{"operation":"document","citation":"CPF 220101011M","title":"GULF SOUTH PIPELINE COMPANY, LLC — Notice of Amendment","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2010-11-23","effective_on":null,"summary":"CLOSED notice of amendment citing 192.461(a)(1), 192.463(a), 192.465(c), 192.473(a), 192.475(b)(1), 192.605(b)(8), 192.605(c)(4), 192.709(c), 192.736(c), 192.739(a)(1), 192.739(a)(4), 192.805(i), 192.911(l), 192.917(a), 192.917(b), 192.919(b), 192.925(b), 192.925(b)(3), 192.925(b)(4), 192.927(c)(1)(ii), 192.929(b)(2), 192.935(a), 192.939(a)(3).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-220101011m.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-220101011m.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-220101011m","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/220101011M","body":"Notice of Amendment involving GULF SOUTH PIPELINE COMPANY, LLC. PHMSA's enforcement data identifies the cited regulations as 192.461(a)(1),  192.463(a),  192.465(c),  192.473(a),  192.475(b)(1),  192.605(b)(8),  192.605(c)(4),  192.709(c),  192.736(c),  192.739(a)(1),  192.739(a)(4),  192.805(i),  192.911(l),  192.917(a),  192.917(b),  192.919(b),  192.925(b),  192.925(b)(3),  192.925(b)(4),  192.927(c)(1)(ii),  192.929(b)(2),  192.935(a),  192.939(a)(3). The case was opened on 2010-11-23 and is reported as closed as of 2012-04-03. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n220101011M_Closure Letter_04032012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220101011M/220101011M_Closure%20Letter_04032012.pdf\n\n220101011M_Closure Letter_04032012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220101011M/220101011M_Closure%20Letter_04032012_text.pdf\n\n220101011M_Notice Letter_11232010.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220101011M/220101011M_Notice%20Letter_11232010.pdf\n\n220101011M_Notice Letter_11232010_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220101011M/220101011M_Notice%20Letter_11232010_text.pdf\n\n220101011M_Operator_Response_and_Request_Extension_12162010.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220101011M/220101011M_Operator_Response_and_Request_Extension_12162010.pdf\n\n220101011M_Notice Letter_11232010_text.pdf\n\nNOTICE OF AMENDMENT\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\nNovember 23, 2010\nMr. David Goodwin\nVice President Compliance and Operations Services\nGulf South Pipeline Co., L.P.\n9 Greenway Plaza, Suite 2800\nHouston, TX 77046\nCPF 2-2010-1011M\nDear Mr. Goodwin:\nBetween June 22, 2009, and October 9, 2009, representatives of the Pipeline and Hazardous\nMaterials Safety Administration (PHMSA) inspected Gulf South Pipeline Co., L.P. (Gulf\nSouth) procedures for Operations and Maintenance, Operator Qualification, and Integrity\nManagement in Gulf South’s offices and field locations in Louisiana, Texas, and Mississippi\npursuant to Chapter 601 of 49 United States Code.\nOn the basis of the inspection, PHMSA has identified apparent inadequacies found within\nGulf South’s Operations and Maintenance (O&M) procedures as described in Items 1 - 11\nbelow:\n1. § 192.739 Pressure limiting and regulating stations: Inspection and testing.\n(a) Each pressure limiting station, relief device (except rupture discs), and\npressure regulating station and its equipment must be subjected at intervals not\nexceeding 15 months, but at least once each calendar year, to inspections and\ntests to determine that it is -\n(1) In good mechanical condition;\nGulf South's written O&M relief valve inspection and testing procedures were\ninadequate because they did not provide enough detail to instruct personnel on how to\nproperly determine if pilot-operated relief valves were in good mechanical condition.\nRelief valves on pipeline systems must be inspected each calendar year for, among\nother things, good mechanical condition. Gulf South’s work instruction procedure WI-\n00074, Regulation and Over-Pressure Protection (rev. 06/15/09) did not contain the\ndetail required to instruct personnel on how to properly determine if pilot-operated\n\n\n\nrelief valves were in good mechanical condition. Instead WI-00074 refers Gulf South's\ntechnicians to the relief valve manufacturer's operating and maintenance manuals for\ninspection and testing. This reference was insufficient to perform the required task.\nPHMSA inspectors observed Gulf South's technicians performing a pilot-operated\nrelief valve test at the Amite Town Border Station. The technicians explained that the\nreferenced manufacturer's documentation did not provide inspection and testing\nrequirements, and therefore, they did not known how to determine if the relief valve\nwas in good mechanical condition. Also, information provided by Gulf South relating\nto a different relief valve manufacturer for a relief valve located at the International\nPaper Meter Station did not specifically require the valve to be tested and observed to\nbe in good mechanical condition; i.e. to test and observe for the valve plug to move off\nof the seat when required.\n2. §192.739 Pressure limiting and regulating stations: Inspection and testing.\n(a) Each pressure limiting station, relief device (except rupture discs), and\npressure regulating station and its equipment must be subjected at intervals not\nexceeding 15 months, but at least once each calendar year, to inspections and\ntests to determine that it is -\n…. (4) Properly installed and protected from dirt, liquids, or other conditions\nthat might prevent proper operation.\nGulf South's written O&M relief valve inspection and testing procedures were\ninadequate because they did not require inspections and tests to determine if pilot\noperated relief valves were properly installed and protected from dirt, liquids, or other\nconditions that might prevent proper operation.\nRelief valves on pipeline systems must be inspected each calendar year to determine if\nthe relief valves were properly installed and protected from dirt, liquids, or other\nconditions that might prevent proper operation. While Gulf South’s work instruction\nprocedure WI-00074, Regulation and Over-Pressure Protection (rev. 06/15/09)\nrequired relief valve vent flapper and weep hole inspections of some relief valves, it\ndid not require these inspections for pilot operated relief valves.\n3. §192.461 External corrosion control: Protective coating.\n(a) Each external protective coating, whether conductive or insulating,\napplied for the purpose of external corrosion control must—\n(1) Be applied on a properly prepared surface;\nGulf South's written O&M external corrosion control protective coating procedures\nwere inadequate because they were incorrect, unclear, and lacked specificity.\nGulf South's work instruction procedure WI-00089, Apply Approved Coatings to\nAbove- and Belowground Piping (07/13/09) was incorrect in that it stated that a\ncompany approved coatings list was provided in the Company Coating Specification\nwhile no such document was provided. In lieu of the approved coatings list, Gulf\nSouth provided a June 10, 2004, email which included a list of approved underground\ncoatings, with an attached undated draft procedure for selecting and applying below\ngrade field coatings. The draft procedure was incorrect because the application of 3M\nhot melt patch sticks on thermal welded test lead installations was included (epoxy and\n2\n\n\n\nnon-epoxy coated pipe) but the vendor's literature specifically stated that patch stick\napplications should be restricted exclusively to the repair of pinholes and abrasions on\nepoxy coatings.\nAlso, while protective coating surface preparation standards and specifications were\nlisted in Gulf South's WI-00089, including preparations for hand and power brush, it\nwas not clear what specific levels of surface preparation were required when small\ncoating repairs were made with products such as Enviroline 124 or Ceilcote 252. That\nis, Section 5.3 of the undated draft procedure, Clean Small Areas by hand or Power\nBrush, was unclear in that it required surface preparation by hand or power brush for\nsmall areas such as taps, test lead connections, UT test areas and longitudinal seam\nrepairs, etc. but it did not include specific levels of surface preparation.\nThe draft procedure also lacked specificity. For example, one of the approved products\nwas Tapecoat TC 7100 Wet Bond Gray Epoxy. Detailed application procedures for\nthis product were not defined or directly referenced in the draft procedure. Moreover,\nthe Tapecoat published product information provided by Gulf South contained very\nlittle detail, and recommended that a technician see the “detailed Field Specification\nfor complete instructions” and further indicated that Tapecoat agents were\nstrategically located throughout the world to provide technical service.\n4. §192.463 External corrosion control: Cathodic protection.\n(a) Each cathodic protection system required by this subpart must provide a\nlevel of cathodic protection that complies with one or more of the applicable\ncriteria contained in appendix D of this part. If none of these criteria is\napplicable, the cathodic protection system must provide a level of cathodic\nprotection at least equal to that provided by compliance with one or more of\nthese criteria.\nGulf South’s cathodic protection procedures were inadequate because they did not\nprovide the detail necessary to determine how Gulf South considers voltage (IR) drop.\nGulf South's O&M Manual, Section 3.3 - Criteria for Cathodic Protection states the\nfollowing as it relates to the current-applied - 0.850v criterion, \"Interpretation of\nvoltage measurement: Voltage (IR) drops other than those across the structure-\nelectrolyte boundary shall be considered for valid interpretation of the voltage\nmeasurement in paragraphs.\" Yet, nothing in the procedure explains how Gulf South\nactually considers the IR for valid interpretation of the voltage measurement.\nThe inadequacy of these procedures was further supported by evidence in Gulf\nSouth’s cathodic protection survey records. For example, Gulf South performed\nannual cathodic protection surveys in 2007, 2008, and 2009 in the Jackson, MS area.\nA review of the annual survey cathodic protection records showed numerous readings\nranging from - 0.850v to - 0.900v. While these readings were deemed acceptable by\nGulf South using the designated criterion of - 0.850v, there was no documentation\nexplaining how Gulf South considered IR drop with regards to these readings.\n5. §192.465 External corrosion control: Monitoring.\n…. (c) Each reverse current switch, each diode, and each interference bond\nwhose failure would jeopardize structure protection must be electrically checked\n3\n\n\n\nfor proper performance six times each calendar year, but with intervals not\nexceeding 21/2months. Each other interference bond must be checked at least\nonce each calendar year, but with intervals not exceeding 15 months.\nGulf South’s external corrosion control monitoring procedures were inadequate\nbecause they did not provide specific criteria on how to determine if an interference\nbond was \"critical\" to the Gulf South pipeline system. As used here, the term\n\"critical\" means a bond whose failure would jeopardize structure protection; i.e.\njeopardize cathodic protection of the Gulf South pipeline.\nAn operator must electrically check each critical bond six times a calendar year, while\nnon-critical bonds must be checked only once each calendar year. Therefore, an\noperator must have procedures to differentiate critical bonds from non-critical bonds.\nWhile Gulf South's procedures discussed critical bonds, the procedures did not\ndescribe how Gulf South personnel were to differentiate critical from non-critical\ninterference bonds.\nThe inadequacy of these procedures was further supported by evidence in Gulf\nSouth’s cathodic protection survey records. Gulf South’s interference bond records in\nthe Sterlington area indicated significant electrical current through the bonds and were\nlabeled as “FROM US.” Gulf South subsequently determined that the current flow\ndirection across these bonds in these records was incorrect and that the bonds were not\ncritical. Yet, Gulf South’s records did not indicate that these bonds had been\nidentified as needing to be investigated further to determine if they could have been\ncritical based on the initially recorded bond electrical current and current direction.\n6. §192.473 External corrosion control: Interference currents.\n(a) Each operator whose pipeline system is subjected to stray currents shall\nhave in effect a continuing program to minimize the detrimental effects of such\ncurrents.\nGulf South’s external corrosion control interference current procedures were\ninadequate because they did not provide the guidance and detail necessary to identify\nareas of potential stray current so the detrimental effects of stray currents could be\nminimized.\nGulf South had a detailed interference current procedure which it used to comply with\nspecial permit interference survey and remediation requirements but these procedures\nwere not included or referenced in Gulf South's O&M manual or Work Instructions.\n7. §192.475 Internal corrosion control: General.\n…. (b) Whenever any pipe is removed from a pipeline for any reason, the internal\nsurface must be inspected for evidence of corrosion. If internal corrosion is found\n-\n(1) The adjacent pipe must be investigated to determine the extent of internal\ncorrosion;\n(2) Replacement must be made to the extent required by the applicable\nparagraphs of §§192.485, 192.487, or 192.489; and\n(3) Steps must be taken to minimize the internal corrosion.\n4\n\n\n\nGulf South’s internal corrosion control procedures were inadequate because they did\nnot require the examination of all removed pipe coupons for evidence of internal\ncorrosion when hot taps were made.\nGulf South's O&M manual Chapter 9 described hot tapping procedures, but did not\nrequire the examination of removed pipe coupons for evidence of internal corrosion.\nThis deficiency was further evidenced in Work Order No. 23660726, dated 02/20/09\n(Bistineau-Clarence area), which did not indicate that a removed coupon was\nexamined for the presence of internal corrosion.\n8. §192.709 Transmission lines: Record keeping.\nEach operator shall maintain the following records for transmission lines for the\nperiods specified:\n…. (c) A record of each patrol, survey, inspection, and test required by subparts\nL and M of this part must be retained for at least 5 years or until the next patrol,\nsurvey, inspection, or test is completed, whichever is longer.\nGulf South’s record keeping procedures were inadequate because they did not require\nthe full documentation of performance tests conducted on gas detection and alarm\nsystems at compressor stations.\nGulf South’s work instruction procedure WI-00085 Test/Maintain Gas Detection &\nAlarm Systems and the referenced Engine Protective Devices Test Report form (Form\n#PS5576, rev. 06/10/09) did not require adequate documentation of performance test\nresults. Also, Form #PS5576 did not provide enough detail to show 1) that the gas\ndetection and alarm system alarmed at not more than 25% of the lower explosive limit\n(LEL), and 2) that each of the audible and visual alarms performed (or did not\nperform) as required during the test.\n9. §192.736 Compressor stations: Gas detection.\n.… (c) Each gas detection and alarm system required by this section must be\nmaintained to function properly. The maintenance must include performance\ntests.\nGulf South’s compressor station gas detection and alarm system performance test\nprocedures were inadequate because they did not detail all the steps necessary for\nconducting gas detection and alarm system performance tests when a compressor unit\nwas running.\nGulf South’s work instruction procedure WI-00085 Test/Maintain Gas Detection &\nAlarm Systems did not list certain required steps necessary to conduct the referenced\nperformance tests when the compressor units were running. For example, WI-00085\ndid not require opening the fuel gas bypass valve between step 3 and step 4, or placing\nthe PLC into bypass mode between step 4 and step 5 when the compressor units were\nrunning during a PHMSA-observed test at the Montpelier Compressor Station. A\nPHMSA inspector witnessed the technician performing these required steps to prevent\nthe compressor units from shutting down during the test. However, the steps were not\nlisted in the work instruction.\n5\n\n\n\n10. §192.605 Procedural manual for operations, maintenance, and emergencies.\n…. (b) Maintenance and normal operations. The manual required by paragraph\n(a) of this section must include procedures for the following, if applicable, to\nprovide safety during maintenance and operations.\n…. (8) Periodically reviewing the work done by operator personnel to determine\nthe effectiveness and adequacy of the procedures used in normal operation and\nmaintenance and modifying the procedure when deficiencies are found.\nGulf South’s O&M procedures were inadequate because they did not include the\nperiodic review of work done by Gulf South gas control personnel to determine the\neffectiveness and adequacy of the procedures used in normal operation and\nmaintenance and to modify the procedures if deficiencies were found.\nAt the time of the inspection, Gulf South management personnel expressed that only a\nverbal review of normal operation and maintenance procedures was conducted with\nGulf South gas controllers.\n11. §192.605 Procedural manual for operations, maintenance, and emergencies.\n…. (c) Abnormal operation. For transmission lines, the manual required by\nparagraph (a) of this section must include procedures for the following to provide\nsafety when operating design limits have been exceeded:\n…. (4) Periodically reviewing the response of operator personnel to determine the\neffectiveness of the procedures controlling abnormal operation and taking\ncorrective action where deficiencies are found.\nGulf South’s O&M procedures were inadequate because they did not include the\nperiodic review of the response of Gulf South gas control personnel to abnormal\noperations to determine the effectiveness of abnormal operation procedures and to\ncorrect deficiencies if found.\nAt the time of the inspection, Gulf South management personnel expressed that only a\nverbal review of the response to abnormal operations was conducted with gas\ncontrollers. They also expressed that corrective actions were adopted when\ndeficiencies were found.\nOn the basis of the inspection, PHMSA has identified apparent inadequacies found within\nGulf South’s Operator Qualification (OQ) program as described in Item 12 below:\n12. §192.805 Qualification program.\nEach operator shall have and follow a written qualification program. The\nprogram shall include provisions to:\n…. (i) After December 16, 2004, notify the Administrator or a state agency\nparticipating under 49 U.S.C. Chapter 601 if the operator significantly modifies\nthe program after the Administrator or state agency has verified that it complies\nwith this section.\nGulf South’s Operator Qualification (OQ) program was inadequate because it did not\nrequire all the notifications an operator was required to make to PHMSA to comply\nwith the OQ regulations.\n6\n\n\n\nGulf South’s OQ program was covered under the Boardwalk OQ Plan (Boardwalk is\nthe parent company of Gulf South). The OQ Plan, Section 3.6, Management of\nChange, contained the subsection entitled “Communication of Significant\nModifications of Program to Office of Pipeline Safety or Applicable State Agency.”\nThe OQ Plan then defined \"significant change\" as being “a change that would weaken\nthe program.\n” Therefore, the OQ Plan required a notification to be made to PHMSA\nonly when plan modifications were made \"that would weaken the program.” This is\nnot consistent with the regulations, which require notification to PHMSA of any\nsignificant modification, regardless of the outcome or results of the modification.\nFor example, Gulf South did not notify PHMSA of the March 3, 2008, merging of the\nTexas Gas and Gulf South OQ plans into a common Boardwalk OQ plan.\nOn the basis of the inspection, PHMSA has identified apparent inadequacies found within\nGulf South’s Integrity Management Program (IMP) as described in Items 13-17 below:\n13. §192.911 What are the elements of an integrity management program?\n…. (b) A baseline assessment plan meeting the requirements of §192.919 and\n§192.921.\n§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…. (b) The methods selected to assess the integrity of the line pipe, including an\nexplanation of why the assessment method was selected to address the identified\nthreats to each covered segment. The integrity assessment method an operator\nuses must be based on the threats identified to the covered segment. ( See\n§192.917.) More than one method may be required to address all the threats to\nthe covered pipeline segment;\n• Item 13A: §192.919(b)\nGulf South’s IMP was inadequate because it did not include in the assessment portion\n(Chapter 6) of its IMP the process it used to assess for hard spot/sleeve interactive\nthreats on applicable pipelines. Gulf South should have documented this process to\nprovide a basis for its past use and to facilitate any modifications of the process for\nongoing assessments.\n• Item 13B: §192.919(b)\nGulf South’s IMP was inadequate because Gulf South’s process for assessing for\nthird-party damage (TPD) when hydrostatic pressure testing was used as the\nassessment method was not adequately documented in its IMP.\nChapter 6, Table 3-1 in the Gulf South IMP indicated that hydrostatic pressure testing\nwas not applicable to assess the TPD threat, with footnote 10 stating, \"Third-Party\nDamage is identified by data integration and managed by Preventative and\nMaintenance Measures.\" But, footnote 10 did not provide sufficient detail as to what\nwas required to assess the TPD threat. There was no mention of the required data sets\nthat should have been used (e.g., one-call tickets, foreign line crossings,\n7\n\n\n\nencroachments, survey results, etc.), or how Gulf South integrated the data. There was\nalso no mention of the methods Gulf South used to gather additional information for\nthe data integration (e.g., CIS, DCVG, etc.). It is important to note that TPD was the\ndominant weighted threat of Gulf South’s IMP, with an assigned threat weighting\nfactor of 0.43.\n14. §192.911 What are the elements of an integrity management program?\n…. (c) An identification of threats to each covered pipeline segment, which must\ninclude data integration and a risk assessment. An operator must use the threat\nidentification and risk assessment to prioritize covered segments for assessment\n(§192.917) and to evaluate the merits of additional preventive and mitigative\nmeasures (§192.935) for each covered segment.\n§ 192.917 How does an operator identify potential threats to pipeline integrity\nand use the threat identification in its integrity program?\n(a) Threat identification. An operator must identify and evaluate all potential\nthreats to each covered pipeline segment. Potential threats that an operator must\nconsider include, but are not limited to, the threats listed in ASME/ANSI B31.8S\n(incorporated by reference, see §192.7), section 2, which are grouped under the\nfollowing four categories:\n(1) Time dependent threats such as internal corrosion, external corrosion, and\nstress corrosion 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\ndamage; and\n(4) Human error.\n(b) Data gathering and integration. To identify and evaluate the potential\nthreats to a covered pipeline segment, an operator must gather and integrate\nexisting data and information on the entire pipeline that could be relevant to the\ncovered segment. In performing this data gathering and integration, an operator\nmust follow the requirements in ASME/ANSI B31.8S, section 4. At a minimum,\nan operator must gather and evaluate the set of data specified in Appendix A to\nASME/ANSI B31.8S, and consider both on the covered segment and similar non-\ncovered segments, past incident history, corrosion control records, continuing\nsurveillance records, patrolling records, maintenance history, internal inspection\nrecords and all other conditions specific to each pipeline.\n§192.935 What additional preventive and mitigative measures must an operator\ntake?\n(a) General requirements. An operator must take additional measures beyond\nthose already required by Part 192 to prevent a pipeline failure and to mitigate\nthe consequences of a pipeline failure in a high consequence area. An operator\nmust base the additional measures on the threats the operator has identified to\neach pipeline segment. (See §192.917) An operator must conduct, in accordance\nwith one of the risk assessment approaches in ASME/ANSI B31.8S (incorporated\nby reference, see §192.7), section 5, a risk analysis of its pipeline to identify\nadditional measures to protect the high consequence area and enhance public\n8\n\n\n\nsafety. Such additional measures include, but are not limited to, installing\nAutomatic Shut-off Valves or Remote Control Valves, installing computerized\nmonitoring and leak detection systems, replacing pipe segments with pipe of\nheavier 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 14A: §192.917(a)\nGulf South’s IMP was inadequate because Gulf South’s practice of identifying hard\nspot related threats was not adequately documented in its IMP.\nThe Gulf South threat identification process indicated that hard spots did not meet the\nthreshold for being a threat of concern. However, given past instances of leaks at\nType A sleeve-repaired hard spot locations on the Gulf South pipeline system (e.g.,\nIndex 129) and the ongoing potential for additional leaks, it would appear that certain\nrepaired hard spots represent a type of time dependent threat that, in fact, rises to a\nlevel of concern.\nGulf South appeared to recognize this and was utilizing magnetic flux leakage (MFL)\nin-line inspection (ILI) assessments to provide indicators that corrosion and/or coating\ndeterioration had occurred near Type A sleeve repaired hard spots, which could then\npotentially lead to hydrogen induced hard spot cracking. This practice, however, was\nnot adequately addressed in the IMP Chapter 4, Threat Identification, Data\nIntegration, and Risk Assessment.\n• Item 14B: §192.917(a)\nGulf South’s IMP was inadequate because Gulf South’s process for evaluating the\nthreat of potential pipe seam defects on certain vintage pipe was not properly\ndocumented in its IMP, which resulted in inconsistencies.\nGulf South’s IMP had two different algorithms that addressed potential seam defects\nand the two algorithms conflicted with each other in certain scenarios. Gulf South's\nprimary risk algorithm used to address potential seam defects was contained in\nAppendix 1, Section 2.5.2 of its IMP. This risk algorithm generated a Seam Defect\nScore. The secondary threat assessment algorithm used to address potential seam\ndefects was a flow chart shown in Chapter 4 Figure 2-7of the IMP, i.e. Manufacturing\nThreat Criteria.\nThe source of the inconsistencies related to pressure tests requirements. The Seam\nDefect Score risk algorithm indicated that pressure test applicability was only a\nfunction of maximum test pressure. It did not, however, consider if the pressure test\nwas equivalent to a Part 192, Subpart J test, which has many requirements in addition\nto maximum test pressure. Conversely, the Manufacturing Threat Criteria in Figure\n2-7 did indicate that a Subpart J pressure test was required to address potential seam\ndefects.\n9\n\n\n\nThis process inconsistency was reflected in the Seam Defect Score for Index 129, a\n1952 A.O. Smith flash welded pipeline located in HCA 809. Because this pipeline\nwas not subjected to a Subpart J test, the algorithm used for Manufacturing Threat\nCriteria, i.e. Figure 2-7 indicated this pipe to be a threat. Yet, the Seam Defect Score\nwas zero, which effectively eliminated this pipe at the time as a candidate for\nassessment.\nIn the absence of a Subpart J pressure test, the federal pipeline safety regulations and\nincorporated references consider seam defects to be stable threats only when there has\nbeen no MAOP increase, the 5-yr historical maximum operating has not been\nexceeded, the pipeline was not subjected to cyclic fatigue or other interacting threats,\nand there was no failure history of similar pipe. If a pipeline meets all these criteria,\nintegrity assessments capable of assessing seam integrity are not required. Instead the\npipe must be monitored for MAOP increases, pressure increases exceeding the 5-yr\nhistorical conditions, cyclic fatigue, seam failures elsewhere in the system, and other\ninteracting threats.\n• Item 14C: §192.917(b)\nGulf South’s IMP was inadequate because Gulf South’s procedures did not require the\nintegration of ILI tool tolerance in making decisions regarding remediation of\nanomalies.\nGulf South's IMP addressed ILI tool tolerance in Appendix 4 Section 13 only in the\ncontext of determining reassessment intervals, not with regards to making decisions\nregarding remediation of anomalies. PHMSA inspectors discussed this with Gulf\nSouth during the inspection and were told it was being evaluated by Gulf South.\n• Item 14D: §192.935(a)\nGulf South’s IMP preventive and mitigative (P&M) measures processes were\ninadequate because they did not address all the threats to pipeline integrity that Gulf\nSouth has identified. Gulf South's processes only specifically evaluated Third-Party\nDamage, Corrosion, and Outside Force threats for P&M measures, though Chapter 8,\nSection 2, Table 2-1 of its IMP lists other threats for which candidate measures are\navailable.\n15. § 192.911 What are the elements of an integrity management program?\n…. (d) A direct assessment plan, if applicable, meeting the requirements of\n§192.923, and depending on the threat assessed, of §§192.925, 192.927, or\n192.929.\n§ 192.925 What are the requirements for using External Corrosion Direct\nAssessment (ECDA)?\n…. (b) General requirements. An operator that uses direct assessment to assess\nthe threat of external corrosion must follow the requirements in this section, in\nASME/ANSI B31.8S (incorporated by reference, see §192.7), section 6.4, and in\nNACE RP 0502–2002 (incorporated by reference, see §192.7). An operator must\ndevelop and implement a direct assessment plan that has procedures addressing\npreassessment, indirect examination, direct examination, and post-assessment. If\n10\n\n\n\nthe ECDA detects pipeline coating damage, the operator must also integrate the\ndata from the ECDA with other information from the data integration\n(§192.917(b)) to evaluate the covered segment for the threat of third party\ndamage, and to address the threat as required by §192.917(e)(1).\n(1) Preassessment. In addition to the requirements in ASME/ANSI B31.8S\nsection 6.4 and NACE RP 0502–2002, section 3, the plan's procedures for pre-\nassessment must include—\n(i) Provisions for applying more restrictive criteria when conducting ECDA\nfor the first time on a covered segment; and\n(ii) The basis on which an operator selects at least two different, but\ncomplementary indirect assessment tools to assess each ECDA Region. If an\noperator utilizes an indirect inspection method that is not discussed in Appendix\nA of NACE RP0502–2002, the operator must demonstrate the applicability,\nvalidation basis, equipment used, application procedure, and utilization of data\nfor the inspection method.\n(2) Indirect examination. In addition to the requirements in ASME/ANSI\nB31.8S section 6.4 and NACE RP 0502–2002, section 4, the plan's procedures for\nindirect examination of the ECDA regions must include—\n(i) Provisions for applying more restrictive criteria when conducting ECDA\nfor the first time on a covered segment;\n(ii) Criteria for identifying and documenting those indications that must be\nconsidered for excavation and direct examination. Minimum identification\ncriteria include the known sensitivities of assessment tools, the procedures for\nusing each tool, and the approach to be used for decreasing the physical spacing\nof indirect assessment tool readings when the presence of a defect is suspected;\n(iii) Criteria for defining the urgency of excavation and direct examination of\neach indication identified during the indirect examination. These criteria must\nspecify how an operator will define the urgency of excavating the indication as\nimmediate, scheduled or monitored; and\n(iv) Criteria for scheduling excavation of indications for each urgency level.\n(3) Direct examination. In addition to the requirements in ASME/ANSI\nB31.8S section 6.4 and NACE RP 0502–2002, section 5, the plan's procedures for\ndirect examination of indications from the indirect examination must include—\n(i) Provisions for applying more restrictive criteria when conducting ECDA\nfor the first 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 allowable limits (Section\n5.5.2.2 of NACE RP0502–2002), or\n(B) Root cause analysis reveals conditions for which ECDA is not suitable\n(Section 5.6.2 of NACE RP0502–2002);\n(iii) Criteria and notification procedures for any changes in the ECDA Plan,\nincluding changes that affect the severity classification, the priority of direct\nexamination, and the time frame for direct examination of indications; and\n(iv) Criteria that describe how and on what basis an operator will reclassify\nand reprioritize any of the provisions that are specified in section 5.9 of NACE\nRP0502–2002.\n11\n\n\n\n(4) Post assessment and continuing evaluation. In addition to the\nrequirements in ASME/ANSI B31.8S section 6.4 and NACE RP 0502–2002,\nsection 6, the plan's procedures for post assessment of the effectiveness of the\nECDA process must include—\n(i) Measures for evaluating the long-term effectiveness of ECDA in addressing\nexternal corrosion in covered segments; and\n(ii) Criteria for evaluating whether conditions discovered by direct\nexamination of indications in each ECDA region indicate a need for reassessment\nof the covered segment at an interval less than that specified in §192.939. (See\nAppendix D of NACE RP0502–2002.)\n§ 192.927 What are the requirements for using Internal Corrosion Direct\nAssessment (ICDA)?\n…. (c) The ICDA plan. An operator must develop and follow an ICDA plan that\nprovides for preassessment, identification of ICDA regions and excavation\nlocations, detailed examination of pipe at excavation locations, and post-\nassessment evaluation and monitoring.\n(1) Preassessment. In the preassessment stage, an operator must gather and\nintegrate data and information needed to evaluate the feasibility of ICDA for the\ncovered segment, and to support use of a model to identify the locations along the\npipe segment where electrolyte may accumulate, to identify ICDA regions, and to\nidentify areas within the covered segment where liquids may potentially be\nentrained. This data and information includes, but is not limited to—\n(ii) Information needed to support use of a model that an operator must use to\nidentify areas along the pipeline where internal corrosion is most likely to occur.\n(See paragraph (a) of this section.) This information, includes, but is not limited\nto, location of all gas input and withdrawal points on the line; location of all low\npoints on covered segments such as sags, drips, inclines, valves, manifolds, dead-\nlegs, and traps; the elevation profile of the pipeline in sufficient detail that angles\nof inclination can be calculated for all pipe segments; and the diameter of the\npipeline, and the range of expected gas velocities in the pipeline;\n§ 192.929 What are the requirements for using Direct Assessment for Stress\nCorrosion Cracking (SCCDA)?\n…. (b) General requirements. An operator using direct assessment as an integrity\nassessment method to address stress corrosion cracking in a covered pipeline\nsegment must have a plan that provides, at minimum, for—\n…. (2) Assessment method. The plan must provide that if conditions for SCC are\nidentified in a covered segment, an operator must assess the covered segment\nusing an integrity assessment method specified in ASME/ANSI B31.8S, appendix\nA3, and remediate the threat in accordance with ASME/ANSI B31.8S, appendix\nA3, section A3.4.\n• Item 15A: §192.925(b)\nGulf South’s IMP was inadequate because the definition of the word \"should\" was not\nconsistent throughout its IMP.\n12\n\n\n\nThe definition of \"should\" in Gulf South External Corrosion Direct Assessment Plan\n(ECDAP), Section 1.10, Definitions, was not consistent with the definition of \"should\"\nused in Gulf South’s overall IMP. That is, Gulf South's ECDAP did not require\nwritten technical justification for deviations from “should” statements or\nrecommendations in incorporated documents, including NACE Standard RP0502-\n2002 “Pipeline External Corrosion Direct Assessment Methodology.”\n• Item 15B: §192.925(b)(3)(i)\nGulf South’s IMP was inadequate because the manner in which Gulf South\nimplemented the §192.925 (b)(3)(i) requirement for \"more restrictive criteria when\nconducting ECDA for the first time on a covered segment\" in the direct examination\nphase of ECDA was not apparent to PHMSA inspectors who reviewed Figure 4-2,\nTable 4-1, and the narrative found in ECDAP Sections 4.1 and 4.2.\n• Item 15C: §192.925(b)(3)\nGulf South’s IMP was inadequate because the verbiage in ECDAP Sections 4.1 and\n4.2 and associated Table 4-1 and Figure 4-2 was not consistent and did not clearly\ndefine the intent of the number of required digs for each case.\nFor example, Table 4-1 heading \"For Each ECDA Region\" was not consistent with\nContaining/Action verbiage for the \"most likely corroded region\" in the Monitored\nOnly and No Indication cases. Table 4-1 did not address the Figure 4-2 description of\n\"Were any of the above digs found more severe than IMMEDIATE and have >20%\nwall loss?\" In addition, the word \"uprated\" (i.e. \"If Indications Are Uprated\") in\nTable 4-1 was not defined in the ECDAP.\n• Item 15D: §192.925(b)(4)\nGulf South’s IMP was inadequate because its ECDAP did not properly include the\nrequirements of NACE RP 0502–2002, Section 6, as required by §192.925(b)(4). The\nfollowing statement, found in ECDAP Section 5.1 was incorrect: \"Calculation: The\nlargest scheduled indications for ECDA Region after the reprioritization process shall\nhave their remaining life determined.\" NACE RP0502-2002 Section 6.2.2 actually\nrequires the largest non-unique corrosion defect found to be applied regardless of\nwhether or not it has been repaired.\n• Item 15E: §192.927(c)(1)(ii)\nGulf South’s IMP was inadequate because the minimum requirements to provide\naccurate line and feature location elevation information to support Internal Corrosion\nDirect Assessment (ICDA) were not well defined in its Internal Corrosion Direct\nAssessment Plan (ICDAP), as required by §192.927(c)(1)(ii).\nGulf South's ICDAP (effective 08/01/09) Section 3.6 states, \"USGS maps represent a\nminimum profile accuracy requirement.\" This general reference to USGS, however,\ndid not specify a minimum accuracy needed to adequately perform ICDA while the\nICDAP Section 3.6 specifically states, \"Collecting accurate information regarding the\nelevation and inclination of a pipeline is particularly important in DB-ICDA.\n\"\nPHMSA has inspected ICDA plans using USGS maps for the calculation of\ninclination angles and has found the method to be insufficient in some applications.\n13\n\n\n\n• Item 15F: §192.929(b)(2)\nGulf South’s IMP was inadequate because its Stress Corrosion Cracking Direct\nAssessment Plan (SCCDAP) was not in accordance with the threat remediation\nrequirements of §192.929(b)(2). The SCCDAP was not clear in Sections 4 and 5 that\nall areas of detected SCC indications (including those not defined as \"significant\")\nmust be mitigated in accordance with §192.929(b)(2) and ASME B31.8S Section\nA3.4.1.d.2.\nAlso, the SCCDAP did not clearly specify actions Gulf South should take based on\nconditions it identified during the direct examination phase. SCCDAP Sections 4 and\n5 were not consistent with descriptions of certain SCC severity categories and how\nthey relate separately to mitigation and assessment intervals. For example, Section 4.4\nstates, \"A category 2 crack has a failure pressure that is greater than Boardwalk's\n[Gulf South's] safety tolerance and","truncated":true,"body_characters":48616}