{"operation":"document","citation":"PHMSA-2019-0207","title":"Gulf South Pipeline Company, LP — Pipeline Special Permit","source_type":"permit","agency":"Pipeline and Hazardous Materials Safety Administration","status":"current","official":true,"published_on":"2020-07-20","effective_on":"2020-07-20","summary":"PHMSA-2019-0207, issued 2020-07-20 for Gulf South Pipeline Company, LP's gas transmission system.","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2019-0207.json","markdown":"https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2019-0207.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2019-0207","source_url":"https://www.regulations.gov/docket/PHMSA-2019-0207","body":"PHMSA pipeline special permit PHMSA-2019-0207. Operator: Gulf South Pipeline Company, LP. System: Gas Transmission. Issue date: 2020-07-20.\n\n<<<PAGE 1>>>\n\nU.S. Department\nof Transportation\nPipeline and Hazardous\nMaterials Safety\nAdministration\n1200 New Jersey Avenue, SE\nWashington, DC 20590\nJuly 20, 2020\nDocket No. PHMSA-2019-0207\nMr. Tony Rizk\nVice President, Technical Services\nGulf South Pipeline Company, LP\n9 Greenway Plaza, Suite 2800\nHouston, TX 77046\nDear Mr. Rizk:\nOn October 4, 2019, pursuant to the 49 Code of Federal Regulations § 190.341, Gulf South\nPipeline Company, LP (GSPC) applied to the Pipeline and Hazardous Materials Safety\nAdministration (PHMSA) for a special permit. GSPC requested to waive compliance with\n§ 192.611(a) for a Class 1 to Class 3 location change of 214 feet of the 42-inch diameter Index\n817 Pipeline (Pipeline) located in Madison Parish, Louisiana. A gas transmission pipeline is\nrequired by § 192.611(a) to have the maximum allowable operating pressure of a pipeline\nsegment to be confirmed or revised where the class location has changed as defined in § 192.5.\nOn February 7, 2020, PHMSA published a Federal Register notice (85 FR 7388), announcing the\nspecial permit request. The Special Permit Request letter, Final Environmental Assessment\n(FEA) and Finding of No Significant Impact (FONSI), Special Permit Analysis and Findings,\nand all other pertinent documents for this special permit are available in Docket No. PHMSA-\n2019-0207 in the Federal Docket Management System located at www.regulations.gov.\nPHMSA grants this special permit (enclosed) based on the information provided by GSPC\nand the findings set forth in the Special Permit Analysis and Findings, FEA, and FONSI. This\nspecial permit provides relief from the Federal Pipeline Safety Regulations for 214 feet of\nthe Pipeline and requires GSPC to comply with certain conditions and limitations designed\nto maintain pipeline safety for the period as defined in the special permit.\n\n<<<PAGE 2>>>\n\nMy staff would be pleased to discuss this special permit or any other regulatory matter with you.\nSentho White, Director of PHMSA Engineering and Research Division, may be contacted at\n202-366-2415, on technical matters; and Allan Beshore, Director, Office of Pipeline Safety,\nCentral Region, may be contacted at 816-329-3811, for operational matters specific to this\nspecial permit.\nSincerely,\nDigitally signed by ALAN\nALAN KRAMER\nKRAMER MAYBERRY\nMAYBERRY Date: 2020.07.20\n16:02:51 -04'00'\nAlan K. Mayberry\nAssociate Administrator for Pipeline Safety\nEnclosure: Special Permit – PHMSA-2019-0207\nPHMSA-2019-0207 Gulf South Pipeline Company, LP - Letter of Decision - Page 2 of 2\n\n<<<PAGE 1>>>\n\nU.S. DEPARTMENT OF TRANSPORTATION\nPIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION\nSPECIAL PERMIT – Class 1 to 3 Location Change\nSpecial Permit Information:\nDocket Number: PHMSA-2019-0207\nRequested By: Gulf South Pipeline Company, LP\nOperator ID#: 31728\nDate Requested: October 4, 2019\nOriginal Issuance Date: July 20, 2020\nEffective Dates: July 20, 2020 to July 20, 2030\nCode Section(s): 49 CFR 192.611(a)\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),1 grants this special\npermit to Gulf South Pipeline Company, LP (GSPC).2 This special permit waives compliance\nwith the 49 Code of Federal Regulations (CFR) 192.611(a) for a Class 1 to Class 3 location\nchange of GSPC’s Index 817 Pipeline, which is a 42-inch diameter natural gas transmission\npipeline, in Madison Parish, Louisiana. This special permit requires that GSPC implement\nadditional conditions on the operations, maintenance, and integrity management of the Index 817\nPipeline.\nI. Purpose and Need:\nThe special permit is needed for a Class 1 to Class 3 location change that has occurred on the 42-\ninch diameter Index 817 Pipeline located in Madison Parish, Louisiana. On the condition that\nGSPC complies with the terms and conditions set forth below, this special permit waives\ncompliance from 49 CFR 192.611(a) for 214 feet of natural gas transmission pipeline on the 42-\n1 Throughout this special permit the usage of “PHMSA” or “PHMSA OPS” means the U.S. Department of\nTransportation’s Pipeline and Hazardous Materials Safety Administration, Office of Pipeline Safety.\n2 GSPC is a wholly-owned subsidiary of the Boardwalk Pipeline Partners, LP.\nSpecial Permit: PHMSA-2019-0207 - Gulf South Pipeline Company, LP\nIndex 817 Pipeline – Class 1 to 3 Location Change\nPage 1 of 20\n\n<<<PAGE 2>>>\n\ninch diameter Index 817 Pipeline. This special permit allows GSPC to continue to operate the\nspecial permit segment as defined below at its current maximum allowable operating pressure\n(MAOP) of 1,456 pounds per square inch gauge (psig) for the Index 817 Pipeline.3\nThe Federal pipeline safety regulations in 49 CFR 192.611(a) require natural gas transmission\noperators to either pressure test, replace the pipe with stronger pipe, or lower the MAOP when\nthere is a Class 1 to Class 3 location change as defined in 49 CFR 192.5. The 214 feet of 42-inch\ndiameter pipe in the GSPC special permit request operates at a stress level of 65.2% of specified\nminimum yield strength (SMYS) based upon a 1,456 psig MAOP. Without this special permit,\nin accordance with 49 CFR 192.611(a), GSPC would be required to replace the pipe segment or\nreduce the pipeline MAOP. The 214 feet of the 42-inch diameter Index 817 Pipeline was\nhydrostatically tested to a minimum pressure of 1,875 psig for 8 hours in late 2007, whereas 49\nCFR 192.611(a) requires a minimum test pressure of 2,184 psig for a Class 3 location and the\npipe design factor is greater than 60% of SMYS.\nII. Special Permit Segments and Inspection Areas:\nMadison Parish, Louisiana\nThis special permit applies to the special permit segment defined using the GSPC survey station\n(SS) references as follows:\n• Special permit segment – Index 817 Pipeline – 4,638 feet, SS 9409+44 to SS\n9455+82.\nNote: GSPC’s special permit request was for 214 feet from SS 9431+56 to SS\n9433+70. All procedures, surveys, assessments, remediation, and assessment\nintervals required in these special permit conditions for the special permit segment\nare applicable on either side of the special permit segment end points for a distance\nof two (2) times the potential impact radius (PIR), as defined in 49 CFR 192.903.\nThe PIR for a 42-inch diameter, 1,456 psig MAOP pipeline is 1,106 feet. Two (2)\n3 This special permit is for a 214-foot segment of 42-inch diameter Index 817 Pipeline as requested by GSPC. The\nspecial permit segment includes additional pipeline footage beyond the 214 feet that extends the special permit\nsegment which the special permit conditions are applicable. Condition 14 will allow extensions beyond the 214\nfeet of pipeline should the Class 3 location extend further. PHMSA has granted this special permit due to the 214\nfeet of 42-inch diameter pipe operating at a stress level of 65.2% of specified minimum yield strength (SMYS)\nbased upon a 1,456 psig MAOP. Pipelines with a MAOP of over 72% SMYS are not allowed to operate in a\nClass 3 location. This special permit is not for pipe operating above 72% SMYS.\nSpecial Permit: PHMSA-2019-0207 - Gulf South Pipeline Company, LP\nIndex 817 Pipeline – Class 1 to 3 Location Change\nPage 2 of 20\n\n<<<PAGE 3>>>\n\ntimes the PIR would be 2,212 feet. The special permit segment total footage is 4,638\nfeet. PHMSA extended this special permit request from a 214-foot special permit\nsegment to a 4,638-foot special permit segment since this pipeline has an existing\nAlternative MAOP special permit4 to operate up to 80% SMYS in Class 1 locations.\nThis special permit applies to the special permit inspection area defined using the GSPC SS\nreferences as follows:\n• Special permit inspection area – Index 817 Pipeline – SS 8898+40 to 10752+83,\napproximately 35.1 miles.\nThe special permit inspection area is in Madison Parish, Louisiana, and Warren and Hinds\nCounties, Mississippi. The special permit inspection area starts at the Tallulah, Louisiana\nCompressor station and ends at a pointed located in Hinds County, Mississippi for a length of\napproximately 35.1 miles and includes the special permit segment. Attachments A and B\ninclude Index 817 Pipeline route maps showing the special permit segment and special permit\ninspection area.\nPHMSA grants this special permit based on the findings set forth in the “Special Permit Analysis\nand Findings” and “Final Environmental Assessment and Finding of No Significant Impact”\ndocuments, which can be read in its entirety in Docket No. PHMSA-2019-0207 in the Federal\nDocket Management System located on the internet at www.regulations.gov.\nIII. Conditions:\nPHMSA grants this special permit to GSPC subject to GSPC implementing the following\nconditions on the Index 817 Pipeline as detailed below:\n1) Maximum Allowable Operating Pressure for the Special Permit:\na) MAOP: GSPC must continue to operate the special permit segment and special permit\ninspection area at or below the existing MAOP of 1,456 psig.\nb) Alternative MAOP: GSPC must continue to implement the conditions in the Alternative\nMAOP special permit (PHMSA-2006-26533) for both the special permit segment and\n4 PHMSA-2006-26533.\nSpecial Permit: PHMSA-2019-0207 - Gulf South Pipeline Company, LP\nIndex 817 Pipeline – Class 1 to 3 Location Change\nPage 3 of 20\n\n<<<PAGE 4>>>\n\nthe special permit inspection area. The special permit inspection area is defined in this\nspecial permit (PHMSA-2019-0207).\n2) Integrity Management Program: GSPC must incorporate the requirements of this special\npermit into its written integrity management program and standard operating procedures\n(SOPs).\na) GSPC must treat the special permit segment as a “covered segment” in a “high\nconsequence area (HCA)” in accordance with 49 CFR Part 192, Subpart O.\nReassessments of the special permit segment and special permit inspection area using\nhigh resolution magnetic flux leakage (HR-MFL) and high resolution (HR) Deformation\ninline inspection (ILI) must be conducted at the frequency specified for HCAs in 49 CFR\n192, Subpart O.\nb) If GSPC identifies threats within the special permit segment and special permit\ninspection area that require running additional ILI tools, pursuant to 49 CFR Part 192,\nSubpart O, such as for crack detection5 or pipe movement from soil or geologic stresses,\nGSPC must use the appropriate ILI tools or other evaluation methods for pipeline\nassessments.\n3) Operations and Maintenance Manual: GSPC must amend applicable sections of its\noperations and maintenance (O&M) Manual(s) and Procedures to incorporate the procedures,\ninspections, assessments, reassessments, remediation, reporting, documentation, permitting,\nand timing or time intervals required by the special permit conditions. The O&M Manual\nand Procedures must include requirements to address each condition in this special permit for\nthe special permit segment and the special permit inspection area.\n4) Close Interval Surveys:\na) CIS: GSPC must conduct close interval surveys (CIS) at a maximum 5-foot spacing and\nwith interrupted on/off current on the special permit segment and special permit\ninspection area in accordance with 49 CFR 192.463 and 192.465.\nb) CIS Timing: GSPC must perform periodic CIS of the special permit segment and\nspecial permit inspection area at the applicable reassessment interval(s) for a “covered\nsegment” determined in concert and integrated with ILI in accordance with 49 CFR 192,\n5 “Pipe Crack” activity shall be defined as over both 20% wall thickness depth and 2-inches in length.\nSpecial Permit: PHMSA-2019-0207 - Gulf South Pipeline Company, LP\nIndex 817 Pipeline – Class 1 to 3 Location Change\nPage 4 of 20\n\n<<<PAGE 5>>>\n\nSubpart O, reassessment intervals as required in 49 CFR 192.937(a) and (b) and 192.939.\nIf a CIS was not conducted with the last ILI survey, it must be conducted within one (1)\nyear of issuance of this special permit.\nc) CIS Timing Delay: If environmental permitting or right-of-way factors beyond GSPC’s\ncontrol prevent the completion of the CIS and remediation6 within six (6) months from\nthe issuance of this special permit, GSPC must complete the CIS and subsequent\nremediation including coating repair as soon as practicable. GSPC must submit a letter\njustifying the CIS and remediation delays, no later than one (1) month prior to the end of\nsix (6) month interval, and must provide the anticipated date of completion to the\nDirector, PHMSA Central Region.7\nd) CIS Reassessments: GSPC must perform periodic CIS of the special permit segment\nand special permit inspection area at the applicable reassessment interval(s) for a\n“covered segment” determined in concert and integrated with ILI in accordance with 49\nCFR 192, Subpart O, reassessment intervals as required in 49 CFR 192.937(a) and (b)\nand 192.939. CIS assessments within the reassessment interval are not required to be\nperformed in the same year as ILI reassessments.\n5) Cathodic Protection Test Stations:\na) Test Station Locations: At least one (1) cathodic protection (CP) pipe-to-soil test station\nmust be located within the special permit segment with a maximum spacing of one-half\nmile between test stations. In cases where obstructions or restricted areas prevent test\nstation placement, the test station must be installed in the closest practical location.\nb) Monitoring: Annual monitoring of cathodic protection pipe-to-soil test stations must be\nperformed in accordance with 49 CFR 192.463 and 192.465.\n6) Annual Cathodic Protection Test Station Readings:\na) CP Findings: If any annual CP test station readings on the special permit inspection\narea fall below 49 CFR Part 192, Subpart I requirements, remediation must occur within\n6 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.\n7 Upon notice to GSPC by the Director, PHMSA Central Region, PHMSA may change the reporting responsibilities\nfor this special permit to another PHMSA Region Director.\nSpecial Permit: PHMSA-2019-0207 - Gulf South Pipeline Company, LP\nIndex 817 Pipeline – Class 1 to 3 Location Change\nPage 5 of 20\n\n<<<PAGE 6>>>\n\nsix (6) months of the survey and must include a CIS on each side of the affected test\nstation to the next test station. GSPC must implement corrosion system modifications\nthat are identified through the CP test station readings and remediation findings to ensure\ncorrosion control.\nb) Remediation Timing: If factors beyond GSPC’s control prevent the completion of\nremediation within six (6) months, GSPC must complete the remediation as soon as\npracticable and submit a letter justifying the delay with the anticipated date of completion\nto the Director, PHMSA Central Region, no later than one (1) month prior to the end of\nthe six (6) month remediation period. GSPC must receive a letter of “No Objection”\nfrom the Director, PHMSA Central Region, prior to implementing an extended\nremediation interval.\n7) Interference Currents Control: GSPC must incorporate measures to control induced\nalternating current (AC) from parallel electric transmission lines and other interference issues\nin the special permit inspection area, that may affect the pipeline. An induced AC program\nto protect the pipeline from corrosion caused by stray currents must be in place within one\n(1) year of the date of this special permit.\n8) Anomaly Assessment and Remediation:\na) General: GSPC must conduct anomaly assessments using ILI that meets the assessment\nintervals of special permit PHMSA-2006-26533 and 49 CFR Part 192, Subpart O. GSPC\nmust account for ILI tool tolerance8,9 and corrosion growth rates in scheduled response\ntimes and repairs, and document and justify the values used.\n8 ILI tool calibration excavations may include previously excavated anomalies or recent anomaly excavations with\nknown dimensions that were field measured for length, depth, and width, externally re-coated, CP maintained, and\ndocumented for ILI calibrations prior to the ILI tool run. ILI tool calibrations must use ILI tool run results and\nanomaly calibrations from either the special permit inspection area or from the complete ILI tool run segment, if\nthe continuous ILI segment is longer than the special permit inspection area. A minimum of four (4) calibration\nexcavations must be used for unity plots or as an alternative a minimum of one (1) calibration excavation and\ncompliance with API 1163-2013, In-Line Inspection Systems Qualification Standard (API 1163), Level 1 criteria\nmust be used. For API 1163, Level 1 criteria to be used, all anomalies greater than 20-percent wall loss must be\nexcavated and remediated unless Director, PHMSA Central Region gives GSPC a “No Objection” to an\nalternative ILI tool calibration procedure (see Footnote 9).\nSpecial Permit: PHMSA-2019-0207 - Gulf South Pipeline Company, LP\nIndex 817 Pipeline – Class 1 to 3 Location Change\nPage 6 of 20\n\n<<<PAGE 7>>>\n\nb) Dents: GSPC must repair dents to the Index 817 Pipeline in the special permit\ninspection area in accordance with the 49 CFR 192.933 repair criteria. The special\npermit inspection area must have a high resolution (HR) deformation tool inspection as\npart of the ILI. The HR deformation ILI can be from past inspections. The timing for\nthese dent repairs should follow GSPC’s O&M Procedures, but must not be longer than\none (1) year after discovery.\nc) Anomaly Evaluation Repair Criteria and Timing: The following provisions provide\nthe required timing for excavation and investigation of anomalies based on ILI results.\nGSPC must evaluate ILI data by using either the ASME Standard B31G, “Manual for\nDetermining the Remaining Strength of Corroded Pipelines”,\n10 the modified B31G\n(0.85dL) or R-STRENG for calculating the predicted failure pressure ratio (FPR) to\ndetermine anomaly responses.\ni) Special permit segment:\n- Immediate response time – repair immediately:\no Any anomaly within a special permit segment that meets either: (1) a FPR\nequal to or less than 1.25; or (2) an anomaly depth equal to or greater than\n60% wall thickness loss.\n- One-year response:\no Any anomaly within a special permit segment with pipe operating over 56%\nSMYS and up through 67% SMYS that meets either: (1) a FPR equal to or\nless than 1.50; or (2) an anomaly depth equal to or greater than 40% wall\nthickness loss.\n9 Note: Other known and documented pipeline features that are appropriate for the type ILI tool used may be used\nas calibration excavations for ILI tool calibration with technical documentation of their validity. To use other\nknown and documented pipeline features as calibration excavations for ILI tool calibration GSPC must submit a\nplan for using known and documented pipeline features as calibration excavations to, and receive a “No\nObjection” from the Director, PHMSA Central Region, prior to performing the ILI tool calibration using pipeline\nfeatures. PHMSA must reply to GSPC within 90-days of GSPC’s request. The plan must include at least the\nfollowing information: (1) reason that known and documented pipeline features will be used in place of anomalies\non the pipelines; the pipeline features that will be used for the ILI tool calibration, and the technical justification\nfor using the pipeline features for ILI tool calibration; and (2) submit a report to the Director, PHMSA Central\nRegion and to the Director, PHMSA Engineering and Research with the results of the use of pipeline features for\nthe ILI tool calibration that includes technical documentation establishing the validity of using the pipeline\nfeatures for the ILI tool calibration. GSPC must submit the report to PHMSA within 90-days after completion of\nthe ILI tool calibration.\n10 Standards used in this special permit must be the edition incorporated by reference in 49 CFR 192.7.\nSpecial Permit: PHMSA-2019-0207 - Gulf South Pipeline Company, LP\nIndex 817 Pipeline – Class 1 to 3 Location Change\nPage 7 of 20\n\n<<<PAGE 8>>>\n\no Any anomaly within a special permit segment with pipe operating over 67%\nSMYS and up through 72% SMYS that meets either: (1) an FPR equal to or\nless than 1.39; or (2) an anomaly depth equal to or greater than 40% wall\nthickness loss.\no Any anomaly within a special permit segment with pipe operating over 72%\nSMYS and up through 80% SMYS that meets either: (1) an FPR equal to or\nless than 1.25; or (2) an anomaly depth equal to or greater than 40% wall\nthickness loss.\no Any anomaly within a special permit segment with pipe operating up through\n56% SMYS that meets either: (1) an FPR equal to or less than 1.80; or (2) an\nanomaly depth equal to or greater than 40% wall thickness loss.\n- Monitored response:\no Any anomaly within a special permit segment with pipe operating over 56%\nSMYS and up through 67% SMYS that meets either: (1) an FPR over 1.50; or\n(2) an anomaly depth less than 40% wall thickness loss.\no Any anomaly within a special permit segment with pipe operating over 67%\nSMYS and up through 72% SMYS that meets either: (1) an FPR over 1.39; or\n(2) an anomaly depth less than 40% wall thickness loss.\no Any anomaly within a special permit segment with pipe operating over 72%\nSMYS and up through 80% SMYS that meets either: (1) an FPR over 1.25; or\n(2) an anomaly depth less than 40% wall thickness loss.\no Any anomaly within a special permit segment with pipe operating up through\n56% SMYS that meets either: (1) an FPR over 1.80; or (2) an anomaly depth\nless than 40% wall thickness loss.\nii) Special permit inspection area:\n- Immediate response time – repair immediately:\no Any anomaly within a special permit inspection area that meets either: (1) an\nFPR equal to or less than 1.10; or (2) an anomaly depth equal to or greater\nthan 80% wall thickness loss.\n- One-year and monitored response:\no The anomaly assessment remediation and response time for a special permit\ninspection area must be in accordance with: (1) 49 CFR Part 192, Subpart O;\nSpecial Permit: PHMSA-2019-0207 - Gulf South Pipeline Company, LP\nIndex 817 Pipeline – Class 1 to 3 Location Change\nPage 8 of 20\n\n<<<PAGE 9>>>\n\n(2) Special Permit PHMSA-2006-26533, Condition 43, for the Index 817\nPipeline; and (3) 49 CFR 192.620(d)(11). The assessment response that has a\nshorter repair timing or more conservative anomaly remediation requirements\nmust be implemented by GSPC.\no Any anomaly within the special permit inspection area with a depth equal to\nor greater than 40% wall thickness loss must be remediated within one-year of\nGSPC finding the anomaly.\n9) Damage Prevention Program: GSPC must ensure its damage prevention program\nincorporates the applicable best practices of the Common Ground Alliance within the special\npermit inspection area.\n10) Annual Report to PHMSA: Annually,11 after the grant of this special permit, GSPC must\nsubmit an annual pipeline integrity report to the Director, PHMSA Central Region,\nsummarizing any significant integrity threats and the following items:12\na) In the first annual report, GSPC must describe the economic benefits of the special\npermit, including both the costs avoided from not replacing the pipe and the added costs\nof the inspection program. Subsequent annual reports must address any changes to these\neconomic benefits.\nb) In the first annual report, GSPC must fully describe how the public benefits from energy\navailability. GSPC must address the benefits of avoided disruptions as a consequence of\npipe replacement and the benefits of maintaining system capacity. Subsequent reports\nmust indicate any changes to this initial assessment.\nc) Any new integrity threats identified during the previous year in the special permit\nsegment, and the results of any ILI or direct assessments performed (including any\nremediated anomalies with the associated wall loss, length, and unrepaired failure\npressure; any un-remediated anomalies over 30% pipe wall loss and the associated wall\nloss, length and failure pressure; cracking found in the pipe body; weld seam or girth\n11 Annual reports must be received by PHMSA by the last day of the month in which the special permit is granted.\nFor example, the annual report for a special permit granted on July 15, 2020, must be received by PHMSA no\nlater than July 31 each year beginning in 2021.\n12 GSPC must submit a copy of the annual reports on the special permit docket - PHMSA-2019-0207, at\nwww.regulations.gov.\nSpecial Permit: PHMSA-2019-0207 - Gulf South Pipeline Company, LP\nIndex 817 Pipeline – Class 1 to 3 Location Change\nPage 9 of 20\n\n<<<PAGE 10>>>\n\nwelds; and dents with metal loss, cracking or stress riser) during the previous year in the\nspecial permit segment;\nd) Summaries of any close interval surveys that resulted in low cathodic protection levels in\nthe special permit segment and a remediation schedule;\ne) Any reportable incident or any leak normally indicated on the DOT Annual Report, and\nall repairs on the pipeline that occurred during the previous year in the special permit\nsegment;\nf) Any pressure test leaks or failures with a description of the cause in the special permit\nsegment;\ng) Any mergers, acquisitions, transfer of assets, or other events affecting the regulatory\nresponsibility of the company operating the pipeline;\nh) Any emergency events that cause closure of mainline valves as described in Condition\n12, including the location (Mile Post) of valves and closure times.\n11) Special Permit Segment Specific Conditions: GSPC must comply with the following\nrequirements:\na) Line-of-Sight Markers: GSPC must install and maintain line-of-sight markers within\nthe special permit inspection area in accordance with 49 CFR 192.620(d)(4)(iv) to the\nextent practicable. Line-of-sight markers must be installed within three (3) months of\nissuance of this special permit and replaced as necessary by GSPC within 30 days of\ndiscovering the marker is removed or missing.\nb) Data Integration: GSPC must maintain data integration of all special permit condition\nfindings and remediation in the special permit inspection area. Data integration must\ninclude the following information: (1) Pipe diameter, wall thickness, grade, and seam\ntype; (2) pipe coating; (3) MAOP; (4) class location (including boundaries on aerial\nphotography); (5) HCAs (including boundaries on aerial photography); (6) hydrostatic\ntest pressure including any known test failures; (7) casings; (8) any in-service ruptures or\nleaks; (9) ILI survey results including HR-MFL, HR-geometry/caliper or deformation\ntools; (10) CISs – most recent; (11) depth of cover surveys; rectifier readings – past five\nyears; (12) cathodic protection test point survey readings – past five years; (13) AC/DC\ninterference surveys; (14) pipe coating surveys; (15) pipe coating and anomaly\nevaluations from pipe excavations; (16) stress corrosion cracking excavations and\nSpecial Permit: PHMSA-2019-0207 - Gulf South Pipeline Company, LP\nIndex 817 Pipeline – Class 1 to 3 Location Change\nPage 10 of 20\n\n<<<PAGE 11>>>\n\nfindings; and (17) pipe exposures from encroachments.13 Structures must be validated\nevery three (3) years by obtaining new aerial imagery or by ground patrol.\ni) Data integration must be performed in accordance with 49 CFR 192.917 for threat\nidentification, evaluation, remediation, and mitigation.\nii) Data integration documentation and drawings, with four (4) years of prior data, to\nmeet Condition 11(b), must be completed and must be submitted, if requested by\nPHMSA, beginning with the 2nd annual report of this special permit.\niii) Data integration must be updated on an annual basis. GSPC must conduct, at least, an\nannual review of integrity issues to be remediated.\niv) GSPC must maintain data integration as a composite of all applicable data elements\nin a data viewer.\nc) Pipeline Patrolling: Pipeline patrolling must be conducted at least monthly (12 times\nper calendar year), not to exceed 45 days, to inspect the special permit inspection area\nfor excavation activities, ground movement, wash-outs, leakage or other activities and\nconditions affecting the safe operation of the pipeline.\nd) Environmental Assessments and Permits: GSPC must evaluate the potential\nenvironmental consequences and affected resources of any land disturbances and water\nbody crossings needed to implement the special permit conditions for special permit\nsegment or special permit inspection area prior to the disturbance. If a land disturbance\nor water body crossings is required, GSPC must obtain and adhere to all applicable\n(Federal, state, and local) environmental permit requirements when conducting the\nspecial permit conditions activity.\ne) Root Cause Analysis for Failure or Leak: If a leak or rupture (incident as defined by 49\nCFR 191.3) occurs in any of the special permit inspection area, GSPC must notify the\nDirector, PHMSA Central Region, within five (5) days of the leak or rupture. A root\ncause analysis must be performed to determine the cause of the failure and must be sent\nto the Director, PHMSA Central Region, and the Director, PHMSA Engineering and\nResearch, within 90 days of the incident. If a root cause analysis cannot be performed\n13 Hydrostatic test failures, in-service ruptures, rectifier readings, cathodic protection test point survey readings,\nAC/DC interference surveys, pipe coating surveys, pipe coating and anomaly evaluations from pipe excavations,\nSCC excavations and findings, and pipe exposures from encroachments must be maintained for data integration\ninto a comparable data viewer. These data elements may not be on a drawing.\nSpecial Permit: PHMSA-2019-0207 - Gulf South Pipeline Company, LP\nIndex 817 Pipeline – Class 1 to 3 Location Change\nPage 11 of 20\n\n<<<PAGE 12>>>\n\nwithin 90 days of the incident, GSPC must submit to the Director, PHMSA Central\nRegion, a request for an extension of time. GSPC must receive a letter of “No Objection”\nfrom the Director, PHMSA Central Region, prior to implementing an extended timeframe\nto perform the root cause analysis. PHMSA will review the root cause analysis report to\ndetermine if revocation, suspension, or modification of the special permit is warranted\nbased upon incident findings.\n12) Mainline Valve – Monitoring and Remote Control for Leaks or Ruptures: GSPC must\nautomate the nearest existing mainline valves on both sides of the special permit segment for\nclosure, or demonstrate the capability to manually close the mainline valves in accordance\nwith the requirements of Condition 12. The mainline valves must be within a maximum 20-\nmile total spacing, upstream and downstream, of the special permit segment. GSPC\nmainline valves are located at Index 817 Pipeline Mile Posts 168.5 (SS 8897+01) and 183.06\n(SS 9665+82). GSPC must develop and implement procedures to initiate closure of each\nmainline valve as follows:\na) Supervisory Control and Data Acquisition System and Remote Monitoring: The\nspecial permit segment must be controlled by a supervisory control and data acquisition\n(SCADA) system and must be equipped for remote monitoring and control, or remote\nmonitoring and automatic control in accordance with 49 CFR 192.620(d)(3)(iii) and the\nbelow requirements of Condition 12;\nb) Crossovers or Lateral Pipe Isolation: If any crossover or lateral pipe for gas receipts or\ndeliveries connects to the isolated segment between the upstream and downstream\nmainline valves, the nearest valve on the crossover connection(s) or lateral(s) must be\nisolated, such that, when all valves are closed, there is no flow path for gas to flow to the\nleak or rupture site (except for residual gas already in the shut-off segment). If the\nnearest valve for a gas receipt or delivery line to the special permit segment is not\nisolated, isolation valves must be used;14\n14 Gas delivery pipelines must have a remote-controlled shutoff valve (gate or ball valve) either at the connection to\nthe Index 817 Pipeline or at the delivery meter station. Any gas delivery or receipt station over 5 miles in length\nthat is connected to the Index 817 Pipeline must have a remote-controlled shutoff valve within 5 miles of the\nIndex 817 Pipeline. For gas delivery or receipt pipelines, manual shutoff valves can be used for isolation, but must\nbe closed within 30 minutes from the pipeline leak or rupture confirmation.\nSpecial Permit: PHMSA-2019-0207 - Gulf South Pipeline Company, LP\nIndex 817 Pipeline – Class 1 to 3 Location Change\nPage 12 of 20\n\n<<<PAGE 13>>>\n\nc) Remote Control Valve Monitoring for Valve Status and Operating Pressure:\nMainline valves must be constantly monitored for valve status (open, closed, or partial\nclosed/open), upstream pressure, and downstream pressure;\nd) Valve Closure for a Leak or Rupture: Closure of the appropriate valves following a\npipeline leak or rupture meeting the criteria specified in this Condition 12(d)(i) must\noccur as soon as practicable from the time the pipeline leak or rupture location is\nconfirmed, not to exceed 30 minutes from such confirmation;15\ni) “Rupture” means a significant breach of a pipeline that results in a large-volume,\nuncontrolled release of gas. For purposes of this special permit, GSPC must treat any\nof the following as ruptures unless and until determined otherwise:\n1) A release of gas observed or reported to the operator by its field personnel, nearby\npipeline or utility personnel, the public, local responders, or public authorities,\nand that may be representative of an unintentional and uncontrolled release event\ndefined in paragraphs (2) or (3) of this definition;\n2) An unanticipated or unplanned pressure loss of 10 percent or greater, occurring\nwithin a time interval of 15 minutes or less, unless the operator has documented in\nadvance of the pressure loss the need for a higher pressure-change threshold due\nto pipeline flow dynamics that cause fluctuations in gas demand that are typically\nhigher than a pressure loss of 10 percent in a time interval of 15 minutes or less;\nor\n3) An unexplained flow rate change, pressure change, instrumentation indication, or\nequipment function that may be representative of an event defined in paragraph\n(2) of this definition.\nNote: Rupture identification occurs when a rupture, as defined in this section, is\nfirst observed by or reported to pipeline operating personnel or a controller.\nii) Within five (5) minutes of the initial notification to GSPC, GSPC must evaluate and\nidentify a rupture, as defined above, as being either an actual leak event, rupture event\nor non-rupture event in accordance with operating procedures and 49 CFR 192.615.\n15 The pipeline valve section location to be closed and isolated (if there should be a rupture) must be confirmed by\nGSPC through Gas Control or other field operations personnel monitoring of the appropriate pipeline pressures,\npressure changes, or flow rate changes through a compressor discharge section or by location confirmation from\nresponsible persons.\nSpecial Permit: PHMSA-2019-0207 - Gulf South Pipeline Company, LP\nIndex 817 Pipeline – Class 1 to 3 Location Change\nPage 13 of 20\n\n<<<PAGE 14>>>\n\ne) 24-Hour Monitoring by Gas Control Center: The GSPC Gas Control Center must\nmonitor the special permit segment 24 hours a day, 7 days a week and must confirm the\nexistence of a leak or rupture in accordance with Condition 12(d)(i) and as soon as\npracticable, in accordance with the GSPC pipeline operating procedures;\nf) Remote Monitoring of Valves: GSPC must maintain remote monitoring and automatic\ncontrol equipment, mainline valves, mainline valve operators, and pressure sensors in\naccordance with 49 CFR 192.631 and 192.745. All remote monitoring and automatic\ncontrol equipment including pressure sensors must have backup power to maintain\ncommunications and control to the GSPC Gas Control Center during power outages;\ng) Point-to-Point Verification: GSPC must conduct a point-to-point verification between\nSCADA displays and the mainline valve, sensors, and communications equipment in\naccordance with 49 CFR 192.631(c) and (e), or an equivalent verification;\nh) Maintenance of Valves: All valves used to isolate a leak or rupture must be maintained\nin accordance with this special permit and 49 CFR 192.745;\ni) Inoperable Valves: GSPC must take remedial measures to correct any valve used to\nisolate a leak or rupture that is found to be inoperable or unable to maintain shut-off, as\nfollows:\ni) Repair or replace the valve as soon as practicable but no later than six (6) months\nafter the finding;\nii) Designate an alternative valve within seven (7) calendar days of the finding while\nrepairs are being made. Repairs must be completed within six (6) months; and\niii) If valve repair or replacement cannot be met due to circumstances beyond GSPC’s\ncontrol, GSPC must notify the Director, PHMSA Central Region, in writing of\nthe reasons the schedule cannot be met and obtain a letter of “No Objection”\nfrom PHMSA prior to implementing the schedule change.\nj) Communications: GSPC must establish and maintain adequate means of communication\nwith the appropriate public safety access point (9-1-1 emergency call center) and must\nnotify them if there is a leak or rupture, as well other emergency responders as required\nin 49 CFR 192.615;\nSpecial Permit: PHMSA-2019-0207 - Gulf South Pipeline Company, LP\nIndex 817 Pipeline – Class 1 to 3 Location Change\nPage 14 of 20\n\n<<<PAGE 15>>>\n\nk) Notifications: GSPC must immediately and directly notify the appropriate public safety\naccess point (9-1-1 emergency call center) or other coordinating agency for the\ncommunities and jurisdictions in which the pipeline is located when a release is\nindicated;16 and\nl) Operator Actions During an Emergency: GSPC must establish actions required to be\ntaken by a pipeline controller, or the appropriate emergency response coordinator,\nduring an emergency in accordance with these special permit conditions and as required\nin 49 CFR 192.615 and 192.631.\n13) Documentation: GSPC must maintain the following records for each special permit\nsegment:\na) Documentation showing that each special permit segment has received a hydrostatic\ntest for eight (8) continuous hours and at a minimum pressure of 1.25 times MAOP in\naccordance with 49 CFR 192.505, Subpart J. If GSPC does not have hydrostatic test\ndocumentation, then the special permit segment must be hydrostatically tested to\nmeet this requirement within one (1) year of receipt of this special permit.\nb) Documentation (mill test reports) showing that the pipe in the special permit segment\nmeets the wall thickness, yield strength, tensile strength and chemical composition of\neither the American Petroleum Institute Standard 5L, 5LX or 5LS, “Specification for\nLine Pipe” (API 5L)17 approved by the 49 CFR Part 192 code at the time of\nmanufacturing, or if the pipe was manufactured and placed in-service prior to the\ninception of 49 CFR Part 192, then the pipe meets the API 5L standard in usage at\nthat time. Any special permit segment that does not have mill test reports for the\npipe cannot be authorized per this special permit.\nc) Documentation of compliance with all conditions of this special permit must be kept\nfor the life of this special permit for the referenced special permit segment and\nspecial permit inspection area.\n14) Extension of the Special Permit Segment: PHMSA may extend the special permit segment\nto include contiguous segments of the Index 817 Pipeline up to the limits of the special\n16 GSPC must designate the pipeline controller or the appropriate operator emergency response coordinator in its\noperating procedures and train the pipeline controller or the appropriate operator emergency response coordinator\nfor coordinating with emergency responders.\n17 Standards used for this special permit must be the edition incorporated by reference in 49 CFR 192.7.\nSpecial Permit: PHMSA-2019-0207 - Gulf South Pipeline Company, LP\nIndex 817 Pipeline","truncated":true,"body_characters":45546}