QQ'H'l(M MESC CQYi4YlM, %0 'Assess 6M one pipe oY that segment at the tntevvats\nspecified in g 192. 939 and periodically evaluate the integrity of each covered pipeline\nsegment as provided in paragraph (b) of this section. An operator must reassess a\n\n\n\ncovered segment on which a prior assessment is credited as a baseline under g\n192. 921(e) by no later than December 17, 2009. An operator must reassess a covered\nsegment on which a baseline assessment is conducted during the baseline period\nspecified in g 192. 921(d) by no later than seven years after the baseline assessment of\nthat covered segment unless the evaluation under paragraph (b) of this section\nindicates earlier reassessment.\n~ Item 6A: g 192. 937(a)\nThe APC IMP has no procedures to determme if an earlier reassessment is necessary than\nthat required by 192 939\n7. Preventive and Mitigative Measures\ng 192. 907 What must an operator do to implement this subpart?\n(a) General. No later than December 17, 2004, an operator of a covered pipeline\nsegment must develop and follow a written integrity management program that\ncontains all the elements described in g 192. 911 and that addresses the risks on each\ncovered transmission pipeline segment.\ng 192. 917 How does an operator identify potential threats to pipeline integrity and\nuse the threat identification in its integrity program?\n(e) ActioIis to address particular threats. If an operator identifies any of the following\nthreats, the operator must take the following actions to address the threat.\n(5) Corrosion. If an operator identifies corrosion on a covered pipeline segment that\ncould adversely affect the integrity of the line (conditions specified in g 192. 933, the\noperator must evaluate and remediate, as necessary, all pipeline segments (both\ncovered and non-covered) with similar material coating and environmental\ncharacteristics. An operator must establish a schedule for evaluating and\nremediating, as necessary, the similar segments that is consistent with the operator's\nestablished operating and maintenance procedures under part 192 for testing and\nrepair.\ng 192. 935 What additional preventive and mitigative measures must an operator\ntake?\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 g 192. 917) An operator must conduct, in accordance with one of the\nrisk assessment approaches in ASMK/ANSI B31. 8S (ibr, see g 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\n10\n\n\n\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 7A: g 192. 907, g 192. 917(e)(5), and ) 192. 935(a)\nThe APC IMP has no documented process to check for the potential threats of internal\ncorrosion or SCC\n~ Item 7B: g 192. 907 and g 192. 935(a)\nThe APC IMP has no documented, systematic, decision-makmg process for decidmg\nwhich P&M measures are to be implemented\n8. Performance Measures\ng 192. 945 What methods must an operator use to measure program effectiveness'?\n(a) General. An operator must include in its integrity management program methods\nto measure, on a semi-annual basis, whether the program is effective in assessing and\nevaluating the integrity of each covered pipeline segment and in protecting the high\nconsequence areas. These measures must include the four overall performance\nmeasures specified in ASME/ANSI B31. 8S (ibr, see f192. 7), section 9. 4, and the\nspecific measures for each identified threat specified in ASME/ANSI B31. 8S,\nAppendix A. An operator must submit the four overall performance measures, by\nelectronic or other means, on a semi-annual frequency to OPS in accordance with\n$192. 951. An operator must submit its first report on overall performance measures\nby August 31, 2004. Thereafter, the performance measures must be complete through\nJune 30 and December 31 of each year and must be submitted within 2 months after\nthose dates.\n~ Item 8A: g 192. 945(a)\nThe APC performance measure report endmg 12/31/04 was submitted to PHMSA on\n3/09/05 (nme days late)\n9. Management of Change\ng 192. 909 How can an operator change its integrity management program.\n(a) General. An operator must document any change to its program and the reasons\nfor the change before implementing the change.\ng 192. 911 What are the elements of an integrity management program?\n11\n\n\n\nAn operator's initial integrity management program begins with a framework (see g\n192. 907) and evolves into a more detailed and comprehensive integrity management\nprogram, as information is gained and incorporated into the program. An operator\nmust make continual improvements to its program. The initial program framework\nand subsequent program must, at minimum, contain the following elements. (When\nindicated, refer to ASME/ANSI B31. 8S (ibr, see g 192. 7) for more detailed\ninformation on the listed element. )\n(k) A management of change process as outlined in ASME/ANSI B31. 8S, section 11.\n~ Item 9A: g 192. 909(a) and g 192. 911(k)\nThe APC Management of Change Process does not fully implement the requirements of\nthe Rule and the referenced ASME B 318S, Section 11 requirements The following are\nspecific areas noted\no Inadequate documentation of the reason for changes prior to implementation,\no No documented criteria for what constitutes a sigmficant program change for the\npurpose of notifymg PHMSA,\no Inadequate procedures to consider impacts of changes to pipehne systems and their\nintegrity;\no MOC procedures do not address all of the nme basic elements of the change process as\ndefined m ASME B31. 8S,\no Physical pipeline system changes are not addressed by the MOC process and are not\ntherefore evaluated for their potential impact on the IMP,\no Procedures do not require that equipment or system changes are identified and\nreviewed before implementation\n10. Quality Assurance\ng 192. 7 Incorporation by reference.\n(a) Any documents or portions thereof incorporated by reference in this part are\nincluded in this part as though set out in full. When only a portion of a document is\nreferenced, the remainder is not incorporated in this part.\ng 192. 911 What are the elements of an integrity management program?\nAn operator's initial integrity management program begins with a framework (see g\n192. 907) and evolves into a more detailed and comprehensive integrity management\nprogram, as information is gained and incorporated into the program. An operator\nmust make continual improvements to its program. The initial program framework\nand subsequent program must, at minimum, contain the following elements. (When\nindicated, refer to ASME/ANSI B31. 8S (ibr, see g 192. 7) for more detailed\ninformation on the listed element. )\n(i) A quality assurance process as outlined in ASMK/ANSI B31. 8S, section 12.\n12\n\n\n\n$ 192. 915 What knowledge and training must personnel have to carry out an integrity\nmanagement program?\n(a) Supervisory personnel. The integrity management program must provide that each\nsupervisor whose responsibilities relate to the integrity management program\npossesses and maintains a thorough knowledge of the integrity management program\nand of the elements for which the supervisor is responsible. The program must\nprovide that any person who qualifies as a supervisor for the integrity management\nprogram has appropriate training or experience in the area for which the person is\nresponsible.\n(b) Persons who carry out assessments and evaluate assessment results. The integrity\nmanagement program must provide criteria for the qualification of any person—\n(1) Who conducts an integrity assessment allowed under this subpart; or (2) Who\nreviews and analyzes the results from an integrity assessment and evaluation; or (3)\nWho makes decisions on actions to be taken based on these assessments.\n(c) Persons responsible for preventive and mitigative measures. The integrity\nmanagement program must provide criteria for the qualification of any person — (1)\nWho implements preventive and mitigative measures to carry out this subpart,\nincluding the marking and locating of buried structures; or (2) Who directly\nsupervises excavation work carried out in conjunction with an integrity assessment.\n~ Item 10A: g 192. 911(l)\nAPC does not have a documented Quahty Assurance Plan, therefore, no annual review of a\nQA Plan is bemg performed\n~ Item 10B: g 192. 911(l)\nAPC does not have a documented process by which corrective actions for identified\nprogram weaknesses are tracked to completion and vahdated as effective\n~ Item 10C: g 192. 911(l)\nAPC does not have processes to ensure vendor supphed services meet quality requirements\nand these processes are not documented as part of a quahty program\n~ Item 10D: g 192. 915(a)\nThe APC IMP does not identify quahfication requirements for supervisory personnel and\ndoes not estabhsh that these personnel meet these requirements Note This is specific to\nquahfications beyond those provided by the OQ program.\n~ Item 10K: $ 192, . 915(b)\n13\n\n\n\nThe APC IMP does not provide quahfication requirements or evidence of trammg to meet\nthese requirements for personnel evaluatmg assessment results nor for personnel who\nperform activities withm the Integrity Management Program\n~ Item 10F: g 192. 915(c)\nQuahfications for three APC lme locators have lapsed with respect to required training for\nAbnormal Operating Conditions.\n~ Item 10G: g 192. 7(a)\nAPC has not documented its position with regard to \"should\" statements appearing in\ncodes and standards.\n11. Communications Plan\ng 192. 911 What are the elements of an integrity management program?\nAn operator's initial integrity management program begins with a framework (see g\n192. 907) and evolves into a more detailed and comprehensive integrity management\nprogram, as information is gained and incorporated into the program. An operator\nmust make continual improvements to its program. The initial program framework\nand subsequent program must, at minimum, contain the following elements. (When\nindicated, refer to ASME/ANSI B31. 8S (ibr, see g 192. 7) for more detailed\ninformation on the listed element. )\n(m) A communication plan that includes the elements of ASME/ANSI B31. 8S, section\n10, and that includes procedures for addressing safety concerns raised by—\n(1) OPS; and (2) A State or local pipeline safety authority when a covered segment is\nlocated in a State where OPS has an interstate agent agreement.\n~ Item 11A: g 192. 11(m)\nThe APC IMP does not contam provision to address safety concerns raised by PHMSA as\nappropriate\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 in Compliance\nPi\"oceeCkngs. Please refer to this document and note the response options Be advised that all\nmaterial you submit m response to this enforcement action is subject to being made pubhcly\navailable If you believe that any portion of your responsive material quahfies for confidential\ntreatment under 5 U. S C 552(b), along with the complete origmal document you must provide a\nSCCDQh CD' D( 5e hocumertt, whh the Iior6ons you beheve quabfy for confidential treatment\nre ac e an\nd t d d an explanation of why you beheve the redacted mformation quahfies for confidential\ntreatment under 5 U. S C 552(b) If ou do not respond withm 30 days of receip\n14\n\n\n\nthis constitutes a waiver of your right to contest the allegations m this Notice and authorizes the\nAssociate Admmistrator for Pipeline Safety to find facts as alleged m this Notice without further\nnotice to you and to issue a Final Order\nIf, after opportunity for a hearing, your plans or procedures are found inadequate as alleged in this\nNotice, you may be ordered to amend your plans or procedures to correct the inadequacies (49\nC F R. ) 190. 237). If you are not contestmg this Notice, we propose that you submit your\namended procedures to my office withm 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 5-2008-0009M and, for each\ndocument you submit, please provide a copy in electronic format whenever possible.\nSmcerely,\nChris Hoidal\nDirector, Western Region\nPipehne and Hazardous Materials Safety Admmistration\ncc PHP-60 Comphance Registry\nPHP-500 J Strawn (¹118987)\nEnclosure' Response Options for Pipeline Operators in Compliance ProceeCkngs\n15","truncated":false,"body_characters":35682}