{"operation":"document","citation":"PHMSA-2016-0006","title":"Southern Natural Gas Company, LLC — Pipeline Special Permit","source_type":"permit","agency":"Pipeline and Hazardous Materials Safety Administration","status":"current","official":true,"published_on":"2016-09-01","effective_on":"2016-09-01","summary":"PHMSA-2016-0006, issued 2016-09-01 for Southern Natural Gas Company, LLC's gas transmission system.","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2016-0006.json","markdown":"https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2016-0006.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2016-0006","source_url":"https://www.regulations.gov/docket/PHMSA-2016-0006","body":"PHMSA pipeline special permit PHMSA-2016-0006. Operator: Southern Natural Gas Company, LLC. System: Gas Transmission. Issue date: 2016-09-01. Renewal: Mar 17, 2023.\n\n<<<PAGE 1>>>\n\nU.S. DEPARTMENT OF TRANSPORTATION\nPIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION\nSPECIAL PERMIT\nSpecial Permit Information:\nDocket Number:\nRequested By:\nOperator ID#:\nDate Requested:\nOriginal Issuance Date:\nEffective Dates:\nPHMSA-2016-0006\nSouthern Natural Gas Company, L.L.C.\n18516\nJanuary 11 ,2016\nSeptember 1, 2016\nCode Section(s):\nSeptember 1, 2016 to September 1, 2021\n49 CFR §§ 192.611 (a) and (d), 192.619(a), and 192.5\nGrant of Special Permit:\nBy this Order, subject to the terms and conditions set forth below, the Pipeline and Hazardous\nMaterials Safety Administration (PHMSA) Office of Pipeline Safety (OPS) grants a special\npermit (PHMSA-20 16-0006) from September 1, 20 16 to September 1, 2021, to Southern Natural\nGas Company, L.L.C. (SNG) 1 waiving compliance from 49 Code of Federal Regulations (CFR)\n§§ 192.6 11 (a) and (d), 192.619(a), and 192.5 for 26 special permit segments and 5.90 miles of\nnatural gas transmission pipeline as described in Appendix A 2 of this special permit.\nI. Special Permit Segment and Special Permit Inspection Area:\nStates of Alabama, Georgia, Louisiana, and Mississippi\nOn the condition that SNG complies with the terms and conditions set forth below, this special\npermit waives compliance from 49 CFR § 192.611 (a) for 26 special permit segments and 5.90\nmiles of natural gas transmission pipeline as described in Appendix A. This special permit\nallows SNG to continue to operate each special permit segment listed in Appendix A at its\n1 SNG is owned by Kinder Morgan, Inc.\n2 Appendix A of this special permit lists the pipeline special permit segmetJt location (County and State), MAOP,\nclass location, diameter, wall thickness, grade, seam type, boundaries, and other attributes.\nSpecial Permit: PHMSA-2016-0006- Southern Natural Gas Company Page 1 of27\n\n<<<PAGE 2>>>\n\ncurrent listed maximum allowable operating pressure (MAOP). The Federal pipeline safety\nregulations in 49 CFR § 192.611 (a) require natural gas pipeline operators to confirm or revise the\nMAOP of a pipeline segment after a change in class location.\nThis special permit applies to the special permit segments listed in Appendix A. Special permit\nsegments shall be divided into two (2) categories: Type A special permit segments and Type B\nspecial permit segments.\nType A special permit segments include those special permit segments where there is a cluster,\nas described in 49 CFR § 192.5(c), ofmore than 10 buildings intended for human occupancy in a\n\"class location unit\" and for which the MAOP has not been confirmed in accordance with 49\nCFR § 192.611 (a). Type A special permit segments must be replaced or pressure tested so that\nthe MAOP is commensurate with the present class location within three (3) years of issuance of\nthis special permit. Type A special permit segments3 total 1.54 mites of pipe as described in\nAttachment A.\nType A special permit segments with pipe with integrity issues as determined by Conditions\n6(c) and 14 or that have not been pressure tested in accordance with 49 CFR Part 192, Subpart J\nto 1.25 times MAOP of this special permit must be replaced within two and one-half (2Y 2) years\nof the grant of this special permit or within two (2) years of assessment finding.\nType B special permit segments include those special permit segments where there is a cluster,\nas described in 49 CFR § 192.5(c), of I 0 or fewer buildings intended for human occupancy in a\n\"class location unit\" and for which the MAOP has not been confirmed in accordance with 49\nCFR § 192.611 . Type B special permit segments4 total 4.36 miles of pipe as described in\nAttachment A.\n3 There are 1.54 miles of Type A special permit segments and of this total 1.50 miles must be replaced and 0.04\nmiles must be pressure tested as listed on Attachment A, see Condition 16 for pressure test requirements.\n4 There are 4.36 miles of Type B special permit segme11ts and 0.72 miles of this total must be pressure tested as\nlisted on Attachment A, see Condition 16 for pressure test requirements. One (I ) Type B special permit segment\n(KM segment number 352) is a § 192.6 19(c) Grandfathered segment and wi ll require pressure testing.\nPHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 2 of27\n\n<<<PAGE 3>>>\n\nSubsequent to the issuance of this special permit, those special permit segments that have been\npressure tested or replaced such that the MAOP has been made commensurate with the present\nclass location as defined in 49 CFR § 192.6 11 would no longer be included in this special permit.\n5\nSpecial permit inspection area\n- is defined as a one ( I) mile continuous segment on both sides\nof the special permit segment (Type A and Type B) plus the footage in the special permit\nsegment. Appendix A lists the boundaries for the special permit inspection area associated with\neach special permit segment. The SNG special permit inspection area totals 57.90 miles of pipe\nas described in Attachment A.\nPHMSA hereby grants this special permit for the pipeline special permit segments listed in\nAppendix A based on the findings set forth in the \"Special Permit Analysis and Findings \"\ndocument, which can be read in its entirety in Docket No. PHMSA-2016-0006 in the Federal\nDocket Management System (FDMS) located on the internet at www.Regulations.gov.\nII. Conditions:\nPHMSA OPS grants this special permit subject to the following conditions:\nl) Maximum Allowable Operating Pressure: SNG must continue to operate the special\npermit segments at or below their existing MAOP as noted in Appendix A.\n2) Integrity Management Program: SNG must incorporate the special permit inspection\nareas into its written integrity management program (IMP) as a \"covered segment \" in a\n\"high consequence area (HCA) \" in accordance with 49 CFR § 192.9036\n.\n3) Close Interval Surveys: SNG must perform a close interval survey (CIS) along the entire\n5 Special permit inspection areas throughout these conditions include special permit segme11ts unless specifically\ndefined as not applicable or if the special permit segment has more stringent conditions.\n6 SNG is not required to report the mileage included as part of this special permit in its annual report per the\nrequirements of 49 CFR § 191. 17, unless it is in a high consequence area.\nPHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 3 of27\n\n<<<PAGE 4>>>\n\nlength of all special permit inspection areas\n7 and remediate any areas of inadequate cathodic\nprotecti on no later than three (3) years after the issuance of this special permit. However, a\nCIS need not be performed if SNG has performed a CIS and completed remediation8\nincluding damaged coating repair along the entire length of all special permit inspection\nareas Jess than seven (7) years9 prior to the issuance of this special permit. If environmental\npermitting or right-of-way factors beyond SNG control should prevent the completion of the\nCIS within three (3) years from the issuance of this special permit, a CIS and subsequent\nremediation including coating repair must be completed as soon as practicable and a letter\njustifying the delay and providing the anticipated date of completion must be submitted to the\nappropriate PHMSA OPS Region Director no later than three (3) months pri or to the end of\nthree (3) years after the issuance of this special permit and must receive a \"no objection\"\nfrom the PHMSA OPS Region Director for a delay. CIS remediation activities must be\ncompleted within one (1) year of the finding. Any extended evaluation and remediation\nschedules submitted to PHMSA from SNG must receive a \"no objection\" from the\nappropriate PHMSA OPS Region Director to implement an extended CIS and remediation\ninterval.\n4) Close Interval Surveys- Reassessment Interval: SNG must perform a periodic close\ninterval survey (CIS) of the special permit inspection areas at the applicable reassessment\ninterval(s) for a \"covered segment\" in accordance with 49 CFR Part 192, Subpart 0, for\nreassessment intervals as contained in 49 CFR §§ 192.937(a) and (b) and 192.939, not to\nexceed a seven (7) year reassessment interval10\n• CIS data shall be integrated with in-line\ninspection (ILl) data. Condition I5(b)- Data Integration - gives a complete description of\n7 Each condition that requires SNG to perform an action with respect to the special permit inspection areas shall\nalso require SNG to perform that action on all special permit segments within such areas. T ype A special permit\nsegments that will be replaced within three (3) years of this special permit issuance do not require a CIS.\n8 The terms \"remediate\" or \"remediation\" of pipe coating shall include repair of damaged external pipe coating,\nwhere required to maintain cathodic protection of the pipeline in accordance with 49 CFR § 192.463.\n9 lf49 CFR § 1 92.939(a) integrity management reassessment interval sho uld change·from seven (7) years to some\nother reassessment interval under eig ht (8) years, SNG may use that reassessment interval instead of seven (7)\nyears.\n10 If 49 CFR § 192.939(a) integrity management reassessment interval should change from seven (7) years to some\nother reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7)\nyears.\nPHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 4 of27\n\n<<<PAGE 5>>>\n\ndata integration information that an operator must maintain for a special permit in the special\npermit inspection areas which includes CIS and ILl data. CIS assessments within the\nreassessment interval are not required to be performed in the same year as ILl reassessments.\n5) Cathodic Protection Reliability Improvement Plan: SNG shall implement a plan to\nimprove cathodic protection reliability and perform inspections for stress corrosion cracking\n(SCC).\na) Cathodic Protection Reliability Improvement Plan\ni) SNG must perform a periodic CIS of special permit inspection areas as part\nof Condition 4, Close Interval Surveys, with reassessment intervals at an\nincreased frequency, not to exceed a seven (7) year reassessment interval\nwith CIS data integrated with the most-recent in-line inspection data 11\n;\nii) SNG must integrate the most current CIS data with in-line inspection results\nin the special permit inspection area in accordance with Condition 15(b)\ntiming requirements:\niii) Within 90 days of the issuance of this special permit, SNG must amend\napplicable sections of its operations and maintenance (O&M) manual(s) to\nprohibit future use of coating that is known to shield cathodic protection\nalong the entire length of the special permit inspection areas; and\niv) SNG must perform a run comparison analysis of in-line inspection results\nsubsequent to the baseline inspection in the special permit inspection areas\nto identify areas of external corrosion growth after each new tool run when\nthe same in-line inspection vendor is used for consecutive inspections.\nAreas with corrosion growth over 30% in depth must be remediated within\none ( 1) year of the finding or direct current voltage gradient (DCVG) survey\nrun to locate problem coating areas within six (6) months of the finding with\nremediation completed within six (6) months of the DCVG survey.\n11 lf49 CFR § 192.939(a) integrity management reassessment interval should change fTom seven (7) years to some\nother reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7)\nyears.\nPHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 5 of27\n\n<<<PAGE 6>>>\n\nv) Within one ( 1) year of the issuance of this special permit, SNG must install\ncathodic protection remote monitoring units (RMUs) at all impressed\ncurrent sources directly influencing the special permit segments;\nvi) SNG must configure the RMUs in the special permit segments with alarms\nto notify SNG immediately in the event of any interruption in cathodic\nprotection current output; and\nvii)SNG must respond and correct any interruption in cathodic protection\ncurrent output immediately (within two (2) working days). If a systemic\nissue is present, then SNG must investigate and remediate the problem\nwithin one ( 1) month or less or SNG must receive a \"no objection\" from the\nappropriate PHMSA OPS Region Director for issues that require longer to\nremediate.\nb) Stress Corrosion Cracking Inspections\ni) SNG must review historical records to determine if SCC inspections have\nbeen performed in the special permit segments and from these inspections\nevaluate the threat of stress-corrosion cracking as part of the SCCDA Pre-\nAssessment Step in Condition 6(a).\nii) SNG must perform magnetic particle inspection on any pipe (with the\nexception of pipe coated with fusion-bonded or liquid-applied epoxy\ncoatings, which are not at risk for SCC) excavated in the special permit\ninspection areas to evaluate the pipe for sec where disbonded coating is\nremoved in order to perform the inspection.\n6) Stress Corrosion Cracking Direct Assessment: SNG must evaluate pipelines along the\nentire length of the special permit inspection areas for sec as follows:\na) SNG must perform a stress corrosion cracking direct assessment (SCCDA) or other\nappropriate assessment method for sec [such as pressure test or in-line inspection\n(ILl) with a crack detection tool] of pipelines along the entire length of all special\npermit inspection areas according to the requirements of 49 CFR § 192.929 and/or\nNACE SP 0204-2008 no later than three (3) years after of the issuance of this special\nPHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 6 of27\n\n<<<PAGE 7>>>\n\npermit. The SCCDA or other approved method must address high pH SCC and near\nneutral pH SCC. The SCCDA Pre-Assessment Step will include the results of all\nclose-interval surveys and coating surveys required in Conditions 3, 4, and 5.\ni) If environmental permitting or right-of-way factors beyond SNG control\nprevent the completion of the SCCDA survey and remediation within three\n(3) years from the issuance ofthis special permit, a SCCDA and remediation\nmust be performed as soon as practicable and a letter justifying the delay\nand providing the anticipated date of completion must be submitted to the\nappropriate PHMSA OPS Region Director no later than three (3) months\nprior to the end of three (3) years after the issuance of this special permit\nand must receive a \"no objection\" from the PHMSA OPS Region Director\nfor a delay.\nii) SNG may eliminate this Condition 6(a), provided SNG provides an\nengineering assessment showing that the pipeline does not meet the criteria\nfor either near neutral or high pH SCC in accordance with the applicable\nedition of the American Society of Mechanical Engineers Standard B31.8S,\n\"Managing System Integrity of Gas Pipelines \" (ASME B3 1.8S), Appendix\nA3, or NACE SP 0204-2008, \"Stress Corrosion Cracking (SCC) Direct\nAssessment Methodology \", Section 1.2. 1.1 and 1.2.2.\niii) A SCCDA need not be performed ifSNG has performed a SCCDA of\npipelines along the entire length of the special permit inspection areas\nwithin the timeframe for SCCDA re-assessments specified in 49 CFR Part\n192, Subpart 0 , not to exceed seven (7) years\n1 2 prior to the issuance of this\nspecial permit.\nb) If the SCCDA required in Condition 6(a) demonstrates SCC, SNG must directly\nexamine pipe in the special permit inspection areas for sec using an accepted\nindustry detection practice, such as dry or wet magnetic particle tests, anytime the\npipelines are exposed for any reason, including damage prevention activities. Poor\ncoating is coating losing adhesion to the pipe which is shown by falling off the pipe,\n1 2 If 49 CFR § 1 92.939(a) integrity management reassessment interval should change from seven (7) years to some\nother reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7)\nyears.\nPHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 7 of27\n\n<<<PAGE 8>>>\n\nand/or shields the cathodic protection. SNG must keep coating records13 of all\nexcavation locations for the special permit inspection areas to demonstrate the\ncoating condition.\nc) If SCC14\nactivity is discovered by any means within the special permit inspection\narea in similar pipe and pipe coating vintage [in accordance with 49 CFR\n§ 192.917(e)], or has had an in service or hydrostatic test sec failure or leak; the\nspecial permit segment must be further assessed and mitigated, using one of the\nfollowing methods, within one ( I) year of finding SCC:\ni) Hydrostatic test program\nA. The SCC hydrostatic test program must be performed at a\nreassessment interval no greater than seven (7) calendar years (but\nmay be at a lesser interval in accordance with the results of an\nengineering critical assessment) in the special permit segment.\nB. If pipe in the special permit segment leaks or ruptures during a\nhydrostatic test due to sec, all pipe in the special permit segment\nmust be replaced with new pipe within 18 months of the completion of\na successful SCC hydrostatic test. A successful SCC hydrostatic test\nmust be completed prior to returning the special permit segment to\noperational service.\nii) Crack detection tool assessment\nA. sec detection tool must be run in the special permit inspection area,\nB. All SCC 15 cracking found in the special permit segment must be\nreplaced with new pipe within one (I ) year of finding sec,\niii) Operating pressure lowered to 60% of the specified minimum yield strength\n(SMYS),\niv) Replace all affected pipe to meet 49 CFR § 192.6 11 in the special permit\nsegment.\n1 3 The records must include, at a minimum, a description of the SNG 's detectio n procedures, records of finding, and\nmitigation procedures implemented for the excavation.\n14 \" SCC\" activity shall be defined as over both I 0 percent wall thickness depth and 2-inches in length.\n15 ··sec· activity shall be defined as over both I 0 percent wall thickness depth and 2-inches in length.\nPHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 8 of27\n\n<<<PAGE 9>>>\n\nd) If any SCC activity is discovered in the special permit inspection area, SNG must\nsubmit a SCC remediation plan to the appropriate PHMSA OPS Region Director with\na copy to the Director, PHMSA OPS Engineering and Research Division no later than\n60 days after the finding of SCC:\ni) That meets Condition 6(c), including a SCC remediation/repair plan with\nsec characterization and timing, or\nii) Technical justification that shows that the threat for SCC in the special\npermit segment is being addressed.\n7) O&M Manual- In-line Inspections, Close Interval Survey Inspections, and\nReassessment Intervals: SNG must amend applicable sections of its operations and\nmaintenance (O&M) manual(s) to incorporate the in-line inspection (ILl), close interval\ninspections (CIS), and reassessment intervals by the appropriate integrity assessment method\nincluding both high resolution metal loss and deformation/geometry tools along the entire\nlength of the special permit inspection areas at a frequency consistent with 49 CFR Part 192,\nSubpart 0 , but not to exceed a seven (7) year reassessment interval1 6\n•\n8) In-Line Inspection Initial Assessment: SNG must perform integrity assessments along the\nentire length of the special permit inspection areas using appropriate assessment methods\nbased on threats identified during the risk assessment process including both high resolution\nmagnetic flux leakage (HR-MFL) and either HR-geometry or HR-deformation tools. If\nintegrity assessments have not been performed within seven (7) years prior to the issuance of\nthis special permit, SNG must complete initial integrity assessments along the entire length\nof the special permit inspection areas within three (3) years of the issuance of this special\npermit. Subsequent integrity assessments along the entire length of the special permit\ninspection areas must conform to the required maximum reassessment intervals specified in\n49 CFR § 192.939, but may not exceed a seven (7) year reassessment interval17\n.\n1 6 If 49 CFR § 1 92.939(a) integrity management reassessment interval should change from seven (7) years to some\nother reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7)\nyears.\n17 If 49 CFR § 192.939(a) integrity management reassessment interval should change from seven (7) years to some\nother reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7)\nyears.\nPHMSA-2016-0006 - Southern Natural Gas Company Special Permit Page 9 of27\n\n<<<PAGE 10>>>\n\n9) Integrity Reassessment Intervals: SNG must schedule integrity reassessment dates for the\nentire length of the special permit inspection areas according to 49 CFR § 192.939 by\nadding the required time interval to the previous assessment date, but may not exceed a seven\n(7) year reassessment interval 18\n•\n1 0) High Consequence Area Assessments: SNG must not let this special permit be a basis fo r\ndeferring any of its assessments for HCAs in accordance with 49 CFR Part 192, Subpart 0.\n11) Annual Reports to PHMSA: Within three (3) months following the issuance of this special\npermit and annually\n1 9 thereafter, SNG must report the following to the appropriate PHMSA\nOPS Region Director with copies to the Deputy Associate Administrator, PHMSA Field\nOperations; Deputy Associate Administrator, PHMSA Policy and Programs; Director,\nPHMSA Engineering and Research Division; and Director, PHMSA Standards and\nRulemaking Division:\na) The number of new residences, other structures intended for human occupancy and\npublic gathering areas built within the special permit segment and also within one ( I)\nmile on either end of the special permit segment.\nb) Any new integrity threats identified during the previous year and the results of any\nILl or direct assessments performed (including any un-remediated anomalies over\n30% wall loss, cracking found in the pipe body, weld seam or girth welds, and dents\nwith metal loss, cracking or stress riser) during the previous year in the special permit\ninspection segment.\nc) Any reportable incident or any leak normally indicated on the DOT Annual Report,\nand all repairs on the pipeline that occurred during the previous year in the special\npermit inspection areas.\n18 If 49 CFR § 192.939(a) integrity management reassessment interval should change from seven (7) years to some\nother reassessment interval under eight (8) years, SNG may use that reassessment interval instead of seven (7)\nyears.\n1 9 Annual reports must be received by PHMSA by the last day of the month in which the Special Permit is dated.\nFor example, the annual report for a modified Special Permit dated November, 20 1 2, must be received by\nPHMSA no later than November 30, each year beginning in 20 13.\nPHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 10 of27\n\n<<<PAGE 11>>>\n\nd) Summary report of any fatigue analysis performed on all in-service, non-remediated\ndents over 6% and with total strain :S 5%, as required in Condition 13(b ).\ne) Annual data integration information, as required in Condition l5(b) - Data Integration\nmust be submitted beginning with the 2\"d annual report that includes an annual\noverview of any new threats, or if requested by PHMSA a fu ll information package.\nf) Any mergers, acquisitions, transfer of assets, or other events affecting the regulatory\nresponsibility of the company operating the pipeline.\ng) An updated Appendix A reflecting changes in Special Permit Segment boundaries\nincluding extensions, deletions, or modifications.\nh) In the first annual report, SNG must describe the estimated economic benefits of the\nspecial permit including both the capital and operational costs avoided from not\nreplacing the pipe and the estimated incremental operational costs of any inspection\nprogram requirements of the special permit for the 5-year grant period that are not\nalready being conducted by SNG through their operational procedures.\ni) In the first annual report, SNG must describe whether the public benefits from energy\navailability. This should address the benefits of any avoided disruptions as a\nconsequence of pipe replacement and the benefits of maintaining system capacity.\n12) Interference Currents Control: SNG must address induced alternating current (AC) from\nparallel electric transmission lines and other interference issues such as direct current (DC) in\nthe special permit inspection areas that may affect the pipeline. An induced AC or DC\nprogram and remediation plan to protect the pipeline from corrosion caused by stray currents\nmust be in place within one (l) year of the date of this special permit.\na) At least once every seven (7) years not exceeding 90 months, SNG must perform an\nengineering analysis on the effectiveness of the AC and DC mitigation measures and\nmust evaluate any AC interference between 20 and 50 Amps per meter squared. In\nevaluating such interference, SNG must integrate AC interference data with the most\nrecent ILl results to determine remediation measures. Any AC interference between\n20 and 50 Amps per meter squared must be remediated within six (6) months of the\nfinding. If SNG does not remediate AC interference between 20 and 50 Amps per\nPHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 11 of27\n\n<<<PAGE 12>>>\n\nmeter squared, SNG must provide an engineering justification for not remediating\nsuch interference to the appropriate PHMSA OPS Region Director, who may accept\nor reject the justification and require remediation.\nb) In special permit inspection areas with co-located high voltage alternating current\nc) d) (HYAC) power lines, SNG must take interference readings (continuous 24 hour\nrecordings) during the calendar quarter of the known or anticipated highest voltage\nreading. If there are any significant increases to the amount of electricity/current\nflowing in any co-located high voltage alternating current (HY AC) power li nes, such\nas from additional generation, a voltage up-rating, additional lines, or new or enlarged\nsubstations, SNG must perform an AC mitigation survey along the entire co-located\npipeline special permit inspection area right of way within six (6) months of any\nsuch change.\nWithin six (6) months of the engineering analysis, SNG must remediate any AC\ninterference greater than 50 Amps per meter squared. Remediation means the\nimplementation of performance measures including, but not limited to, additional\ngrounding along the pipeline to reduce interference currents. Any DC interference\nthat results in CP levels that do not meet the requirements of 49 CFR Part 192,\nSubpart I, must be remediated within six (6) months of this evaluation.\nIf environmental permitting or right-of-way factors \" beyond SNG control\" prevent\nthe completion of remediation within six ( 6) months of the interference evaluation.\nremediation must be completed as soon as practicable and a letter justifying the delay\nand providing the anticipated date of completion must be submitted to the appropriate\nPHMSA OPS Region Director no later than one ( 1) month prior to the end of the six\n(6) months completion date. Any extended evaluation and remediation schedules\nsubmitted to PHMSA from SNG must recei ve a \"no objection\" from the appropriate\nPHMSA OPS Region Director.\n13) Anomaly Evaluation and Repair:\na) General: SNG must account for ILl tool tolerance and corrosion growth rates in\nscheduled response times and repairs and document and justify the values used. SNG\nmust demonstrate ILl Tool tolerance accuracy for each ILl Tool run by usage of\nPHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 12 of 27\n\n<<<PAGE 13>>>\n\nb) calibration excavations and unity plots that demonstrate ILl Tool accuracy to meet\nthe tool accuracy specification provided by the vendor (typical for depth within\n+ 10% accuracy for 80% of the time). The unity plots must show: a) actual anomaly\ndepth versus predicted depth and b) actual failure pressure/MAOP versus predicted\nfailure pressure/MAOP. Discovery date must be within 120 days of an ILl Tool run\nfor each type ILl Tool (HR-geometry, HR-defonnation, or HR-MFL).\ni) ILl tool evaluations for metal loss must use \"6t x 6t\" interaction cri teria (or\nmore conservative criteria) for detennining anomaly failure pressures and\nremediation response timing with \" 61\" being pipe wall thickness times six.\nDents: SNG must repair dents in the special permit segment and special permit\ninspection area in accordance with 49 CFR § 192.933 if it is located in a HCA and in\naccordance with 49 CFR §§ 192.933(a)-(c) repair criteria and \"Table 1 - Special\nRequirements for Scheduling Remediation\" if it is not located in an HCA.\nTable 1 -Special Requirements for Scheduling Remediation\nRequired Response Required Response\nDefect Type Orientation Special Permit Special Permit\nSegment Inspection Area\nTop or Bottom Immediate Immediate\nDent Associated with\nCracks or Stress Risers\nDent Associated with\nTop or Bottom l Year Scheduled 2 Year Scheduled\nMetal Loss\nPlain Dent > 6 % OD\nDeep or that exhibits Top 1 Year Scheduled 2 Year Scheduled\ntotal strain > 5 %\nPlain Dent > 2% OD\nDeep Associated with Top or Bottom l Year Scheduled 2 Year Scheduled\nGirth or Seam Weld\nPlain Dent > 6 % OD\nDeep and that exhibits Top or Bottom Monitored Monitored\ntotal strain ~ 5 %\nPlain D\nent\n~ 2% OD\nDeep Associated with Top or Bottom Monitored Monitored\nGirth or Seam Weld\nPHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 13 of 27\n\n<<<PAGE 14>>>\n\nDefinitions\nI. Plain Dent - Dent without metal loss, crack or stress riser.\n2. Immediate Response - Reduce pressure to 80% of recent maximum pressure. Immediate\ndents require an immediate pressure reduction and I or restriction and examination and\nremediation as required in conformance with SNG requirements within fi ve (5) calendar\ndays from the date of discovery. If the remediation cannot be met according to the\nresponse schedule, a technical justification must be prepared that explains the reasons why\nthe schedule cannot be met and indicate how the changed schedule will not jeopardize\npublic safety. Any extended response schedules must be submitted to PHMSA from SNG\nwithin 14 days of pressure reduction after discovery and must receive a \"no objection\"\nfrom the appropriate PHMSA OPS Region Director.\n3. Scheduled Response - Schedule excavation within an appropriate time frame based on the\nopinion of the SME (not to exceed 365 days for special permit segments and 730 days for\nspecial permit inspection areas).\n4. Monitored - Catalog data for future monitoring.\n5. Top - located between 8 o'clock and 4 o'clock positions (upper 2/3 of the pipe).\n6. Bottom - located between 4 o'clock and 8 o'clock positions (bottom 1/3 of pipe).\nSpecial permit segments and special permit inspection areas must have a HR-\ngeometry or HR-deformation tool inspection as part of the initial ILI or these ILI\ninspections must be completed within two (2) years after issuance of this special\npermit. All dent repairs must be made in accordance with 49 CFR §§ 192.933(a)\nthrough (c) repair criteria and \"Table 1 - Special Requirements for Scheduling\nRemediation\" on page 13 of 24. SNG must conduct the following fatigue analysis of\ndents in special permit segments and special permit inspection areas:\ni) SNG must conduct a fatigue analysis of all in-service, non-remediated dents\nabove 6% and with total strain $ 5% after each high resolution MFL and\nhigh resolution caliper or deformation ILl evaluations. Dent fati gue analysis\nmust include as a minimum the following: gross geometry of dent;\norientation of dent; soil cover and type; pressure and temperature; including\ncycles; and stress and strains caused by terrain. The fatigue analysis must\nbe completed within the time frames in \"Table 1 -Special Requirements for\nScheduling Remediation\" of this special permit.\nii) The overall remaining fatigue life of all in-service, non-remediated dents\nover 6% and with total strain $ 5% must be either twice the designated\nPHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 14 of27\n\n<<<PAGE 15>>>\n\nremaining life of the pipeline or at least 500 years.\nc) Investigation and Repair Criteria: In-line inspection anomalies in the special\npermit inspection areas with a safe pressure less than MAOP (e.g. Failure Pressure\nRatio (FPR) < 1.39) or an anomaly depth greater than 80% of pipe wall thickness\nrequire an immediate pressure reduction and/or restriction and continuous action until\nthe anomaly is examined, evaluated, and remediated.\nd) Response Time for ILl Results: SNG will follow Kinder Morgan O&M Procedure\n916 (In-Line Inspections)20 for excavating, investigating, and remediating anomalies21\nbased on ILl data results in accordance with 49 CFR §§ 192.485 and 192.933. SNG\nmust evaluate ILl data by using either the ASME Standard B31 G, \"Manual for\nDetermining the Remaining Strength of Corroded Pipelines \" (ASME 831 G), the\nmodified 831 G (0.85dL), or R-STRENG for calculating the predicted FPR to\ndetermine anomaly responses ..\n• Special permit segments and special permit inspection areas:\n- Immediate response: Any anomaly within a special permit segment and\nspecial permit inspection areas operating up to 72% SMYS that meets either:\n(I) an FPR equal to or less than 1.1 ; or (2) an anomaly depth equal to or\ngreater than 80% wall thickness loss.\n- One-year response: Any anomaly within a special permit segment and\nspecial permit inspection areas with original Class I location pipe in a Class\n3 location (cluster area) operating up to 72% SMYS that meets either: (1) an\nFPR less than 1.39; or (2) an anomaly depth greater than 40% wall thickness\nloss.\n- Monitored response: Any anomaly within a special permit segment and\nspecial permit inspection areas with original Class 1 location pipe in a Class\n3 location (cluster area) operating up to 72% SMYS that meets both: (1) an\nFPR equal to or greater than 1.39; or (2) an anomaly depth less than or equal\nto 40% wall thickness loss.\ne) Special permit segments and special permit inspection areas: Upon issuance of this\n20 The requirements of this Special Permit and 49 CFR §§ 192.485 and 192.933 supersedes Kinder Morgan O&M\nProcedure 916 (In-Line Inspections).\n21 The timing intervals for dent remediation in non-HCAs are in Condition 6(b).\nPHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 15 of27\n\n<<<PAGE 16>>>\n\nspecial permit, SNG must implement the repair and remediation of any pipe\nanomalies or dents that are not in compliance with Condition 13 based upon existing\nILl assessment results from the high resolution MFL and geometry/deformation tools\nused to previously assess pipelines in the special permit segments and special permit\ninspection areas. SNG must review existing ILl assessment results within 18 months\nfrom the issuance of this special permit according to the following schedule: 30% of\npipelines in the special permit segments and special permit inspection areas must be\nreviewed within six (6) months of the issuance of this Special Permit, 65% of\npipelines in the special permit segments and special permit inspection areas must be\nreviewed within 12 months of the issuance this special permit, and I 00% of pipelines\nin the special permit segments and special permit inspection areas must be reviewed\nwithin 18 months of the issuance of this Special permit. Anomalies and dents\ndiscovered during this review must be remediated in accordance with Condition 13\ntiming requirements.\n14) Pipe Seam Evaluations:\na) SNG must identify any pipe in the special permit segment that may be susceptible to\npipe seam issues because of the vintage of the pipe, the manufacturing process of the\npipe, or other issues. Once SNG has identified such issues, SNG must complete\nCondition 14(a). If the engineering analysis required in Condition 14(a) reveals that\nthere is a threat to the pipeline, then SNG must complete all of the applicable\ncondition requirements in Condition 14(a)(ii), (a)(iii), (a)(iv), (a)(v), (a)(vi), (a)(vii),\nand (a)(viii):\ni) SNG must perform an engineering analysis to determine if there are any\npipe seam threats on pipelines located in the special permit segment. This\nanalysis must include the documentation that the processes in ' M Charts' in\n\"Evaluating the Stability of Manufacturing and Construction Defects in\nNatural Gas Pipelines\" by Kiefner and Associates updated April 26, 2007,\nunder PHMSA Contract DTFAA-COSP02120 and Figure 4.2, ' Framework\nfor Evaluation with Path for the Segment Analyzed Highlighted· from TT0-\n5 \"Low Frequency ERW and Lap Welded Longitudinal Seam Evaluation\" by\nPHMSA-2016-0006 - Southern Natural Gas Company Special Permit Page 16 of 27\n\n<<<PAGE 17>>>\n\nMichael Baker Jr., and Kiefner and Associates, et. at. under PHMSA\nContract DTRS56-02-D-70036 were utilized along with other relevant\nmaterials. If the engineering analysis shows that the pipe seam issues on\npipelines located in the special permit segment are not a threat to the\nintegrity of the pipeline, SNG does not have to complete Conditions l4(a)\n(ii) through (vii), but must complete Conditions 14(a)(viii) and (ix).\nii) If a 49 CFR Part 192, Subpart J hydrostatic test has not been performed, the\nspecial permit segments must be hydrostatically tested to a minimum\npressure of 100 percent SMYS, in accordance with 49 CFR Part 192,\nSubpart J requirements for eight (8) continuous hours, within two and one-\nhalf (21 /2) years of issuance of this special permit. The hydrostatic test must\nconfirm no systemic issues with the weld seam or pipe. A root cause\nanalysis, including metallurgical examination of the failed pipe, must be\nperformed for any failure\n22 experienced to verify that it is not indicative of a\nsystemic issue. The results of this root cause analysis must be reported to\nthe appropriate PHMSA Region Director with a copy to the Director,\nPHMSA Engineering and Research Division, within 60 days of the failure.\niii) Special permit segments with low frequency electric resistance welded (LF-\nERW) pipe with a history of leaks or failures without a \"spike test\" within\nthe special permit inspection area must be pressure tested23 with a \"spike\ntest\" within two and one-half (2 Y2) years of the issuance of this special\npermit.\niv) Special permit segments24 with pressure tests less than 1.25 times MAOP\nthat may be susceptible to pipe seam issues must be tested with a Subpart J\npressure test within two and one-half (2 Y2) years of issuance of this special\n22 A root cause analysis, including metallurg ical examination of the pipe, must be performed for any leaks that are\nremoved from the special permit segment.\n23 A root cause analysis, including metallurgical examination of the pipe, must be performed for any pressure test\nfai lures or leaks from the special permit segment.\n24 SNG must implement the replacement of all Type A special permit segments as defined on page 2 of this special\npermit as noted: \" Type A special permit segments with pipe with integrity issues as determined by Conditions 6\nand 14 or that have not been pressure tested in accordance with 49 CFR Part 192, Subpart J to 1.25 times MAOP\nof this special permit must be replaced within two and one-half (2 Y:z) years of the grant of this special permit or\nwithin two (2) years of assessment finding.\"\nPHMSA-2016-0006- Southern Natural Gas Company Special Permit Page 17 of27\n\n<<<PAGE 18>>>\n\npermit or the pipe must be replaced with pipe that meets§ 192.619 within\ntwo and one-half (2 \\12) years of issuance of this special permit. If the pipe is\nthen commensurate with the Class location in accordance with\n§ 192.6 1l(a)(3)(i i) the segment is no longer part of this Special Permit.\nv) If the pipeline in the special permit inspection area has experienced a seam\nleak or failure in the last f","truncated":true,"body_characters":91762}