{"operation":"document","citation":"PHMSA-2023-0022","title":"Florida Gas Transmission — Pipeline Special Permit","source_type":"permit","agency":"Pipeline and Hazardous Materials Safety Administration","status":"current","official":true,"published_on":"2023-07-27","effective_on":"2023-07-27","summary":"PHMSA-2023-0022, issued 2023-07-27 for Florida Gas Transmission's gas transmission system.","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2023-0022.json","markdown":"https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2023-0022.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2023-0022","source_url":"https://www.regulations.gov/docket/PHMSA-2023-0022","body":"PHMSA pipeline special permit PHMSA-2023-0022. Operator: Florida Gas Transmission. System: Gas Transmission. Issue date: 2023-07-27.\n\n<<<PAGE 1>>>\n\nU.S. DEPARTMENT OF TRANSPORTATION\nPIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION\nDRAFT SPECIAL PERMIT - Class 1 or Class 2 to 3 Location\nSpecial Permit Information:\nDocket Number: PHMSA-2023-0022\nRequested By: Florida Gas Transmission Company, LLC\nOperator ID#: 5304\nOriginal Date Requested: March 24, 2023\nOriginal Issuance Date: Month Day, 20XX\nEffective Dates: Month Day, 20XX to Month Day, 20XX\nCode Section(s): 49 CFR 192.611(a)(3)(iii)\nProposed Grant 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 proposes to grant this\nspecial permit to Florida Gas Transmission (FGT)2 for four (4) special permit segments consisting of\napproximately 0.13 miles of 18-inch diameter gas transmission pipelines and 0.46 miles of 30-inch\ndiameter gas transmission pipelines located in Hillsborough County, Florida. This special permit\nwaives compliance from 49 Code of Federal Regulations (CFR) 192.611(a)(3)(iii)3 for three (3)\nspecial permit segment(s) that have undergone changes from Class 1 to Class 3 and one (1) special\npermit segment that has undergone a change from Class 2 to Class 3. The Federal pipeline safety\nregulations in 49 CFR 192.611(a)(3)(iii) require natural gas pipeline operators to confirm or revise the\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 FGT is owned by Energy Transfer and Kinder Morgan.\n3 A Class 2 or 3 location requires a pressure test of 1.5 times the maximum allowable operating pressure (MAOP) in 49\nCFR 192.620(a)(2). Section 192.611(a)(3)(iii) requires a pressure test of 1.5 times the MAOP for a Class 2 or 3 class\nlocation change upgrade after the pipeline has been constructed and placed into operational service. A special permit\nfor 49 CFR 192.611(a)(3)(iii) would include 49 CFR 192.620(a)(2).\nPHMSA-2023-0022 – Florida Gas Transmission Company, LLC\nDraft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 1 of 53\n\n<<<PAGE 2>>>\n\nmaximum allowable operating pressure (Alternative MAOP) of a pipeline segment after a change in\nclass location.4\nI. Purpose and Need\nFGT sought this special permit for Class 1 to Class 3 location or Class 2 to Class 3 location changes\noccurring on the 18-inch diameter St. Petersburg Sarasota Connector and 30-inch diameter West Leg\nStation 27 to Ft. Myers Pipelines. On the condition that FGT complies with the terms and conditions\nset forth below, the proposed special permit would waive compliance from 49 CFR 192.611(a)(3)(iii)\nfor approximately 0.59 miles (3,135 feet) of natural gas transmission pipeline. This proposed special\npermit is for class location changes where the pipeline has not been pressure tested to 1.50 times\nAlternative MAOP or greater for eight (8) hours to meet 49 CFR 192.611(a)(3)(iii). The four (4)\nproposed special permit segments have been pressure tested to greater than 1.42 times the Alternative\nMAOP. This proposed special permit would allow FGT to maintain the current Alternative MAOP5\nas shown in Table 1 – Special Permit Segments.\nII. Special Permit Segments and Special Permit Inspection Areas\nThis permit pertains to the specified special permit segments and corresponding special permit\ninspection areas defined in this section.\nSpecial Permit Segments:\nThis proposed special permit applies to the special permit segments in Table 1 – Special Permit\nSegments and are identified using the FGT survey station (SS) references.\n4 The Class 1 to 3 or Class 2 to 3 location changes on the FGT pipelines have pipe with design factors in accordance with\n49 CFR 192.620(a)(1) for Alternative MAOP. The special permit segments utilize alternate design factors from 49\nCFR 192.620 per existing special permit PHMSA-2008-0077.\n5 The “MAOP” defined in Table 1 – Special Permit Segments and used throughout this document is an “Alternative\nMAOP” as defined in 49 CFR 192.620.\nPHMSA-2023-0022 – Florida Gas Transmission Company, LLC\nDraft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 2 of 53\n\n<<<PAGE 3>>>\n\nTable 1 – Special Permit Segments\nSpecial\nPermit\nStart\nSeam\nOutside\nDesign\nPressure\nDiameter\nLine Name Length\n(feet)\nSurvey\nStation\nEnd Survey\nStation\nCounty, State Class\nSummary\nNo.\nYear\nDwellings\nInstalled\nType/\nExternal\nMAOP\nSegment\nNumber\n(psig)6\n/ Test\n(inches)\n(SS)\n(SS)\nCoating\nFactor\n201350 18\n703 277+47 284+50 Hillsborough,\nFL 1 to 3 2 1992 DSAW/\nFBE 188251 30\n783 4105+18 4113+00 Hillsborough,\nFL 2 to 3 8 2000 FBE DSAW/\n188253 30\n1,255 4200+34 4212+89 Hillsborough,\nFL 1 to 3 2 2000 FBE DSAW/\n188257 30\n394 4445+98 4449+92 Hillsborough,\nFL 1 to 3 36 2000 DSAW/\nFBE St. Petersburg\nSarasota\nConnector\n(18”, 0.309”, X70)\nWest Leg Station\n27 to Ft Myers\n(30”, 0.515”, X70)\nWest Leg Station\n27 to Ft Myers\n(30”, 0.429”, X70)\nWest Leg Station\n27 to Ft Myers\n(30”, 0.515”, X70)\nNote: DSAW is a double submerged arc welded pipe longitudinal seam.\nFBE is fusion bonded epoxy external pipe coating.\nSpecial Permit Inspection Areas:\nThe special permit inspection areas are defined as the area that extends 220 yards on each side of the\ncenterline as listed in Table 2 – Special Permit Inspection Areas.\n1,333 0.56 /\n1.42\n1,333 0.56 /\n1.43\n1,333 0.67 /\n1.43\n1,333 0.56 /\n1.43\nTable 2 – Special Permit Inspection Areas\nSpecial\nSpecial Permit\nOutside\nStart Survey\nEnd Survey\nPermit\nLength7\nInspection\nDiameter\nLine Name\nStation\nStation\nSegment(s)\n(miles)\nArea Number\n(inches)\n(SS)\n(SS)\nIncluded\n1 201350 18 FLBVW 8+99 1951+01 36.9\n2\n188251,\n188253,\n188257\n30 FLMEE27 3670+75 7924+64 80.4\nExtended Special Permit Segments:\nThe extended special permit segment is defined as the special permit segment and the five (5)\ncontiguous miles past each endpoint.\nAttachment B contains general maps that include the pipeline route map showing the special permit\nsegment(s) and special permit inspection area(s) and a more detailed maps showing the area near the\nspecial permit segment(s).\n6 Pressure tests were conducted after July 1, 1965, see 49 CFR 192.619(a)(3) for applicability.\n7 If the special permit inspection area footage does not extent from launcher to receiver then the special permit\ninspection area would need to be extended.\nPHMSA-2023-0022 – Florida Gas Transmission Company, LLC\nDraft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 3 of 53\n\n<<<PAGE 4>>>\n\n8\nPHMSA proposes to grant this special permit based on the findings set forth in the “Draft\nEnvironmental Assessment and Proposed Finding of No Significant Impact” documents, which can be\nread in their entirety in Docket No. PHMSA-2023-0022 in the Federal Docket Management System\n(FDMS) located on the internet at www.regulations.gov.\nIII. Conditions\nPHMSA proposes to grant this special permit subject to FGT implementing the following conditions\non the special permit segments and special permit inspection areas. FGT must continue to\nimplement all applicable conditions of Special Permit – PHMSA-2008-0077 unless the condition is\nless stringent than Special Permit – PHMSA-2023-0022. Each condition detailed in this section\napplies to the special permit inspection areas and the corresponding special permit segment(s)\nunless otherwise noted in the condition:\n1) Condition 1 - Maximum Allowable Operating Pressure\na) Maximum Allowable Operating Pressure: FGT must continue to operate each special\npermit segment and special permit inspection area at or below the existing MAOP as\ndefined in Table 1 – Special Permit Segments.\nb) Pressure Test: FGT must identify previous pressure tests for each special permit segment.\nPressure test records for each special permit segment must meet 49 CFR 192.517(a) and be\ntraceable, verifiable, and complete (TVC)9 as required in 49 CFR 192.624(a)(1).10\ni) FGT must furnish TVC pressure test records to the Director, PHMSA Engineering and\nResearch Division, and to the Director, PHMSA Southwest Region, within 60 days of the\ngrant of the special permit. The pressure test records must be compliant with Condition\n1(b).\n11 FGT must receive a “no objection” letter from the Director, PHMSA Southwest\n8 If this application is granted, PHMSA may merge these special permit segments with existing special permit PHMSA-\n2020-0044.\n9 TVC procedures and records must follow the following: 1) “Pipeline Safety: Safety of Gas Transmission Pipelines:\nMAOP Reconfirmation, Expansion of Assessment Requirements and Other Related Amendments”; 84 FR 52218 to\n52219; October 1, 2019; and 2) PHMSA Advisory Bulletin: Pipeline Safety: Verification of Records; 77 FR 26822;\nMay 7, 2012; https://www.gpo.gov/fdsys/pkg/FR-2012-05-07/pdf/2012-10866.pdf.\n10 If PHMSA determines that FGT has not furnished TVC pressure test records to PHMSA for each special permit\nsegment FGT must meet Condition 1(b).\n11 The pressure test records must cover the entire length of the special permit segment, regardless of when the pipeline,\nsingle or multiple pipe joints, or other pipeline components were installed. Affidavits for a pressure test are not\nacceptable TVC pressure test records.\nPHMSA-2023-0022 – Florida Gas Transmission Company, LLC\nDraft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 4 of 53\n\n<<<PAGE 5>>>\n\nRegion, that the TVC pressure test records are compliant with 49 CFR 192.517(a) and\n192.620(a)(2) for Class 1, 2, or 3 locations with a pressure test at or above 1.42-times the\nMAOP, or FGT must pressure test each special permit segment in accordance with\nCondition 1(b)(ii).\nii) If FGT does not have a TVC record of a 1.42-times the MAOP hydrotest in accordance\nwith Subpart J, or the special permit segment requires an updated pressure test, the\nspecial permit segment must be hydrostatically tested12 to a minimum of 1.50 times the\nMAOP for eight (8) continuous hours in accordance with 49 CFR Part 192, Subpart J,\nwithin 18 months of the grant of this special permit.13\nc) MAOP Restoration or Uprating of Previously De-rated Pipe: MAOP restoration or\nuprating is not approved for this special permit.\n2) Condition 2 - Procedure Updates\nWithin 90 days of the grant of the special permit, FGT must develop and maintain procedures in\naccordance with 49 CFR 192.603 and 192.605 that incorporate the special permit condition\nrequirements as follows:\na) Operations and Maintenance Manual: FGT must amend the applicable sections of its\nOperations and Maintenance (O&M) manual(s) and procedures to incorporate the special\npermit conditions.\nb) Integrity Management Program:\ni) FGT must incorporate each special permit segment into its written integrity management\nprogram (IMP) procedures as if the special permit segment is a “covered segment” as\ndefined in 49 CFR 192.903, except for the reporting requirements contained in 49 CFR\n192.945.14 A special permit inspection area outside of a special permit segment is not\nrequired to be included as a “covered segment” in accordance with 49 CFR 192.903.\n12 For all in-service and pressure test failures, FGT must perform a root cause analysis, including the metallurgical\nexamination of the failed pipe, to determine if the failure is caused by a systemic or non-systemic issue. FGT must\nprovide the written results of this root cause analysis to the Director, PHMSA Southwest Region, within 90 days of the\nfailure and must submit a copy of the root cause analysis to the Director, PHMSA Engineering and Research Division.\n13 The grant of this special permit, as used throughout, is the signed issuance date of the special permit.\n14 FGT must follow the reporting requirements in Condition 15 – Annual Report as well as those noted throughout the\nconditions contained herein.\nPHMSA-2023-0022 – Florida Gas Transmission Company, LLC\nDraft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 5 of 53\n\n<<<PAGE 6>>>\n\nii) The special permit inspection area and special permit segment must have integrity threats\nidentified, assessed, and remediated in accordance with these special permit conditions, 49\nCFR 192.917, and 49 CFR Part 192, Subpart O.\niii) Any high consequence area (HCA) in either a special permit segment or a special permit\ninspection area must be assessed and remediated for threats in accordance with these\nspecial permit conditions and 49 CFR Part 192, Subpart O.\niv) All permit conditions that are applicable to a special permit segment or to a special permit\ninspection area are applicable to HCAs where the HCA overlaps a special permit segment\nor a special permit inspection area.\nv) All special permit conditions that are applicable to a special permit inspection area are\nalso applicable to the special permit segment. A special permit segment must meet the\nrequirements of 49 CFR 192, Subpart O, if Subpart O is more stringent than the special\npermit conditions.\nvi) The special permit inspection area must be able to be assessed using inline inspection\n(ILI) tools, including tethered or remotely controlled tools, in accordance with 49 CFR\n192.150 and 192.493.\nc) Damage Prevention Program: FGT must incorporate within a special permit inspection area\nthe applicable best practices of the Common Ground Alliance (CGA)15 in its damage\nprevention (DP) program.\n3) Condition 3 – Corrosion Control\nFGT must promptly address any corrosion control deficiencies in a special permit segment that\nare indicated by the inspection and testing programs required under 49 CFR 192.463 and 192.465.\na) Cathodic Protection Test Station Spacing: At least one (1) cathodic protection (CP) pipe-to-\nsoil test station must be located within each special permit segment, with a spacing not to\nexceed ½ mile between CP pipe-to-soil test stations. In cases where obstructions or restricted\nareas prevent such test station placement, the test station must be placed in the closest practical\nlocation, not to exceed a 3,000-foot spacing. CP pipe-to-soil test stations must be installed\nwithin 12 months of the grant of this special permit.\n15 Common Ground Alliance. (March 2020). Best Practices Guide. Retrieved from:\nhttps://commongroundalliance.com/BPguide.\nPHMSA-2023-0022 – Florida Gas Transmission Company, LLC\nDraft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 6 of 53\n\n<<<PAGE 7>>>\n\nb) Annual Monitoring of Test Station Potential Measurements: At least once every calendar\nyear, not to exceed 15 months, FGT must monitor CP pipe-to-soil test stations to meet 49 CFR\n192.463 and 192.465 for the special permit segment and must include “on and off” potential\nmeasurements. Test station readings (pipe-to-soil potential measurements) must comply with\nAppendix D – Section I.A. (1) of 49 CFR Part 192 or remediation detailed in paragraph (c) of\nthis condition is required. For hard spots identified with a Brinell Hardness (HB) of 300 HB or\ngreater, CP voltage levels must be maintained more electro-positive than minus 1.2 volts direct\ncurrent (DC).\nc) Inadequate Cathodic Protection Level Determination:\ni) In instances where inadequate potentials are a result of an electrical short to an adjacent\nforeign structure, a rectifier malfunction, an interruption of power source, or an\ninterruption of CP current due to other non-systemic or location-specific causes, FGT must\ndocument and repair these instances. A close interval survey (CIS) will not be required.\nii) All other instances must be assessed as detailed in Condition 4 – Close Interval Surveys.\nd) Remedial Action Plans:\ni) Within six (6) months of identifying a deficiency, FGT must develop a remedial action plan\nto restore CP to meet 49 CFR 192.463. Within two (2) months of the finding, FGT must\napply for any necessary environmental permits (Federal or state).\nii) FGT must complete the remediation and confirm restoration of adequate CP over the entire\narea where inadequate CP levels were detected within 12 months of the deficiency finding\nor as soon as practicable after obtaining the necessary permits.\n4) Condition 4 – Close Interval Surveys\na) Survey Methodology and Boundaries:\ni) FGT must perform an “on and off” current CIS at a maximum 5-foot spacing along the\nentire length of each special permit segment.\n16\nii) FGT must evaluate each special permit segment in accordance with 49 CFR 192.463.\n16 Each condition in this special permit that requires FGT to perform an action with respect to the special permit\ninspection area also requires FGT to perform that action on each special permit segment within the area.\nPHMSA-2023-0022 – Florida Gas Transmission Company, LLC\nDraft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 7 of 53\n\n<<<PAGE 8>>>\n\niii) For inadequate CP level determination described in Condition 3(c)(ii), FGT must conduct\na CIS in both directions from the test station with an inadequate CP reading with the CIS\nending at the adjacent test stations.\nb) Survey Intervals: FGT must perform the CIS within the following timeframes:\ni) Initial assessment must be completed for each newly incorporated and extended special\npermit segment within 12 months after the grant of the special permit. For a special\npermit segment renewal, the CIS may be conducted at the next reassessment interval.17\nii) Reassessments must be conducted every five (5) years not to exceed 66 months. CIS\nassessments within the reassessment interval are not required to be performed in the same\nyear as ILI reassessments.\nc) Survey Remediation and Remedial Action Plans:\ni) If a special permit segment requires the use of 100 millivolt shift criteria18 or the\ninstallation of linear anodes along the special permit segment to meet the CP requirements\nof 49 CFR 192.463, it is not eligible to operate with a Class 1 pipe in a Class 3 location.\nFGT must either: (1) replace the pipe in the special permit segment with Class 3 location\nstandard (design factor) pipe (see 49 CFR 192.111(a)); (2) recoat the pipe with non-\nshielding external coating within 12 months of the finding; or (3) lower the MAOP to meet\n49 CFR 192.611.\nii) Within four (4) months of identifying a deficiency, FGT must develop a remedial action\nplan to restore CP to meet 49 CFR 192.463. Within two (2) months of the remedial action\nplan being developed, FGT must apply for any necessary environmental permits (Federal\nor state).\n17 A CIS survey conducted in 2020 for a special permit segment that is permit condition compliant would not need to be\nresurveyed in 2021 but could wait until the next CIS survey reassessment time.\n18 A.W. Peabody, “Peabody’s Control of Pipeline Corrosion,” second edition, “Criteria for Cathodic Protection.” “The\n100mV polarization criterion should not be used in areas subject to stray current because 100 mV of polarization may\nnot be sufficient to mitigate corrosion in these areas. This criterion also should not be used in areas where the\nintergranular form of external SCC, also referred to as high-pH or classical SCC, is suspected. The potential range for\ncracking lies between the native potential and -850 mV (CSE) such that application of the 100mV polarization criterion\nmay place the potential of the structure in the range for cracking.”\nPHMSA-2023-0022 – Florida Gas Transmission Company, LLC\nDraft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 8 of 53\n\n<<<PAGE 9>>>\n\niii) FGT must complete remediation of each special permit segment and confirm restoration of\nadequate CP over the entire area where inadequate CP levels were detected within 12\nmonths of the survey or as soon as practicable after obtaining the necessary permits.19\n5) Condition 5 – Inline Inspection\na) Threat Identification: FGT must implement data integration and identify integrity threats in\nthe special permit inspection area at least once each calendar year, with intervals not to\nexceed 15 months, in accordance with 49 CFR 192.917 and Condition 13(c) – Data\nIntegration. The stress corrosion cracking (SCC) threat assessment for the extended special\npermit segment,\n20 must be conducted using the current incorporated by reference (IBR) edition\nof the American Society of Mechanical Engineers (ASME) Standard B31.8S, \"Managing\nSystem Integrity of Gas Pipelines\" (ASME B31.8S) Appendix A3 and National Association of\nCorrosion Engineers (NACE) Standard Practice (SP) 0204-2008, \"Stress Corrosion Cracking\nDirect Assessment Methodology,\" Sections 1.2.1.1 and 1.2.2.\nb) Inline Inspection Methodology: FGT must conduct instrumented ILI integrity assessments in\naccordance with 49 CFR 192.493, for each special permit inspection area for all threats\nidentified in accordance with 49 CFR 192.919 and 192.921.\ni) At a minimum, FGT must conduct ILI assessments for corrosion and denting with high-\nresolution (HR) magnetic flux leakage (HR-MFL) and HR deformation tools with\ndeformation-extended sensor arms not limited by pig cups.\nii) For near-neutral or high-pH SCC (cracking threat), FGT must use an ILI tool21 that will\nidentify tight cracks.\n22\niii) A special permit segment with electric flash welded (EFW) pipe must have an ILI tool\nassessment run for hard spots and cracking from hard spots.\n19 If remediation based upon the findings of the CIS is not practicable within 12 months of the CIS survey, FGT must\nsubmit a schedule and justify the delay 60 days prior to the 12-month completion requirement to the Director, PHMSA\nSouthwest Region. FGT must receive a “no objection” letter from the Director, PHMSA Southwest Region, prior to a\npipe coating remediation schedule extension.\n20 The extended special permit segment is defined as the special permit segment and the five (5) contiguous miles past\neach endpoint.\n21 The crack ILI tool must be comparable to an electro-magnetic acoustic transducer (EMAT) ILI tool.\n22 FGT may propose an alternative assessment method for SCC (such as spike hydrostatic testing in accordance with 49\nCFR 192.506) to the Director, PHMSA Southwest Region, with a copy of the proposal to the Director, PHMSA\nEngineering and Research Division. FGT must receive a “no objection” letter from the Director, PHMSA Southwest\nRegion, prior to implementing any alternative assessment methods for SCC.\nPHMSA-2023-0022 – Florida Gas Transmission Company, LLC\nDraft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 9 of 53\n\n<<<PAGE 10>>>\n\niv) In a special permit inspection area that has experienced pipe or girth weld leaks or\nruptures due to soil movement or the threat has been identified, FGT must run inertial\nmeasurement unit (IMU) and HR-deformation ILI tools for detection and remediation of\nstrains and denting of the pipe body and girth welds from soil or pipe movements that\nimpair pipeline integrity. Remediation must be conducted as determined by Condition\n13(j) – Pipe and Soil Movement.\nc) Inline Inspection Assessment Intervals: FGT must conduct initial assessments and\nreassessments for the special permit inspection area in accordance with the following:\ni) Initial ILI assessments must be conducted as follows:\n(1) If the special permit segment has EFW pipe, it must be assessed for hard spots within\n18 months of the special permit grant date.\n(2) If cracking has been identified as a threat for the extended special permit segment, it\nmust be assessed within 18 months of the special permit grant date.\n(3) All other identified threats must be assessed within two (2) years of the special permit\ngrant date.\n(4) For newly identified threats, assessments must be completed within two (2) years of\nidentification.\n(5) Previous ILI assessments may be applied if Condition 8 – Anomaly Evaluation and\nRemediation is completed, and the Condition 5(c)(ii) reassessment interval is\nmaintained.\nii) Reassessments must be completed in accordance with the shortest interval of the following:\n(1) 49 CFR 192.939(a);\n(2) Intervals of five (5) calendar years not to exceed 66 months, if the special permit\nsegment contains any of the following:\n(a) low-frequency electric resistance welded (LF-ERW) or EFW pipe,\n(b) hard spots,\n(c) shorted carrier pipe to the casing,\n(d) susceptible to SCC, or\n(e) pipe or soil movement; or\nPHMSA-2023-0022 – Florida Gas Transmission Company, LLC\nDraft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 10 of 53\n\n<<<PAGE 11>>>\n\n(3) The engineering critical assessment (ECA) determined interval, if applicable,\niii) After conducting two (2) assessments of a threat, one (1) of which must be after the grant\nof this special permit, FGT may request reassessment intervals up to seven (7) years for\nthat threat assessment. FGT must submit for and receive a “no objection” letter from the\nDirector, PHMSA Southwest Region, prior to implementing this change.\niv) If factors beyond FGT’s control prevent the completion of an assessment within the\nrequired timeframe or reassessment interval, FGT must perform the assessment as soon as\npracticable, and FGT must submit a letter justifying the delay and provide the anticipated\ndate of completion to the Director, PHMSA Southwest Region, no later than two (2)\nmonths prior to the end the timeframe or interval. FGT must receive a “no objection” letter\nfrom the Director, PHMSA Southwest Region, for the delay or must lower the MAOP of\nthe special permit segment in accordance with 49 CFR 192.611.\nd) Remediation: Anomaly assessments must be evaluated and remediated in accordance with\nCondition 8 – Anomaly Evaluation and Remediation.\n6) Condition 6 - Girth Welds\na) Construction Girth Weld Non-Destructive Test Records: FGT must provide records to\nPHMSA that demonstrate the girth welds in the special permit inspection area were either:\ni) Non-destructively tested (NDT) at the time of construction in accordance with the Federal\npipeline safety regulations at the time the pipelines were constructed, or\nii) At least 1% of the girth welds and a minimum of two (2) girth welds in each special permit\nsegment were NDT after initial construction and prior to the special permit application.\nFGT must demonstrate these welds were excavated, NDT, and repaired, if the welds do not\nmeet Federal pipeline safety regulations at the time the pipelines were constructed.\nb) Missing Records: If FGT cannot provide girth weld records to PHMSA to demonstrate\ncompliance with Condition 6(a), FGT must complete either Condition 6(b)(i) or both\nConditions 6(b)(ii) and (iii) within 12 months of the grant of this special permit as follows:\ni) Certify to PHMSA, in writing, that there have been no in-service leaks or breaks in the\ngirth welds in the special permit inspection area for the life of the pipeline; or\nPHMSA-2023-0022 – Florida Gas Transmission Company, LLC\nDraft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 11 of 53\n\n<<<PAGE 12>>>\n\nii) Evaluate the terrain along each special permit segment for threats to girth weld integrity\nfrom soil or settlement stresses, perform NDT, and remediate all such integrity threats;23\nand\niii) Excavate,24 visually inspect, and perform NDT on at least two (2) girth welds on each\nspecial permit segment in accordance with the applicable American Petroleum Institute\nStandard 1104, “Welding of Pipelines and Related Facilities” (API 1104) as follows:\n(1) Using the edition of API 1104 current at the time the pipeline was constructed;\n(2) Using the edition of API 1104 IBR in the Federal pipeline safety regulations at the time\nthe pipeline was constructed; or\n(3) Using the edition of API 1104 currently IBR in 49 CFR 192.7.\nc) Defective Girth Welds: If any girth weld in a special permit segment is found unacceptable in\naccordance with the API 1104 IBR Edition at the time of pipeline construction, FGT must\nrepair the girth weld immediately and then prepare an inspection and remediation plan for all\nremaining girth welds in the special permit segment based upon the repair findings and the\nthreat to the special permit segment. FGT must submit the inspection and remediation plan\nfor girth welds to the Director, PHMSA Southwest Region, and must receive a “no objection”\nletter for the girth weld remediation plan prior to its implementation.25 FGT must remediate\ngirth welds in the special permit segment in accordance with the inspection and remediation\nplan within 90 days of the “no objection” letter receipt.26\n7) Condition 7 - Stress Corrosion Cracking Threat\nFGT must evaluate the entire length of each special permit inspection area27 for SCC as follows:\n23 If a special permit segment has not had girth weld NDT to meet Condition 6 – Girth Welds and has experienced pipe\nor girth weld leaks or ruptures due to soil movement or the threat has been identified, then Condition 5(b)(iv) must be\nconducted within 12 months of the finding.\n24 FGT must evaluate the pipe for SCC any time the special permit inspection area is uncovered or excavated in\naccordance with Condition 8(b) or (c) of this special permit. Pipe with fusion bonded epoxy coating does not require\nSCC evaluation when excavated unless SCC has been identified as a threat in the special permit inspection area.\n25 The Director, PHMSA Southwest Region, must respond to FGT's submittal letter within 90 days of receipt with a\ndecision letter, or either give FGT a request for additional information or a need of additional time for PHMSA to\nreview the request.\n26 FGT must include any plan requirements or comments received from the Director, PHMSA Southwest Region, into the\nremediation plan.\n27 FGT has documented 0 occurrences of SCC or cracking in the [special permit segment/special permit inspection area].\nPHMSA-2023-0022 – Florida Gas Transmission Company, LLC\nDraft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 12 of 53\n\n<<<PAGE 13>>>\n\na) Threat Assessments: FGT must complete the SCC threat assessment as detailed in Condition\n5(a) – Threat Assessment.\nb) SCC Integrity Assessment: If the threat assessment required under Condition 7(a) indicates\nthe extended special permit segment28 is susceptible to either near-neutral or high-pH SCC,\nFGT must perform an SCC assessment on the extended special permit segment in accordance\nwith Condition 5 – Inline Inspection. SCC integrity assessment using spike pressure testing\nis not approved for this special permit.29\nc) Examination of Pipe: If the threat of SCC exists in the extended special permit segment as\ndetermined in Condition 7(a), FGT must directly examine the pipe for SCC when the coating\nhas been identified as poor during the pipeline examination. The examination must be\nconducted using an accepted crack detection practice in accordance with 49 CFR\n192.710(c)(4), (d), and Condition 7(d) when the extended special permit segment is\nuncovered for any reason to comply with the special permit and integrity management\nactivities, not including One Call activities (49 CFR 192.614).\nd) Inspection of Pipe at Excavations: Except for pipe coated with non-shielding coatings\n(fusion-bonded or liquid-applied epoxy coatings) and excavations performed in accordance\nwith 49 CFR 192.614(c), FGT must directly examine the pipe for SCC using non-destructive\nexamination methods appropriate for the type of pipe and integrity threat conditions in the\nditch. FGT must use appropriate methods for crack detection, such as phased array ultrasonic\ntesting (PAUT), inverse wavefield extrapolation (IWEX), or magnetic particle inspection\n(MPI),\n30 when an extended special permit segment is uncovered, and the coating has been\nidentified as poor during the pipeline examination. Visual inspection is not sufficient to\ndetermine “poor coating.” FGT must “jeep” the excavated segment to determine the coating\ncondition. Examples of “poor coating” include, but are not limited to, a coating that has\nbecome damaged and is losing adhesion to the pipe which is shown by falling off the pipe\n28 The extended special permit segment is defined as the special permit segment and the five (5) contiguous miles past\neach endpoint.\n29 FGT may propose an alternative assessment method for SCC (such as spike hydrostatic testing in accordance with 49\nCFR 192.506) to the Director, PHMSA Southwest Region, with a copy of the proposal to the Director, PHMSA\nEngineering and Research Division. FGT must receive a “no objection” letter from the Director, PHMSA Southwest\nRegion, prior to implementing any alternative assessment methods for SCC.\n30 When MPI finds cracking, another method must be used to size the crack unless the crack can be completely ground\nout and still meet the pipeline Alternative MAOP.\nPHMSA-2023-0022 – Florida Gas Transmission Company, LLC\nDraft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 13 of 53\n\n<<<PAGE 14>>>\n\nand/or shields the CP. FGT must keep coating records31 at all excavation locations in the\nspecial permit inspection area to demonstrate the coating condition.\ne) Discovery of SCC: If FGT discovers SCC32 activity by any means within the extended special\npermit segment in similar pipe vintage (manufacturer, manufacturing time or age, diameter,\nwall thickness, grade, and seam type) and pipe coating vintage (in accordance with 49 CFR\n192.917(e)), or the extended special permit segment has had an in-service or hydrostatic test\nSCC failure or leak,\n33 the special permit segment must be further assessed and mitigated,\nwithin 18 months of finding SCC and reassessed every five (5) calendar years or less34 based\nupon the evaluated growth of the SCC, using one (1) of the following methods:\ni) Spike Hydrostatic Test Program:35\n(1) FGT must perform its SCC spike hydrostatic test program in an extended special\npermit segment in accordance with 49 CFR 192.506 and include an ECA of the results\nthat includes a determination of the reassessment interval, and\n(2) If a joint of pipe in an extended special permit segment leaks or ruptures during a\nhydrostatic test due to SCC, FGT must replace the pipe joint that does not meet 49 CFR\n192.611 in the extended special permit segment with new pipe. FGT must complete a\nsuccessful SCC hydrostatic test prior to returning the extended special permit segment\nto operational service;\n31 The records must include, at a minimum, a description of FGT’s detection procedures, records of finding, and\nmitigation procedures implemented for the excavation.\n32 “SCC” activity shall be defined as greater than 20 percent wall thickness depth and 2-inches in length.\n33 For all in-service and pressure test failures, FGT must perform a root cause analysis, including the metallurgical\nexamination of the failed pipe, to determine if the failure is caused by a systemic or non-systemic issue. FGT must\nprovide the written results of this root cause analysis to the Director, PHMSA Southwest Region, within 90 days of the\nfailure and must submit a copy of the root cause analysis to the Director, PHMSA Engineering and Research Division.\n34 FGT has the option to submit a written request to the Director, PHMSA Southwest Region, with a copy to the Director,\nPHMSA Engineering and Research Division, for extension of the crack assessment interval to seven (7) years, as\ndefined in 49 CFR 192.939(a), if the ECA shows that five (5) calendar year assessments are not required. FGT must\nreceive a “no objection” letter from the Director, PHMSA Southwest Region, prior to extending the assessment interval\nto seven (7) calendar years.\n35 FGT may propose an alternative assessment method for SCC (such as spike hydrostatic testing in accordance with 49\nCFR 192.506) to the Director, PHMSA Southwest Region, with a copy of the proposal to the Director, PHMSA\nEngineering and Research Division. FGT must receive a “no objection” letter from the Director, PHMSA Southwest\nRegion, prior to implementing any alternative assessment methods for SCC.\nPHMSA-2023-0022 – Florida Gas Transmission Company, LLC\nDraft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 14 of 53\n\n<<<PAGE 15>>>\n\nii) Crack Detection Tool Assessment: FGT must run an electro-magnetic acoustic transducer\n(EMAT) ILI tool or other equivalent crack detection ILI tool in the extended special\npermit segment;\niii) MAOP Lowered: FGT must lower the MAOP of the special permit segment to 60%\nspecified minimum yield strength (SMYS).\niv) Pipe Replacement: FGT must replace all pipe and comply with 49 CFR 192.611 and\n192.619 in the special permit segment; or\nv) Operating Pressure Lowered: FGT must lower the operating pressure of the special\npermit segment to 20% below the maximum pressure during the preceding 90-day\noperating interval until FGT conducts an ECA and remediates the special permit segment.\nf) SCC Remediation Plan: If FGT discovers any SCC activity in the extended special permit\nsegment, FGT must submit an SCC remediation plan to the Director, PHMSA Southwest\nRegion, and send a copy to the Director, PHMSA Engineering and Research Division, no later\nthan 90 days after the finding of SCC.36 The plan must:\ni) Meet Condition 7(e) and include an SCC remediation/repair plan with SCC\ncharacterization and timing; or\nii) Include a technical justification that shows that FGT is addressing the threat for SCC in the\nspecial permit segment.\n8) Condition 8 - Anomaly Evaluation and Remediation\na) General: FGT must use the procedures specified in the special permit conditions, 49 CFR\n192.712, and Attachment A when evaluating anomalies. FGT must account for ILI tool\ntolerance and corrosion growth rates in determining scheduled response times and repairs and\nmust document and justify the values used.\ni) ILI Tool Accuracy: FGT must demonstrate ILI tool tolerance accuracy for each ILI tool\nrun by using calibration excavations and unity plots that demonstrate ILI tool accuracy to\nmeet the tool accuracy specification provided by the vendor (typical for depth within +10%\naccuracy for 80% of the time). FGT must incorporate ILI tool accuracy by ensuring that\neach ILI tool service provider determines the tolerance of each tool and includes that\n36 For FGT to go forward with the technical justification for addressing the SCC threat, FGT must receive a “no\nobjection” letter from the Director, PHMSA Southwest Region.\nPHMSA-2023-0022 – Florida Gas Transmission Company, LLC\nDraft Special Permit – Class 1 and 2 to Class 3 Locations – Florida Page 15 of 53\n\n<<<PAGE 16>>>\n\ntolerance in determining the size of each anomaly feature reported to FGT. FGT must\ncompare previous indications to current indications that are significantly different. If a\ntrend is identified where the tool has been consistently overcalling or under-calling, the\nremaining ILI features must be re-graded accordingly. ILI tools used must be calibrated as\nfollows:\n(1) General ILI Tool Calibration: ILI tool calibrations must use ILI tool run results and\nanomaly calibrations from either the special permit inspection area or from the\ncomplete ILI tool run segment if the continuous ILI segment is longer than the special\npermit inspection area. ILI calibration excavations may include previously excavated\nanomalies or recent anomaly excavations with known dimensions that were field\nmeasured for length, depth, and width, externally re-coated, CP maintained, and\ndocumented for ILI calibrations prior to the ILI tool run. A minimum of four (4)\ncalibration excavations must be used for unity plots.37\n(2) EMAT ILI Tool Calibration:\n(a) ILI calibration for EMAT ILI Tools must be based upon excavation results of a\nminimum of the two (2) most severe anomalies from a combined review of crack\ndepth and length. If the EMAT tool identifies only one (1) anomaly, the anomaly\nmust be excavated and assessed. FGT can propose alternative EMAT ILI Tool\nevaluation procedures to the Director, PHMSA Southwest Region, but must receive\na “no objection” letter prior to usage of these procedures.\n(b) If the EMAT ILI tool does not identify any cracking anomalies above the minimum\nlength and depth criteria for 90% probabilit","truncated":true,"body_characters":156564}