{"operation":"document","citation":"CPF 220101009M","title":"FLORIDA GAS TRANSMISSION CO — Notice of Amendment","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2010-08-18","effective_on":null,"summary":"CLOSED notice of amendment citing 192.905(c), 192.911(a), 192.911(k), 192.919(e), 192.921(a)(1), 192.925(b)(1), 192.925(b)(2), 192.925(b)(4), 192.933(b).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-220101009m.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-220101009m.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-220101009m","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/220101009M","body":"Notice of Amendment involving FLORIDA GAS TRANSMISSION CO. PHMSA's enforcement data identifies the cited regulations as 192.905(c),  192.911(a),  192.911(k),  192.919(e),  192.921(a)(1),  192.925(b)(1),  192.925(b)(2),  192.925(b)(4),  192.933(b). The case was opened on 2010-08-18 and is reported as closed as of 2012-04-04. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n220101009M_closure letter_04042012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220101009M/220101009M_closure%20letter_04042012.pdf\n\n220101009M_closure letter_04042012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220101009M/220101009M_closure%20letter_04042012_text.pdf\n\n220101009M_NOA_08182010.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220101009M/220101009M_NOA_08182010.pdf\n\n220101009M_NOA_08182010_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220101009M/220101009M_NOA_08182010_text.pdf\n\n220101009M_Operator_Response_and_Request_for_Time_Extension_and_Request_for_Hearing_09172010.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220101009M/220101009M_Operator_Response_and_Request_for_Time_Extension_and_Request_for_Hearing_09172010.pdf\n\n220101009M_Order Directing Amendment_12292011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220101009M/220101009M_Order%20Directing%20Amendment_12292011.pdf\n\n220101009M_Order Directing Amendment_12292011_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220101009M/220101009M_Order%20Directing%20Amendment_12292011_text.pdf\n\n220101009M_closure letter_04042012_text.pdf\n\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\nApril 4, 2012\nMr. Eric Amundsen\nVice President and Chief Asset Integrity Officer\nPanhandle Energy\n5444 Westheimer Road\nHouston, Texas 77056\nCPF 2-2010-1009M\nDear Mr. Amundsen:\nOn April 12-16, 2010 and April 26-30, 2010, representatives of the Pipeline and Hazardous\nMaterials Safety Administration (PHMSA), Office of Pipeline Safety (OPS) inspected the\nPanhandle Energy (Panhandle) Gas Integrity Management Program (IMP) written procedures\nin Houston, Texas, pursuant to Chapter 601 of 49 United States Code. As a result of the\ninspection, PHMSA issued a Notice of Amendment (NOA) on August 18, 2010.\nPanhandle asked for and was granted a hearing to address two issues in the NOA. After the\nhearing, PHMSA issued an Order Directing Amendment (ODA) on December 29, 2011.\nWe have received and reviewed revised IMP procedures from Panhandle in response to the\nODA. This letter is to inform you that Panhandle has complied with the terms of the NOA\nand ODA. No further action is necessary with regards to the NOA and ODA. This case is\nnow closed.\nPlease be advised that this letter refers only to the NOA and ODA referenced above\n(CPF 2-2010-1009M) and not to any other PHMSA pending cases. Also be advised that\nnothing herein states or implies that the above described IMP meets the requirements of the\nfederal pipeline safety regulations or that the IMP is approved. The pipeline system and IMP\nremain subject to inspection by PHMSA.\nSincerely,\nWayne T. Lemoi\nDirector, Office of Pipeline Safety\nPHMSA Southern Region\n\n220101009M_Order Directing Amendment_12292011_text.pdf\n\nDEC 29 2011\nMr. Eric Amundsen\nVice President and Chief Asset Integrity Officer\nPanhandle Eastern Pipeline Company\n5444 Westheimer Road\nHouston, TX 77056\nRe: CPF No. 2-2010-1009M\nDear Mr. Amundsen:\nEnclosed is the Order Directing Amendment issued by the Associate Administrator for\nPipeline Safety in the above-referenced case. It makes a finding of inadequate procedures and\nrequires that you amend your written integrity management program. When the terms of the\nOrder are completed, as determined by the Director, Southern Region, this enforcement action\nwill be closed. Your receipt of the Order Directing Amendment constitutes service of that\ndocument 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. Wayne T. Lemoi, Director, Southern Region, OPS\nCERTIFIED MAIL – RETURN RECEIPT REQUESTED [_71791000164203039955___]\n\n\n\nU.S. DEPARTMENT OF TRANSPORTATION\nPIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION\nOFFICE OF PIPELINE SAFETY\nWASHINGTON, DC 20590\n_______________________________________\nIn the Matter of )\nPanhandle Energy, ) CPF No. 2-2010-1009M\n)\n)\n)\nRespondent. )\n_______________________________________)\nORDER DIRECTING AMENDMENT\nOn April 12-16 and April 26-30, 2010 pursuant to 49 U.S.C. § 60117, representatives of the\nPipeline and Hazardous Materials Safety Administration’s (PHMSA) Office of Pipeline Safety\n(OPS) inspected Respondent’s written gas integrity management program (IMP) procedures in\nRespondent’s Houston, Texas office. Panhandle Energy (Panhandle) operates three gas pipeline\nsystems, consisting of over 10,000 miles of transmission lines: Panhandle Eastern Pipe Line\nCompany, Trunkline Gas Company, and Sea Robin Pipeline Company.1\nAs a result of the inspection, the Director, Southern Region, OPS issued to Respondent, by letter\ndated August 18, 2010, a Notice of Amendment (NOA). The Notice alleged inadequacies in\nRespondent’s integrity management program and proposed, in accordance with\n49 C.F.R. § 190.237, that Respondent amend its integrity management procedures.\nPanhandle Energy responded to the NOA on September 17, 2010 (“Response”) and agreed to\namend its procedures for the items 1, 2A, 3, 4, and 6. Respondent contested the two remaining\nitems in the NOA, 2B and 5. Respondent requested a hearing for these contested items in\naccordance with 49 C.F.R. § 190.211. A hearing was held via telephone conference on\nMarch 3, 2011, with an attorney from the Office of Chief Counsel, PHMSA, presiding.\nRespondent was represented by counsel during the hearing. Respondent had a court reporter\nrecord the hearing, and the court reporter provided a final transcript of the hearing to all parties\napproximately one week afterwards. Respondent submitted a post hearing response (“Closing”)\non May 2, 2011.\nFINDINGS OF INADEQUATE PROCEDURE\nThe Notice identified the following apparent inadequacies in Respondent’s plans or procedures:\n1 http://www.panhandleenergy.com/serv_trans.asp (last accessed 12/9/2011).\n\n\n\n2\nItem 2B: The Notice alleged that Respondent’s gas IMP failed to adequately address\n49 C.F.R. § 192.921(a)(1), which states:\n§ 192.921 How is the baseline assessment to be conducted?\n(a) Assessment methods. An operator must assess the integrity of the\nline pipe in each covered segment by applying one or more of the\nfollowing methods depending on the threats to which the covered segment\nis susceptible. An operator must select the method or methods best suited\nto address the threats identified to the covered segment (See § 192.917).\n(1) Internal inspection tool or tools capable of detecting corrosion, and\nany other threats to which the covered segment is susceptible. An operator\nmust follow ASME/ANSI B31.8S (incorporated by reference, see\n§ 192.7), section 6.2 in selecting the appropriate internal inspection tools\nfor the covered segment.\nThe NOA alleged that Respondent’s IMP assessment method procedures did not require the\nconsideration of internal in-line inspection (ILI) tool tolerances to effectively address pipeline\nthreats. Also, the NOA alleged that Respondent’s procedures lacked specific requirements for\ncomparing recent ILI runs to previous ILI runs for monitoring anomalies.\nIn its Response and during the hearing, Respondent stated that its IMP procedures satisfied the\ncited regulation. Respondent stated that it considers the condition of the specific pipeline section\nat the time of ILI contract bidding and considers the tool and performance specifications\nsubmitted by vendors prior to awarding ILI contracts.2 Accordingly, Panhandle’s “Inline Metal\nLoss Inspection, Tool Specification” procedure requires that ILI vendors provide tool tolerance\ninformation; the procedure also contains tool tolerance minimum requirements.3 Panhandle\nfurther argued in its Response that Part 192, subpart O “does not require, much less define\ntolerance.”4 Respondent also stated during the hearing that its procedures required consideration\nof previous runs and monitored conditions between subsequent inline inspections.5\nPHMSA began its hearing presentation by acknowledging that Panhandle specifies tool tolerance\nwhen it runs an ILI tool by ensuring that the tool performed to within 10% or 15% accuracy by\ncomparing reported indications by the tool to the actual condition of the excavated pipe.\nPHMSA clarified that its concern was not simply ensuring that a tool performed within the\nexpected accuracy range. Rather, PHMSA pointed to Respondent’s lack of procedures requiring\nadditional engineering analysis on anomalies that are not reported by the tool as defects requiring\nimmediate repair or remediation. PHMSA explained that given that the ILI tool that Respondent\nuses is generally accurate within 10% of the anomaly depth 80% of the time, the tool will\nprovide less accurate results 20% of the time. Therefore, PHMSA’s concern is that the size or\ndepth of some anomalies may be underreported, even when a tool is performing as required.\nThis could allow for defects that threaten the integrity of the pipeline to be identified as less\nserious anomalies. Therefore, in order to accurately “assess the integrity of the line pipe,” as\nrequired in the regulation, the 20% margin of error must be accounted for.\n2 “Panhandle Energy Response to NOA CPF 2-20101009M, September 17, 2010” (hereinafter Response), at 1.\n3 “Inline Metal Loss Inspection, Tool Specification,” Sections 3.2 and 3.5.\n4 Response at 4.\n5 Hearing Transcript, page. 13, lines 8-12, dated March 3, 2011.\n\n\n\n3\nPHMSA explained that a pipeline operator can account for the lack of certainty in the tool in\nvarious ways. Some operators simply add or subtract a vendor-supplied accuracy specification\nto the reported depth of metal loss, although PHMSA recognized that Panhandle does not agree\nwith this approach. PHMSA pointed out that another way to achieve this is by conducting a\nprobability of exceedance analysis.6\nTo further support its position and to counter Respondent’s argument that Item 2B is not\nsupported by the regulation, PHMSA cited guidance document Gas IM FAQ 68, that it issued to\nassist pipeline operators in meeting the requirement in §192.921(a) that it “select the method or\nmethods best suited to address the threats identified to the covered segment.” (emphasis added)\nGas IM FAQ 68 states, in part,\n“Immediate repair conditions may not be discovered (because the\nILI tool “under called” the defect) even if the tool functioned\nwithin its published accuracy specifications, if tool accuracy is not\nconsidered. . . . This does not necessarily mean simply adding the\nvendor-supplied accuracy specification to reported depth of metal\nloss indications. Several sources of data may be used, in\nconjunction with vendor-supplied tool specifications, to\ncharacterize pipeline defects. These include results of previous\nexcavations, confirmation digs, results of concurrent inspections\nand comparison to prior inspections.”7\nRespondent could not identify language in its IMP that required the consideration of tool\ntolerances as described in FAQ 68. Instead, Respondent stated that it did perform this type of\nanalysis, but the analysis was not documented in its procedures. Respondent then agreed to add\nlanguage to its IMP that would document this analysis.8 However, the documentation that\nRespondent submitted after the hearing (“Closing”) stated, “PHMSA agreed in the hearing that\nadding internal processes and procedures outlined in A through L of PEs initial Hearing\nDocument to PE’s SOP’s would satisfy Pumas’ concerns.”9 This statement is untrue, as PHMSA\nspecifically stated in the hearing that Panhandle’s Hearing Document was not responsive to\nPHMSA’s concerns.10 Furthermore, the updates to the gas IMP that Panhandle submitted\nrevised the development of unity plots, which compare ILI tool performance to the tool\nspecification. The discussion at the hearing (as memorialized in the transcript) established that\nmeasuring accuracy of the ILI tool was not at issue.11\nContrary to Panhandle’s assurances at the\nhearing, it did not develop or include procedures in its IMP to analyze anomalies with additional\ninformation from previous inspections and excavations, concurrent inspections, confirmation\n6 Hearing Transcript, page 17, lines 9-14.\n7 Gas IM FAQ 68, available at: http://primis.phmsa.dot.gov/gasimp/faqlist.gim\n8Hearing Transcript, page 22, lines 10 -16 and page 25, lines 5-9.\n9 Closing, May, 2 2011, at 1.\n10 Hearing Transcript, page 15, lines 22-25 (“And so I think in terms of Panhandle’s response, I guess, I think item D\nunder the tool tolerance discussion is really the only item in their response that specifically addresses what this issue\nis related to.”) Item D of Panhandle’s is a comment and not part of its procedure.\n11 Hearing Transcript, page 16, line 26 and page 17, lines 1 – 5. (“I fully realize that they are actually specifying the\ntool tolerance when they do an inline inspection contract and that they are doing a plot to determine whether or not\nthe tool meets those specifications, comparing the reported indications to the ones that they excavate and actually\nexamine.”)\n\n\n\n4\ndigs, or application of the vendor-supplied accuracy specification to investigate whether the tool\nunder reported them.\nAccordingly, I find that Respondent’s gas IMP fails to include procedures that ensure a complete\nassessment of the integrity of each covered segment because it does not require analysis to\naccount for an ILI tool’s allowed margin of error. This incomplete assessment prevents\nRespondent from “select[ing] methods best suited to address the threats identified to the covered\nsegment.” Therefore, I find that Respondent’s procedure for ensuring tool accuracy is\ninadequate to ensure safe operation of its pipeline system.\nItem 5: The Notice alleged that Respondent’s gas IMP failed to adequately address\n49 C.F.R. §§ 192.911(e) and 192.933(b) and (d)(1), which state:\n§ 192.911 What are the elements of an integrity management\nprogram?\nAn operator's initial integrity management program begins with a\nframework (see § 192.907) and evolves into a more detailed and\ncomprehensive integrity management program, as information is gained\nand incorporated into the program. An operator must make continual\nimprovements to its program. The initial program framework and\nsubsequent program must, at minimum, contain the following elements.\n(When indicated, refer to ASME/ANSI B31.8S (incorporated by\nreference, see § 192.7) for more detailed information on the listed\nelement.) (1) Internal inspection tool or tools capable of detecting\ncorrosion, and any other threats to which the covered segment is\nsusceptible. An operator must follow ASME/ANSI B31.8S (incorporated\nby reference, see § 192.7), section 6.2 in selecting the appropriate internal\ninspection tools for the covered segment.\n(a) . . . .\n(e) Provisions meeting the requirements of § 192.933 for remediating conditions\nfound during an integrity assessment.\n§ 192.933 What actions must be taken to address integrity issues?\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 threat\nincludes, but is not limited to, those conditions that require remediation or monitoring\nlisted under paragraphs (d)(1) through (d)(3) of this section. An operator must promptly,\nbut no later than 180 days after conducting an integrity assessment, obtain sufficient\ninformation about a condition to make that determination, unless the operator\ndemonstrates that the 180-day period is impracticable.\n(d) Special requirements for scheduling remediation.\n--(1) Immediate repair\nconditions. An operator's evaluation and remediation schedule must follow ASME/ANSI\nB31.8S, section 7 in providing for immediate repair conditions. To maintain safety, an\noperator must temporarily reduce operating pressure in accordance with paragraph (a) of\nthis section or shut down the pipeline until the operator completes the repair of these\n\n\n\n5\nconditions. An operator must treat the following conditions as immediate repair\nconditions:\n(i) 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 the\nlocation of the anomaly. Suitable remaining strength calculation methods include,\nASME/ANSI B31G; RSTRENG; or an alternative equivalent method of remaining\nstrength calculation. These documents are incorporated by reference and available at the\naddresses listed in appendix A to part 192.\n(ii) A dent that has any indication of metal loss, cracking or a stress riser.\n(iii) An indication or anomaly that in the judgment of the person designated by the\noperator to evaluate the assessment results requires immediate action.\nThe Notice alleged that Respondent’s procedure SOP J.14 entitled, “In-Line Inspection: Data\nIntegration, Analysis, and Response” is inadequate because it does not consider anomalies\nexceeding 80% wall loss as an immediate repair condition. In its Response and at the hearing,\nRespondent argued that § 192.933(d)(1) is a performance- based regulation and leaves the\ndecision to repair defects of 80% or greater wall loss to the operator. In support of this,\nRespondent pointed to the language in § 192.933(d)(1)(iii), which relies on the judgment of the\noperator or its contractor. It also explained that it uses the rupture pressure ratio (RPR)\nmethodology, as described in B31.83 (2009).12 This method requires the repair of anomalies\nwith a depth equal to or greater than 80% of wall thickness only when the RPR is equal to or less\nthan 1.39. Respondent emphasized that its methodology focuses on preventing ruptures. It\nadmitted that some leaks on short, deep flaws could occur, but Panhandle maintained that their\nmethodology is consistent with both subpart of O and B31G because the focus of those standards\nis to prevent ruptures, not necessarily leaks.13\nIn the hearing, PHMSA disagreed with Respondent’s evaluation and remediation methods and\narguments. First, it argued that § 192.933(d) is a prescriptive regulation, not performance based.\nIt recognized that § 192.933(d) references ASME/ANSI B31G, but it clarified that the edition\nincorporated by reference at § 192.7 is the B31G 1991 edition, which was reaffirmed in 2004.\nUnlike the 2009 edition, the 1991 edition requires that a corroded area with a depth of greater\nthan 80% must be repaired or replaced.14 Although PHMSA did not dispute the validity of the\n2009 edition of B31G, it stated that the law requires that PHMSA enforce the regulations as\nwritten, which includes enforcing the industry standards that had been properly vetted and\nincorporated into the regulations through a public notice and comment process.15\nPHMSA\ncontinued that the 1991 edition of B31G does not allow for strength calculations or provide\n12 Hearing Transcript, pages 29 and 30; Response, page 2 and 3. RPR is the ratio of the predicted burst pressure to\nthe Maximum Allowable Operating Pressure (MAOP).\n13 Response, at 2 (“PE mitigates the risk associated with leaking anomalies by aerial patrols and surveys and has\ndemonstrated with historical data that external corrosion related leaks are effectively managed and as such do not\npose a threat to public safety.”); Hearing Transcript, Pages 29- 30, lines 24 – 2 (“ . . and mostly the subpart O\nregulations for natural gas transmission lines are focused on preventing or reducing the likelihood of large releases,\nor pipeline ruptures.”); page 30, lines 21 – 23. (“[T]the short, deep flaws, if they produce a release at all, are almost\ncertainly going to be a leak rather than a rupture.”); page 32, lines 10 -14 (“And we are doing that by making our\nprimary determination of immediate response conditions in this kind of case based on the RPR, plus the\nmanagement of leaks and potential leak conditions.”).\n14 ASME B31G-1991, Fig. 1-2.\n15 Hearing Transcript Pages 39 – 40.\n\n\n\n6\nalternative options when the wall loss surpasses 80%.\n16 In further support of its position,\nPHMSA cited its Gas IM FAQ 241, which states that operators may not exclude metal loss\nindications of more than 80% from immediate repair requirements even if B31G or RSTRENG\ncalculations predict a failure pressure greater than 1.1 times MAOP.17\nPHMSA also differed with Panhandle’s assertion that the threat of leaks can be “managed” by\naerial patrols and that leaks do not pose a threat to public safety.18 It pointed out that ASME\nB31.8S-2004 requires “immediate response” for “immediate or near term leaks or ruptures.”19\n(emphasis added.) PHMSA also pointed out that the transmission lines at issue transport\nunodorized gas, and any leak, especially one that could go unnoticed by the public, jeopardizes\nsafety.20\nI do not agree with Respondent’s arguments. First, I agree with PHMSA that § 193.933(d)(1) is a\nprescriptive, rather than performance based regulation. The last sentence in the provision states,\n“An operator must treat the following conditions as immediate repair conditions:” (emphasis\nadded.) This means that if any of the conditions exist, an immediate repair is required. The\npresence of a corrosion area with greater than 80% wall loss triggers (i), mandating an immediate\nrepair. Contrary to Panhandle’s arguments, the language in (iii) simply means that if neither (i)\nnor (ii) require an immediate repair, an immediate repair may still be required if, in the judgment\nof the operator or its contractor, an anomaly “requires immediate action.” Most importantly,\nPHMSA established that Panhandle erroneously relied on the 2009 edition of B31G that has not\nbeen incorporated into the Pipeline Safety Regulations.\nIn its Closing, Panhandle raised arguments not discussed in its Response or during the hearing.\nFirst, Respondent stated that PHMSA erroneously focused solely on the 1991 edition of ASME\nB31G for determining immediate repair conditions. Instead, Panhandle pointed to the language\nin § 192.933(d)(1) that states that an operator's evaluation and remediation schedule must follow\nASME/ANSI B31.8S, section 7. Presumably, Respondent raised this argument because section\n7, “Response to Integrity Assessments and Mitigation (Repair and Prevention)”of B31.8S\nmentions the RPR methodology and 1.1 ratio. However, the subject matter of section 7 is not\nevaluation of anomalies; it is the appropriate response to the information obtained through those\nevaluations, i.e. repair, replacement, pressure reduction, etc. Section 7 reviews which indications\nrequire immediate response, and it includes “any corroded areas that have a predicted failure\npressure less than 1.1 times the MAOP as determined by ASME B31G or equivalent.” Therefore,\nSection 7 is merely referencing the edition of B31G that PHMSA has not incorporated; it does\nnot provide an independent means of determining pipe strength of wall loss areas.\nNext, Respondent argues that § 192.933(d)(1)(i) allows for “an alternative equivalent method of\nremaining strength calculation.” It contends that the 2009 version of ASME/ANSI B31G\nqualifies as an “alternative equivalent.” I disagree. Given the substance of this Item, PHMSA\n16 ASME B31G-1991, Fig. 1-2.\n17 Frequently – Asked Question FAQ # 241, available at, http://primis.phmsa.dot.gov/gasimp/faqlist.gim\n18 Response at 2. (“PE mitigates the risk associated with leaking anomalies by aerial patrols and surveys and has\ndemonstrated with historical data that external corrosion related leaks are effectively managed and as such do not\npose a threat to public safety.”)\n19 ASME B31.8S-2004, Section 7.2.3.\n20 Hearing Transcript Page 51\n\n\n\n7\ndoes not consider the 2009 version of B31G to be “equivalent” because the 2009 edition does not\ntreat areas of greater than 80% wall loss as immediate repair conditions.\nLastly, Respondent argues that PHMSA incorrectly interpreted the 1991 edition of B31G to\nrequire “immediate” repair or replacement for corrosion areas of greater than 80% depth because\nFigure 1-2 does not give a timeframe for the repair or replacement. Respondent argues that,\ngiven this fact, it is compliant with the 1991 edition because it “currently schedules 80%\nanomalies, which meets the guidance to repair or replace.”21 Although this statement is not\nconsistent with the arguments it raised at the hearing and in its Response, I agree that the figure\ndoes not give a timeframe for repair or replacement. The 1991 edition of B31G does not discuss\ntimeframes for repair but provides a methodology and calculations for pipeline operators to\nmeasure pipe strength and safe operating pressure depending on the size and depth of corroded\nareas. Figure 1-2 simply states that these calculations do not apply to 80% anomalies because\nthey must be repaired or replaced. On the other hand, ASME B31.8S-2004 does provide for\nrepair timeframes. It states that, “any defect found to require repair or removal shall be promptly\nremediated by repair or removal unless the operating pressure is lowered to mitigate the need to\nremoval,” of corrosion areas of greater than 80%, ASME B31.8S-2004 requires prompt\nrepair or remove the defect.”22 Given that the relevant edition of B31G requires “repair or\nremediation by repair or removal of those areas.\nAccordingly, I find that Respondent’s procedures for determining immediate repair conditions\nare inadequate to ensure safe operation of its pipeline system. Pursuant to 49 U.S.C. § 60108(a)\nand 49 C.F.R. § 190.237, Respondent is ordered to make the following changes to its IMP.\nRespondent must—\n1. Amend the procedures for evaluating anomalies indicated by the tool but not identified as\ndefects requiring immediate repair. The IMP must provide for additional engineering\nanalysis on anomalies not identified as requiring immediate repair; this process should\ninclude data from some combination of the following: previous excavations, confirmation\ndigs, results of concurrent inspections, comparison to prior inspections, and applying the\nvendor-supplied accuracy specification.\n2. Amend SOP J.14, “In-Line Inspection: Data Integration Analysis and Response” and all\nappropriate procedures to ensure that anomalies exceeding 80% wall loss are identified as\nimmediate repair conditions.\n3. Complete the above items and submit documentation of completion within 30 days of\nreceipt of this Order. Submit documentation to the Director, Southern Region, Pipeline\nand Hazardous Materials Safety Administration, 233 Peachtree Street NE, Suite 600\nAtlanta, Georgia 30303.\nThe Director, Southern Region, OPS may grant an extension of time to comply with any of the\nrequired items upon a written request timely submitted by the Respondent demonstrating good\ncause for an extension.\n21 Closing at Item 5.\n22 ASME B31.8S-2004, Section 7.2.1 Metal Loss Tools for Internal and External Corrosion.\n\n\n\n8\nFailure to comply with this Order may result in administrative assessment of civil penalties up to\n$100,000 per day for each violation and in referral to the Attorney General for appropriate relief\nin a district court of the United States. The terms and conditions of this Order Directing\nAmendment are effective upon receipt.\n___________________________________ ____________________\nJeffrey D. Wiese Date Issued\nAssociate Administrator\nfor Pipeline Safety","truncated":false,"body_characters":27730}